LNG Industry March 2013

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FMC Technologies invented the first offshore LNG loading technology. Today we are developing new solutions built on proven components. Our Articulated Tandem Offshore Loader (ATOL) safely performs high-velocity LNG transfers in severe conditions with waves up to 18 feet (5.5 meters). Our Offshore Loading Arm Footless (OLAF) side by side transfer solution accommodates massive new FLNG freeboards in the range of 82 feet (25 meters). And for tomorrow? We’re practically there already.

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CONTENTSISSN 1747-1826

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12 LNGINDUSTRY MAR/APR 2013 MAR/APR 2013 LNGINDUSTRY 13

Looking back at 2012, a certain theme emerges centred around the realisation of the abundant supply of natural gas in the US as a result of the rapid growth in shale development and production. Because of this

supply growth, Henry Hub prices are at unsustainably low levels and demand growth is necessary in order to stabilise prices and to support a healthier market with supply and

demand in closer balance. In the December 2012 release of its long-term fundamental outlook, North American Natural Gas Market Outlook, Fall 2012,1 Navigant has anticipated that this market growth will come in the near-term from the recovery of US industrial demand, in the mid-term from the addition of North American LNG exports, and in the long-term from stable increases in US natural gas-fired generation.

As most now recognise, growth in shale production has been profound over the last few years, increasing 900% from around 2 billion ft3/d in 2005 to 20 billion ft3/d in 2011. In doing so, it has transformed the North American gas market. While more recently natural gas-directed activity, as measured by its drilling levels, has declined precipitously, the current total US dry production level of 64.8 billion ft3/d is still above the 2011 average levels of 62 billion ft3/d.2 This increase of 2.8 billion ft3/d can be explained by a variety of market factors, although the key ones are the continued increase in Marcellus shale production, increased drilling and production efficiencies being developed by the gas industry, and growth in associated gas as a consequence of increasing oil directed drilling going on in the country. In this article, Navigant provides a snapshot of how it sees the natural gas market unfolding over the long-term to 2035, as reflected in its North American Natural Gas Market Outlook, Fall 2012 release.

As the US experiences a shale gas revolution, the question now is where is

all this abundant natural gas going to go? Rebecca Honeyfield and Gordon Pickering,

Navigant Consulting Inc., USA, suggest three key demand areas.

MAR/APR 2013

12

19 In or out?Roberto Ruiperez Vara, PE, PMP, and Phil J. Suter, CH-IV International, USA.

26 LNG global surveyJohn A. Sheffield, John M. Campbell | PetroSkills.

32 Is it a ship? Is it a permanent installation?Simon Rainey Q.C., Quadrant Chambers, UK.

37 Efficiency vs availability in FLNGTom Haylock, KANFA Aragon, Norway.

42 Offshore processingDominique Gadelle, Tania Simonetti and Sylvain Vovard, Technip, France.

49 A new ventureJohn Hritcko, Wison Offshore & Marine Inc., USA.

53 FLNG rock and rollFabien A. Wahl, Nikkiso Cryo Inc., USA.

59 Made to measureChristopher Finley, Ebara International Corp., USA.

63 Glass sealingThomas Goettlinger, Schott, Germany, and Don Polkinghorn, Ebara International Corp., USA.

67 Setting standardsKeith Stewart, Herose GmbH, Germany.

70 Moving forwardJon Gorrotxategi, AMPO Poyam Valves, Spain.

75 A gas powered futureLuis Benito, Lloyd’s Register, UK.

80 All aboardTore Lunde and Per Helge Madsen, Gas Solutions, Wärtsilä Ship Power.

87 Floating flexibilityBrooke E. King, Excelerate Energy, USA.

91 Ship to shoreJack X. Liu, Liu Advanced Engineering LLC, USA.

97 Analysing the weakest linkShane Hale, Emerson Process Management, Rosemount Analytical, USA.

101 Go with the flowMike Williams, Invensys Operations Management, USA.

105 Partner upGreg Hallauer, Yokogawa Corporation of America, USA.

111 Detailed dataC. Souprayen; A. Tripathi; G. Vaton; T. Grinnaert; M. Leguellec; and L. Ait-Hamou, Fluidyn France.

117 Simplifying simulationColin Watson, Symetri, UK.

121 Standards, competence and quality...preserving a trinityJames R.C. Garry, Red Core Consulting, Canada.

03 Comment

05 LNG news

12 Where’s all the gas going?Rebecca Honeyfield and Gordon Pickering, Navigant Consulting Inc., USA.

CB&I, as part of a joint venture with Zachry Industrial, Inc., was selected to provide front-end engineering and design (FEED) services for Freeport LNG’s liquefaction project located near Freeport, Texas, USA. The project encompasses three LNG liquefaction trains, each rated at 4.4 million tpy, and corresponding pretreatment facilities.

Graphic courtesy of Freeport LNG Development, L.P.

LNG_MARAPR_2013_01-02.indd 1 25/03/2013 10:44

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In the January/February issue of LNG Industry, I commented on how rising LNG prices had contributed to Japan’s record trade deficit of US$ 78 billion last year. Since then, the

country’s Prime Minister Shinzo Abe has met with President Barack Obama in Washington to ask the US to permit exports of its vast shale gas reserves to Japan. In a move that may help facilitate such a deal, Japan has now signaled its intention to join talks on the Trans-Pacific Partnership (TPP), a free trade agreement (FTA) currently being negotiated by 11 countries in Asia and the Americas.

This should come as no surprise, as Japan attempts to gain automatic access to cheaper LNG. The US shale gas boom has driven prices well below those seen in much of Asia and Europe. US exporters currently price their gas off Henry Hub, which sells for around US$ 3 – 4/million Btu, less than a quarter of the price that LNG is sold for in Asia.

This price gap is leading to increasing pressure from Asia for changes to traditional oil-indexed pricing and contract mechanisms. Such change may be on the way. According to a recent global survey of the LNG industry conducted by John M. Campbell | Petroskills (the results of which are presented in this issue, starting on p. 26), we can expect to see more short-term contracts based on negotiated gas prices going forward.

The survey also suggests that an Asian hub pricing may eventually prevail. The obstacles and opportunities of developing such a trading hub have recently been outlined in a report from the International Energy Agency.* In it, the IEA suggests that “the future role of gas in Asia will depend on whether natural gas pricing is tied more closely with supply and demand fundamentals in the region.” The report emphasises the importance of creating an Asian gas trading hub, with Singapore put forward as the most likely candidate for such a role.

The industry appears to be on the brink of a price reform. In the meantime, Japanese gas importers are understandably reluctant to commit to oil-indexed LNG as they wait to see how much Henry Hub indexed gas is allowed to flow out of the US.

It will be interesting to monitor what influence Japan’s decision to join the TPP negotiations will have on the prospects of such exports. The fact that Japan has decided to join the talks, in itself, does not automatically open the country up for US exporters. The accord would still need to include natural gas and requires congressional approval. There is also a strong campaign underway by many opposed to unrestricted LNG exports from the US, who raise both environmental and domestic pricing concerns. However, bringing Japan into a FTA agreement would certainly appear to be welcome news for those companies trying to export LNG from the US.

The question is what impact those exports, and the potential new LNG pricing structure, will have on the rest of the industry. There are conerns that Japan’s desire for lower prices is holding up other projects, where developers require the revenue security provided by long-term, oil-linked contracts. As Ernst & Young points out in its latest ‘Global LNG Report’: “As substantial volumes of lower-cost LNG move into Asian markets, projects at the high end of the supply curve – namely, many of the Australian projects – will become increasingly vulnerable.”

The debate is set to continue at this year’s LNG 17 Conference in Houston, Texas. LNG Industry will be exhibiting at the show, so please drop by stand 1065 to give us your thoughts!

*A summary of this report, and many more, can be found in the new ‘Special Reports’ section of our website: www.energyglobal.com/news/special-reports.

LNG_MARAPR_2013_03-04.indd 3 25/03/2013 11:31

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LNG_MARAPR_2013_03-04.indd 4 22/03/2013 16:39

LNGNEWS

MAR/APR 2013 LNGINDUSTRY 5

Russia

GE awarded Sakhalin service contract

GE Oil & Gas has received a 16-year service contract extension valued at US$ 333 million for Sakhalin-2,

one of the world’s largest integrated oil and gas projects that operates on Sakhalin Island in the Russian Far East.

As part of the new extension, GE also signed an MOU with the provincial government to work together with them in developing future power generation projects for Sakhalin Island.

The service contract extension covers four GE Frame 7EA gas turbines that drive the process trains for Sakhalin’s LNG plant and five GE Frame 5 gas turbines that are used for electricity production at the site.

The service agreement includes planned and unplanned outages, parts and repairs, an availability guarantee, remote monitoring and diagnostics, and an on-site GE team of technicians.

Sakhalin Energy operates the project under a production sharing agreement with the Russian Federation. The production capacity of the plant is 9.6 million tpy of LNG, most of which is exported to South Korea and Japan.

Malaysia

JGC wins Petronas LNG contract

JGC Corp. has been awarded the Engineering, Procurement, Construction and Commissioning (EPCC) contract for the

9th LNG train and its associated facilities in the Petronas LNG complex in Bintulu, Sarawak, Malaysia.

The contract is valued at US$ 2 billion and is scheduled for completion at the end of 2015.

Over the last 30 years, JGC Corp. has performed the EPCC contracts for the other eight LNG trains at the complex. The company has also completed rejuvenation projects to increase the plant’s capacity.

Train 9 will have a capacity of 3.6 million tpy of LNG and will source its feed gas from Petronas’s newly discovered offshore gas fields off the coast of Sarawak.

In January 2012, two groups including JGC were awarded the contract to take part in a design competition for the Front-End Engineering Design (FEED) and EPCC early works for this project. Both FEED packages were then put through a rigorous technical and commercial evaluation to select the winning contractor, leading to the award of the EPCC contract.

Tanzania

BG and Statoil still proceeding with LNG project

T im Dodson, Executive Vice President for Exploration in Statoil, has told Reuters reporters in an interview

that Statoil and BG Group intend to proceed with their combined plan to build an LNG terminal in Tanzania and are working with BG to find a suitable landing site.

The announcement follows news that Statoil has made a third major gas disocvery in Block 2 offshore Tanzania in a year. The company discovered 4 – 6 trillion ft3 of natural gas in the Tangawizi-1 well, which brings the total in-place volumes up to 15 – 17 trillion ft3.

BG Group has also completed an appraisal programme in the Jodari field of Block 1 offshore Tanzania, with a drill stem test confirming the excellent quality of the Tertiary reservoir.

Meanwhile, BG group has completed an agreement to supply LNG to Gujarat State Petroleum Corporation Limited (GSPC) in India. The Group will initially supply 1.25 million tpy of LNG beginning in 2015 and for up to 20 years, potentially increasing to 2.5 million tpy after two years.

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LNGNEWS

6 LNGINDUSTRY MAR/APR 2013

NEWS HIGHLIGHTS

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Scope for transformation of Asia-Pacific natural gas market

Breakthrough floating LNG agreement

Shell acquires Repsol’s LNG assets

USA

NASA’s Michoud Facility to build LNG tanks

NASA’s Michoud Assembly Facility in New Orleans, the agency’s only large-scale advanced manufacturing

facility, will soon be building LNG tanks with commercial applications on Earth.

Lockheed Martin Corp. has announced it is drawing on the unique experience and equipment at Michoud to manufacture the LNG tanks. The company has received initial orders to manufacture cryogenic tanks for fueling LNG-powered vessels. As part of its longer-range business plan, Lockheed Martin will adapt production equipment used to manufacture the external tank for the space shuttle to a wide range of LNG supply chain applications.

“Our entry into the LNG tank market is a prime example of how Lockheed Martin is leveraging capabilities and technologies developed for government programmes to meet the needs of private sector customers who drive our nation’s economy,” said Gerry Fasano, President of Lockheed Martin Information Systems and Global Solutions-Defense.

“We are very pleased to add Lockheed Martin’s liquefied natural gas tank production to the portfolio of advanced manufacturing work and research under way here,” said Roy Malone, Director of Michoud Assembly Facility. “It is gratifying to see the manufacturing processes and capabilities developed to build large space flight structures being put to use in the energy industry here on Earth.”

Netherlands

Shell launches LNG barge

Shell has launched the first 100% LNG powered tank barge at a Christening ceremony attended

by Shell CEO Peter Voser at Peters Shipyards in the Netherlands.

The LNG powered barge, Greenstream, has been built and designed at Peters Shipyards and will be managed by the Dutch based Interstream Barging (ISB). This is the first of two new LNG powered barges to be chartered by Shell. Greenstream has been launched on schedule and will start operating on the Rhine in the next few weeks.

Dr. Grahaeme Henderson, Shell Vice President Shipping and Maritime, commented, “Shell anticipates a bright future for LNG as a fuel in both coastal and inland shipping as it can help customers meet strict emissions standards such as those that are due to apply on the Rhine.”

Greenstream has been designed with many new safety and efficiency features. For example, she has four small efficient engines rather than one large engine as in traditional barges. This means that power can be varied, as less is required to travel downstream than upstream, with potential for fuel savings.

LNG_MARAPR_2013_05-11.indd 6 25/03/2013 10:46

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LNG_MARAPR_2013_05-11.indd 7 22/03/2013 16:44

LNGNEWS


DIARY DATES

6 - 9 May 2013OTC 2013Houston, Texas, USAwww.otcnet.org/2013/

3 - 5 June 2013ILTA 2013Houston, Texas, USAwww.ilta.org

3 - 6 June 2013Unconventional Gas & Oil SummitLondon, UKwww.oilandgasunconventional.com

6 - 7 June 2013Small Scale LNG 2013Oslo, Norwaywww.tekna.no/intconf

24 - 27 September 2013LNG Global CongressLondon, UKwww.informaenergyevents.com/event/LNG-World-Conference

30 September - 3 October 2013Pump/Turbomachinery SymposiaHouston, Texas, USAturbolab.tamu.edu/articles/pump_turbomachinery_symposia

France

KSB plant visit

I n November last year, LNG Industry was invited to visit KSB’s research and production facilities for a presentation

on the new technologies it is developing in the field of rubber and cryogenic valves for the industry.

Delegates went on a tour of KSB’s huge factory complex in La Roche Chalais, France, where the valves and rubber seals are made. The valves, up to 42 in. dia., are assembled and cryogenically tested in pools of liquid nitrogen at -196 ˚C. Over 350 000 valves/year are produced on site.

KSB showcased a number of new technologies for the LNG industry that will aid safety and efficiency, including its range of double offset and triple offset cryogenic valves for LNG tankers and terminals. The valve stem is offset relative to its passages through the valve body, (i.e. it is not in the centreline of the seat axis). A further offset refers to the stem, which is laterally offset relative to the pipe axis. It helps reduce the angle at which the disc is in contact with the seat during closing and opening. The contact pressure and wear are thus reduced, while the service life

is prolonged. To achieve shut-off at even higher pressures, triple offset is required.

KSB also showcased its new Connectis loading system, which was developed as a joint industrial project (JIP) with Technip and Eurodim. Offshore loading/unloading is an increasingly popular option for LNG producers and consumers, and FSRUs and FPSOs are increasingly being viewed as a safe investment. However, there are safety implications for loading vessels that are rising and falling with the sea swell. The Connectis loading system is a lightweight system designed for offshore loading in harsh conditions and can operate where the swell is +/- 5.5 m (although it can be adapted for use in more conventional onshore facilities). If emergency release is required for whatever reason, then the unloading system can shut off instantaneously, losing less than 2 litres of gas in the process. This is achieved by using cryogenic tandem offset double-disc butterfly valves, which give long lasting tightness.

LNG_MARAPR_2013_05-11.indd 8 22/03/2013 16:44

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For more information, visit www.uop.com/LNG.© 2012 Honeywell International, Inc. All rights reserved

LNG_MARAPR_2013_05-11.indd 9 22/03/2013 16:44

LNGNEWS


Brazil

LLX Logistica wins LNG terminal construction license

LLX has received a preliminary and construction license to build an LNG terminal at Açu Superport. The license

was awarded by the State Environmental Department (Inea) in March. The LNG terminal will be located at the onshore terminal (TX2) between the north side of the breakwater and the channel’s entrance.

With a capacity of 10 million m3/d, the LNG terminal will have a regasification unit, which will supply MPX’s thermal electricity plant to be built at Açu Superport, in addition to other companies comprising the industrial complex.

Açu Superport is located in São João da Barra, in northern Rio de Janeiro state. The venture has been designed to handle up to 350 million tpy of cargo, ranking it amongst the world’s largest ports. The Superport has an offshore terminal (TX1) and an onshore terminal (TX2), which will jointly offer up to 47 berths and a 17 km pier.

Australia

QGC Pty Ltd awards GE maintenance contract

QGC Pty Ltd has awarded a US$ 620 million maintenance contract to GE Oil & Gas Australia Pty Ltd to support

carbon-efficient turbines and other equipment at the Queensland Curtis LNG (QCLNG) plant near Gladstone.

The QCLNG project will be the first LNG facility in the world to operate the new GE-manufactured low-emission turbines, which require less fuel than older models.

Under the 22-year contract, GE will provide maintenance support for the plant’s 15 turbines and 28 centrifugal

compressors, gearboxes, generators and other equipment.Use of the turbines will result in the QCLNG plant having

27% less greenhouse emissions than the original design.All the turbines and compressors, which range up to 620 t,

have been delivered for installation on Curtis Island.Five GE staff will initially be based in Gladstone to do

testing, inspections and maintenance, and planned shutdowns will be managed by mechanical and electrical specialists.

The QCLNG project is on schedule for first LNG in 2014.

USA

LNG truck fuelling system unveiled

Chart Industries Inc. has announced the release of a high capacity, fully integrated LNG truck fuel system. For the 2013 model year, Chart’s LNG truck fuel

system has been integrated into a self-contained unit for simplified and expedited installation, as required by high-volume assembly lines. Additionally, the maximum single tank capacity has been increased to greater than 100 diesel gallon equivalent (DGE), enabling extended driving range without the cost of an additional tank.

“Combining various on-board fuel system components into one integrated LNG truck tank package will facilitate more efficient installation,” stated Tom Carey, President of Chart’s Distribution and Storage Group. “Providing 100 DGE of storage in a single fuel tank will make LNG an even more attractive cost, space, weight and driving range alternative in heavy duty truck and bus applications.”

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LNG_MARAPR_2013_12-18.indd 12 21/03/2013 12:22


Looking back at 2012, a certain theme emerges centred around the realisation of the abundant supply of natural gas in the US as a result of the rapid growth in shale development and production. Because of this

supply growth, Henry Hub prices are at unsustainably low levels and demand growth is necessary in order to stabilise prices and to support a healthier market with supply and

demand in closer balance. In the December 2012 release of its long-term fundamental outlook, North American Natural Gas Market Outlook, Fall 2012,1 Navigant has anticipated that this market growth will come in the near-term from the recovery of US industrial demand, in the mid-term from the addition of North American LNG exports, and in the long-term from stable increases in US natural gas-fired generation.

As most now recognise, growth in shale production has been profound over the last few years, increasing 900% from around 2 billion ft3/d in 2005 to 20 billion ft3/d in 2011. In doing so, it has transformed the North American gas market. While more recently natural gas-directed activity, as measured by its drilling levels, has declined precipitously, the current total US dry production level of 64.8 billion ft3/d is still above the 2011 average levels of 62 billion ft3/d.2 This increase of 2.8 billion ft3/d can be explained by a variety of market factors, although the key ones are the continued increase in Marcellus shale production, increased drilling and production efficiencies being developed by the gas industry, and growth in associated gas as a consequence of increasing oil directed drilling going on in the country. In this article, Navigant provides a snapshot of how it sees the natural gas market unfolding over the long-term to 2035, as reflected in its North American Natural Gas Market Outlook, Fall 2012 release.

As the US experiences a shale gas revolution, the question now is, where is

all this abundant natural gas going to go? Rebecca Honeyfield and Gordon Pickering,

Navigant Consulting Inc., USA, suggest three key demand areas.

LNG_MARAPR_2013_12-18.indd 13 25/03/2013 09:13


Navigant is recognised for having long-established and widely confirmed assessments as to the abundance of shale gas in North America. Its team has been involved in extensive research and analysis on the commercial and economic impacts of the abundance of supply even before the wide-spread acknowledgement of it. This expertise has been used to develop its long-term view of the natural gas resource base, including the increasingly important unconventional natural gas segment and its resulting impact on production. Figure 1 represents shale growth in the US continuing over the forecast term to 2035, more than offsetting declines in conventional production over the period.

Figure 2 demonstrates how increased supply has pushed Henry Hub natural gas prices down to unsustainable levels that have not been seen for a decade. In addition, it shows projected annual average natural gas prices at Henry Hub, highlighting the stabilisation of prices over the near to mid-term and prices over the long-term reaching only moderate levels by 2035.

There are a number of reasons why the US will head into a period of more stabilised natural gas prices over the long-term. This includes the anticipated growth of natural gas demand from a number of different industries including the industrial, LNG export, and electric generation sectors. Over time, increased demand in these sectors will support a balanced supply and demand structure that will provide a

market exhibiting long-term market sustainability without the risk of price shock.

The new natural gas industryThe ‘new natural gas industry’, which is driven by shale gas development, is not like the ‘old natural gas industry’. Looking forward, as the supply profile of shale gas continues to increase as a share of total supply, Navigant sees the natural gas industry developing into something very different than in the past. The industry is evolving into something more akin to a manufacturing industry and moving away from its historical roots as a high-risk industry dependent upon finding resources in deep underground locations that are subject to high levels of expenditures on resource identification. In the new natural gas industry, exploration becomes less of a factor as exploitation and production related activities become the key activities of the producing industry. As a result of the key technological breakthrough of hydraulic-fracturing through horizontal drilling, production related activities have transformed the industry. Furthermore, the market is not expected to revert back to its previous key fundamental structure by which exploration and the risks associated with it drove much of the volatility in the market. In many ways, the new natural gas industry is about better managing North American natural gas resources with an increased capability to achieve balance between supply and demand.

Figure 3 shows US natural gas demand. Residential and commercial sectors will experience a jump from 2012 to 2013 on recovery of load lost during the mild 2011/2012 winter, and will then stabilise and remain level to 2035.

While the natural gas vehicle (NGV) fuel sector is expected to only increase from 0.1 billion ft3/d to 0.4 billion ft3/d over the outlook period, it is a wildcard that represents great potential for the natural gas industry and for the country in the future. However, it also poses significant challenges, such as the need for extensive infrastructure build-out in the face of a still very oil dependent economy. Navigant continues its conservative view towards NGV penetration, watching for developments on both the infrastructure side and in the face of lower domestic gasoline consumption on higher fuel efficiency standards for traditional cars.

Figure 4 illustrates the previously mentioned three key areas of demand growth: industrial demand recovery in the near-term, the emergence of North American LNG exports in the mid-term, and stable and moderate growth in the gas-fired generation sector in the long-term.

In the near-term and early part of the mid-term, low natural gas prices in the industrial sector will pull natural gas demand and present an opportunity for gas market growth.

The correlation between historical annual average Henry Hub prices and industrial natural gas consumption can be seen in Figure 5. Today’s natural gas commodity prices, as previously noted, are similar to those of 1997, when industrial consumption was at a 20-year high. Navigant’s North American Natural Gas Market Outlook, Fall 2012 shows incremental industrial gas consumption of 2 billion ft3/d by 2015 and 3.6 billion ft3/d over 2013 levels Figure 2. Henry Hub outlook (source: Platt’s, Navigant’s North

American Natural Gas Market Outlook, Fall 2012).

Figure 1. US natural gas supply outlook (source: Navigant’s North American Natural Gas Market Outlook, Fall 2012).

LNG_MARAPR_2013_12-18.indd 14 21/03/2013 12:22

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by 2020. These levels would be a recovery to levels last seen at the beginning of the decade.

Currently, there is a great deal of overseas interest in the US on behalf of large industrial gas users, but these same companies have some apprehension about how long natural gas prices will remain at current low levels. The key question for the industrial market is whether the timing of LNG export projects will coincide with greenfield industrial facilities such that natural gas prices in North America will approach the same higher price levels in other countries. The answer Navigant has come to is that the size of the US natural gas resource appears to be very large and getting larger, yet still the resource is in the very early stages of development, with much more to be learned regarding the geology and geoscience of today’s ‘new natural gas industry’. Through increased understanding of the resource over time, it is only logical that this domestic resource will develop as an increasingly core energy resource for North America over the long run. Additionally, with a well-developed market structure to support and continue to provide new infrastructure as required, the company sees the North American market being able to serve both the domestic industrial and global LNG export markets at price levels that are attractive and that balance the needs of both producers and buyers alike.

In the mid-term, Figure 6 illustrates the addition of North American LNG exports, with a total potential of 6.8 billion ft3/d (US export levels of up to 4.8 billion ft3/d by 2020, and Canadian export levels reaching 2 billion ft3/d by 2019).

A number of factors have contributed to Navigant’s view for LNG export levels. These include difficult regulatory processes, uncertainty surrounding US financial and commercial issues relating to large infrastructure facilities, and global market considerations including supply competition. Currently, many in the industry are following the developments, or lack thereof, of the US Department of Energy (DOE) as it reviews applications from 15 different companies that have filed for export licenses that would ship 23.71 billion ft3/d of LNG to countries with no existing free-trade agreement (non-FTA) with the US.3 The DOE has yet to make a decision on which projects, if any, will clear DOE approval hurdles. Currently, the only successful application has been Cheniere’s Sabine Pass export project. However, on 5 December 2012, the DOE released a study by NERA on the macroeconomic impacts of LNG exports on the US economy, which finds that for all LNG export scenarios studied there is a net economic benefit to the US.4 The DOE has indicated that it will begin to act on the applications on a case-by-case basis after the reply comment period ends at the end of February 2013.

Aside from US domestic regulatory uncertainty, there are also a number of other factors that Navigant believes will ultimately limit the number of facilities built in the US. These include the substantial capital requirements, commercial contractual issues, global competition from existing LNG exporters such as Qatar and Australia, and competition from the potential development of global world shale resources.

Regardless of the volume of exports ultimately approved by the DOE, the global market needs will determine the actual level of US exports and capacity that is built. Toward this thought, total 2011 global demand for LNG was 32 billion ft3/d.5 The 23.71 billion ft3/d of non-FTA country LNG export applications therefore represent 74% of today’s natural gas needs if all were approved. As Navigant believes the ultimate export levels will be determined by the future incremental market for LNG over current levels, it also believes the global LNG market to be supplied from North America will be much less than the total application volumes now filed and in the end are more likely to be in the 6 billion ft3/d. This is at odds with others who suggest the market is much larger. While it does not agree with these larger forecasts, Navigant views the outlook for global LNG as strong, particularly in the Asia-Pacific markets, where a gap between supply and demand is forecast to reach 37.3 billion ft3/d by 2030.6 The company believes North America is well-positioned to capture a portion of this market.

Looking back again at Figure 4, the largest growth in natural gas demand in North America is expected to come from the natural gas-fired electricity generation sector over the longer term, with incremental demand increases of 12.5 billion ft3/d by 2035 (compared to 2013 levels). In recent years, natural gas-fired generation has seen strong growth as a result of coal retirements and favourable natural gas prices. In the near-term, growth from these sectors is

Figure 3. US natural gas demand outlook (source: Navigant’s North American Natural Gas Market Outlook, Fall 2012).

Figure 4. US incremental natural gas demand from 2013 (levels by sector). (Source: Navigant’s North American Natural Gas Market Outlook, Fall 2012.)

LNG_MARAPR_2013_12-18.indd 16 21/03/2013 12:22

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expected to remain strong, but will become more moderate in the longer term due to the eventual slowing in retirements of coal-fired plants. The country’s coal-fired generation fleet is ageing, and several older less efficient plants will be retiring in the coming years – providing the opportunity for a leaner, more efficient generation fleet. During this time, Navigant expects that natural gas prices will stabilise on natural gas demand growth, and the resulting moderately higher natural gas price levels, along with a more efficient coal generation fleet, will serve to reduce some of the economic incentive to switch from coal to gas-fired generation.

As indicated in the North American Natural Gas Market Outlook, Fall 2012, growth in gas-fired generation over the longer term will be primarily driven by environmental regulation of coal plants and state renewable portfolio standard (RPS) mandates. As electricity demand grows over time, additional capacity will be needed to maintain mandated capacity margins in various Independent System Operator (ISO) control areas and generation pools. With environmental standards limiting the amount of additional coal-fired generation capacity, margins will increasingly be met by additional gas-fired generation capacity.

Another source of growth in natural gas demand will come from the state enacted RPS mandates. The District of Columbia plus 29 states and two US territories have created such mandates in favour of renewables increasingly making

up a growing share of the electric generation mix. Another eight states and two other US territories have adopted renewable portfolio goals. These goals and mandates will require a higher level of electricity generation to come from renewable resources in the coming years. While a majority of the additional generation will come from wind and solar power, both are intermittent resources that require additional generation options for load balancing and grid reliability. Most of the additional generation is likely to come from peaking natural gas plants that can be quickly ramped-up and down in order to balance the intermittent output from renewable resources.

Where is the gas going to go?In closing, the key question is where is all this abundant gas going to go? As Navigant sees it, the growing natural gas supply will end up in three key natural gas demand areas:

Into a revitalised industrial sector.

Into the new North American LNG exports market that is in development, although first deliveries will not be until after 2017.

To meet the increasing natural gas-fired generation needs as a result of growth in the demand for power but also as a result of continuing coal-to-gas switching.

These three demand areas will primarily support North America’s large, fungible, conventional and unconventional resource base that, in the end, will serve to stabilise natural gas prices over the long-term. Navigant allows that regional differences to stable gas prices are also set to exist for periods of time, especially in those areas where new infrastructure is most required. In these regional areas, significant price volatility could occur on a localised basis that in turn could create challenges in parts of the country. In sight of these regional areas where prices will still be unstable, Navigant’s long-term view is valuable but still only a starting point to begin to answer the significant questions as to how the North American natural gas market will evolve in the future. The North American Natural Gas Market Outlook, Fall 2012 carefully analyses the market and establishes a baseline to address further market developments that could occur in the future. Furthermore, it opens the door towards a process for more dialogue and a better understanding of this large and vital market as a key segment of the US economy and for the long-term energy security of the country.

References1. North American Natural Gas Outlook, Fall 2012: http://

www.navigant.com/insights/library/energy/2012/gas_market_out_look/

2. Lippman Consulting Inc., October 2012.

3. Applications received by DOE/FE to export domestically produced LNG from the lower-48 states (as of 26 October 2012): http://www.fossil.energy.gov/programs/gasregulation/reports/Long_Term_LNG_Export_10-26-12.pdf

4. http://www.fe.doe.gov/programs/gasregulation/LNGStudy.html

5. BP Statistical Review of World Energy, 2012.

6. BP Energy Outlook to 2030, 2012.

Figure 5. Henry Hub correlation with industrial natural gas consumption (1997 – 2008). (Source: Navigant, EIA.)

Figure 6. North American LNG export outlook (source: Navigant’s North American Natural Gas Market Outlook, Fall 2012).

LNG_MARAPR_2013_12-18.indd 18 21/03/2013 12:22


Recent technological advances in horizontal drilling and fracturing have made the extraction of shale gas possible and

the resulting boost in domestic US natural gas production has suppressed natural gas prices to a level not seen in over a decade. The combination of increased reserves and low natural gas prices has piqued interest in the export of natural gas in the form of LNG to expanding worldwide markets. While the development of new export facilities are both capital intensive and can take several years to permit and construct, the several existing US LNG import facilities that are currently sitting idle provide an ideal platform to commercialise investment since they already include much of the technology also necessary for LNG export, such as storage and marine facilities. This article discusses key factors that owners of existing LNG import facilities must consider when converting to world class LNG export facilities.

Roberto Ruiperez Vara, PE, PMP, and Phil J. Suter,

CH-IV International, USA, look at the trending

market in the US for bidirectional

LNG plants.

LNG_MARAPR_2013_19-25.indd 19 21/03/2013 12:35


BOG handling and LNG loading

LNG storage tank pressureTypically, full containment LNG tanks at import facilities operate between 2 to 3.5 psig (138 to 241 mbarg). LNG export facilities operate their LNG tanks at 0.5 to 1.5 psig (35 to 103 mbarg) to minimise boil-off gases (BOG) during LNG carrier loading operations. Depending on the design, a typical LNG carrier’s operating pressure can vary from 0.7 to 2.2 psig (50 to 150 mbarg), which is considerably lower than typical import facility full containment tank operating pressures, hence the need for storing LNG at lower pressures.

LNG productionConsideration should be given to flash gas, which is BOG predominantly composed of methane and nitrogen generated during pressure let down prior to the introduction of the LNG into the storage tanks. Liquefaction facilities that have all electric driven refrigerant compressors and do not have on-site power generation can have difficulties in handling flash gas. Depending on the nitrogen content of the feed gas composition, if the flash gas is compressed and re-injected into the feed stream to the LNG liquefaction train, nitrogen content could build up to unwanted levels.

Liquefaction trains can produce LNG at different temperatures. When LNG is produced at a sub-cooled temperature, it results in a lower production rate due to limitations in refrigeration capabilities. However, sub-cooled LNG reduces the amount of BOG generated once the LNG reaches the storage tanks.

LNG carrier loadingDuring LNG loading operations, the LNG carrier will return displaced vapours to the LNG facility. Depending on the length of the existing vapour line to the storage tanks, it may be necessary to install vapour return blower(s) at the LNG loading area.

If the LNG carrier arrives at the facility from a dry dock, it will need to be cooled down. During the approximate 12 hour cool down process, a mixture of predominantly inert gas and methane will form and will need to be disposed to a low pressure flare or vent until an adequate composition is achieved. Gassing-in the LNG carrier may be needed if an inert gas generator has been used during dry dock operations. In this case, inert gas could contain concentrations of CO2 up to 15% or more, which will freeze at temperatures lower than -108 ˚F (-78 ˚C).

In-tank pumps, columns and discharge pipingIf needed, it is important to verify that new in-tank LNG sendout pumps can be installed in the existing tank columns; maximum LNG carrier loading rates may be limited by the size of pump that can be installed in the existing pump columns. The new pumps may need a higher total developed head, depending on the distance between the storage tanks and the loading platform. A general rule of thumb is that LNG needs to be delivered to the LNG carrier manifold at approximately 30 psig (2 barg).

Table 1 shows the difference between in-tank pump sendout rate for typical import and export facilities.

LNG storage tank vacuum breakers (vacuum safety valves) designVacuum breakers installed on an LNG storage tank protect against under-pressure. The design should take into account the following factors acting simultaneously:

Rise in barometric pressure.

Maximum LNG withdrawing rate.

Maximum BOG withdrawing rate.

Collapsing of vapour space due to introduction of sub-cooled LNG into the tank.

As previously discussed, LNG withdrawal (sendout) rate from an export facility is considerably higher than an import facility. This change in withdrawal rate is a significant factor and should be analysed to verify that the vacuum breakers are properly designed for a change in operation for the tank.

FlaringA flare system provides safe disposal of hydrocarbon vapour and liquid streams that result from startup activities or process upset conditions. It is common to segregate wet, heavy hydrocarbons and dry, light hydrocarbons so that hydrate formation, freezing or condensation does not block piping or equipment. LNG import facilities typically have a single dry flare or just a vent and would therefore need to install additional flares during conversion to an export facility.

In a conventional baseload LNG export facility comprising pre-treatment, heavy hydrocarbon removal, fractionation and liquefaction, four separate flare systems need to be provided:

Warm flare (also known as wet flare) – this flare is typically designed to handle any wet hydrocarbons from pre-treatment.

Cold flare (also known as dry flare) – this is typically designed to handle any dry hydrocarbons from liquefaction. It also typically determines the height of the flare stack when warm and cold flares are combined into a common derrick structure.

Low pressure flare (also known as dock flare) – this is typically designed to dispose BOG or other low pressure gases from gassing-in or cooling down the LNG carrier.

Incinerator (also known as thermal oxidiser) – this system is typically designed to dispose of acid gases from the pre-treatment process.

Table 1. Import/export facility LNG pump sendout rate comparison

Facility type Pump sendout rate (m3/hr)1

Import/regasification (2 billion ft3/d of natural gas sendout to pipeline)

3750

Export/liquefaction (LNG loading to LNG carrier)

12 000

1 Total flow rate from at least two LNG storage tanks

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The height of the flare stack is generally based on the radiant heat intensity generated by the flame. The maximum radiation level at grade, where emergency actions lasting several minutes may be required by personnel without shielding but with appropriate clothing, should not exceed 1500 BTU/hr-ft2 (API 521).

Due to economics, the traditional choice has been elevated flares. An elevated flare designed to handle a blocked-in condition on the outlet of a main refrigerant compressor in a 4.5 million tpy liquefaction train would be more than 400 ft (120 m) in height and relatively separated from the LNG facility. However, due to height restrictions, as well as environmental and social impacts, flare designs will have to be innovative to reduce controlling cases for flare sizing and thermal radiation. Some of the strategies that could be considered in the facility design include the following.

High integrity pressure protection system (HIPPS)HIPPS is widely used in chemical plants and oil refineries. In LNG facilities, it is often used to protect the main natural gas sendout pipeline. HIPPS is a safety instrumented system (SIS) and its primary purpose is to mitigate potential overpressure scenarios. For example, HIPPS can be implemented in the feed gas compressor’s discharge or refrigerant compressor’s discharge to eliminate large load releases to the flare.

Passive fire protection for equipmentIn general, it is recommended to install passive fire protection (such as fire rated insulation for thermal protection or a properly designed firewall or radiant heat shields) in vessels located in congested process areas that contain a flammable or combustible liquid at high liquid level. Alternatively, they may be protected by a fixed water spray system, although active mitigation measures have not generally been acceptable as a mitigation measure for siting purposes to the Federal Energy Regulatory Commission (FERC) and the Department of Transportation (DOT). API 521 allows credit for

insulation on equipment that reduces the heat absorption and therefore the load relief to the flare during the event of a fire. Propane refrigerant storage tanks can be mounded (covered with earth) as another effective method of limiting heat input.

Minimise blowdown scenariosAlthough depressurising equipment during a fire event is not mandatory by code, it is recommended and is a mitigation tool against boiling liquid expanding vapour explosions (BLEVE). This is also a way of reducing a jet fire time period and the loss of containment in the event of a compressor seal failure. In order to minimise coincident blowdown loads, depressurisation should be done by zones.

Marine jetty operations: loading and unloading capabilitiesDepending on the current design, it may be necessary to install strainers, check valves and additional isolation valves to perform warm and cold ESD tests at the LNG arms headers while the transfer lines are pressurised. The existing LNG transfer lines can be used as a means to load the LNG from liquefaction trains to the storage tanks, and therefore they will be pressurised at all times. The internals of the check valves installed in existing transfer pipelines could be removed, or new ‘defeatable’ check valves could be installed to allow bidirectional flow. In addition, even though most LNG carriers are equipped with bidirectional conical strainers at the manifolds, it is expected that the LNG export facility will provide a clean cargo to the LNG carrier and therefore additional strainers may be necessary.

LNG and refrigerants in liquid form – troughingAs required by 49 CFR Part 193, LNG, flammable refrigerant or flammable liquids must be contained in the event of a spill. Existing troughs and impoundment areas can be used to route and contain refrigerant and natural gas liquid spills from the

liquefaction facilities. In most cases, the size of the impoundment area is sufficient to contain a 10 minute spill resulting from a guillotine rupture of the main loading/unloading LNG transfer pipeline operating at maximum flow. Therefore, in order to ensure compliance with code requirements, if the LNG transfer rate within the facility increases additional troughs and impoundment areas may be needed.

LNG piping pressure protectionLiquefaction processes produce LNG at pressures that vary, depending on the technology selected and the gas composition; 700 to 1000 psig (48 to 69 barg) is typical. The LNG liquefaction train rundown headers will likely be connected to existing LNG transfer piping, which is typically rated at lower pressure. Therefore, an

Figure 1. Rendering design for the Freeport LNG export project located in Quintana Island, Texas, USA (courtesy of Freeport LNG).

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adequate overpressure protection system would need to be installed.

Electrical consumptionLiquefaction processes require large amounts of electrical power. In traditional baseload LNG export facilities, power is self-generated by gas turbine driven generators (GTG), where the number of GTGs is selected on an n+1 basis for high reliability. Contracting power with a reliable supplier instead of self-generating could potentially simplify permitting processes and reduce capital costs.

Table 2 provides a comparison of typical electrical consumption.

Guidelines about modeling vapour dispersionUS LNG facilities must comply with the siting requirements of the Department of Transportation’s (DOT) regulations under 49 CFR Part 193. A hazard analysis that includes site-specific modeling is required to calculate thermal and vapour exclusion zone distances, which are established in Parts 193.2057 and 193.2059.

An exclusion zone is an area that could be exposed to a specified level of thermal radiation or flammable vapour in the event of a release of flammable substances. The requirements state that an operator or government authority must exercise control over the activities that can occur within an exclusion zone. Therefore, the thermal radiation and vapour dispersion exclusion zones must stay within a facility’s property or fall within a property under control of the owner or a government authority.

In 2010, the US DOT PHMSA issued written interpretations stating that the effects of jetting and flashing must be considered in order to comply with Part 193.2059 and that source term models must have a credible scientific basis and must not ignore phenomena that can influence the discharge, vaporisation and conveyance of LNG.

Current permit applications in the US must use DOT approved model(s) to evaluate the hazards in a site-specific hazard analysis. Det Norske Veritas’s (DNV) Process Hazard Analysis Software Tool – Unified Dispersion Model (PHAST) and GexCon’s Flame Acceleration Simulator (FLACS) Computational Fluid Dynamics (CFD) Model were approved by DOT PHMSA in 2011 as alternate dispersion models.

If initial modeling indicates it is difficult to contain vapour dispersion distances within the facility property boundary, passive mitigation measures such as vapour fences can be used. However, use of these mitigation measures requires the use of a model that can take into account the physical layout of a site and site geometries. If required, the following design

philosophies and strategies can help reduce dispersion distances to site the liquefaction facilities:

Develop an equipment layout that minimises the length of piping for major refrigerant and LNG lines. Since the exclusion analysis is based on a design spill calculated from a frequency of occurrence of typical pipeline failures, this philosophy will reduce the failure rate for a given pipeline and therefore reduce the spill size for a given failure. Typical failure rates of long lengths of piping could require an analysis that assumes a full guillotine failure resulting in a large spill scenario, whereas smaller length pipelines may only require smaller spill scenarios.

Develop an equipment layout that locates potential spill locations of major process pipelines away from property boundaries. This philosophy will help keep the calculated hazard distances on-site.

Minimise the storage inventory of refrigerants. If high purity refrigerants are readily available it may not be necessary to maintain large quantities on site. Reducing the amount of refrigerants stored to a minimum would reduce the hazard calculations in the event of a failure of the storage container. Daily make-up of refrigerants is needed because a very small amount is continuously being lost in compressor seals, valve packing, etc. Designing around daily make-up rates and not overall refrigerant inventory would minimise the space needed to site refrigerant storage.

Some liquefaction technologies may allow you to choose among different refrigerants. If possible, choose refrigerants with smaller MESG (maximum experimental safe gap) value and MIC (minimum igniting current) ratio (e.g. ethane vs. ethylene).

Minimise residence time of refrigerant accumulators to minimise overall refrigerant inventory in the train.

Sizing refrigerant storage tanks and transfer pumpsInitial liquefaction train inventories could be filled by trucking in the refrigerants directly from a petrochemical facility. A plan should be in place to perform a full charge within 24 hours; therefore, logistics must be arranged in advance. As previously mentioned, designing refrigerant storage for make-up rates only will significantly reduce the total amount of hydrocarbons onsite. Although make-up is performed on an as needed basis, it is usually once a day for a short period of time.

Future considerationsAs recently as just a few years ago, future energy projections determined that LNG imports would play a role in the US

energy markets for years to come. At that time, it was not predicted that shale gas production would become such a significant part of the natural gas supply mix and that the market would lean towards LNG exports. In order to mitigate against future potential uncertainties it is beneficial to maintain vaporisation capabilities in existing facilities and consider some level of LNG import and regasification capacity in future LNG facilities.

Table 2. Import/export facility power consumption comparison

LNG import facility using forced draft ambient air vaporisers (2 billion ft3/d)

All electric air-cooled LNG export facility (4.5 million tpy)2

Gas turbine driven air-cooled LNG export facility (4.5 million tpy)2

Power consumption (MW)

32 215 55

2 Without feed gas compressor

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John A. Sheffield,

John M. Campbell | PetroSkills,

presents the findings from

a recent global survey on

commercial and technical

trends in the LNG industry.Survey

LNG Global

LNG_MARAPR_2013_26-31.indd 26 22/03/2013 10:15


A s worldwide LNG capacity now exceeds 300 million tpy and on the eve of LNG 17 it seems appropriate to reflect on what are perceived to be

some of the major technical and commercial issues facing the LNG industry. To this end, John M. Campbell | PetroSkills commissioned a survey to solicit views on some of these key issues, the results of which are summarised in the following article.

When the survey was closed, John M. Campbell had nearly 170 responses from the LNG community around the world, indicating great interest both in the producing and consuming countries (Figure 1). The survey looked at both commercial and technical issues and focused on new developments and the major challenges facing the industry.

Market growth and pricingThe first question addressed LNG market growth. Following a brief slow-down in 2009, the volume of LNG trade has increased by 10%/year to be 245 million tpy in 2011. This was partly driven by ‘events’ such as the Japanese tsunami and the consequent closure of most of Japan’s nuclear power generation industry. But there is a strong level of underlying growth, particularly in developing countries. The responses showed an optimistic expectation that growth rate would be sustained at 5 – 7%, suggesting that the volume of LNG trade in 2020 would be around 450 million tpy (Figure 2).

Since the early days of the LNG industry, LNG prices in Asia have been linked to the price of crude oil and LNG supply contracts have been for 20 years or more. In contrast, in the

LNG_MARAPR_2013_26-31.indd 27 22/03/2013 10:15


US and parts of Europe, gas is priced on a supply and demand basis and contracts are for capacity at an import terminal to give access to the market, rather than for a specific long-term contract with a consumer. However, there is now pressure for change because the gap between Henry Hub and Japanese LNG prices has widened. The gap has been as much as US$ 12/million Btu. Consequently, there is increasing pressure from Japan and South Korea for changes to the established pricing and contract mechanisms.

However, the views on pricing were more disparate. The questions asked what changes were anticipated. A majority believe that there will be more short-term contracts based on negotiated gas prices and it is clear that only a few responders believe

that oil-related LNG pricing would continue to be the mainstay of the industry (Figure 3). There is clear anticipation that an Asian hub pricing or price based more directly to cost of production might prevail.

It has been pointed out that there are clear structural differences between the physical reality of Henry Hub and the long-term needs of the gas markets in the Far East. There is also an expectation that in time the prices will balance in the medium term and the International Energy Agency (IEA) is forecasting that US gas prices will trend towards US$ 5 – 7/million Btu, thus narrowing the current differential with LNG trades in Asia. Others point out that the producers require that prices should reflect capital expenditure (CAPEX), but the buyers view would be the opposite and that CAPEX must align with achievable prices.

Exports from the USThis leads neatly to the interesting issue of LNG exports from the US. In the past few years new shale gas reserves in several regions of the country have been developed. These discoveries have made most US LNG terminals redundant for import. The owners of these terminals have turned their minds to exporting this low cost gas by adding liquefaction facilities to the terminals and exporting LNG. This is a low CAPEX option since approximately 50% of the value is already invested in the marine, storage and pipeline facilities. Work has already started on one of these, the Cheniere-owned Sabine Pass facility in Louisiana. The company is proposing to build two trains with a capacity of 9 million tpy to come into production in 2015 with an option for two more trains in the future.

The question posed was: ‘How much LNG will be exported from the USA in 10 years time?’ The view is quite clearly that this will not amount to a very significant volume, with most people comfortable with an estimate of 20 – 40 million tpy (Figure 4).

It is clear that there is still a lot of political and social turmoil in the US over the question of exporting gas. To put this into context, 40 million tpy of LNG represents about 8%

Figure 1. Survey responses.

Figure 2. LNG trade in 2020.

Figure 3. LNG pricing.

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LNG_MARAPR_2013_26-31.indd 29 22/03/2013 10:15


of US gas consumption so this would influence prices, and given that prices are forecast to rise towards US$ 7/million Btu it is unlikely that all of the envisaged export facilities will materialise. A recent NERA report showed the positive economic benefits of LNG exports to the US economy as a whole, but this report has precipitated a vigorous campaign by many opposed to the idea of unrestricted exports of LNG from the US.

Short-term tradingThe responses to the pricing question clearly showed a leaning towards shorter term contracts, not necessarily short-term trades. So a further question was asked specifically about short-term trades, which are currently about 60 million tpy, accounting for some 25% of all LNG trades (mostly due to the additional LNG being bought by Japan, which in 2012 amounted to approximately 15 million t). The responses indicated that most believe these short-term trade levels will continue and even grow towards 30% of total LNG trades. This mode of trading could well be favoured by those major producers operating a portfolio business, but will be difficult for the smaller, newer entrants, who would find it difficult to support the investment without more traditional long-term contracts.

New developments for the next decadeThe final ‘commercial’ topic links to the technical discussions as it looked at what would be the most significant factors in the development of the LNG industry over the next 10 years. Nearly half of the respondents cited the development of floating LNG (FLNG) facilities as a major factor (Figure 5). FSRUs (floating storage and regasification units) are now being deployed in many locations around the world, including countries such as Indonesia and Malaysia which have traditionally been exporters. However, many more of the respondents believe that FLNG facilities will be a more significant game changer now that there are three FLNG units under construction. A significant proportion of the respondents believe that development of new areas such as East Africa and the Eastern Mediterranean will be a major factor in FLNG advances.

Perhaps surprisingly, a large number pointed to the use of LNG as fuel for marine and land transport as a major factor in the LNG industry. Certainly the introduction of emission control areas (ECAs) in many ports is encouraging the development of LNG as a marine fuel. Use of LNG as a fuel for heavy trucks is being supported by such disparate entities as Shell and T. Boone Pickens.

What is clear is that there is great scope for technology innovation to develop new business opportunities in the LNG industry, although one respondent noted that shale gas will ‘kill-off’ LNG!

Potential developments in onshore LNG facilitiesOne of the big innovations in the last decade has been the development of the six ‘mega LNG trains’ in Qatar. These 7.8 million tpy trains have made Qatar the largest exporting country with 77 million tpy production capacity. The question posed was to establish whether people view the large LNG trains as the future direction for the LNG business. The result was a resounding ‘maybe’ (Figure 6), with many making the point that these large capacity trains are only feasible with a large gas reserve. But more critically, large trains require access to a large and liquid gas market and these large Qatari trains were focused on the US before the growth of shale gas eliminated the need for LNG imports. The point was made that cost effectiveness of the train should prevail, and that the large trains are not necessarily cheaper. There is some evidence that smaller trains in the 3 – 5 million tpy range are more cost effective and can more easily secure firm customers to underpin the initial investment.

The issues that concern developers of onshore facilities are numerous but the survey requested a view on four major issues. The results showed that reducing capital cost and improving the schedule are considered to be the most important factors, with safety and improving efficiency also being ranked as important. Several people noted that improving construction productivity levels is most important and in recent years there have been several instances of delayed start-ups due to lower than anticipated productivity levels. Departmental and supplier interface management was another issue raised as a concern; as was the overall development time for some of the projects. LNG quality was also mentioned as a key concern, presumably as LNG may

Figure 4. USA exports.

Figure 5. New developments.

LNG_MARAPR_2013_26-31.indd 30 22/03/2013 10:15


now have to be sold into several different market places with different quality requirements.

Offshore LNG developmentsThe decision by Shell and Petronas to proceed with FLNG projects has brought offshore LNG developments to the fore and there is now a strong body of opinion that there will be several more projects based on this concept. However, it is clear that there are still some major concerns. Safety was highlighted as the main issue, due to the more congested and compact layout, but also because the facility will be more remote for support services. LNG transfer and reliability are seen as important factors, whereas efficiency and driver selection were viewed as less critical. LNG transfer is generally accepted to be proven for side-by-side transfer in relatively benign sea conditions. However, it is clear that with the current state of technology and marine procedure there will be times when off-loading is not possible. This might well be one of the challenges that is best addressed commercially, which is why a larger operator who can supply from a portfolio may be better suited to utilise this technology.

So when asked about the issues with FLNG the main concern was identified as the high cost (Figure 7). This is an interesting conclusion because it has long been proclaimed that FLNG offered a potentially lower cost option, but it is clear from the published data that these early adopters are relatively high cost. One can expect costs to come down as experience is gained, and certainly in the case of Prelude, it is not just an LNG facility but also processes significant quantities of LPG and condensate. The risk as perceived by the buyers was rated as a low factor.

Potential for small scale LNG developmentsThe final part of the survey dealt with the development of small scale LNG for monetising stranded gas reserves and producing LNG as a transportation fuel. It is clear that many support the concept of the development of small scale LNG facilities for transportation fuel. The gas may come from gas reserves but could also come from pipeline gas and it is recognised that small scale plants have already been established in Norway, Australia, China and the US.

The clear view is that LNG could be a realistic substitute for diesel for land transportation and with no tax regime, LNG is a cheaper option. In the marine world, LNG is already making great strides and the adoption of ECAs will encourage this, especially with new-build vessels.

There are now several coastal ferries and offshore rig service vessels operating off the coast of Norway and the idea is being taken up in the Baltic. Plans are being developed for LNG bunkering in Singapore, the world’s largest bunkering port.

Land transportationLooking specifically at land based transportation, long distance haulage is seen to be the biggest opportunity for further development. It is clear that this is already happening in the US, with several transportation companies announcing the addition of LNG-fuelled trucks to their fleets. The exploitation of LNG as a fuel for local transportation (e.g. bus, taxi and refuse vehicle fleets) is equally seen as a potential growth area and there are many cities around the world

where this would clearly be of great benefit if the perception of potential risks by the public can be overcome.

Environmental issues Finally, the survey looked at the main environmental issues that the industry faces and it is clear that the disposal of acid gases tops this list. Several projects have now implemented the disposal of the acid gas components removed from the feed gas, yet no project has addressed CO2 released from the fuel consumption. The cost of acid gas removal and sequestration is high, so that the cost of the feed gas must be low to compensate and allow the project to compete economically.

An exciting future for LNGIt is clear from the interest shown in the survey that whilst there are many problems to be addressed, there is a large and enthusiastic community of creative developers who will rise to the challenge and ensure that the LNG business continues to grow and provide a valuable component of the world’s energy mix. The main challenge will be to provide LNG to the developing markets at an affordable cost, so the pressure to reduce the capital expenditure and shorten schedules will continue to be the main challenges facing the industry.

NoteIf you are interested in participating in the survey, visit: www.jmcampbell.com/lngsurvey

Figure 7. FLNG issues.

Figure 6. Large LNG trains.

LNG_MARAPR_2013_26-31.indd 31 22/03/2013 10:15

Simon Rainey Q.C., Quadrant Chambers, UK, attempts to define the new generation of FLNG facilities.

IS IT A PERMANENT INSTALLATION?

IS IT A SHIP?

LNG_MARAPR_2013_32-36.indd 32 21/03/2013 12:47

In December 2012, the US Department of Energy (DOE) released its long-awaited second independent study on the impact of increased exports of LNG to foreign countries. This

predicted strong economic benefits for the US from such exports. The wider development of LNG resources, which the US decision confirms in the US context, will bring with it further technological advances. A new generation of floating LNG (FLNG) facilities will join the existing range of moveable floating objects already in current use in offshore energy exploration and production.

A recent example is the Shell FLNG facility Prelude, which will operate in Australia. This is a pioneering FLNG facility and the largest floating structure yet built (488 m long; 74 m wide; 600 000 t laden, to be permanently moored in 250 m deep water at location for 25 years), which has just started building in South Korea. Similarly, Keppel Shipyard recently entered into an agreement with Golar LNG for the conversion of three LNG carriers into FLNG units.

The definitional problemThe question that arises in relation to these mammoth new floating facilities is under which maritime legal regime they will fall. Will they be treated as ‘ships’, because they float and can be and are (sometimes) navigated across the seas to their site of operation either under their own power or under tow? Or are they better viewed as permanent offshore installations, because of their fixed connection to the seabed and the fact that they are permanently on location, for all practical purposes?

The answer to these questions has not always been an easy one to predict even with existing FPSOs, FSUs, jack-ups and semi-subs. Much will depend upon the context. In some cases, the context may be one that has to be resolved by consideration of the applicable local law, for example in relation to operating or health and safety standards that are likely to depend upon the law of the place of registration of the unit (if it is registered) or the place of operation (depending on territorial application). In others,

LNG_MARAPR_2013_32-36.indd 33 25/03/2013 09:14


the context may be one where an international conventional regime for ‘ships’ exists (such as for limitation of liability under the 1976 Limitation of Liability Convention or for oil pollution under the Civil Liability and the International Oil Pollution Fund Conventions of 1992), where the questions are whether the unit can be described as the sort of ‘ship’ dealt with in the convention in question, and whether the applicable local law giving effect to the convention has adopted a different definition, wider or narrower.

Unfortunately, there is no single international conventional model for offshore units that lays down a common international regime, although there have been unsuccessful attempts to devise one. Proposals for a new international convention on the regime applicable to offshore mobile craft have so far not fared well. The Comité Maritime Internationale formulated drafts seeking to apply established legal concepts specific to maritime law to the new offshore industry. These were presented to the IMO as long ago as 1998, but there has been very little international interest or support. Technological advances and the birth of semi-permanent floating facilities, which are only set to grow in size and complexity as countries follow the US and Australian lead in developing their LNG resources, make the problem of defining how these structures are to be regarded as increasingly important.

An example: limitation of liabilityTake the example of one of the most pressing issues: limitation of liability. Test the position in regard to the 1976 Convention and the applicability of limitation of liability to an FLNG facility like the Prelude.

Under the Convention, a ‘shipowner’ can limit liability in respect of liability for the specific claims set out in Article 2 of the Convention. This is widely drawn and the listed claims will usually cover those that arise in a typical maritime casualty situation that might affect an FLNG, extending to liability for pollution, including liability for oil pollution, provided that that liability is not one that is covered under the 1992 Conventions. However, to be able to limit liability, the head of claim must be one that arises in respect of the operation of a ‘ship’.

‘Seagoing’ and ‘vessel’, etc.‘Ship’ is defined as “any seagoing ship” by Article 15. However, Article 15(5) excludes offshore units, which it defines as “platforms constructed for the purpose of exploring or exploiting the natural resources of the seabed or the subsoil”. An FSU, usually simply a converted tanker used to store oil received from a platform or FPSO, will probably not fall within the exclusion, although the question remains whether it is a ‘seagoing ship’. However, an FPSO is usually much closer to a floating platform constructed for exploration or exploitation. Once moored on location, it is usually in place either permanently or semi-permanently. However, some may be designed to disconnect from their risers, e.g. in adverse weather or for operation on adjacent fields. It is likely that FPSOs, and therefore the new generation of FLNGs with them, are excluded from the operation of the 1976 Convention.

However, this raises the question of how the Convention has been enacted locally. Different countries apply the 1976 Convention differently. The UK enacts the 1976 Convention but without the Article 15(5) offshore unit exclusion. The Convention

as applied in the UK extends without restriction to ‘seagoing ships’. While the term ‘seagoing’ is not defined, the term ‘ship’ is defined as “[including] every description of vessel used in navigation”.

‘Seagoing’ means “really and substantially” able to go to and remain at sea (Ex parte Ferguson (1871)) and is unlikely to cause any difficulty in the context of the modern offshore unit, whatever its type, since it is built for this purpose. The real question is: what is meant by “vessel used in navigation”?

The ‘used in navigation’ test‘Vessel’ simply means anything that is built to float and carry something while afloat and poses no problem: an FLNG floats and carries product. But the term “used in navigation” has proved more tricky. The best modern guidance in the context of offshore units is to be found in the English Court of Appeal’s decision in Perks v Clark (2001). The case concerned an appeal by the Inland Revenue against an assessment that workers on two Santa Fe jack-up drilling rigs were liable to pay tax as seafarers, being employed upon ‘ships’. The Court held that the rigs were ‘ships’ although they had no motive power, did not look like or have any of the characteristics of a typical ship or hull form shape, were designed to explore and exploit seabed resources rather than regularly to perform seagoing marine transits and spent most of their working life in drilling or production on field.

The Court set out a useful summary of the earlier English cases falling on either side of the line and held that the courts had rejected a test of navigation being the ‘primary purpose’ of the object or structure (as contended for by the Revenue in order to narrow the category of objects caught by the term ‘ship’). On the one hand, it noted that cases in which the courts had held the object to be a ‘ship’ had been ones where the navigation was a feature of the use of the object, but where “its mobility was purely incidental to its main function”, viz. an offshore industry floating accommodation unit in Addison v. Denholm Ship Management (1997) and a fixed operation dredger in The Von Rocks (1998). On the other hand, it categorised the cases where the object had failed to be recognised as a ‘ship’ as being “ones in which ‘navigation’, in the sense of ‘moving across the seas’, was minimal or non-existent”, such as a floating dock crane moved very rarely and unstable under way: Merchants Marine v. North of England P. & I. (1926). The Court’s conclusion was as follows: “so long as ‘navigation’ is a significant part of the function of the structure in question, the mere fact that it is incidental to some more specialised function, such as dredging or the provision of accommodation, does not take it outside the definition. There may be an issue of degree as to the significance of the navigation on the facts of a particular case, but that [...] is a question for the fact-finding tribunal. [...] ‘navigation’ does not necessarily connote anything more than ‘movement across water’; the function of conveying persons and cargo from place to place [...] is not an essential characteristic.”

Semi-subs, MODUs and jack-upsThe answer will usually therefore be straightforward for regularly moved floating objects such as semi-subs, MODUs and jack-ups, voyaging by sea from site to site as part of ordinary operation: self-propulsion and ability to steer are not essential. The decisions in other offshore cases, such as Addison, relating to an offshore worker accommodation unit, and Global Marine v. Triton Holdings (1999), in relation to a semi-submersible drilling rig

LNG_MARAPR_2013_32-36.indd 34 21/03/2013 12:48

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that the Scottish Court of Session held to be a ‘ship’, support the approach of holding such objects to be ‘ships’.

FSUs/FPSOs and beyondFSUs and for FPSOs designed for disconnection and movement will probably also fall within the term ‘ship’, since their marine purpose, while only a minor part of their day-to-day role, cannot be said to be ‘insignificant’. In The Cossack Pioneer (2005), an Australian court held an FPSO designed to disconnect from its riser and to navigate off-site in bad weather to be “a ship used in navigation by water” under equivalent legislation.

More permanently fixed and connected objects such as the Shell FLNG Prelude and other fixed FPSOs are much less likely to qualify as a ‘ship’ and will probably be regarded simply as species of permanent floating offshore installations. Such a facility, while much more complex and sophisticated and capable in principle of moving at sea, is in kind closer on the Perks v Clark test to the floating crane held not to be a ship but simply a floating platform in Merchants Marine in 1926 (“undoubtedly capable of being moved, but […] obviously so unseaworthy that it can only be moved short distances [... and] moved very occasionally”), and the dismasted ship-of-the-line permanently anchored off the coast as a coaling station held not to be a ‘ship’ (although still registered as one on the register of shipping) but “a mere chattel, a coal-hulk” in European Royal Mail v P. & O. (1866).

Limitation of liability is but one example. Pollution and hazardous and noxious substances are obviously other pressing concerns.

The future pictureLNG development raises new challenges not just technologically but also legally both at the national and international level. The need for a uniform standard as a minimum in the context of application of international conventions applicable to ‘ships’, perceived in the 1990s by the CMI, will become more pressing. Cases like the criticised Slops decision of the Greek Supreme Court where a vessel, permanently anchored as a storage unit with propeller removed and engine dismantled, was held to be a ‘ship’ capable of ‘carrying bulk oil’ for the purposes of compensation under CLC 1992, highlight the need for an international standard for the new generation of LNG floating offshore unit.

Some pointers to the solution can be found in the field of admiralty jurisdiction and the 1952 Brussels Convention on the Arrest of Ships. Here, some common law jurisdictions such as Canada, Australia and Singapore include different definitions of floating offshore units within the concept of ‘ship’. But there is no single approach between countries, even in this limited context. This means that the solution will have to be worked out on a case by case basis, depending on the approach of local courts or of applicable local legislation with, almost inevitably, inconsistent results. If the FLNG is a permanent installation situated for its working life within a single jurisdiction, this may narrow the focus. However, if it is being moved to, on or from site then more difficult questions arise (as the CMI percipiently foresaw as far back as 1998).

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T he floating LNG (FLNG) sector currently has two main types of liquefaction technology proposed: mixed refrigerant cycles and

nitrogen cycles. Those proposing mixed refrigerant cycles often do so based on onshore LNG experience and focus on maximising the liquefaction cycle efficiency. Those proposing nitrogen cycles do so based on experience from offshore oil and gas production and are mainly focused on optimising availability and safety.

As a result, there is disagreement over which technology will come to dominate FLNG. It is clear that each will have their own place in the market, but which is best suited for FLNG? To answer this it is important to understand the issues and how they affect project revenue.

Tom Haylock,

KANFA Aragon,

Norway, investigates

which is the most

important factor in

FLNG developments;

optimised efficiency or

optimised availability.

LNG_MARAPR_2013_37-41.indd 37 21/03/2013 12:54


Technical challengesFLNG plants have different technical and safety challenges to well-established onshore plants. Restrictions concerning space, weight, logistics, operability and potential future re-location are forcing engineers to overcome the technical challenges in plant design.

Experience from the offshore oil and gas sector shows that prioritising safety, availability and flexibility for both changing feed gas composition and more frequent start and stops compared to onshore plants is critical for any offshore process plant’s success. Applying this logic to FLNG leads to the use of nitrogen as a refrigerant as it is non-hazardous, single phase and simple to operate.

However, a nitrogen cycle has poorer process efficiency than a mixed refrigerant cycle. But is the improved process efficiency of a mixed refrigerant cycle worth the resulting increased safety risk, higher complexity, lower availability and reduced flexibility when applied offshore?

Assuming that the challenges for operability and safety can be addressed for mixed refrigerant cycles offshore, the question then becomes: what really is the more important factor for FLNG developments; optimised efficiency or optimised availability?

EfficiencyAlthough it is common to compare

efficiencies of liquefaction processes using specific power consumption (kWh/kg of LNG produced), i.e. the amount of power required per kg of LNG, this method of measuring efficiency is often misleading. Specific power consumption focuses only on the power required for the main cycle compressors and does not take into account important factors such as ambient conditions and driver efficiencies. The calculated efficiency of a liquefaction cycle is highly influenced by where the calculation boundary is set. As such, the boundaries applied in the efficiency calculations should be clearly stated, but unfortunately numbers are often compared on unequal terms.

For accurate comparison it is often best to use the overall plant thermal efficiency to benchmark different liquefaction processes. By assuming natural gas is used as fuel, thermal efficiency expresses how much of the feed is recovered as product and how much is lost during processing, giving a clear picture of the entire liquefaction system efficiency.

As an example, the overall thermal efficiencies using identical and realistic conditions, for both a mixed refrigerant plant and a nitrogen expander plant, have been calculated for comparison.1

Table 1 shows that there are significant differences in the specific power consumption between the two technologies. The mixed refrigerant cycle has a lower specific power consumption than the nitrogen cycle. However, because of the fundamental differences of the driver efficiencies, the resulting

Figure 1. A typical mixed refrigerant cycle.

Table 1. Comparison of key parameters between a mixed refrigerant cycle and a nitrogen expander cycle (the figures are for the liquefaction train only)1

Propane pre-cooled mixed refrigerant cycle

Dual nitrogen expander cycle

Gas turbine driver Frame 7 and frame 6 LM6000

Average thermal efficiency of driver

33.2% 41.9%

Production capacity per train 4.35 million tpy 1.11 million tpy

Specific power consumption for liquefaction cycle

0.243 kWh/kg of LNG 0.345 kWh/kg of LNG

Thermal efficiency 94.7% 94.3%

Figure 2. A typical nitrogen expander cycle.

LNG_MARAPR_2013_37-41.indd 38 21/03/2013 12:54

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difference in the liquefaction cycles’ thermal efficiency is so small as to be negligible.

This is because mixed refrigerant cycles onshore typically apply heavy duty industrial gas turbines with relatively poor thermal efficiencies. For offshore applications, some mixed refrigerant cycles are being applied with steam turbine drivers, which have even poorer efficiency, as well as no available waste heat. High efficiency aero-derivative gas turbines that are used on nitrogen cycles are rarely applied to MR cycles as their output limits would require duplication of units, which adds more complexity to an MR plant. Aero-derivatives are limited on output, which limits the production possible per train for N2 cycles. But when looking at the overall plant efficiency, there is little difference between a nitrogen cycle and a mixed refrigerant cycle in reality.

Efficiency’s effect on revenueHow does improved efficiency actually affect a project’s revenue? If we assume that everything else is equal, improved efficiency will result in reducing the amount of fuel gas required, giving longer production time. So what is the cost of fuel gas and how does it affect net present value calculations?

How much extra investment cost would be reasonable to consider for improved efficiency/lower feed gas shrinkage?

For an offshore field developed with a single liquefaction plant for processing all recoverable reserves, the value of the fuel equals LNG sales value at the end of the production time. Assuming that it is possible to apply drivers with the same efficiency and the availability is equal, the most efficient mixed refrigerant cycle will typically give 30% lower fuel consumption than a nitrogen cycle. This difference corresponds to 2 – 3% of the plant total feed gas flow.

Again, for a true picture of the fuel consumption the overall plant efficiency should be used, as this takes into account the total fuel gas consumption for the plant.

The present value data shown in Figure 3 applies a conservative internal rate of return of 15% on a field with reserves of 2.5 trillion ft3 and a nominal production time of 25 years when producing 2 million tpy of LNG. Initial CAPEX of US$ 1000/tpy (topsides and hull only) was set and should be in the lower range of recently published costs for onshore and offshore LNG projects, together with a fixed amount for subsea CAPEX (US$ 500 million).

A nitrogen expander plant with thermal efficiency of 94.4% will produce for 24 years, giving an overall present value of US$ 4550 million. A development based on a 30% more efficient technology, and identical capacity, availability, and capital cost, would give six months longer production and a present value of US$ 4566 million. So having a cycle that is 30% more efficient gives a revenue increase of only 0.4% over the field lifetime.

Based on the above example there is little incentive to invest more CAPEX in order to boost efficiency, as the effect on net present value is so low.

AvailabilityAvailability is more straight forward than discussing efficiency. Reduced availability results in reduced revenue for each year of production. It also delays part of the production, such that the last part of the reserves will be sold later and generate less present value.

When considering the two main technologies for FLNG, mixed refrigerant is expected to have poorer availability than nitrogen. This is because mixed refrigerant cycles are more complex multiphase processes, which require fine tuning to hit their optimum efficiency for a specific gas

Figure 3. Production profile and present value for constant production capacity while varying thermal efficiency.1

Figure 4. Cumulative present value for different levels of availability.1

LNG_MARAPR_2013_37-41.indd 40 21/03/2013 12:54

composition. Vessel motions will affect the liquid phase and distribution in the cold box, and gas compositions can change quickly in an offshore environment due to wells coming on and off line, all of which will make availability suffer accordingly. Mixed refrigerant cycles are also very complex and require more manpower and a large inventory of hazardous refrigerants, which again affects operability and availability. Nitrogen, on the other hand, is a simple, single phase non-hazardous technology that is well suited to an offshore environment.

Taking the same example of two plants with the same production capacity (2 million tpy), efficiency and investment costs, but with different availability (93% and 95%), the effect on present value is quite pronounced (Figure 4).

The 2% reduction in availability reduces cumulative present value by 3%. According to supplementary calculations,1 the saving in initial CAPEX (plant and ship) to justify this reduced availability is a minimum of 5%. Alternatively, a maximum of 5% more CAPEX can be invested to recover the availability. Hence, high inherent availability is much more important for the project economy as it has a greater effect on revenue.

ConclusionIn conclusion, considering the examples detailed in this article, it is clear that selecting the liquefaction technology with the optimal availability is the most important consideration.

Overall production levels affect the project economy the most. This is a question of multiple nitrogen cycle trains vs. single mixed refrigerant cycle trains. Due to their lower CAPEX costs and significant advantages offshore, multiple N2 trains are a strong solution for high production with high availability.

The common claims and assumptions that mixed refrigerant cycles are a better choice than nitrogen cycles for natural gas liquefaction due to their specific power consumption can be misleading.

The examples show that when considering whole plant efficiency, a nitrogen expander cycle utilising a highly efficient aero-derivative gas turbine is as efficient as most of the onshore LNG plants operating today.

So it is highly important that a clear understanding and comparison of key factors such as safety, availability, thermal efficiency and net present value are taken into consideration when selecting technologies for FLNG. Nitrogen gas expander cycles offer a safe, simple, reliable and low cost solution for offshore or at-shore FLNG, with overall efficiency comparable to state-of-the-art mixed refrigerant cycles onshore or offshore, but importantly with optimised availability.

Reference1. Faugstad, S., and Nilsen, I.L., ‘Natural gas

liquefaction using Nitrogen Expander Cycle - An efficient and attractive alternative to the onshore base load plant’, GPAE AGM & Technical Meeting, 29 November 2012.

[email protected] Ritmore Dr./P.O. Box 490Ravenswood, WV 26164

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Dominique Gadelle, Tania Simonetti and Sylvain VovardTechnip, France, examine different process technologies for offshore LNG facilities.

Offshore processing

LNG_MARAPR_2013_42-48.indd 42 21/03/2013 14:07


I n recent years, floating LNG (FLNG) technology has progressed to a point where it is now an effective way to recover and monetise gases that previously

were either inaccessible in stranded fields, or destined to be flared or re-injected as the unwanted by-product of oil production. FLNG increasingly represents the most effective way to monetise remote gas assets, without the need for the costly and complex facilities required when the gas must be brought onshore to be treated and liquefied.

Modular construction in well-equipped and experienced shipyards offers high labour productivity, excellent quality and the possibility for continuous improvement. The projects are no longer prone to a wide variety of potential difficulties at site.

On the other hand, an FLNG unit poses a number of new challenges in terms of safety, energy efficiency, adaptation to limited space and random multi-directional motions.

An FLNG unit is expected to meet a number of requirements:

Process units shall be compact.

Weight shall be minimised.

LPG inventories shall be low.

Process technologies and designs shall be proven.

Availability shall be comparable to a land-based installation despite the location, sea motions, potential for shut downs, etc.

LNG_MARAPR_2013_42-48.indd 43 21/03/2013 14:07


With these constraints in mind, this article presents three processes developed by the authors, each one simple and efficient as required by the offshore industry, that can be applied in future FLNG projects to further this emerging industry.

Feedstock preparationRaw natural gas has to be treated prior to being liquefied to remove the following impurities that could freeze during liquefaction: carbon dioxide (CO2), sulfur compounds, water (H2O), mercury (Hg) and heavy hydrocarbons including benzene.

Two schemes are commonly used in the LNG industry to remove C2+ components and benzene, both based on cryogenic fractionation. These are the widely used scrub

column and a turbo-expander based NGL recovery process for high performance plants or those treating more difficult gases.

FLNG refrigerant cycles composed of a gaseous mixture of one or all of N2, CO2 and C1 have been proposed for safety reasons. In this case, refrigeration does not rely on extracted LPGs for inventory make-up. In addition, the production of C2+ hydrocarbons offshore is undesirable for reasons of space, weight and safety. Consequently, a new process (Figure 1) is presented for fractionation of a natural gas feedstock into two products only: a treated gas, which can be liquefied; and a saleable condensate with a low vapour pressure. Equipment number, the unit’s footprint and downtime for maintenance are all minimised.

This new scheme fulfils the requirements of an FLNG facility:

The low liquid inventory increases safety.

A turbo-expander provides all refrigeration, resulting in smooth and fast start-up and re-start.

During start-up, the treated gas is recycled to the inlet of the plant, thus avoiding flaring.

A booster compressor is used to allow liquefaction at very high pressure, which improves efficiency.

All C4 components are left in the treated gas and produced as LNG, so this process is best suited when the refrigeration system used to chill the gas is not based on mixed light hydrocarbon refrigerants.

Tricycle – a new liquefaction processOnshore liquefaction plants use mechanical refrigeration and light hydrocarbons (C2 – C5 depending on the process) among the refrigerant components. Offshore, it is important to minimise the inventory of light hydrocarbons, particularly in the liquid phase, to reduce the risk of explosion and the need for safety gaps between modules. If they can be eliminated entirely, the production or the importation of propane and ethane and respective storage facilities can be avoided.

Nitrogen expansion cycles are one known solution. However, they suffer from poor efficiency and the heat to be dissipated from the compression loop is significant, increasing the size of the cooling water system, piping and heat exchangers.

The newly developed Tricycle liquefaction process uses three gaseous phase refrigeration cycles with expansion turbines. Unlike the standard nitrogen cycle, the efficiency of the Tricycle process approaches that of processes using light hydrocarbons refrigerants to within 20%. Each of the three cycles is totally independent from the other two. Gas compositions, pressures and temperatures are optimisation parameters.

The gaseous refrigerants of the three expansion cycles are mixtures of natural gas and nitrogen, which is produced in all LNG plants for inerting piping and equipment. Refrigerants can be produced rapidly from the process. This avoids the problems caused by the first fill of refrigerant, eliminating the hazards from LPG handling and the problems of finding a refrigerant with very high purity.

Figure 1. Offshore dual column process.

Figure 2. Tricycle liquefaction process.

Figure 3. HiPur process.

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The fact that all refrigerants stay in the gaseous phase reduces the hydrocarbon inventory, compared to a traditional refrigeration cycle. There is no need for a large liquid accumulator.

A major advantage on a floating platform is that the process is not sensitive to motion.

In short, the Tricycle process fills the gaps between the reverse Rankine cycles, which boast high efficiency but result in liquid light hydrocarbons refrigerant inventory on-board, and the reverse Brayton cycles using pure nitrogen, which improve safety at the expense of low efficiency.

The proposed scheme consists of three reverse Brayton cycles, in which the refrigerants remain in the gas phase even at the expansion turbine outlet where temperatures are lowest.

The refrigerant selected will depend on the temperature sought. Pure nitrogen can be easily used from ambient down to -170 ˚C with the possibility of subcooling the LNG and having no end flash. Methane can be used down to -110 ˚C. Mixtures of methane and nitrogen are often the most advantageous. Performance can be optimised through the addition of CO2 or C2 – C5 hydrocarbons, on the condition that the refrigerant remains gaseous.

Figure 2 shows the simplest configuration using three separate cycles to precool, liquefy and subcool the natural gas.

The three totally independent cycles can be adjusted individually to obtain the best thermodynamic efficiency. In addition, three cycles are easier to start up and operate.

This intrinsic flexibility has been extensively studied to know how to adapt to the most frequently met cases. For example, a gas mixture fairly close to raw natural gas can be used for the precooling cycle, while a lean natural gas can be used for the liquefaction cycle. The subcooling cycle is inevitably high in nitrogen.

From this insight it is apparent that the Tricycle process is a potentially attractive alternate liquefaction process for the FLNG industry as it moves forward.

HiPur nitrogen removal unitWhen the nitrogen content of the feed gas is high, an end flash unit is a necessary step to ensure the LNG product nitrogen content is below 1% mol. This limit on nitrogen is dictated by the storage tank minimum design temperature, by the need to eliminate the risk of roll-over and the simplification of boil-off gas management.

For low nitrogen feedstock, subcooled LNG can be routed straight to storage and an end flash unit can be avoided.

However, for feedstocks rich in nitrogen, the drawbacks of a simple flash drum become increasingly problematic as N2 content progresses. The outlet temperature from liquefaction is the only adjustment variable, with higher N2 requiring a higher temperature that generates increasing quantities of flash gas. When this exceeds fuel gas requirements it must be recycled for liquefaction. This results in an accumulation of N2, which can render the flash gas unsuitable as fuel gas through insufficient calorific value and control instabilities, due to the large differences in Wobbe index between sources.

A process that removes nitrogen from the picture solves all these end flash gas disposal issues.

For FLNG, high utility nitrogen demand associated with a need for cryogenic quality is a new challenge for the offshore industry, where compactness and a small footprint and weight are so important. LNG carriers and offshore production platforms have used multiple banks of membranes that are frequently oversized to cover for peak demand generated by purging requirements associated with offloading, tank maintenance, etc. Conventional LNG carrier operations require 97% purity nitrogen whereas FLNG may require up to 98 – 99% purity. High purity can be attained with membranes by adding additional stages in series. However, this consumes space.

So the idea of producing high purity cryogenic nitrogen in large quantities from end flash gas is attractive, particularly for nitrogen rich feedstock. The challenge is to maintain purity and exclude methane in the nitrogen vent.

Technip’s HiPur process has been designed to meet these challenges; to obtain low levels of nitrogen in the LNG product even for challenging feed stocks, produce nitrogen with a methane content below 0.1% mol that can be used in the plant or vented in an environmentally friendly way, and to eliminate fuel gas quality management problems.

The process can also be designed to produce liquid nitrogen that can be stored to meet peak demand, and helium, a highly valuable product, which is concentrated in the nitrogen vent and becomes easily recoverable.

The process consists of a distillation column, refluxed to achieve the low methane content in the overhead nitrogen and reboiled to remove nitrogen from the LNG bottom product.

Key features include a reverse Brayton refrigeration cycle using the expansion of part of the nitrogen to subcool LNG from liquefaction. An open heat pump is used to produce high purity nitrogen and to extract an eventual helium rich stream. Finally, as the fractionation of methane

Figure 4. FLNG vessel.

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and nitrogen is performed at cryogenic temperatures, the design includes extensive thermal integration to minimise power consumption.

The heat pump allows condensation of the compressed overhead vapour by exchanging with the reboiling bottoms. To be effective, the column condenser and reboiler must have comparable duties. This is achieved by adjusting the LNG feed inlet temperature using the reverse Brayton cycle, which results in the adjustment of the reflux flow requirement. Given the low refrigerant temperatures reached, the reverse Brayton cycle requires nitrogen with a purity of 99%. As shown in Figure 3, the reverse Brayton cycle can then be integrated with the heat pump compressor and use the same refrigerant, i.e. the nitrogen product itself.

The HiPur process allows full advantage to be taken of the installed gas turbine power and cryogenic heat exchanger surface. It also provides several valuable products: liquid and gaseous nitrogen and eventually helium.

Compared to a conventional end flash scheme, the main advantages can be summarised as follows:

LNG production is maximised through full recovery of methane.

Nitrogen no longer goes into fuel gas, increasing gas turbine availability and simplifying the control scheme.

The methane content in the nitrogen can be as low as 0.1% mol, reducing the impact on the environment if vented.

High purity gaseous nitrogen can be produced and fed directly to the utility network or used as refrigerant make up to the liquefaction cycles.

Fuel gas can be drawn from unprocessed feed gas, reducing the size and power of the liquefaction unit.

Liquid nitrogen can be produced and stored to meet peak demand.

Helium in the feed gas is concentrated in a single nitrogen vent stream and can eventually be recovered to provide an additional source of revenue.

ConclusionIn recent years, FLNG technology has gained acceptance with two offshore projects under construction for Shell and Petronas. Technip has a central role as the engineering contractor leading both EPIC contracts in consortia with Samsung Heavy Industries (SHI) and Daewoo Shipbuilding and Marine Engineering (DSME), respectively. In parallel, a suite of three processes have been developed and patented to provide a new response to the demands of offshore operations, including increased safety, flexibility, operability and compactness, reduced sensitivity to motions and ultimately improved profitability. Although the next step is to adapt the processes to equipment that is already available, or that can be developed easily by scale up of proven designs, these processes can now be considered for use on new projects.

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LNG_MARAPR_2013_42-48.indd 48 21/03/2013 14:07


A new venture

John Hritcko, Wison Offshore & Marine Inc., USA,

introduces the world’s first FLSRU.

The challenge: a customer wants to produce natural gas from a relatively small, remote onshore resource base and needs a cost effective, fit for purpose

solution to deliver the production to market. The local gas market is not an optimal choice for the project and the gas supply deliverability is not large enough to support a traditional onshore liquefaction facility.

This is the situation that confronted Pacific Stratus Energy Colombia Corporation, a subsidiary of Pacific Rubiales Energy (PRE), the Colombian-Canadian exploration and production company, producing natural gas from the onshore Creciente Field in Colombia’s Lower Magdalene Valley basin.

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To solve its dilemma, PRE teamed up with Exmar, the independent, diversified Belgium-based shipping company serving the oil and gas industry and specialising in transporting LNG and other liquefied gases. The resulting scheme that developed will soon become the world’s first floating liquefaction, regasification and storage unit (FLRSU).

The solution The solution is a barge-based FLRSU capable of converting the gas stream into LNG that may temporarily be stored in onboard tanks, delivered into an adjacent floating storage unit, then offloaded into shuttle tankers that would carry the LNG to market.

In the summer of 2012, Exmar turned to Shanghai-based Wison Offshore & Marine Ltd to construct this innovative solution. The company provides full life-cycle of project delivery from engineering and design, project management and construction, to commissioning and operations of all types of oil and gas projects.

The FLRSU will be built, owned and operated by Exmar. The entire capacity of the facility is leased to PRE under a long-term contract. Wison Offshore & Marine executed an engineering, procurement, construction, installation, and commissioning contract to serve as the primary contractor to Exmar.

The design and engineering of the FLRSU has been undertaken by Wison’s engineering centre in Shanghai. Construction began in December with the first striking of steel at the company’s fabrication yard outside of Shanghai at Nantong. The Houston, Texas subsidiary of Wison is providing support for the project.

Two of the major subassemblies of the FLRSU, the topsides equipment including the liquefaction plant and the storage tanks and cargo handling equipment, are being supplied by Black & Veatch and TGE Marine, respectively.

Black & Veatch will incorporate its patented PRICO single mixed refrigerant technology in a compact, modular liquefaction unit. The process lends itself to this type of offshore use because of its simplicity and scalability, resulting in relatively low cost.

The LNG storage will consist of three IMO Type C tanks with a total liquid capacity of 16 100 m3. TGE Marine will also supply the cargo handling equipment along with the electrical, instrumentation and gas safety systems.

Location and designThe FLRSU facility will be located approximately 4 km offshore, where the water depth is about 14 m. In order to link the onshore natural gas supply with the offshore facility, PSE will construct an 18 in. dia. pipeline, approximately 88 km long, extending from the Creciente Field to the coast. Natural gas will be delivered to the FLRSU barge using conventional hoses between the jetty and the barge.

As a result of the relatively shallow water depth, the FLRSU barge will be moored to four guide piles using a bracket system that will allow the barge to move vertically (heave), but not forward and backward or sideways. The floating storage unit (FSU), which may be either a converted or new-built LNG carrier, will be moored conventionally to the mooring piles of the jetty with the FLRSU barge held fast between it and the jetty. LNG carriers arriving to receive cargoes from the facility will use the proven Exmar ship-to-ship (STS) transfer system for offloading the LNG from the FSU.

The facility’s design parameters were dictated by the customer’s gas production and local market requirements. PSE has the exclusive right to deliver natural gas and liquefy up to 0.5 million tpy of LNG over a 15-year period pursuant to a tolling agreement. The natural gas supply is expected to have a composition of less than 1% CO2, allowing ready application of a floating modular unit.

Figure 1. Wison Offshore & Marine Ltd is delivering the world’s first floating LNG liquefaction, regasification and storage unit (FLRSU).

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A regasification option was designed into the facility to accommodate the occasional need to import LNG to serve the Colombian market. Approximately 65% of Colombia’s electricity is generated by hydropower, but occasionally during La Niña weather patterns, water shortages necessitate the increased use of gas-fired power generation. During those times, the Creciente Field production may not meet the market needs and the ability to import LNG will be critical.

The dimensions of the FLRSU barge are: 144 m long x 32 m wide x 20 m deep. The draft will be 5.4 m. The three storage tanks will be arranged in-line along the axis of the beam and located inside the hull. The topsides equipment will weigh approximately 5000 t.

The three 5367 m3, IMO Type C, LNG tanks were chosen to avoid concerns regarding sloshing. In addition, the robust tank design offers considerable strength to withstand both inner and outer pressure with safe and simple control. These tanks are designed for easy operation and maintenance and there is no need for a secondary barrier.

The liquefaction unit will be capable of processing nearly 70 million ft3/d of gas, or roughly 0.5 million tpy of LNG, while the regasification capacity will be up to 400 000 million ft3/d of gas. The FSU alongside of the FLRSU barge will offer an additional 151 000 m3 of LNG storage capacity.

Following the yard commissioning, the FLRSU will be loaded onto a transport vessel for dry transport to

Colombia, where the unit will be offloaded at an inshore location, then wet-towed to the final installation site. The barge will be fitted to the mooring brackets and the natural gas feed lines attached. The target date for the mooring of the FLRSU is the fourth quarter of 2014.

ConclusionWison Offshore & Marine is proud to be the primary contractor for Exmar’s pioneering FLRSU project. Capitalising on Wison’s deep-water offshore experience and applying patented Black & Veatch liquefaction technology in conjunction with TGE Marine’s cargo containment and handling systems to deliver a first of its kind solution opens new doors for the company in the floating LNG (FLNG) sector.

Barge-based FLNG is an enabler for small to mid-scale emerging gas markets. The project size lends itself to ‘off-the-shelf’ modular components that are relatively easy to fabricate and outfit in controlled shipyard settings. Additionally, with an unobtrusive, smaller environmental footprint and higher likelihood of successful permitting, FLNG holds many advantages relative to traditional onshore plants. Ultimately, the customer gets the benefit of cost and schedule advantages over alternative new build solutions.

Given the market’s desire for innovative, cost effective solutions, this venture into LNG is likely to be the first of many for Wison.

LNG_MARAPR_2013_49-52.indd 51 21/03/2013 14:12

Experience LNG industry

Excellence cryogenics.

Outstanding records

Nikkiso Co. LTD, JAPAN— Tel +81 42 392 3548, [email protected]

Nikkiso Cryo Europe, ITALY— Tel +39 02 93468623 , [email protected]

Nikkiso Cryo Inc., USA—

SUBMERGED MOTOR CRYOGENIC

PUMPS FOR LIQUEFIED GASES

LNG_MARAPR_2013_49-52.indd 52 21/03/2013 14:12


L ower capital costs, shorter on-stream time, lower coastal environment impact and flexibility… these are some

reasons that led to the development of the floating storage and regasification unit (FSRU).

Typically these units are like large barges that are semi-permanently moored offshore from their regasified LNG delivery sites and are fed by

standard LNG carriers. A special subset of the FSRU concept is the LNG carrier, which is fitted with full

regasification capability. These ships transport LNG from the liquefaction plant to the customer and then

regasify the LNG offshore. These special vessels are known as LNG shuttle and regas vessels (SRVs).

As the SRV is repeatedly subjected to seagoing vertical and lateral accelerations exceeding those of

moored FSRUs, these unique vessels require regasification pumping systems designed and tested to

perform during and after exposure to differing levels of motion. Along the various phases of the SRV delivery

rotation, the pumps are exposed to a spectrum of accelerations, as shown in Table 1.

FABIEN A. WAHL, NIKKISO CRYO INC., USA, DISCUSSES TECHNICAL ADVANCES FOR LNG PUMPS ABOARD FSRUS.

FLNG

LNG_MARAPR_2013_53-58.indd 53 21/03/2013 15:44


LNG pumps for SRVFigure 1 shows the Nikkiso Cryo regasification ship pump set, which has been used on board the Excelerate Energy fleet of vessels since 2004. Standing on the left, is the emergency/in-tank pump, which on an SRV must perform the duty of being the primary feeder to the deck mounted high pressure send out pumps and to the line packing pumps. Lying on the Horizontal Assembly Stand© is the send out pump. The line packing pump is positioned on the far right.

The in-tank pumps are located inside the emergency wells found on a traditional LNG carrier. Unlike the original emergency pumps that are part of a classical ship set, these primary pumps are permanently lowered in the column. These pumps feed the suction drum, and are rated for a flow of 620 m3/hr, with a differential head of 115 m. The pump rated power is 200 kW.

The send out pumps are located on the bow of the ship. They are mounted in their own suction vessel, themselves integrated onto skids. These pumps feed the vaporisers at a flow of 205 m3/hr, and with a differential head of 2370 m. The pump rated power is 1100 kW.

Line packing pumps are operated during the start-up of the regasification unit to pressurise the vaporisers and the downstream pipeline smoothly without any liquid hammer. These 200 kW pumps deliver the same differential head as the send out pumps (2370 m), but at a lower flow rate (20 m3/hr). The line packing pumps are vessel mounted on the bow of the ship along with the send out pumps.

For more recent projects, such as Golar – Winter and Höegh LNG – Neptune, larger send out pumps have been developed, reaching 15 stages and 1500 kW.

Technical advances

In-tank pumpsOn a conventional LNG carrier, the emergency pump, if ever needed, is lowered with cables and rests on the foot valve unsecured. If the pump remained in position while underway, it would be free to tilt or rebound vertically on the foot valve seat, especially during severe sea conditions. Therefore, emergency pumps are stored on deck.

Figure 1. Nikkiso Cryo regasification ship set.

Table 1. Operation environment

Accelerations (G) Regasification operation

Transit seagoing

Vertical 0.4 0.8

Transversal 0.2 0.5

Longitudinal 0.1 0.6

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To meet the needs of floating LNG (FLNG), Nikkiso Cryo has developed a method to replace lifting cables with a segmented lifting pole. This engineered system not only functions to lower or remove the pump from the column but also holds the pump on the foot valve seat and prevents any movement of the pump in the column. Additionally, the design of the foot valve seat has been enhanced to a conical shape, which offers a self centering and optimised contact surface and eliminates any possibility of the pump sliding on a flat seat.

Send out pumpsThe mass and the size of the send out pump, combined with the motion of the ship, induce high mechanical

stress issues. In traditional land based applications, the send out pump is suspended from its discharge manifold inside the suction vessel. When the ship is pitching and rolling, the mass-inertia-induced lateral displacement of the pump would generate high stress loads on the bolt circle connecting the pump to the suction vessel. In order to prevent any relative motion of the pump with respect to the vessel, Nikkiso Cryo has added a stabilising pin underneath the suction manifold of the pump. This brass male pin engages in the stainless steel female receiver at the bottom of the vessel. The design enables longitudinal translation to account for thermal contraction differences between the aluminium pump and the stainless steel vessel. The pin also prevents lateral displacement,

suppresses any bending moment and also ensures the pump housings will not flex or cause interference between the rotating elements of the pump and the close fitting bushings and bearings.

The same flexing might occur between the suction vessel and the deck of the ship. If this were to occur, the pump mounted stabilising pin could transmit the flexure to the pump housing through the above mentioned receiver mounted at the bottom of the suction vessel. Additionally, the vessel supporting pods would be subject to an increased bending stress. To eliminate these effects, Nikkiso Cryo has added a similar male/female pin arrangement on the external bottom of the vessel and the deck of the ship.

This dual male/female pin configuration between the pump and the vessel on one hand, and between the vessel and the deck on the other hand, creates a rigid design with no lateral degree of freedom.

In a usual land based send out pump design, when the pump is not operating, the dead weight of the entire rotation assembly (rotor, shaft, all impellers, and their retainers) is supported by only one radial bearing. The vertical acceleration experienced on a ship while underway would significantly multiply the vertical load imparted to this radial bearing. The balls would brinnel the races and the bearing could be destroyed with very little, if any,

Figure 2. Send out performance curve with and without motion.

Figure 3. Line packing pump high speed validation.

LNG_MARAPR_2013_53-58.indd 56 21/03/2013 15:44

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pump operation. Nikkiso Cryo has added a stowage piston located on the suction vessel head plate. This piston reaches through the discharge manifold to the end of the shaft and is actuated either with compressed nitrogen or by a pneumatic motor. When the pump is not operating, the stowage piston lifts the shaft and relieves the rotor weight from the supporting bearing. This stowage position totally unloads the bearing, and preserves the pump indefinitely. Just before pump operation, the rotor is lowered smoothly onto the support bearing.

The pump stabilisation method and the stowage piston have been patented by Nikkiso under United States Patent No. US 7,063,512 B2.

Send out pumps are classically long multistage pumps. In the case of the Neptune project, Nikkiso Cryo supplied a 15-stage pump. The lateral displacement of the shaft induced by the motion of the ship must be carefully addressed to prevent a rotor/stator contact during operation in rough weather conditions. Nikkiso Cryo has added three radial ball bearings along the pump shaft line. This unique construction yields a stiff rotor, perfectly guided on multiple points. Bushings disposed in all non-bearing carrying stages, provide additional damping. This stiff and damped rotor dynamics enables a safe pump operation while the ship is pitching and rolling.

During pump operation, the weight of the rotor and the hydraulic forces are compensated by the Nikkiso balance drum assembly. In motion less design, the balance drum has to account for the changes in hydraulic forces. In case of vertical acceleration changes, the weight force is also changing. The Nikkiso balance drum design is a separate function in the pump, and is independent of the design of any other component of the pump. Therefore, the balance drum assembly is designed in order to meet the requirement of the axial thrust balancing, regardless of the main flow, head specifications and from the vertical accelerations environment.

Line packing pumpsThe line packing pump specification presents a more complicated task in that the duty requires the combination

of low flow and high head. Traditional centrifugal pump selection based on a 60 Hz two-pole motor would have led to a slim 20-stage, 3.4 m-long pump. With respect to the vertical and longitudinal vertical accelerations environment expressed previously, such a long and thin pump appears as a poor fit. Nikkiso has specifically developed a Small High Pressure pump, which takes advantage of a higher speed of rotation to reconcile low flow and high head. Nikkiso’s line packing pump uses a VFD driven motor at 120 Hz. Advantageously, this Small High Pressure pump has only eight stages and measures only 1.9 m in length.

The high speed design was supported by a detailed rotor dynamics analysis and impeller stress calculations.

ValidationsThe compliance of the design of the large send out pump with the motion of the ship has been demonstrated during a full size test on an articulated platform. The platform was set up near the peak shaver in Trussville, Alabama in 2004, by El Paso. An entire regasification unit was fitted on the platform: suction drum, send out pump and vaporiser. The platform simulated the motion of the bow of the ship in 8 m waves. The regasification test was run at full capacity with LNG supplied by the peak shaver. Comparisons of data between the steady and articulated operations show that the send out pump service is insensitive to the motion.

The Small High Pressure line packing pump was successfully tested on the Nikkiso test stand of North Las Vegas, Nevada. The pump was tested at 110 Hz and 120 Hz. The operational speed was then determined to be 116 Hz. For this pump, no impeller trim was necessary, because the final tune up was performed by speed adjustment.

Following the validation programme, the Nikkiso regasification ship set was certified by Bureau Veritas Marine and Det Norkse Veritas Maritime.

With the eye of Hurricane Katrina only 60 miles away, the FSRU Excellence was sending out gas at 100% capacity in the Gulf of Mexico. Regasification operations were performed in 4 m waves. This validation by Mother Nature proved the robustness of the entire floating regasification concept.

ConclusionNikkiso Cryo is dedicated to the LNG industry and has heavily invested in technologies to advance FLNG including FSRU, FPSO and SRV operations. The company's packages include the full range of in-tank, send out and line packing pumps proven in the field. Original technologies addressing the specificity of operation during ship motion have been developed, patented and successfully validated. This line of product is presently in service or will be installed on board all Excelerate Energy/Exmar ships, Höegh ships, and Golar ships. Further, this floating pumping technology has been extended to floating production facilities, like Shell/Prelude FPSO, which uses Nikkiso Cryo in-tank pumps derived from ones presented in this article.

Figure 4. Articulated platform.

LNG_MARAPR_2013_53-58.indd 58 25/03/2013 09:18

A ccording to China’s latest five year plan, the annual demand for LNG throughout the country will increase threefold from the current level of 2.3 million tpy to

over 7.5 million tpy. Additionally, the ratio of primary energy consumption from natural gas will increase from 4% to 8% by 2015. Most of this increase will be in the small to mid-scale LNG market, making it the fastest growing natural gas market in the world. This small to mid-scale market will use the flexibility of LNG technology to create virtual pipelines, providing natural gas to new remote markets that were previously out of reach.

The supply chain for small to mid-scale LNG is not much different from the fuels that it competes with. From the LNG source (either an LNG plant or import terminal), LNG is moved by ships to smaller satellite terminals where it is stored in cryogenic storage tanks. From these terminals, LNG is pumped onto standard semi-trailers, LNG rail cars or LNG barges, where it is shipped to remote locations. From there, the liquid is vaporised back into gas form and piped to the customer’s point of use. In addition to the supply chain side of the small scale markets, there are plans to construct more than 1500 LNG filling stations, supplying fuel to as many as 200 000 LNG fueled vehicles.

The concept of small to mid-scale LNG shares much of the technology with traditional, large scale LNG, however the scope

Made to measureChristopher Finley, Ebara International Corp., USA, discusses the development of a new generation of small to mid-scale submerged LNG pumps for small scale LNG facilities.

LNG_MARAPR_2013_59-62.indd 59 21/03/2013 14:21


of equipment supply is much smaller. Due to the smaller volumes of gas, all of the related equipment from ships to tanks and receiving terminals are around one-tenth the size of typical large scale LNG. The smaller equipment size results in lower capital outlay requirements, less time to build and requires less effort to get through local approval processes.

Pumping equipment for small to mid-scale applications At several points in the small to mid-scale LNG logistics chain, land based LNG storage tanks are used for receiving and off-loading purposes. The typical and preferred method to unload these LNG tanks is to utilise a retractable submerged motor centrifugal pump, mounted inside each tank. Although these types of tanks may vary significantly in size and construction, the design of the retractable submerged motor pumps and related systems are similar. The main components of this type of pump are the tank column and suction valve, the retractable pump and the retraction system.

The purpose of the pump column is two-fold. First, it acts as a discharge pipe for the submerged pump, guiding all flow from the pump to the outside of the storage tank. The second purpose of the pump column is to provide a method to safely remove the pump from the tank, with liquid inside. To accomplish this task, the retraction system is used to slightly raise the pump inside the column. As the pump is raised, a suction valve mounted to the bottom of the pump column closes, sealing off the column from the storage tank’s content. Once the valve is completely closed, any residual LNG left in the pump column is removed by pressurising it with nitrogen, creating a safe environment. The pump can then be completely removed from the tank without removing any of the liquid in the tank. This gives operators on site flexibility in scheduling routine maintenance both on the tank and on the pump itself. Today, almost all LNG storage tanks built use this type of submerged motor pump and pump column design.

There are many benefits to using these types of submerged motor retractable pumps over external sealed motor pumps. In non-submerged motor pumps, the pump motor is mounted outside of the process fluid, while pump hydraulics are mounted inside the process fluid. This configuration requires a dynamic shaft seal between the cryogenic LNG and the relatively high temperature of the outside atmosphere.

Because the temperature differential is so high between the two sides of the seal (typically more than 160 ˚C), effectiveness and reliability are a major concern. Another benefit of submerged motor pumps is that due to the non-conductive nature of liquefied gases, the pump motor is completely submerged and cooled in the process liquid without fear of a short circuit in the motor windings. Also, due to the fact that there is no oxygen present in the LNG tank itself, the pump is installed in a safe, explosion free environment. Finally, because the entire motor and pump assembly are completely submerged, there is no need for shaft seals, eliminating the risks experienced in external motor pumps.

Typical LNG pump designsSince the initial development of cryogenic submerged retractable pumps, most pump designs are ‘engineered to order’. This means that each pump component is custom engineered to meet very specific duty requirements including flow, head, power, electrical classifications and other installation site needs. These major pump components consist of pump casings, electrical motor and shaft and hydraulics.

The first step in designing custom pumps is to review the performance requirements and develop hydraulic components to meet them. In many cases, pump manufacturers have extensive libraries of pump hydraulic designs allowing them to simply choose impeller, diffuser and inducer combinations to meet the specified duty. However, it is not uncommon to design completely new hydraulics when the required duty point is outside of the existing hydraulic library.

The next step in the engineer to order process is to size and design the pump motor. Although several stator frame diameters are standardised, the length of the stator and rotor are specified for each individual pump to maximise efficiency at the given duty point. This results in a virtually infinite number of possible motor designs, requiring each motor to be custom manufactured.

The final step in the pump design process is to design the pump and motor casings to house all of the

Figure 2. Typical engineered to order retractable pump.

Figure 1. Typical retractable pump system.

LNG_MARAPR_2013_59-62.indd 60 21/03/2013 14:21

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previously designed components. Due to the variety of pump hydraulic and motor designs described above, the pump casings must also be custom designed for each application. Once the casing designs are created, they are sent to a pattern maker who then builds custom patterns before the parts can be produced. These patterns are then sent to a foundry where they are used to produce custom aluminium sand castings of each component. Next, the castings are sent to a machine shop where they are machined to the final design parameters. The end result is casings that perfectly match the pump hydraulics and motors, but sometimes cannot be used again in the future.

Once all of these pump components are manufactured, they are sent to an assembly plant for final assembly, full performance testing, inspection and shipment. The complete process from pump sale to shipment can commonly take 12 to 16 months to complete. With traditional large-scale LNG projects planned many years in advance of construction, this lead-time is perfectly acceptable and expected. For small to mid-scale applications, where the speed and cost of planning and construction must be much lower, engineer to order lead times and costs are too high.

Next generation small scale LNG pumpsTo be competitive in the small to mid-scale LNG market both in China and throughout the world, the design methodology for small and mid-scale retractable pumps had to be adapted. Due to the ever-increasing unit volume demand, shorter lead-time requirements and cost pressure, specialty engineer to order (ETO) companies must find ways to apply configure to order (CTO) techniques to streamline internal processes. By adopting CTO techniques, state-of-the-art engineering companies can produce technologically advanced products with shorter lead times, higher quality and at lower costs. The main difference between CTO products and ETO products is that for CTO products, most of the engineering, design and manufacturing is done upfront, before specific demand for the product is generated. This allows manufacturers to simply assemble pre-designed and manufactured components in unique configurations to meet the customers’ requirements. To meet this challenge, Ebara International Corp. has developed a line of standardised, CTO pumps that provide ETO quality and customisation.

One of the benefits of the small to mid-scale market is the relatively small operating range required for pumps. Specifically, this range was found to be anywhere between 45 m3/hr at 60 m of head to 200 m3/hr at 375 m of head. Through thorough analysis, the company developed a design matrix defining all of the possible flow and head variations within this range with the specific goal of minimising the amount of design variation required. This analysis showed that with only three impeller/diffuser/inducer combinations,

every possible combination could be reached with minimal effect on hydraulic efficiency.

Although only three hydraulic combinations are required to meet the performance envelope, duty points

that required relatively high head would still require multiple hydraulic stages; the number of which varies throughout. This causes the number of design variations to be a product of the three hydraulic combinations, as well as the number of stages. To address this fact, the company decided to incorporate variable speed technology, when necessary. By varying the pump speed using a variable frequency motor drive, all duty points could then be reached with only one hydraulic stage. The end result is that the entire performance range could be met with only three design configurations.

The next challenge to address was the process of designing and manufacturing the pump motors. Because there were only three design variations for the pump hydraulics, the company set out to design only three different motors to cover the entire performance range, to keep the overall design iterations to a minimum. This goal was ultimately achieved by working with motor design specialists to develop highly efficient motors that can operate both at variable speeds (up to 120 Hz or 7200 RPM) and over a wide power range.

The final step in creating pre-configured standardised pumps was to design the pump casings. The goal of this process, as with the other components, was to minimise the number of design variations. By designing all of the pump casing and related hardware to accept the largest motor and hydraulic combination, the company was able to create only one set of casing designs to meet the full performance range. Also, to avoid the typical lengthy manufacturing process of using castings for these casings, the company developed all aluminium billet machined components. Using this type of manufacturing technique removes several steps in the typical casting manufacturing process, reducing part lead times to days instead of months.

The final outcome of this engineering effort was a pre-engineered, CTO product that retains all of the benefits of an ETO product, without the lengthy lead-time and high costs.

ConclusionAs small to mid-scale LNG projects ramp up throughout the world, the need for short lead-time and low cost pumping equipment will also increase. Without sacrificing quality or technological advantages, Ebara International Corp. has developed a new line of small to mid-scale retractable LNG pumps that meet the demanding delivery and cost requirements of this new market.

Figure 3. Ebara International’s new standardised small to mid-scale retractable LNG pump.

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The heat is on in Darwin, Australia’s gateway to Asia, but the reason is cool: LNG. In January 2012, the Japanese company INPEX and its French partner

Total announced the official go-ahead for a US$ 34 billion project: the development of the Ichthys field, located 850 km offshore from Darwin, Australia. Scheduled to start production by the end of 2016, it is estimated to yield a peak output of 8.4 million tpy of LNG.

With this deal, Australia could challenge Qatar as the world’s biggest producer of LNG by 2020. Fueled by urgent orders from Japan and the energy-hungry economies of China, India, and other Asian countries, the demand for LNG is expanding much faster than projects can come onstream. Gas companies are spending billions of dollars building LNG

plants. In Australia, they are currently working on seven of the world’s 10 major LNG projects.

Performing reliablyOne fundamental contributor to the effectiveness of such huge investments is extremely reliable, high-performance equipment. Since 1974, Ebara International Corp.’s Cryodynamics Division has been supplying more than 6000 pumps and expanders for LNG carriers and land-based facilities, including major projects, such as those operated by Qatargas and RasGas or KNPC’s North Tank Farm.

Soon, Ebara will also contribute to the Ichthys LNG project, the world’s longest undersea gas pipeline venture, as well as to Shell’s Prelude facility, a groundbreaking

Thomas Goettlinger, Schott, Germany, and Don Polkinghorn,

Ebara International Corp., USA, explain the technology needed to

steadily and securely feed LNG pumps with power. S

LNG_MARAPR_2013_63-66.indd 63 21/03/2013 14:28


achievement using innovative FLNG technology off the coast of Western Australia. Its pumps and expanders are designed to operate completely immersed in cryogenic liquids. This calls for a commitment to safety and quality that embraces all related components.

Safely powering the pumpsUtmost attention is given to the electrical system. The pumps mounted aboard the cryogenic containment require electricity for control, instrumentation and power of up to 6600 V. The penetration from atmosphere into the cryogenic liquid is accomplished using specially designed electrical feedthroughs, also called terminal headers. Since the late 1990s, Ebara has increasingly been equipping its installations with feedthroughs made by Schott Electronic Packaging, which use a unique compression glass-to-metal sealing technology.

Terminal headers perform two main functions: they safely provide electricity to highly susceptible appliances potentially exposed to explosive atmospheres, and they maintain the pressure boundary integrity of the containment structure. Meeting the most demanding applications for hermetic terminal headers, Schott’s feedthrough modules are resilient to thermo-cycling, thermo-shock, and temperature ranges from -196 to +100 ˚C (-320 to +212 ˚F).

Gastight contraction The feedthroughs are sealed with non-ageing glass that remains pressure and vacuum-proof for many decades. Be it in LNG applications, hydrogen-cooled generators or even nuclear power plants and submarines, Schott’s sealing technology has proven its maintenance-free durability and reliability in more than 12 000 installations around the world since the early 1960s.

The terminal headers basically consist of only three components: metal conductors, a glass sealant and a metal

housing. The preassembled components are heated up to a temperature at which the special glass melts to the metal. During the cooling process, the metal housing contracts to a greater extent than the glass, creating a robust, compression-sealed unit that guarantees practically unlimited pressure-proof hermeticity.

Advantages In contrast, epoxy seals contain organic substances that age naturally, particularly when exposed to severe temperature fluctuations. An inorganic alternative is ceramic, but this material cannot be melted directly to metals like steel or copper. Soldering or welding is required that often tends to corrode in harsh environments, starting with surface imperfections that can develop into fissures. Due to the lack of compression sealing, ceramic isolators are also more likely to develop surface cracks over time. Such developments can impair the isolator’s dielectric function and lower the resistance of the seal following an accident. In addition, loss of tightness may occur.

However, glass-to-metal seals are proven to withstand extremely high pressure and thermal shocks. Before shipment, Schott tests each product vigorously at one-and-a-half times the maximum design pressure, up to 225 bar. It is thoroughly checked for leak tightness with helium mass spectrometers. An electrical test ensures that no short circuits result when electric power of up to 11 000 V and 1000 A flow through the glass-insulated conductors.

Approved and certifiedAs they are employed in hazardous environments, most cryogenic pumps require cable penetrations with a double safety barrier. Conventionally, two feedthroughs connected by cables are integrated in a row. However, a more compact double penetration developed by the company in close cooperation with its customers allows

Figure 1. LNG already accounts for nearly 35% of the world’s natural gas shipments. This success has been made possible by the fact that the highest possible safety standards apply. Gas-tight feedthroughs maintain the integrity of the pressure vessels.

Figure 2. Schott’s electrical penetration assemblies serve as the hermetic feedthroughs for the three-phase electrical power, as well as the control and instrumentation signals.

LNG_MARAPR_2013_63-66.indd 64 25/03/2013 09:15

Hermetic. Safe. Maintenance-free. Glass-to-Metal Sealed Electrical Terminal Headers for LNG Pumps

Non-aging hermetic glass-to-metal sealing technology enables the safe

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Maintenance-free in more than 2,500 pumps worldwide, after more

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LNG_MARAPR_2013_63-66.indd 65 21/03/2013 14:28


for smaller dimensioning of the feed lines. This offers the possibility of nitrogen purging for periodic or permanent leakage-monitoring or inertisation of both pressure barriers. The inner chamber can also be closed and certified as a flameproof enclosure. Therefore, no nitrogen purging equipment is required.

Both single barrier and double penetrations were thoroughly tested at Ebara’s cryogenic performance test facility in Nevada, US. The positive test results add to the feedthrough’s international quality certifications, which facilitate the approval of installations by customers and regulatory authorities. Schott’s explosion-proof glass-to-metal seals comply with the European ATEX directive and international IECEx standard, as well as specific local regulations, such as those from KOSHA (Korea

Occupational Safety and Health Agency) for South Korea.

Expanding offshore Schott has now arranged for all of its products designed for offshore applications to also be certified according to special standards for ship classifications. This certification, based on the so-called ‘plan approval,’ means it is no longer necessary to obtain a project-related approval for each separate use of the product. Once this certification is obtained, it will save the company’s customers a lot of time and effort, because products can be made available much more quickly.

This arrangement additionally supports the use of the company’s feedthrough technology not only in LNG shipping, but also in young and strongly expanding markets, such as maritime propulsion and smaller-scale LNG facilities near harbours. On top of that, the race for FLNG facilities, needed to tap more than 2000 trillion ft3 of proven undeveloped offshore gas reserves

around the world, has just begun. Supplying Shell’s Prelude project, Schott and Ebara continue their pioneering partnership.

ConclusionProviding safe, effective and reliable appliances required in LNG process technology demands expertise and state-of-the-art equipment. Schott’s hermetic glass-to-metal-sealed feedthroughs adhere to the highest quality standards and can be considered a safe technology for supplying electrical signals and power amidst the harshest environments. Their proven performance amplifies the efficiency and safety of submerged cryogenic pumps and expanders that serve in most of the world’s LNG facilities and aboard marine vessels.

Figure 3. Ebara International, suction vessel mounted high pressure pump. Source: Ebara International.

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Keith Stewart, Herose GmbH, Germany, discusses the issue of safety

certification in the LNG industry.

Fuelling ships in the Nordic regions; shale gas fields in the US; vehicle use across the globe; an energy resource to power major cities in China and other

developing countries – these are just some of the applications that demonstrate the incredible scope and breadth of the LNG industry.

But behind this dynamic story of growth and global opportunity, there are major concerns expressed at the diverse LNG forums and conferences. Experts in the shipping industry in particular have highlighted the impact on safety as companies race to keep up with new LNG applications. Ship fuelling, bunkering, vehicle fuelling, mobile stations and a multitude of other uses raise the question: who should set technical and safety standards?

LNG_MARAPR_2013_67-69.indd 67 21/03/2013 14:34


Lessons to learnSafety is a concern that is shared at cryogenic valve provider, Herose. It is the key to commercial success because of the fatal impact that accidents can have on people, the environment, an organisation’s shareholder value and the reputation of the industry. What is more, it only takes one incident to ruin a company’s perfect safety record, as has been seen in the industrial gas industry.

If similar incidents are repeated with LNG, the consequences for the entire industry will be catastrophic. In 1994, an industrial gas incident in Germany was caused when a cryogenic vessel exploded, resulting in a fatality. Concerns about all low-pressure vessels and high-pressure trailer pumping resulted in changes to vessel and valve codes in many countries. Today, industrial gas has regulating authorities and is managed by the major industrial gas companies, which drive high industry standards and make working with industrial gas safer than ever.

Processes such as filling, which have become a daily activity in the LNG industry, are governed by stringent standards in the industrial gas sector. As LNG applications diversify, surely now is the time to learn from previous mistakes and adopt standards, rather than wait for an issue to drive change?

Who should set the standards?The majority of companies using LNG take their safety responsibility seriously and make sure their systems and

components meet industry specifications. However, Herose provides advice and supplies the valves needed for every stage of the cryogenic storage and transportation process, and it still sees companies using different types of valve for the same application. In view of this, there is a need to develop global, mandatory standards. So who should take the lead in setting them?

Perhaps relevant industries need to form partnerships to consider whether the responsibility lies within the specific sectors using equipment, such as oil and gas, shipping or industrial gas sectors. Alternatively, global equipment manufacturers have an in depth understanding of what is required with installations; or national or global agencies could take ownership?

Industrial gas and LNG – two industries, one set of standards? Gas associations and safety organisations that protect the LNG and industrial gas industries include SIGTTO – the world’s leading safety organisation for LNG, encompassing almost all LNG tanker and terminal operators. The industrial gas industry has the CGA in North America, EIGA in Europe and other international organisations including AIIGMA, JIGA, AIGA and ANZIGA. The CGA co-operates with its sister organisation, EIGA, to develop harmonised technical rules to protect the industry, personnel and the public. It could be highly beneficial to both the LNG and industrial gas sectors to harmonise standards for LNG use.

Indeed, many equipment manufacturers supplying the LNG market operate to the standards of the industrial gas industry. As the specifications for vessels and valves used in these markets often differ, surely there is a need for the associations to work together to agree joint standards and share best practice across the full range of cryogenic applications.

Colleagues in each association and industry sector have different views and recently released some powerful messages promoting the safe use of LNG. However these have related to individual market sectors, not LNG as a whole.

An unbroken safety record for LNG shippingThe LNG shipping industry has operated safely, loading and unloading at LNG terminals worldwide, for over 45 years. A group of inspection agencies approve all types of equipment used in shipping and strongly promote standards for pressure containing equipment and valves. This group, together with the international inspection agency, SIGTTO, have contributed greatly to safety standards. Regulation has led to an unbroken safety record, giving the industry its licence to operate.

Although the last few years have seen less demand on existing fleets to ship LNG, new uses and applications for LNG are likely to mean that fleet sizes will increase over the next five to ten years. This will be achieved safely using the standards already practised in shipping.

Figure 1. LNG trailer filling facility.

Figure 2. LNG storage facility.

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With the development of LNG fuel for use in ship propulsion, inspection agencies also inspect and approve fuelling systems on ships and bunkering stations. However, the focal points for bunkering installations and the loading and unloading of smaller ships at river installations need to be regulated not only in Europe but worldwide.

Oil and gas companies have invested greatly in the shipping of LNG, selling it for use as a global energy resource. The loading and unloading of ships carrying LNG is similar to the industrial gas sector, although the latter loads and unloads its cargo more frequently and takes almost a day longer to complete. In the industrial gas industry, the major companies enforce mandatory safety standards and procedures, once again ensuring an impeccable safety record.

Diverse standards in ChinaThere are a growing number of small to mid-scale LNG processing plants across the globe. Specifications for Chinese plants have been developed by the processing industry, while saving stations (storage plants) follow the same standards as either the oil and gas industry or the industrial gas industry, depending on vessel size. Chinese equipment manufacturers use standards taken from the industrial gas industry for applications with argon, nitrogen, oxygen and hydrogen. The standards for these varied projects often come from many different industries, yet the medium for them all is LNG.

In addition to storage vessels, equipment manufacturers supply trailers and rail cars to transport LNG from terminals or saving stations to the point of use. Having already supplied the industrial gas market, suppliers have risen to the challenge of manufacturing cryogenic equipment for new and developing LNG applications, such as ship fuelling and bunkering. These applications are similar to those used in the industrial gas market and therefore they adapt the industrial gas standards.

Selecting the right valve is criticalIndustry associations have an important role in regulating activities, but there is still some way to go to establish standards for valves and to guarantee safety in all LNG installations. When accidents inevitably happen, processes must be in place to make

sure that systems shutdown effectively and that the right valves are always used. This is why selecting the right valve is critical. For example, fire-safe valves are designed to withstand extremely hot temperatures and emergency shut-down (ESD) valves close quickly to prevent fire from spreading, so closing time is important.

The following highlights the valve options for each application:

Ship fuelling – manual and control globe valves; manual gate valves; ESD globe valves with fire-safe control trim; safety and changeover valves.

Trailers – manual globe, gate and ball valves; ESD gate valves and globe valves with fire-safe options; safety and changeover valves.

Bunkering – manual globe, gate, ball and butterfly valves; breakaway couplings; quick closing valves with fire-safe control trim; safety and changeover valves.

Storage vessel – manual globe, gate and ball valves; breakaway couplings; ESD actuated valves with fire-safe control trim; safety and changeover valves.

LNG containers – drain and sampling globe valves with fire-safe control trim.

Terminals and plants – higher pressure globe, gate, full-bore butterfly and ball valves; ESD actuated valves; safety and changeover valves.

As well as selecting the right type of valve, it is also important to consider the following:

Valve trim.

Closing times.

Intrinsic safety type for electrical actuation complete with any other ancillaries.

Fire-safe options to protect your plant and personnel.

Service intervals for all equipment including valves. Reliability plays a major role in improving industry standards, while also reducing total life costs.

Such factors become more critical as LNG supplies are moved closer to densely populated areas, so that the liquid or gas can be used as an energy resource and for vehicle fuelling stations. This is why it is vital that global associations co-operate to make sure that valves and other components meet the highest safety standards. Without doubt, the vast reserves of natural gas in many areas of the world make it the fuel of the future. Therefore, LNG’s role in the market will continue to grow and prosper as long as it is safely regulated to protect its personnel, the general public and our industry.

Figure 3. Class1-Div.1 actuated valve.

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T he LNG industry is continuously working on the development of new

technologies and processes in order to improve the performance of systems and efficiency.

With the aim of supporting the LNG industry, AMPO’s engineering team is committed to the development of new products, technologies and systems, which is why the company usually works together with EPCs and the end user’s engineering teams. AMPO has developed projects tailored to each customer’s requirements, as outlined in the two case studies described in this article.

Moving forward

Jon Gorrotxategi, AMPO Poyam Valves, Spain, outlines the company’s recent cryogenic ball valve projects in Australia and China.

Figure 1. Assembly of a cryogenic AMPO Poyam ball valve in Idiazabal, Spain.

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Case study 1 – cryogenic ball valves for AustraliaWoodside, one of the world’s leading producers of LNG, contacted AMPO Poyam Valves for the urgent replacement of a cryogenic butterfly valve and a cryogenic gate valve for the Pluto LNG plant in Australia. Both valves, previously developed by another company with a different technology, had to be replaced in a short period of time, due to a leakage problem.

The solutionAMPO, specialising in cast steels, high specification valves and an energy-sector engineering service, suggested the installation of two top entry 42 in. cryogenic ball valves. The valves are made of ASTM A351 CF8M/Trim SS316 material, have a pressure rating of 150# (lbs) and were built per API6D ISO 14313 standards, BW end connections and gear-operated. AMPO supplied more than 11 000 valves to Pluto LNG. A key reason for selecting AMPO was that its cryogenic valve standard completely fulfilled Woodside’s strict technical requirements. With its own foundry, and being able to offer integrated solutions with complete control of the production process (valve design, pattern manufacturing, casting, assembly and testing), AMPO undertook the completion of the valves in a period of 20 weeks.

InspectionDespite the size and complexity of the valves, the project had another important milestone: Shell’s TAT Inspection. Shell visited AMPO’s headquarters in Spain for the testing and final approval of the valves. Although the valves were going to operate at ambient temperature, following Woodside’s specifications, they were checked

at cryogenic (-196 ˚C) and high temperature (150 ˚C). Once the testing was completed, both valves were shipped to Australia.

The end user in this particular location did not trust the 42 in. butterfly valves due to the leakage problems experienced. The customer was relieved once the new ball valve was installed, as this critical area requires a reliable valve.

Case study 2 – LNG receiving terminalsIn order to increase plant production capacity, some LNG receiving terminals are increasing plant design pressure up to 1500# (lbs). This brings a new challenge to the design of top entry cryogenic ball valves. The main design challenge could be focused on the sealing components; especially seats, seals and stem packing. Moreover, special care has to be taken with the material selection, as well as the design tolerances.

AMPO Poyam Valves has been selected to collaborate on these projects and has supplied high pressure cryogenic valves for the first two LNG plants in the world. These cryogenic ball valves have been installed in Dalian LNG and Jiangsu LNG in China, owned by Petrochina. Their sizes range from 2 in. to 28 in. and they are made in ASTM A351 CF3 and TRIM SS316 materials. They can withstand temperatures from -196 ˚C to 200 ˚C and have API6D and BS5351 standards, BW connections, lever and gearbox, and pneumatic actuator for actuation.

The company’s main products for LNG receiving terminals are manual and ESDV cryogenic ball valves. Top entry design is the most common, as it results in easy maintenance of the valve, without having to

Figure 2. 42 in. top entry cryogenic ball valve for Australia.

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disassemble it from the pipeline. Moreover, the valves may contain transition pieces (seamless pipe) for extra support, and these are welded at AMPO’s workshop.

It was a big challenge for the EPC of the projects, China Huanqiu Contracting & Engineering Corp. (HQCEC), and the end user, Petrochina. The valves were successfully delivered and commissioned and the plants are now in full operation. However, due to the novelty of these high pressure valves, the end user is concerned about the valve performance on site. Therefore, AMPO Poyam Valves is ready to provide full support during plant operation and is in talks to create a long-term relationship during operation between the maintenance team and the field engineering service (FES) team.

Supplying LNG valvesAMPO began in Idiazabal, Spain, in 1964 as a moulded steel foundry. When it merged with Poyam in 1970, it ran the cooperative company towards the valves sector. Consequently, AMPO Poyam Valves’ first cryogenic valve was supplied in 1979 for an Enagas receiving terminal located in Barcelona.

Since then, AMPO has supplied more than 100 000 cryogenic LNG valves all over the world, in more than 30 countries. To move forward and respond to the LNG market changes and innovations, AMPO’s R&D team has developed a diverse range of projects focused on developing the following:

Green valves – the company is working to improve valve performance to achieve ‘no emission valves’. Key factors towards fulfilling this technological promise are best practices on external and internal sealing, as well as improvements to achieve less torque, lighter weight and ‘no emission’ solutions in valve performance.

Smart safety valves – the company’s remote control processes, such as new engineering solutions, predictive maintenance equipment and new control systems, are just a few of the solutions offered. The performance of the valves under high pressure and temperature cycles meet the safety integrity level (SIL) standards.

Hardwearing solutions – industrial processes are becoming less straight-forward, while difficult extraction processes are increasingly complicating production. In order to help, some of the company’s main projects are cutting edge designs to prevent wear and tear, as well as new coatings to reduce friction between contact surfaces. Therefore, analysis of the capabilities of fluid media, tribological coatings and process studies are also developed.

The experience that AMPO has acquired and its way of understanding service has positioned it as a leader in sectors with very high requirements, and its valves cover the entire LNG chain.

Figure 3. Cryogenic test.

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W ith the explosion in interest in gas as a clean burning fossil fuel there have been huge implications for the shipping and offshore energy

sectors. The prospects for the use of gas to power ships have

really taken off. LNG is certainly a fuel of the future and the combination of emission regulations and energy prices is driving demand for change.

But gas as fuel for ships presents certain risks and hazards that need to be addressed. Operational reality requires that flexibility is accommodated into new rules that interface effectively with risk based approaches to dealing with novel concepts.

Lloyd’s Register has been working to ensure that shipowners, ship designers, shipbuilders, equipment manufacturers and technology developers can meet safety and performance goals by developing an approach that involves both prescriptive (rule based) and risk based approaches for when there are no rules.

With novel concepts there will always be challenges to address: will it work; will it work safely? Shipowners, cargo owners, ports, regulators, banks and insurers are all asking these questions.

Luis Benito, Lloyd’s Register, UK, discusses new developments in gas fuelled shipping.

future?A gas powered

LNG_MARAPR_2013_75-79.indd 75 21/03/2013 14:48


Lloyd’s Register looked at what is unique in designing gas fuelled ships and it developed rules that will now evolve as solutions based on a thorough evaluation of risk that can eventually support rule based solutions. This is an ongoing process of constant improvement following proven performance.

Completed in July 2012, the new rules replace Lloyd’s Register’s provisional natural gas as fuel rules. They have been harmonised with the IGC Code that covers the transportation of gas as a cargo and the draft IGF Code that addresses gas as a marine fuel. They were developed using in-service experience and the company’s work with the industry on joint industry projects, as well as the oversight of its Technical Committees. This experience helps develop new rules as new technologies are validated through the company’s risk guidance and understanding of hazards, combined with the company’s leading risk methodology using qualitative and quantitative risk assessments.

The big question for shipowners is when, or if, to invest. They need to take a view on whether gas prices will justify the investment and whether, for their operational requirements, gas will be available where and when they need it. Securing supplies of gas for a fixed point trading

ship, such as a small ferry, is much easier right now than for deep sea ships trading worldwide.

Are certain ship types more likely to adopt gas as fuel? To date, most LNG as fuel applications are in the smaller ferry and offshore vessel sectors concentrated in the Baltic and Norwegian shelf, where local drivers, including the Norwegian Nox Fund, and ease of moving LNG by road support investment decisions and bunkering operations.

So far as the deep sea trades are concerned, Lloyd’s Register’s LNG bunkering study released last year concluded that containerships and cruise ships will be the most likely to adopt gas as fuel technology – if the price is right and bunkers are available.

Case studies: New gas fuelled ship projectsLloyd’s Register was right at the heart of some of the most significant gas as fuel newbuilding projects to date: the worlds’ first LNG fuelled tanker newbuilding, MT Argonon; Viking Grace at STX Finland; and the largest gas engined application under construction, the new LNG powered bulk carrier design, ‘Clean Sky’.

MT Argonon The world’s first new LNG-fuelled tanker was delivered in Rotterdam, the Netherlands, to Lloyd’s Register class at the end of 2011. The delivery of MT Argonon, a 6100 DWT dual-fuelled chemical tanker, represented a significant milestone for the Deen Shipping subsidiary, Argonon Shipping B.V., in its pursuit of cleaner transport solutions for Europe. Lloyd’s Register helped the owners and regulators to identify their risks, meet regulatory requirements and overcome the technical challenges for the precedent-setting tanker.

“This has been a great project and it is a significant first,” said Piet Mast, Lloyd’s Register’s Marine Business Manager for Western Europe. “The nature of inland waterways traffic,

which passes through or close to major population centres, makes LNG an attractive way to reduce harmful local emissions. We had to look carefully at the risks and worked closely with the owner and the regulators to ensure that they understood, and were comfortable with, the technical solutions that were developed.”

The dual-fuel system is designed to burn an 80/20 mixture of natural gas and diesel, reducing Sox, Nox and particulate-matter emissions, as well as reducing the greenhouse gas emissions from tank to flue. The LNG is stored in a transport tank located on deck, supplied by Cryonorm Projects, based near Amsterdam.

“The inland shipping industry, as far as we know, is the safest and

Table 1. LNG bunkering demand model (base, high and low case scenarios)

Factors Input assumptions

Base case High case -25% Low case +25%

Regulatory compliance

Emission control areas (ECAs)

Confirmed ECAs Confirmed ECAs plus speculative ECAs in 2018 (Japan, Singapore, Panama)

Confirmed ECAs

0.5% global sulfur date

2020 2020 2023

Newbuild demand Propensity to select LNG fuel from 2020

Increase propensity by 50%



Fuel prices HDO/MDO/MGO 2012 forecast

By year-on-year change in crude oil price

Same as base case Same as base case

LNG bunker price forecast 2012 – 2025

By HFO/Henry Hub gas prices (75%/ 25%) year-on-year change

Base case -25% Base case +25%

Figure 1. ‘Clean Sky’ design.

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cleanest mode of transport. But, to keep this lead, we have to take a big step forward in environmental performance,” said shipowner Gerard Deen. “I think that the dual-fuel principle is a way to reduce the emissions in our sector.”

Along with Lloyd’s Register, the Netherlands Shipping Inspectorate approved the vessel’s LNG system for operation in the Netherlands and the ship has taken on its first load of LNG bunker fuel. The next step is to secure the regulatory approvals from the Central Commission for Navigating on the Rhine and the UN-ECE ADN Safety Committee, to open the way for navigation beyond the Netherlands.

New generation VikingViking Line’s decision to order a 56 000 GT ice class passenger ferry, Viking Grace, was a real step up in scale for LNG-fuelled projects. There is nothing else either on the blocks or even ordered yet that comes close to the energy requirements of Viking Grace. Built to operate between Turku and Stockholm, the ship was floated out at STX Turku in August 2012, and will be delivered early in 2013 as Viking Line’s new flagship.

Lloyd’s Register’s role included helping owners and builders navigate a path through the complexity of a novel design to meet regulatory, class and operational requirements.

The ferry’s bunker tanks are located on the stern and propulsive power is from four Wärtsilä 8L50DF engines in a gas electric system that will deliver 30 400 MW. The ship will bunker at the Stadsgården facility in the port of Stockholm. The LNG will come from the AGA LNG terminal in Nynäshamn.

‘Clean Sky’ designA new LNG fuelled bulk carrier design, developed by COSCO Shipyard Group, Golden Union of Greece and Lloyd’s Register, was publicised in December 2012.

The ‘Clean Sky’ design Kamsarmax project moves the industry beyond the concept stage for gas powered bulk carriers.

Lloyd’s Register has provided approval in principle (AIP) for the new design incorporating an LNG as fuel system. COSCO, Golden Union and Lloyd’s Register started the project in June 2011 to investigate the potential to develop a commercially viable bulk carrier design based on an existing COSCO conventional design but employing gas powered propulsion systems.

The ‘Clean Sky’ design builds in flexibility by enabling owners to choose dual, or tri-fuel engines able to burn HFO or diesel as well as LNG.

To date, LNG-as-fuel research, technology development and newbuilding activities have focused on specific niche sectors such as ferries, offshore vessels and short sea, or inland, trades. This project paves the way for take-up in deep sea bulk carrier trades, and for tankers.

The LNG bunkering study

Will LNG be available as a fuel for ships – and where and when?Global acceptance of LNG as a marine fuel will depend on pricing, according to a comprehensive study conducted

by Lloyd’s Register, which aims to help clients draft plans for future emission compliance. The 12 month LNG survey looked at the main deep sea trade routes, the fuel consumption of vessels in the global fleet and the current and future location of bunkering. The study will also help to foster the future design and technology of propulsion systems in the global shipping industry.

The study found that competitive pricing could see widespread adoption and investment in LNG fuel technology by stakeholders in the deep sea trades.

The study’s findings have been turned into an interactive model on LNG bunker demand, that can be used to understand the likely future trajectory of LNG availability and demand as a marine fuel for deep sea ships.

Following rigorous testing and validation processes with key industry stakeholders, the dynamic LNG demand model was developed based on LNG supply, trade routes, ship-type fuel consumption, port locations and bunkering demand, as well as shipowner and port surveys. Three demand and price driven scenarios were then applied (Table 1).

Outside of the niche markets, the study found that the establishment of LNG bunkering infrastructure capable of supporting most of the world’s consumers will be highly sensitive to the price of LNG relative to alternative fuels.

The obstacles to the adoption of LNG as a marine fuel are practical factors, but they are not technical. Establishing safe, reliable global LNG bunkering capability is feasible, but it will require considerable investment and risk management, and it will have to cover significant operational costs to challenge existing fuel-oil delivery systems.

The LNG bunkering infrastructure study, released at Gastech 2012, also suggests some owners would be wise to consider fuel flexibility.

The study’s base-case scenario predicted that by 2025 there could be 653 deep sea, LNG-fuelled ships in service, consuming approximately 24 million t of LNG during 2012 – 2025. These ships are most likely to be containerships, cruise vessels or oil tankers.

When the study modelled relatively cheap LNG – for example, 25% lower than current market prices – the projected number of LNG-fuelled ships rose to approximately 1960 units in 2025. If the cost of LNG increased 25% against current prices, the model found that hardly any new LNG-powered tonnage would hit the water.

Excluding smaller ferries and local trades where there are local market, fiscal and regulatory drivers, such as in parts of the Baltic and Norwegian shelf, it was the container-ship and cruise-ship markets that were the most likely to adopt LNG. This is because of their relatively high energy requirements, the demands of customers in these two sectors, their regular trading patterns and the time those ships spend in emission-control areas.

The difficulty for those looking to make decisions is that forecasting energy prices has always been a dangerous business. For shipowners looking to make these decisions, flexibility may be the key. Choosing engines that can burn both gas and fuel oil, or that can be converted, may be one way to manage the regulatory and commercial issues involved with fuel choices.

LNG_MARAPR_2013_75-79.indd 78 21/03/2013 14:48

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Figure 1. Wärtsilä LNG regasification

technology onboard Höegh LNG’s shuttle regasification vessel

‘GDF Suez Cape Ann’ at Samsung Heavy Industries in South

Korea.

LNG_MARAPR_2013_80-85.indd 80 21/03/2013 14:55


While historically LNG has been stored in shore-based tank terminals, and then regasified and pressurised using vaporising equipment before being delivered to the distribution networks, this is no

longer always acceptable. With demand for LNG growing rapidly, the trend is increasingly towards faster and less expensive methods. One viable alternative is to place the regasification (regas) equipment onboard FSRUs (floating storage and regasification units) and SRVs (shuttle and regasification vessels). The high-pressure gas can then be delivered to land-based networks either via a floating buoy and submerged pipeline system from an offshore location, or via loading arms on the jetty. SRVs and FSRUs both offer flexible solutions with time-frames from investment decision to start-up that compare favourably with onshore regas facilities. Such solutions represent a fast-track

All aboard

The use of natural gas as an engine fuel has made huge strides during the past decade. Tore Lunde and Per Helge Madsen, Gas Solutions, Wärtsilä Ship Power, detail the multiple benefits offered by onboard regasification modules.

W

All aboard

LNG_MARAPR_2013_80-85.indd 81 25/03/2013 09:28


way of opening energy markets to natural gas, thereby increasing supply diversity, while reducing costs and offering notable environmental benefits.

Expanding LNG carrier functionality Typically, systems that use either steam or seawater for heating and regasifying the LNG are used. The choice of heating media usually depends on local regulations and the prevailing climate in the vessel’s operational location. Systems that use seawater as a source of heat to vaporise LNG are more economical than systems using steam. This is because a steam system requires the burning of fuel at a rate equivalent to some 2.5% of the amount of LNG produced. The energy requirement in a seawater based system is far less as energy is needed only for the pumps.

Heating with an intermediate fluid is utilised in both steam-based and seawater-based systems. A typical system installed on a conventional LNG carrier will have a total export capacity in the range 170 – 840 t/hr (200 – 1000 million ft3/d). Each train typically has an output of 40 – 210 t/hr, and complete systems comprise several trains with one or more providing redundant capacity. Delivery pressures are in the range of 30 – 130 bar and depend on the pressure in the receiving grid.

Dedicated pumps in the cargo tank supply LNG to the suction drum, usually at a pressure of approximately 5 bar, i.e. at a temperature below its boiling point at the current pressure. The suction drum acts as a buffer tank, and also as a gas separator to handle the gas and liquid returned from the regas trains during certain modes of operation. The pressure of 5 bar means that LNG is fed to the trains from the suction drum as a sub-cooled liquid. In the regas trains, the LNG is pressurised in multi-stage centrifugal pumps and then regasified in the vaporisers.

The output from each train is high-pressure (30 – 130 bar) natural gas.

Floating regasification solutionsWith six systems already delivered, and orders for four more currently being executed, Wärtsilä has supplied about half of the floating regas units now in operation around the world. Wärtsilä Oil & Gas Systems (formerly Hamworthy Oil & Gas Systems) began its development work in regasification technologies in 2006 with a test facility that was a joint investment project at Kollsnes in Norway with the Norwegian ship owner Höegh LNG. Both propane-based and steam-based regas solutions were successfully proven and demonstrated to potential customers from all over the world.

However, the adding of regas systems to LNG carriers (SRVs or FSRUs) presents a new set of challenges in terms of both equipment size and integration into the vessel’s existing systems. Furthermore, the equipment that was previously located on land must be redesigned to accommodate the unpredictable motion of a seagoing vessel.

The key to this has been a patented propane system that makes it possible to utilise compact plate heat exchangers. Furthermore, the use of latent heat in the evaporation condensation of propane is very efficient, thus allowing a lot of energy to be transferred without the need of bulky equipment.

The development of complete modules with few interconnection points has made integration far easier. Before, when units were supplied on skids, much interconnection work had to be carried out during installation, which was a time consuming and complicated business. Modules also reduce the time required for hook-up to the vessel or jetty.

To protect the multistage LNG pump bearings during sailing (when the pumps are not operating), the pumps have been modified so that it is possible to lower them to a fixed position inside the pumps’ suction pot. This modification is generally made especially for SRVs.

Steam-based systemsThe steam-heated regas system delivered by Wärtsilä for

the Neptune deepwater port project off the coast of Massachusetts, US, uses a water-glycol mixture as the intermediate medium. US Coastguard policy for the area meant that seawater could not be used as a source of heat. The Neptune project consists of two membrane-tank-type SRVs, an offshore terminal with two buoys, and pipelines to shore.

Both vessels are equipped with three regas trains located in front of the trunk behind a large wave breaker. The suction drum is located on the trunk deck close to the regas trains. Each regas train has a capacity of 210 t/hr of LNG and a target send-out

Figure 2. The regas modules supplied by Wärtsilä Oil and Gas Systems feature an uncomplicated vessel interface and rapid hook-up.

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LNG_MARAPR_2013_80-85.indd 83 21/03/2013 14:55


pressure of 46 – 120 bar. All three trains can be operated simultaneously if required.

The main benefit offered by steam-based systems is the fact that the equipment is relatively small. As the heating medium is at a high temperature, the heat exchangers are compact and the regas trains have a small footprint and low weight, making locating them easier.

The drawbacks with steam-based systems are both economic and environmental. From an economic perspective, if LNG is used to produce power for the trains and steam for the vaporisers, approximately 2.5 t of each 100 t of LNG processed will be used for these purposes. From an environmental perspective, even though LNG is a relatively clean power source, the CO2 emissions that result from onboard power and steam production are significant.

Seawater heating using propane as the intermediate mediumSeawater-heated regas systems that use propane as the intermediate medium have been supplied by Wärtsilä for two LNG vessels. Both are equipped with three regas trains, each with a processing capacity of approximately 230 t/hr. Two of the three trains can be operated simultaneously, providing a total capacity of some 460 t/hr.

The system onboard one of these vessels can deliver gas at pressures of up to 105 bar. However, the other vessel operates in Dubai, where the grid has a low maximum pressure. Since lower pump pressures save energy, the LNG pumps in the Dubai-based vessel were delivered de-staged with a delivery pressure of approximately 70 bar. As the

remainder of the regas system is designed to operate at up to 105 bar, the de-staged pumps can be replaced with full-pressure pumps if the vessel is relocated at a future date.

Customer benefits The modular regas units developed by Wärtsilä offer a simple and uncomplicated vessel interface, a small number of connections for rapid hook-up, a choice of heating sources (steam/seawater/combined), easy operation, and quick ramp-up/ramp-down.

Typical delivery times are 12 – 16 months. The compact equipment design has a small footprint, while the use of propane as the intermediate medium eliminates the possibility that the seawater employed will freeze during operation.

Future synergies As the use of natural gas as a fuel for energy plants continues to gain popularity as a result of both cost and environmental considerations, the opportunities for applying the latest regas technology are increasingly significant. For example, while the regas units supplied by Wärtsilä offer significant benefits as stand-alone systems, combining them with equipment supplied by the company’s power plants business allows ‘total scope’ technical and commercial solutions to be offered, for both onshore projects and offshore applications such as power barges.

It is not uncommon for new power plant projects to be contracted on a turnkey or EPC (engineering, procurement and construction) basis covering the whole terminal. Such contracts can also involve the supplying of gas for a pipeline system. In such cases, the regas equipment can be a part of

the total EPC contract. Also, as exhaust gases from the engines in a combustion engine power plant contain a lot of heat energy, this can be used in the regasification process.

In cases where all the heat required for regasification can be supplied from the exhaust gas, a simple direct ethylene glycol-based regas system using elements of the existing steam-based system is probably the best choice. In cases where the amount of heat that can be obtained from exhaust gases is insufficient, a propane-based solution using heat from other sources can be employed.

An EPC solution of this type could in fact constitute a complete combined gas importation terminal and power generation facility, comprising LNG storage tanks, an import jetty, Figure 3. LNG regasification system.

LNG_MARAPR_2013_80-85.indd 84 21/03/2013 14:55

boil-off gas (BOG) compressors, the regasification system, the piping, the power plant itself, and all the required automation and control facilities. Waste energy from the power plant would be used in the regasification system. The ability to deliver a total scope facility of this type and scale represents a competitive edge.

Recent developmentsIn first-generation propane-based systems, natural gas leaving the first propane-LNG heater is superheated in a shell-and-tube heat exchanger with seawater to provide the required heat.

As the natural gas is at high pressure, the heat exchangers have to be of fully-welded construction. Opening them up for cleaning and removing marine growth resulting from the use of seawater is, therefore, impossible.

In a new system patented by Wärtsilä Oil & Gas Systems, the propane passes through two stages. Propane in its liquid state is heated with seawater in a semi-welded plate heat exchanger, before being sent to a printed circuit heat exchanger (PCHE) that superheats the natural gas. Propane leaving the PCHE is then expanded through a pressure-control valve before being sent, in a similar way to that of first-generation propane systems, to the seawater-heated vaporisers that produce propane gas for the first-stage LNG-propane heater. All heating using seawater is therefore carried out using semi-welded plate heat exchangers that can be opened and cleaned on the seawater side to remove marine growth.

In conventional recondenser systems, the BOG is usually recovered by compressing it and sending it to the suction drum, where it is condensed by the use of internal contact with the LNG contained in the drum.

As the compressed BOG is typically at a temperature between 0 and -60 ˚C, cooling it to its condensing temperature and then condensing it adds significant quantities of energy to the LNG in the suction drum, and can raise it to saturation temperatures.

This problem has been addressed through the development of an improved and patented recondenser system. Here, the BOG is pre-cooled to the condensing temperature in printed heat exchangers (BOG coolers) on the high-pressure side of the regas system. As well as allowing significant quantities of heat to be passed to the high-pressure LNG that will be heated anyway, the total quantity of BOG that can be recondensed in the suction drum is approximately doubled since it now enters the drum at its condensing temperature.

Environmental sustainability aspectsThrough a combination of legislative steps and awareness issues that impact company image decisions, environmental sustainability is nowadays of such importance that it is frequently cited as being one of the main considerations in contract negotiations for new power plants. The growing use of natural gas as a fuel is, therefore, hardly surprising. Following Wärtsilä’s acquisition of Hamworthy plc in 2012, the research and development efforts of the two companies have been integrated, with current activities very much related to systems that support the LNG chain.

HOTWORK

LNG_MARAPR_2013_80-85.indd 85 21/03/2013 14:55

TRIZACH O L D I N G

M I D D L E E A S T

M I D D L E E A S T

LNG_MARAPR_2013_80-85.indd 86 22/03/2013 11:26


FLOATING FLEXIBILITYI n 2001, equipment to vaporise LNG was incorporated

into the design of an LNG vessel that would become referred to as a floating storage regasification unit

(FSRU). The purpose of the FSRU is to provide a platform to load LNG at a shore side facility, transport the LNG to another country or location and then regasify the LNG into a vapour, to be transferred into a pipeline grid for consumer or industrial use. The FSRU’s onboard regas system is outfitted with an arrangement of high pressure LNG pumps and corresponding vaporisers. The LNG is pumped from the cargo tanks to the high pressure pumps via a suction drum, through the vaporisers and discharged into a shore mounted connection that taps directly into local pipelines, eliminating the need for an expensive shore side regasification facility. An attractive alternative to a conventional land-based LNG regasification facility can be constructed in a fifth of the time and at a tenth of the cost.

Brooke E. King, Excelerate Energy, USA, discusses how floating regasification technology can provide flexibility in gas delivery.

Figure 1. Regasified LNG is offloaded from the FSRU by way of an HP gas arm.

LNG_MARAPR_2013_87-90.indd 87 21/03/2013 15:05


Pipeline connection alternativesOne popular method to connect the FSRU to gas transmission infrastructure is through dockside equipment that incorporates the offtake pipeline and a jetty-mounted, articulated, high-pressure gas-offloading arm to connect to an FSRU. This method is referred to as a GasPort® facility. The jetty will include all necessary mooring structure to safely berth the LNG regasification vessel. The regasification system will discharge the natural gas into the high pressure gas arm for delivery into the pipeline.

An alternative is delivery through a submerged turret loading (STL) buoy system terminal, which consists of a subsea buoy system moored offshore and linked to a subsea pipeline to shore by a flexible riser. This buoy system, referred to as a Gateway®, is used as both the mooring mechanism for the FSRU and as the conduit through which natural gas is delivered to the subsea pipeline. When an FSRU arrives at a Gateway, the subsea buoy is drawn into the hull of the vessel and locked in place. The regasified LNG then flows from the ship, through the buoy and riser, into the pipeline and onward to shore, where it is delivered to the local gas-pipeline distribution network. The STL system is designed to withstand natural disasters, and demonstrated its effectiveness to do so during Hurricane Katrina in 2005.

Whether the FSRU is moored at a jetty or STL buoy, the vessel can safely discharge regasified LNG with a great degree of flexibility and at considerable volume. The FSRU can deliver regasified LNG at pipeline pressure and flow rates ranging from 50 million ft3/d to over 800 million ft3/d, providing quick and convenient access to incremental gas supplies. The gas throughput capacity of the FSRU can be increased to meet the larger regasification needs of customers with the higher capacities presented by next generation FSRUs.

Ship-to-ship transferThe FSRUs utilise ship-to-ship (STS) transfer of LNG in order to optimise the availability of the regasification vessel. During STS, LNG is transferred between a laden LNG carrier to the FSRU at or near a market access location. STS transfer can be done between LNG and FSRU vessels for cargo transfer or gas-in and containment cool-down. The STS feature can save time and money, whilst easing berth constraints at traditional LNG load port facilities. When utilising a supply vessel to shuttle LNG cargo, STS can be performed at a GasPort or Gateway for uninterrupted regasification service to the consumer. STS can be accomplished alongside a jetty using cryogenic hard-arms, or by double banking while utilising a system of flexible cryogenic hoses. Excelerate Energy developed and implemented the commercialisation of STS and has successfully accomplished over 300 STS operations through the beginning of 2013.

Onboard regasification systemsThe main components of the onboard regasification system are the LNG feed pumps located in the cargo tanks, high-pressure (HP) LNG pumps, shell-and-tube vaporisers, and heating water circulating pumps. During the onboard regas process, LNG stored in the cargo tanks of the FSRU is fed to the suction drum. The suction drum contains the LNG prior to vaporisation and is used to buffer the HP LNG pump suction. The suction drum can also be used to vent and depressurise the regas system. The HP pumps draw LNG from the suction drum and send it to the shell-and-tube vaporisers. An HP LNG pump is a 13-stage centrifugal pump which typically operates at 100 bar discharge pressure. All of Excelerate’s regas vessels are outfitted with six vaporisers; for nominal output, five are online with one in reserve. The vaporisers are a shell and

Figure 2. A ship-to-ship transfer of LNG underway at GNL Escobar. More than one hundred such operations have been successfully completed at GNL Escobar, thus far.

LNG_MARAPR_2013_87-90.indd 88 21/03/2013 15:05

Intergraph, the Intergraph logo, and SmartMarine are registered trademarks of Intergraph Corp. or its subsidiaries in the United States and in other countries. ©2013 Intergraph Corporation. 02/13

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tube-type heat exchanger, adopted to reduce any adverse effect due to the vessel’s motion. Compared to land-based vaporisers, those onboard an FSRU are much more compact. They have been designed to use seawater as the heat exchanger medium. The heating water is drawn from the ballast system, boosted by the booster pumps located in the forward area, and then delivered to the vaporisers. The seawater is an effective means of heat displacement; for a 1 ˚C rise in LNG, the seawater is cooled 0.025 ˚C. To regas LNG from -163 ˚C to 7 ˚C, an equivalent amount of seawater would only be chilled by 4.25 ˚C. The onboard regasification system can be used in one of three different modes, depending on sea water temperature, location and other variables:

Closed-loop mode – steam from the FSRU main and auxiliary boilers is used to heat fresh water circulated through the shell-and-tube vaporisers in the regasification plant. This results in minimal usage of seawater by the FSRU. This method of vaporisation is ideal in areas with sensitive marine wildlife and/or seawater temperatures lower than 5.5 ˚C.

Open-loop mode – relatively warm seawater is drawn in through the FSRU’s sea chests. This warm seawater is used as a heat source and passed through the shell of the shell-and-tube vaporisers, causing the vaporisation of the LNG. During this process, the temperature of the seawater is lowered by approximately 7 ˚C. For this reason, the open-loop mode is not applicable for water temperatures below 7 ˚C.

Combined mode – seawater at temperatures between 7 ˚C and 14.5 ˚C can be used when heated by steam from the FSRU boilers to provide sufficient heat for the vaporisation of the LNG.

The maximum rate of discharge of the natural gas from an FSRU will be determined by a combination of the availability of capacity on downstream pipelines and the regasification capabilities of the facilities located onboard each FSRU.

Regas vesselsCurrently, Excelerate operates a fleet of eight purpose built FSRUs, three with an LNG cargo capacity of 138 000 m3 and five with a capacity of 150 900 m3. Its ninth FSRU is scheduled to be completed in May 2014. The newest of its fleet, it will have the largest LNG capacity in the industry for a regasification vessel at 173 400 m3, and the highest nominal regasification capability at 800 million ft3/d. This vessel is set-up with a capacity of of 1.2 billion ft3/d if called upon to do so. The newest FSRU is purpose built for a customer whose energy needs demand a consistently high output. Until the new vessel is completed, an existing 150 900 m3 vessel, the Exquisite, has been equipped with new, larger HP LNG pumps and regas vaporisers, which have increased its peak output to 700 million ft3/d. This particular ‘bridging vessel’ is operated in the open-loop mode.

Excelerate Energy’s shipping fleet is also one of the most environmentally friendly in operation.

State-of-the-art emissions control systems reduce NOx emissions from the boilers by more than 90% when the vessel is in gas-only operations. In addition, the vessels are fitted with a proprietary heat-recovery system that reduces the amount of seawater used in normal operation by 98%, reduces regasification fuel consumption by 10%, and reduces overall fuel consumption by 16%.

On the riseThe demand for vessels with regas capability is on the rise with “developers of 44% of the 108 developmental import terminals tracked by Zeus aim to use floating regas ships instead of conventional onshore terminals.”1 This concept of deepwater ports to unload regas was proven at the company’s Gulf Gateway in 2005. The company has an active deepwater port facility, Northeast Gateway, with two STL buoys 13 miles off the coast of Massachusetts.

The futureWith the demand for regasification vessels on the rise, the economies of scale demand larger capacity vessels. Several companies, including Excelerate Energy, are building new larger capacity vessels. The company is also working on the design of floating liquefaction storage and offloading vessels (FLSO). These FLSOs are the next frontier in linking cost effective and reliable natural gas production to global market access points.

Energy Bridge® is the propriety offshore LNG regasification and delivery system developed by Excelerate. This system involves the use of the purpose-built FSRUs for the transportation and vaporisation of LNG through specially designed offshore and near shore receiving facilities. Energy Bridge is a combination of proven technology and equipment in a new application that represents an innovative step forward in LNG industry technology.

References1. http://www.zeusintel.com/ChartoftheWeek/20120918.aspx

2. Lee, J.H., Janssens, P., and Cook, J., ‘LNG Regasification Vessel – The First Offshore LNG Facility’, OTC 17161, Offshore Technology Conference 2005.

Figure 3. STL buoy being prepared to be deployed at the Northeast Gateway® deepwater port.

LNG_MARAPR_2013_87-90.indd 90 21/03/2013 15:05

LNG tankers are ocean-going vessels and require a water depth of around 15 m for docking and sailing. Loading/

unloading LNG requires a transfer system extending from storage tanks onshore to a jetty head where a LNG vessel is docked. Traditionally, loading/unloading is through LNG transfer pipelines that are supported above the sea level. With a maintainable navigation channel or a steep shoreline, a designated port is often built. Otherwise, a jetty or trestle is typically selected to reach a suitable water depth. In either jetty or port designs, traditional LNG piping is supported above the sea level. LNG transfer pipelines below the seabed have also been developed and at a few existing terminals, LNG pipelines have been placed inside a large tunnel. Directly buried pipelines have also

Jack X. Liu, Liu Advanced Engineering

LLC, USA, examines the

relative merits of different

LNG transfer systems.

LNG_MARAPR_2013_91-96.indd 91 21/03/2013 15:11


been proposed and a pipe-in-pipe inside a small tunnel with roller supports has recently been developed.

This article focuses on the LNG transfer systems that are either used or proposed. Comparisons are made in terms of basic features, costs, accessability and most importantly risks associated with earthquakes and tsunamis, storm surges and high tides, as well as third-party damage. Finally, the article discusses technology breakthroughs in LNG transfer including cryogenic hoses, highly efficient insulation, and automatic vapour/heat removal.

Existing and proposed systems

Piping above sea levelTrestles or jetties have been used to support LNG piping for over four decades. They keep the piping away from the reach of ocean waves and corrosive sea water. LNG piping is typically made of stainless steel, a thick layer of polyisocyanurate (PIR) for insulation, and metallic cladding as a moisture barrier. In an effort to minimise maintenance and heat transfer, polymer barriers and vacuum insulated pipes have started to gain acceptance.1, 2

At ambient pressures, the temperature of LNG is around -162 ˚C, above which vaporisation begins. Expansion loops are widely used to accommodate thermal expansion/contraction. At some terminals,

bellows are used instead of expansion loops. Typically, an access road is provided along the piping on the trestle/jetty. The advantage of the existing system is the easy access for inspection, maintenance and repair.

Historically, this type of system has performed quite well, however, it does face challenges. For example, the 11 March 2011 earthquake in Japan generated a 9 – 14 m high tsunami along the north-east coast. The Sendai LNG terminal was seriously damaged and almost all of its port facilities were destroyed or permanently disabled because of flooding, except for its 0.08 million m3 LNG underground storage tank. It took 14 months to fully recover from the aftermath.3 The Sendai LNG terminal has a port and a short transfer distance. If the piping were on trestle, the damage would have been much worse because of debris flows.

Severe weather conditions also threaten a system on a trestle. For example, Gorgon LNG has had to alter its original plans and build 56 large size caissons (26 m in diameter) to support the 2 km long trestle due to high tides.4

Pipelines inside a large tunnelTwo receiving terminals have transfer pipelines inside large tunnels. The first one is at Cove Point in Maryland, US. The terminal was built in 1976 and is currently owned by Dominion. The Cove Point tunnel has a rectangular shape with a width of 8.4 m and a height of 4.9 m. Bellows are used in the pipelines for thermal expansion and contraction.5 The second one is at Ohgishima, Yokohama, Japan and was built in 1998. The Ohgishima tunnel has a cylindrical shape with an internal diameter of 7.2 m that is required to host expansion loops.6 The purpose of laying LNG pipelines underground inside this tunnel is to avoid a trestle that would interfere with a shipping channel.

A large tunnel provides strong protection against third-party damage, a water barrier and access to crew and construction equipment. However, no other terminals use this type of large tunnel because of its high cost.

Directly buried pipe-in-pipeA few subsea pipeline systems have recently been proposed with a pipe-in-pipe configuration and direct burial.7-10 A pipe-in-pipe configuration typically comprises an inner pipe for cryogenic fluids, an outer pipe for protection and support, and insulation material in the annulus between the inner and outer pipes. Figure 1 shows a pipe-in-pipe configuration.

With both ends fixed, the thermal stress in a transfer line has to be dealt with in the inner pipe alone. There are two ways to deal with the thermal expansion: bellows can be placed at certain intervals in the inner pipe, or low thermal expansion material such as 36% nickel steel (i.e., invar) can be used for the inner pipe. In this comparison, invar is selected for the inner pipe.

A buried LNG pipeline is straightforward and cost effective. However, the major concern is water leakage or LNG leakage that could jeopardise the whole system. Due to lack of access, a total replacement may be necessary in the case of the leakage.Figure 2. Roller supported pipeline inside a small tunnel.

Figure 1. Pipe-in-pipe configuration.

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LNG_MARAPR_2013_91-96.indd 93 21/03/2013 15:11


Roller supported pipe-in-pipe inside a small tunnelA retrievable subsea pipe-in-pipe system has been developed with a small tunnel (e.g. a reinforced concrete conduit) to host one or two transfer pipelines. Figure 2 shows the cross-section of a transfer pipeline inside a small tunnel. The small tunnel extends from onshore to a loading shaft. Stationary rollers are anchored at the internal bottom of the small tunnel and used to support the transfer pipeline. These rollers also serve as a means for pulling the pipeline in or out. At the offshore end, a vertical shaft extends from the seabed up to above sea level and hosts a riser. The subsea pipeline is detachable from the riser and can be pulled out for repair.

The system has strong protection and is also cost effective. Moreover, with a free end offshore, the thermal contraction (tension) in the inner pipe is shared by compression in the outer pipe. The pipe stresses are reduced by approximately 50% with some end displacement. This arrangement allows nickel enriched steel such as 9% nickel steel to be used for the inner pipe without any bellows or expansion loops.

Comparison among systemsThe four transfer systems discussed above are distinctive. Their key features and costs are listed in Table 1. The existing systems (either on trestle or inside a large tunnel) are costly and require maintenance.

Table 2 lists the common risks, accessibility and failure consequence for the four systems. The common risks to an LNG transfer system are categorised in three groups:

UV light/ageing and ambient temperature changes caused by sunlight.

Ocean waves, storm surges/tsunamis, and high tides.

Third party damage, including intentional and unintentional.

A risk-level is given based on a scale of 1 to 10, with 10 the highest level. The likelihood to failure is the summation of the numbers above (i.e., overall risk). The failure consequence here is defined as the likelihood to failure

divided by accessibility, and then normalised by the minimum value.

As listed in Table 2, the systems inside a tunnel (either large or small) seem to have the least consequence when subjected to environmental and accidental loads.

Technology breakthroughs for LNG transfer

Flexible loading armsConventional loading arms are made of rigid pipes and swivel joints. With a supporting frame and balancing weight, a loading arm is heavily weighted and costly. The swivel joints may have leakage potential and require maintenance and replacement of seals. On the other hand, flexible loading arms offer simple connection with LNG tankers, and are flexible enough to cope with any tanker motions.11 The flexible loading arms use cryogenic hoses that typically consist of multiple layers of polyester fabric and polymeric film, as well as inner and outer spiral wound stainless steel wires. The outer wire provides hoop strength and prevents bursting of the film under internal pressure, while the inner wire prevents the film from collapse. Flexible cryogenic hoses have been tested and used for ship-to-ship transfer.

Highly efficient insulationA widely used thermal insulation material is polyisocyanurate (PIR) with a thermal conductivity of 0.023 W/mk. This material is permeable to water vapour and requires a moisture barrier, such as metallic cladding. Under repeated extremes of temperature, some seals in the cladding are likely to break loose, resulting in moisture setting in. Maintenance is needed for the insulation system.

Silica-based micro/nanoporous panels or blankets have been developed for insulation. They include izoflex, aerogel and nanogel with a thermal conductivity of about 0.01 W/mk. For the same insulation capacity, the thickness of the insulation layer can be reduced by over 60% compared to PIR. With a pipe-in-pipe configuration, the conventional vacuum technique has a thermal conductivity of less than 0.01 W/mk. A combination of

the new material and vacuum in the annulus has a long-term performance with exceptional low thermal conductivity.

Automatic vapour removal Typically, loading/unloading an LNG tanker takes about 12 hours and unloading frequency is around twice per week. In order to avoid repeated heating/cooling, which leads to early failure of a transfer system, it is necessary to keep the system at cryogenic temperatures during idle periods. A conventional

Table 1. Basic features and costs

Trestle Large tunnel Small tunnel with rollers

Direct burial

Material for inner pipe

Stainless steel Stainless steel Nickel steel Invar (36% nickel steel)

Configuration Single pipe Single pipe Pipe-in-pipe Pipe-in-pipe

Insulation PIR PIR Silicon based material/vacuum

Silicon based material/vacuum

Insulation protection

Metal cladding or polymer

Metal cladding or polymer

Outer pipe and tunnel

Outer pipe

Thermal stress reduced by

Expansion loops/bellows

Expansion loops/bellows

End pipe displacement

Low expansion material

Maintenance Yes Yes No No

Cost (rank) 3 4 2 1

LNG_MARAPR_2013_91-96.indd 94 21/03/2013 15:11

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Specialists in the design, design review, plan approval and construction, commissioning and survey of LNG Carriers, LPG Carriers, Oil Tankers, Oil Product Tankers, Chemical Carriers and vessels carrying bulk cargoes. The Offshore Group specialize in Dynamic Positioning, Failure Mode and Effect Analyses, GAP analyses and ASOGs

Mechanical, Electrical, Chemical and Civil Engineers

Specialists in LNG export/import terminals, Liquefaction, Regasification, LNG redistribution and CNG/LNG Fueling Projects.

UK Office:Fullbridge Mill, FullbridgeMaldon, Essex, CM9 4LETelephone: +44 (0) 1621 840447Fax: +44 1621 840457General Email: [email protected]: www.wavespec.com

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LNG_MARAPR_2013_91-96.indd 95 21/03/2013 15:11


method is to circulate LNG with pumps through two LNG lines that form a loop.

A loading shaft is typically located at 15 m deep water while onshore tanks are located above the sea level. An automatic vapour removal system has been developed based on this elevation difference and highly efficient insulation. With a high end at onshore tanks and a low end at the bottom of the loading shaft, cryogenic liquids flow down by gravity and boil-off gas (BOG) flows towards the high end. With a small amount of LNG being fed at the high end, this system is kept at cryogenic temperatures.

This proprietary system eliminates the need for a re-circulation line and pressurised circulation of LNG in which pumping accounts for more than half of the BOG during idle periods. When using a 30 in. pipeline in place of two 24 in. pipelines, the amount of LNG vaporised during the idle periods is reduced by 80%.

Relaxing LNG transfer systemCombining the pipe-in-pipe inside a small tunnel with roller supports, flexible loading arms, and automatic vapour removal technique, a proprietary relaxing LNG transfer system has been developed.12 Figure 3 shows a flow diagram for this LNG transfer system during idle periods. The transfer pipeline has a high end onshore and a low end offshore. At the high end, there is a tee with an upward port for the exit of vapour and a lower port fluidly connected to a small LNG feeding line.

The transfer pipeline is anchored onshore with the offshore end free to expand/contract. Flexible hoses extend from the free end to a storing seat above sea level. During loading/unloading, the flexible hoses are stretched out and connected to a ship manifold. The flexible hoses accommodate both pipe end displacements and vessel motions.

The relaxing system has a double containment transfer line, self-balanced thermal forces between inner and casing pipes. It reduces CAPEX and OPEX, and minimises maintenance.

ConclusionA conventional LNG transfer system on trestle is proven to be satisfactory in general, but starts to face challenges resulting from tsunamis and high tides. Among the systems discussed, the subsea pipeline inside a small tunnel seems to be favourable in terms of both cost and safety. Technology breakthroughs in insulation, cryogenic hose, and automatic vapour removal warrant a fail-safe and cost effective solution for LNG transfer. The relaxing LNG transfer system offers a viable option, especially for sites that are prone to natural disasters and third party damage.

References1. Smallwood, N., ‘Advanced Cladding and Pre-insulation

Systems,’ LNG Industry, pp. 62 – 66, Autumn 2009.

2. Curtis, J., ‘Vacuum-Insulated Pipe Vs. Conventional Foam-Insulated Pipe,’ OTC 18701, 2007.

3. Takai, N. et al, ‘What Happened during and after First Quake and Tsunami Impact on Japanese Terminal,’ LNG Journal, pp. 19 – 20, July/August 2012.

4. News Index, Leighton, LNG Journal, p. 13, July/August 2012.

5. P&GJ Staff Report, ‘6000-ft Tunnel, LNG Unloading’, Pipeline and Gas Journal, June 1975.

6. Maekawa, K. ‘A 21st Century LNG Terminal’, Civil Engineering (Journal), Japan Society of Civil Engineers, Vol. 36, 1997.

7. Rankin, R. and Mick, M.B., ‘Buried, Subsea Line Advanced as LNG Alternative,’ Oil & Gas Journal, 14 November 2005.

8. Beike, D., Gibbons, F., and Stokes, E., ‘Subsea Cryogenic Pipeline-Defining the Next Generation for LNG Loading: Analysis of New Technology vs. Conventional Trestle System,’ OTC 20302, 2009.

9. Prescott, C.N., and Zhang, J., ‘Managing Construction and Stress in an Ambient Pressure Insulated 9% Ni Subsea Cryogenic Pipelines’, OTC 19824, 2009.

10. Cox, P., and Risi, R., ‘How the use of Cryogenic Piping can Reduce the Impact of LNG Transfer Terminals on Environment and Local Communities, While Increasing Site Safety and Security’, OTC 20223, 2009.

11. Rombaut, G., Peigne, A., Loisel, P., Cloirec, A., Machouat, F., and Maocec, D., ‘LNG Trials of a New 16’ Flexible Hose Based LNG Transfer System’, OTC 19405, 2008.

12. LAE, ‘Relaxing LNG Transfer System between Ship and Shore,’ http://www.laengr.com/LNG Transfer.htm.

Figure 3. Flow diagram of a relaxing LNG transfer system.

Table 2. Risk and consequence

Trestle Large tunnel Small tunnel with rollers

Direct burial

UV lights/ageing High (10) Low (1) Low (1) Low (2)High tide/waves, etc.

High (10) Low (1) Low (1) Low (2)

Third party damage

High (10) Low (1) Low(1) Moderate (5)

Likelihood to failure

30 3 3 9

Accessibility Easy (10) Reachable (8) Retrievable (4) None (1)Consequence 8 1 2 24

A risk level is given based on a scale of 1 to 10, with 10 the highest level.

LNG_MARAPR_2013_91-96.indd 96 21/03/2013 15:11


Analysing the weakest linkShane Hale, Emerson Process Management, Rosemount Analytical, USA, addresses the challenge of LNG analysis with gas chromatography technology.

The use of gas chromatography as an analysis tool in the measurement and reporting of

LNG composition is both an industry standard and a unique challenge. The extremely low temperature of LNG and the problems with keeping

it in liquid form make sample handling complex, and the batch handling nature of the operation complicates reporting. The characteristics of the sample handling system and the chromatography capabilities should be designed specifically for LNG operations. The operator needs to be informed and

LNG_MARAPR_2013_97-100.indd 97 21/03/2013 15:16


make careful decisions to ensure accuracy and long-term operational efficiency, while also avoiding costly disputes between the various stakeholders in the LNG fiscal transactions.

Sample handling – the weakest linkThe accuracy and reliability of LNG measurement is critical since the ship loading and unloading operations are highly time-sensitive and there are no second chances. The cost of keeping a ship in port is astronomical and delays due to measurement issues are unacceptable. Failures in a poorly designed or maintained sample handling system can result in inaccurate analysis and even damage to the measurement technology. An easy way to determine if the sample system is operating correctly is to look at the stability of the measurement.

The composition of the LNG at the ship-loading arms is usually very stable and the analysis results should show this. In loading operations, the composition from a single tank should be stable and large changes in composition should only occur if the source of the LNG changes. In offloading operations, the LNG in the ship’s tanks should be consistent and the composition change will be slight over the unloading operation as the pressure in the ship tanks decrease and the lower ends in the LNG boil off. However, if the composition reported by the gas chromatograph (GC) changes significantly from one analysis cycle to the next, it indicates that the vaporisation of the sample is not consistent and the analysis will not match the actual flowing LNG composition.

In order for the sample handling system to deliver an appropriate sample to the GC, the LNG must remain liquid up to the point of vaporisation and must then be vaporised uniformly into a single-phase vapour state. To reach this single-phase state, the sample must first go through a two-phase region in the sample handling system (Figures 1 and 2). If the sample is transported while in the two-phase region, the different velocities of the liquid and gas phases will cause the entire sample to change composition once it reaches the single-phase vapour state. If the LNG starts to vaporise in the sample lines, the nitrogen and methane will boil off first and produce pockets of gas in the liquid stream that reach the vaporiser at different times, resulting in varying compositions. The LNG sample reaching the vaporiser will consist of an unrepresentative liquid sample rich in the heavier components, as well as slugs of methane-rich vapour. The vapour sample leaving the vaporiser will be inconsistent, with dramatic variations in composition. This Figure 1. LNG phase diagram.

Figure 2. Example of LNG sample handling system.

LNG_MARAPR_2013_97-100.indd 98 21/03/2013 15:16

faulty sample then goes into the GC and sample cylinders, and produces an incorrect analysis.

Using an accumulator to reconstitute the sample immediately after the vaporiser can help address some of these challenges, but it can only correct for small fluctuations. If there is substantial vaporisation in the sample lines, then large slugs of gas can actually insulate the vaporiser from the LNG, once again resulting in the sampled gas being unrepresentative of the actual flowing stream. Most modern installations use vacuum-jacketed tubing from the sample probe to the vaporiser, which is located within 7 ft (2 m) of the sample point to ensure the sample remains in the liquid phase right up to the vaporiser.

Once the sample enters the vaporiser, there are additional challenges to overcome. When the LNG sample enters the vaporiser as a pure liquid, sufficient heat must be added to the liquid sample to allow for over 600-to-1 expansion from the liquid phase to the gas phase, without causing sample fractionation. Recent advances in vaporiser design help address these issues. Traditional ‘water bath’ vaporisers are losing favour since they exacerbate the gas pocket formation and are relatively high maintenance. Vaporising regulators are common in the process industry and attempt to perform both the sample vaporising and pressure regulation functions. However, they lack both the heating capacity and volume expansion allowances required to do either

job well for LNG, resulting in inconsistent vaporisation and selective fractionation of the sample. The more effective approach is to separate the vaporisation process from the gas pressure regulation function. The best performing vaporisers are designed specifically for LNG and flash a small liquid sample off quickly, providing very little restriction and allowing the sample to expand over 600 times in volume. The outlet temperature of the vaporiser should be monitored to prevent liquid carryover in order to ensure proper operation. The sample enters the accumulator after it is vaporised, and is then pressure-controlled and sent for analysis to the GC.

GCs designed for LNGWhen it comes to the measurement of LNG, the LNG operator needs to be aware of specific GC capabilities that will enhance accuracy and reduce operating costs. LNG composition is similar to natural gas, but has unique properties as a result of the process requirements involved in chilling the feed gas to the low temperatures necessary for LNG production. In pipeline gas, the CO2 levels are often controlled to just under 2% by the producers as this is the common tariff limit. However, the CO2 content in LNG is typically less than 50 ppm in LNG streams and must be kept this low to prevent solids from forming during liquefaction. The GC must be capable of accurately measuring the CO2 at these low levels and

FBM Hudson Italiana, established in 1941, is a worldwide leading manufacturer of Process Equipment for the Oil & Gas and Petrochemical sectors. Spe-cialising in the research, design and manufacture of Air Cooled HE -Steam Condensers -Shell & Tube HE -HPHE Urea/Ammonia –Process Gas Waste Heat Boilers -Special Tubular Reactors.FBM Hudson Italiana hold proven and trusted experience and, in the perspective of the ever growing global demand for LNG, have developed a new modular concept in particular for Air Cooled HE.FBM Hudson Italiana boasts its position as a leader in thermal design thanks to the optimisation of fans’ air side performance (i.e. different blades, linear or twisted blades, etc.) along with the optimisation and integration of steel structures, strictly in compliance with clients’ specific requirements.The long construction time, as well as the high cost and/or limited availability of manpower at site, have prompted the introduction of pre-assembled units to the market as a way to significantly reduce the timing and logistics of plant installation.Our extensive experience in this area allows us to tailor-make equipment according to clients’ specific objectives and by studying enhanced and innovative solutions. This involvement has led us to improving performance in the evolution of modularisation, which aims at obtaining bigger and bigger modules by

extending the inclusion of pre-assembled components.Therefore, not only the AFC modules alone, but also piping, instrumentation and electrical wiring can now be considered as a whole, unique pre-assem-bled module.FBM Hudson Italiana, working closely with major EPCs, has met the chal-lenge in moving to world-class projects, using advanced technology to power an “off the shelf” design & technology modularisation concept.This new concept leads to faster construction and faster LNG to market, while also maximising field construction by fostering a “plug and play” solution.Moreover this enhanced concept facilitates the incorporation of additional “perfect-fit” modular LNG trains to add capacity to an existing LNG facility to suit gas field needs.

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should have a lower detectable limit (LDL) of better than 25 ppm.

All design characteristics of a GC used for LNG measurement should be ruggedised for a marine environment as the GC is usually located on the dock close to the loading arms. In this environment, it is critical that the analyser can hold up to the demanding salt-laden environment while taking up as little space on the dock as possible.

GCs used for LNG analysis should have an analysis repeatability of at least +/- 0.25 BTU per 1000 BTU (0.025% of energy value) to ensure accurate fiscal accounting. To reach this level of performance, some GCs are required to be housed in a temperature-controlled analyser shelter; however, this significantly increases costs, utility requirements and installation footprint. Alternatively, some GCs can operate at this level of performance across an extended temperature range (typically 0 ˚F – 130 ˚F/-17 ˚C – 55 ˚C) requiring very little protection from the elements (such as a sun-shield or three-sided shelter), which results in a much smaller installation footprint and lower utility and installation costs. As a result of the critical nature of the LNG custody transfer measurement, the end-user should require the manufacturer to demonstrate the repeatability of the unit purchased throughout the extended temperature range of the instrument.

The software criteriaAnalysis, reporting and communication software for LNG gas chromatography systems must be specifically designed for the application. GC software for laboratory applications is too complex for most non-expert GC users found in the field. The software for the online LNG GC should be simple and intuitive for the plant technicians and engineers to use effectively.

Unlike pipeline or process gas chromatographs that run 24/7, GCs used for LNG ship loading and unloading will only be run while the ship is in the dock. On a pipeline, an operator can calibrate and start the system locally since it will run continuously for long periods of

time. For LNG custody transfer applications, the GC should be calibrated immediately prior to the ship loading, the analysis cycle started at the beginning of the loading/unloading operation and stopped at the end of the load, and the calibration validated after the load. To improve efficiency and save operator time, it is important that the GC can be remotely calibrated, started, stopped and validated from the control room. This means that the LNG GC must be able to communicate and provide the control mechanisms to host devices such as flow computers, SCADA systems and distributive control systems (DCS). The Modbus serial communication protocol is most commonly used over either serial or Ethernet communication links, because of the high number of values GCs report. A recent development is the use of Foundation Fieldbus for connection to the DCS for better interoperability with plant-wide diagnostic monitoring software with virtually no customisation. Whatever the protocol for host system communication, additional provision should be made to allow remote diagnostics for the GC-specific diagnostic software. Such capability allows highly trained personnel to analyse, diagnose and maintain multiple devices from a central location, often off-site. Reporting software must also be very specific to LNG requirements and provide the batch load averaging functions and LNG specific calculations required by the custody transfer contracts.

Analysing the analysersThe measurement and reporting of the composition and energy values has a significant impact on the fiscal performance of LNG operations. Therefore, no operator can afford to take short-cuts or use incorrectly designed systems for the analysis of the LNG. While often considerably more expensive than pipeline natural gas custody transfer systems, the up-front investment in the specialised LNG sample vaporisers and the LNG GC reporting systems will be quickly returned in the form of accurate and trouble-free analysis and reporting that avoids disputes over the value or quality of the LNG transferred.

Table 1. Typical compositions of LNG

Example A Example B Example C Example D Example E Example F

Methane 94.73% 92.3% 86.53% 89.94% 88.33% 91.8%

Ethane 3.8% 7.5% 12% 6% 6% 6%

Propane 1.17% 0.2% 1.33% 3% 4.3% 1.4%

iso-Butane 0.3% 0.06% 0.53% 0.5% 0.4%

n-Butane 0.08% 0.53% 0.5% 0.4%

iso-Pentane 0.37%

BTU 1063 1070 1124 1125 1154 1095

Wobbe index 1387 1391 1420 1420 1436 1404

LNG_MARAPR_2013_97-100.indd 100 25/03/2013 09:28


Go with the flowMike Williams,

Invensys Operations

Management, USA, describes

the company’s partnership with

Veris Inc. to develop and implement

advanced flow measurements.

The natural gas industry involves a complex network of production, distribution and delivery to meet the growing global demand for more than 100 trillion ft3/year. Of the many procedures involved in supplying this natural resource, flow measurement is a constant concern. From

the producer to the consumer, accurate flow measurement is the keystone for delivery and product accountability.

The true test of a flow measurement device is its ability to repeat its published flow coefficient within its accuracy band. Maintaining accurate flow measurements at the extremes of both high and low flow rates is a significant challenge for the energy industry with enormous financial stakes. Partnerships across industry players are crucial to developing solutions that meet this challenge.

LNG_MARAPR_2013_101-104.indd 101 21/03/2013 15:39


Demanding flow ratesHeadquartered in Niwot, Colorado, US, Veris Inc. manufactures and inventories more than 95% of the parts to assemble its primary product line, the Verabar averaging pitot flow sensor. With its solid one-piece construction and bullet shape, the Verabar makes flow measurement clog-free and precise. The solution’s sensor shape is designed to reduce drag and flow induced vibration. The location of the low pressure ports also eliminates the potential for clogging and improves signal stability.

With the development of a verified theoretical model that predicts the Verabar flow coefficients, costly calibration tests are avoided with increased flow certainty. Some of its features include:

Built-in valves in the head of the instrument for simplified installation and maintenance.

High accuracy (to 75%) and repeatability (1%) verified at independent NIST traceable flow laboratories.

Velocity averaging – higher accuracy and less straight-run required.

Superior non-clog sensor design.

The aerodynamic bullet shape is less susceptible to flow induced vibration and signal noise.

Installation and operating costs are lower.

The company’s latest innovation is the Accelabar® flow meter, which combines Verabar technology with Invensys Foxboro differential pressure transmitters to produce excellent operating ranges. A single Accelabar can monitor the entire range of flow rates in applications that previously required multiple meters. It is capable of generating high differential pressures for measuring gas, liquids and steam with no straight run requirements. The Accelabar flow meter was designed to:

Have the ability to be installed anywhere in existing piping systems without the costly requirement of additional straight lengths of piping.

Work effectively for energy management applications requiring wide rangeability based on seasonal usage of steam, natural gas and chilled water.

Be ideal for skid mounted installations where space is limited.

Require no maintenance or calibration requirements when combined with a Foxboro DP transmitter.

Be capable of measuring mass or volumetric flow of gas, liquids or steam.

Case studyA Veris customer in Minnesota, US, faced the ever-present challenge of achieving cost savings and improving operational efficiencies at its LNG storage facility. There, temperatures regularly stay well below freezing in winter, which can complicate regular operations. Extremely hot summers make the surrounding environment equally difficult to sustain consistent temperatures and pressures.

The company stores LNG in two 12 million gal. tanks and uses gas-fired heaters to vaporise it as required to meet customer demand. For most of the year demand is low. However, during the coldest winter months gas consumption jumps from 1000 to 60 000 standard ft3/hr, representing an enormous flow rate change (a turndown ratio of 60:1).

The plant had attempted to measure this flow rate with a turbine meter sized for the maximum flow rate, but could not get accurate flow readings at the low end of the measurement range. This makes it impossible to determine actual usage during the off-peak periods. In addition to accuracy limitations, turbine meters have moving parts that wear and require expensive maintenance. When deciding on the best possible solution, given the unique conditions and requirements, the plant operators carried out due diligence and analysed all possible options.

One such option was using a differential pressure (DP) transmitter with an orifice plate – a flow measurement method commonly used in the gas industry. But given the wide span of flow rates, a single meter could not accurately measure the high and low extremes. Use of multiple meters proved too costly with the required bypass manifold piping, valves and complete monitoring electronics necessary to allow seamless changeover between meters.

Another option was to change the orifice plate sizes seasonally to measure widely changing flow rates. However, this approach involved intensive field labour in the plant’s severe weather conditions for manual changing of the plates and rearranging of the transmitter.

The solution was found in the Accelabar flow meter developed by Veris Inc. that incorporates Foxboro d/p Cell® transmitters. It features a Veris-patented toroidal nozzle design with Verabar flow rate measurement technology. The nozzle provides a straight run ‘settling distance’ that accelerates and stabilises the velocity profile, and significantly increases the DP captured by the Verabar located within the nozzle. The result is an accurate and predictable DP over a wide flow range.Figure 1. The Veris Accelabar.

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When designing this system, Veris turned to Invensys, a long-time technology partner, to leverage its expertise in DP transmitters. For this application, the two company’s combined their technologies in one flowmeter to achieve excellent operating ranges.

The Foxboro IDP50 Premium Performance d/p Cell was selected for this application, combing two complementary and effective solutions. Foxboro’s transmitters have grown considerably since 1948, when it invented the first d/p cell transmitter. The Foxboro IDP series intelligent two-wire transmitters now includes a complete offering of measurement ranges, static pressure ratings, materials, analogue and digital communications and premium performance.

The IDP50 features improved characterisation and compensation techniques to achieve accuracy and resistance to environmental effects over a wide measurement range. Two sensor selections are available within the IDP50 group, one with an upper range limit (URL) of 1000 in H2O, and the other with a URL of 200 in H2O. Both selections are accuracy rated ±0.025% of span, for spans as small as 1/10 of maximum span and no more than ±0.05% of span, even for spans as small as 1/80 of maximum span.

Due to the wide range of flow rates in this natural gas application, the engineers chose to use two high-accuracy IDP50 transmitters, one to measure DPs from 302.8 down to 2.5 in H2O with ±0.025% of span accuracy, and the other to

measure DPs from 2.5 down to 0.34 in H2O (and ultimately even lower) with ±0.050% of span accuracy.

Expectations exceededThe Veris Accelabar flowmeter with Foxboro IDP50 transmitters is installed in the LNG plant in a pipeline with no straight runs, with valves, strainers, and pipe expansions and reductions ahead of it. Even in this demanding configuration, it is meeting all performance requirements. The system provides flow rate measurement accuracy of ±0.75% over the entire 60:1 flow operating range and accurately measures flow rates with turndowns as high as 150:1 (from 60 000 standard ft3/hr all the way down to 400 standard ft3/hr).

Veris and Invensys jointly took performance responsibility and gave the customer a five-year performance warranty.

Finally, because both the Accelabar and the Foxboro IDP50s have no moving parts to wear or seize, maintenance is minimal – another key priority for the customer. Moreover, from the perspective of the plant’s day-to-day operations, the natural gas supplier has found that the flow metering system is user-friendly and easy to operate.

The LNG industry requires readings to be as accurate and reliable as possible, given their critical impact on business decisions and ultimately, profitability. To the LNG provider, this has translated into improved material accountability and lower operating costs, both contributing to reduced overall maintenance and improved business performance.

LNG_MARAPR_2013_101-104.indd 104 21/03/2013 15:39

Over the past decade, companies have been using unconventional drilling technology to extract gas and liquid from the readily available shale formations in North America. As the industry gains experience, the production rates continue to rise based on

better use of technology to locate resources and to decrease the time from exploration to production. The use of technology is allowing operators to manage their drilling teams more efficiently, helping to drive down their investment in each well.

This rapid build-up of both gas and liquid wells has resulted in an abundance of natural gas, driving the price of natural gas in North America to an all-time low. With the abundant supply and favourable reserve estimates, the global market is driving many companies to develop projects for the export of LNG from North America. The slate of proposed and potential export terminals includes grassroots land based projects, floating facilities and the addition of liquefaction processes to existing gasification operations. These LNG liquefaction projects are being justified on a perceived market pricing gap and continued overseas demand.

PARTNER UPGreg Hallauer, Yokogawa Corporation of America, USA, discusses the importance of selecting a reliable automation partner.

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If all of the projects currently announced are implemented, with an estimated cost for each plant between US$ 4 – 8 billion, a conservative projected total of US$ 56 billon could be spent from 2013 to 2020 on LNG liquefaction infrastructure. Initial business partners who have announced LNG terminal projects continue to develop relationships for supply and delivery contracts, as well as financing for these projects. At the same time, they are required to begin the permitting process, which does not appear to have an established timeline under the current US energy policy. This permitting process has a direct connection to partner commitments and financing required to move forward with a project.

To add to the overall feasibility and risk assessments, the actual global market needs to be considered. Several studies have recently been issued to somehow document all the variables associated with exporting LNG from North America. These studies and reports do not always align and highlight the potential challenges of competing with existing LNG export facilities in the Middle East and Africa, with more capacity coming online in Australia. These documents also consider the ramifications of introducing additional capacity between 2014 and 2020, based on current conditions and what may happen to current LNG pricing.

Small but crucialAs these LNG projects begin to develop, owners will have their hands full with many decisions. Added to this long list of considerations is a rather small and often overlooked, but very crucial component of these multi-billion dollar liquefaction processes. This crucial component is the automation partner. While it is a relatively small initial financial impact, it can significantly help get an operation into production. Delivery contracts require on-time startup and targeted production levels, making the integration of automation not only a requirement to liquefy natural gas, but a necessity to do so in a safe, timely and dependable manner. When selecting a partner, it must be recognised that the project is just the beginning. To successfully deliver on long-term contracts, the owner will need a reliable partner they can count on for the entire lifecycle of the facility. Today, owners can find global companies that have experience not only in LNG, but engineering, technology, safety and lifecycle support. This experience will also bring with it an understanding

of the different automation requirements in liquefaction, carriers, gasification and terminals.

MAC/MIV methodologyWhen it comes to execution, a proven method to reduce the risk associated with an automation partner is to look for companies that also have successful main automation contractor (MAC) or main instrument vendor (MIV) experience. Engaging a partner with these capabilities will help manage risk and lower the overall cost associated with the project. The MAC project execution method first introduced in the early 1990s for offshore platform development has been successfully used to reduce the implementation timeline, minimise human error and prevent re-work. With the MAC approach, the automation partner is brought in early in the planning and definition phase to support the study and pre-design activities. By doing so, the knowledge of the design process is transferred, alignment of the automation with the overall project objectives is completed, and the partner’s LNG experience is integrated with the EPC design. This process also enables awareness in identifying areas for improvement in the design and operability, with the goal of improving the owner’s or partner’s ROI. The MAC approach keeps the automation partner engaged throughout the implementation phase and into the long-term operational phase.

LNG projects will transition from the planning and definition phase to the implementation phase, which encompasses the design, build/purchase, inspection/tuning and construction/start-up activities. Since the MAC project approach included the partner early in the planning process, owners can expect team ownership from FEED through commissioning. Some of the benefits in this stage include elimination of a bid cycle, re-evaluation, re-design of FEED, reduced team size and a reduced schedule. Other side benefits of maintaining the same team members who are aligned with the overall project objectives are cost reductions associated with mobilisation, improved interface with the EPC, integrated automation procurement, improved constructability and one total integrated factory acceptance testing (FAT). The fact that it is not necessary to staff, de-staff and re-staff also maintains the learning curve of members on the team, increasing their productivity. During this phase of the project is where an early investment in the use of the MAC process starts to

show its benefits in the risk/cost trend. The typical automation project risk/cost trend will start to accelerate, potentially creating cash flow issues for the project management.

Enhancing the processAlong with the MAC/MIV methodology, specific engineering tools and procedures have been developed by companies to enhance this process. Offered with these tools and procedures is a level of standardisation combined with an open and interoperable environment, allowing for best in class technology utilisation. Global engineering standards and procedures, based on proven project experience, increase the flexibility of the owner and EPC Figure 1. MAC risk/cost reduction trend.

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wherever they choose to execute the project. These standards include specifications for components, such as process control systems, emergency shutdown system (ESD) and fire and gas system (F&G), console design, HMI, and alarming, to name a few. Activities will also be included in the standards. Some of these standards include fundamental work breakdowns per activity, including descriptions, objectives, detailed steps to execute, required input and delivered output. More specific engineering tools will include plant knowledge libraries that contain standardised configurations for LNG applications in liquefaction, gasification, carriers and terminal automation. These should be a part of the functional design specification and documentation available from experienced LNG automation partners. These plant knowledge libraries are compiled through professional experience and records from projects executed over many years in the LNG industry.

The plant libraries will cover all process facilities for a plant type and allow for development of the plant master logic. They help provide high quality optimum control from basic design,

improve engineering efficiency with fewer man-hours, and reduce project schedules. The library contents may include elements such as process models, graphics, I/O lists, functional specifications, drawings, logic diagrams, and cause and effects tables.

Finding an automation partner with proven engineering and execution experience is an important part of the selection criteria. Whether it is C3MR, DMR, SMR or Cascade chosen for the project, one should expect the deliverables provided by an automation partner to be capable of working with all of the process technologies available today.

Other important elements included in the deliverables are awareness of technology, safety and lifecycle support. These will be integrated with the engineering as part of the implementation and hardware deliverables provided by the automation partner working side-by-side with the EPC.

The automation architectureThe outcome from all the planning, design and engineering built into the MAC process will provide an equipment list that

becomes the automation architecture. The automation in an LNG plant stretches across the entire facility, ranging from the inlet facility, gas treatment, acid gas removal, dehydration refrigeration preparation, boil-off gas, LNG storage, loading and of course liquefaction. The same system also needs to be integrated into the business to take complete advantage of its capabilities. The technology platforms most commonly employed by an automation partner to handle multiple trains are a distributed control system (DCS); safety system (SIS); ESD; F&G; smart field instruments; advanced analytical packages; electrical control systems; CCTV; UPS systems; valves; vibration monitoring; asset management; leak detection; advanced process control (APC); sequence of events recorder (SER); operator training simulator (OTS); information management systems and potentially more depending on their role as the MAC. These systems and packages are seamlessly integrated for implementation into the project. They provide the solutions platform from field sensing, production control, production management and on to corporate management.

SafetyAs part of any successful business strategy today, safety has become a top priority in all areas of a business’s operations. This is true of the automation partner as well, from safe working practices to actual implementation of safety related systems to fulfill the functional safety management strategy for an LNG project. An automation partner should be capable of supporting the development of hazard and risk analysis,

Figure 2. Functional design specifications.

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overall safety requirements, safety requirement allocation and implementation of the safety related systems. The process involves following specific steps outlined by standards such as IEC61508, using integrated safety controllers as a hardware platform, and implementing it to specific commissioning and validation specifications. The safety controller performing the safety inputs and outputs must meet certain SIL ratings defined by hazard and risk analysis. Certification of these platforms is often provided by organisations such as TÜV Rheinland. These ratings and certifications are best met with ultra-high reliability

systems using multiple processors and hot-swappable I/O modules with advanced diagnostics capability. Automation companies have also developed technology allowing safety data communication from the safety controllers over a common control network to communicate with their process control systems. This provides the plant with isolated safety control where needed, but also makes this data available for viewing on the process display. This once required two different interfaces and displays, complicating the work load for operators during critical events. A well implemented highly reliable system

Table 1. LP pump - I/O list example

Tag No. I/O type Description System Loop name Location Service Alarm/trip Fun bio

HS_LPP DO LP pump motor DCS LPP_PUMP MCC HS-LPP - MC-

XS_LPP DI LP pump motor status DCS LPP_PUMP MCC XS-LPP - MC-

II_LPP AI LP pump motor overcurrent DCS - MCC IIT-LPP H PVI

VI_LPP AI LP pump motor vibration (interlock) DCS - MCC VIT-LPP H PVI

PI_DSCH AI Discharge pressure DCS - Field PIT-DSCH L PVI

FIC_MINFL AI Discharge flow controller DCS FIC_MINFL Field FIT-MINFL LL PID

FV_MINFL AO Kickback flow CV DCS FIC_MINFL Field FV-MINFL - PID

FZSC_MIN DI Kickback flow CV close limit switch DCS - Field FZSC-MIN - SI-1

ZSO_DSCH DI Discharge shutoff valve open limit switch DCS XV_DSCH Field ZSO-DSCH - SIO

ZSC_DSCH DI Discharge shutoff valve close limit switch DCS XV_DSCH Field ZSC-DSCH - SIO

XY_DSCH DO Discharge shutoff valve DCS XV_DSCH Field XV-DSCH - SIO

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platform brings with it increased plant availability and greater opportunity for sustainable profitability.

Training simulatorBeyond the implementation of safety control, another helpful automation deliverable being used by LNG operators today is the operator training simulator (OTS). The OTS provides a dynamic simulator for LNG processes that can be used in various ways. By working with an automation partner that has plant libraries, it becomes easy to develop plant master logic that can be used to provide a complete virtual process of the LNG operations in an online training simulator. This simulator combines the process unit modeling with the control logic and allows for unit management

or critical situations to be loaded as training scenarios. Potential benefits of using a dynamic simulator are the realisation of stable and robust production, operator training tool based on processes and a sustainable method to reduce the knowledge gap as operators change over time. The thoroughly trained operators and a well-engineered automation platform also provide more confidence to operate at maximum capacity. This takes full advantage of the assets capabilities.

ConclusionThe information presented in this brief article is not intended to be a specific roadmap but rather to stimulate dialogue regarding the selection of an automation partner and potential project execution

methodology. Regardless of which method is chosen, it should always include the operation phase. A MAC methodology includes the planning and definition, implementation and operation phase. The operations phase is really a way to sustain the large investment associated with LNG liquefaction process. A truly experienced MAC provider will discuss the entire lifecycle roadmap from feasibility to decommissioning or migration, so every aspect is considered prior to commitment.

When spending US$ 4 – 8 billion to develop an asset expected to produce for years to come, it makes sense to engage potential automation partners with an open mind, and expect them to be a member of your team for the next 15 – 20 years.

Figure 4. LNG automation solutions platforms.

Figure 3. LNG tank area process overview graphic.

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During the design of complex industrial plants or platforms, the efficiency and reliability of unitary process equipments has to be studied for the large

variety of operation parameters (flow assurance, stress, transients, fatigue, corrosion, etc.). In most cases, full experimental qualifications for severe conditions are not available and one may need to explore and improve the design of these equipments for non-standard uses with the help of numerical simulations. Examples of problems and equipments where such approaches with computational fluid dynamics (CFD) and fluid-structure-thermal (FSI/CHT) coupled physics can help include the design of onshore tank farms and retention; analysis of the performance and optimisation of the design of heat exchangers and separators on the decks of FLNGs; sloshing and boil-off gas (BOG) reduction, including the ship motion at sea; and acid gas furnace treatments. The benefits of using multiphysics simulations in process design and optimisation can also

C. Souprayen; A. Tripathi; G. Vaton; T. Grinnaert; M. Leguellec; and L. Ait-Hamou, Fluidyn France, explain how the LNG industry can benefit from CFD modelling in process design, risk assessment and mitigation studies.

LNG_MARAPR_2013_111-116.indd 111 25/03/2013 09:30


be found in the risk and impact assessment related to the assemblies and layout of such equipments in complex plants (onshore) or very complex, high congestion offshore platforms or FLNG/FPSOs. In the consequence modelling steps of a quantitative risk assessment (QRA), many accident scenarios are identified among loss of containments, toxic/flammable dispersion, fires and explosions. Most of them need to be studied for the distance at risk, for the resistance and design analysis of structures submitted to thermal and pressure loads, for the inclusion of mitigations solutions, and ultimately for the preparation of emergency plans (evacuation and confinement). When simplified calculations from semi-empirical tools (e.g. 2D, integral or analytical models) are not precise enough, the application of 3D CFD simulations to the problem can provide detailed

quantitative data. This article provides several examples of such applications for leak, dispersion, explosion and structural resistance of equipments in both onshore and offshore situations.

Applications in process design

Case 1In LNG plant design, liquefaction and regasification processes are common. Large capacity storages need to be fitted in difficult environments onboard FLNG units. With wind loads, currents and waves, the various uncontrolled motions of the platforms result in internal motion, sloshing and increased heat exchanges that need to be carefully studied. Similarly, the quantification of BOG is an important issue for

reliquefaction and downstream equipments and energy budgets. While semi-empirical estimates are often far too conservative, CFD modelling of the phenomena at play can provide the optimal quantification for loads (for stress analysis) as depicted in Figure 1, or for mitigation measures such as LNG spraying in the reservoir on loading. Simulations of such two-phase flows with continuous and dispersed interfaces are now available in CFD tools for such optimal design.

Another key function in LNG plants is the separation and cooling function required for both gas purification and liquefaction at cryogenic temperatures. Engineering, procurement and construction (EPC) competitors and majors operating the platforms search for innovative, high performance heat exchangers. Many designs (geometry, material assembly for both plates, tubes and insulations) are to be studied with the help of CFD codes coupled with structural analysis (thermal transfer/conduction). An example of coupled finite volume (fluid) and finite elements (thermal structure) is provided in the optimisation of a plate-fin heat exchanger in Fluidyn™-MP/CHT CFD code. A delicate balance had to be found in order to keep a reduced pressure loss in the assembly and to keep a strong enough conduction in the steel plates toward the tubes, despite the creation of holes in the conducting surfaces. For this coupled fluid-structure interaction problem, as simulated in Fluidyn-MP-CHT

Figure 1. Simulations in Fluidyn CFD codes. Left: large amplitude sloshing in a vertical reservoir. Right: spray calculation from injection nozzle (design for LNG BOG mitigation).

Figure 2. Flow velocities (left) and temperature field (right) in a central layer depicting the process of the heat exchanger.

Figure 3. Temperature load in the hot and cold chambers (left). Flow lines showing complex patterns in the cold chamber toward exit pipes for further processing (right).

LNG_MARAPR_2013_111-116.indd 112 25/03/2013 09:32

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solutions, the simulation has to simultaneously solve the (cold) gas and (hot) liquid flows with finite volume techniques, the Navier-Stokes equations for the fluids and the convective heat transfer to the steel and coppers surfaces, and the heat conduction diffusion equation in finite element techniques for the structures.

Figure 2 shows the results for flow speed and temperature field on a central layer of the assembly. The calculation included transient (and steady state) operations.

The respective performances of the several design proposals can be quantified with minor modification on the geometry, meshes and material properties for various operating conditions.

Case 2For the second case study, the process in the acid gas treatment units needed to be studied and improved. This applies a controlled combustion with several condensation steps for the gas flow, resulting in sulfur recovery/separation. In the multi-pass system, a hot reversal chamber is located at one end of the furnace and separated with an insulated/heat resistant multilayer wall. A cold chamber is collecting the liquid/condensed sulfur. The initial design for the separation wall and attachment on the furnace outer cylinder includes heat resistant bricks, refractory concretes, fibre sheets and steel.

Variations in operation conditions at warm-up, during acid gas injection, and in gas compositions has resulted in several failures and incidents related to the refractory part of the wall, resulting in increased corrosion of the steel plate on the cold chamber side.

Presumably, the thermal gradients developing in the separation wall submitted to varying thermal loads from the hot and cold chamber have resulted in mechanical deformation and stress (both through dilation and deformation) above the resistance limits for the bricks and concretes. In order to confirm such a diagnostic and locate the zones where maximum values for deformation and stress tensor are observed, the problem has been simulated both in transient and steady (maximum load) situations. It is an aero-thermo-mechanical 3D problem where flow calculations (in FV and Navier-Stokes equations frame) have to be produced simultaneously with the conjugate heat transfer and structural analysis in the sandwich layers and furnace envelops and supports (in F.E frame). The Fluidyn-MP-NS-CHT-FSI multiphysics software has been used in order to simulate and analyse the behaviour and quantify the stress tensor in every grid point of the structure.

Figure 3 shows the results for the diagnostic phase, where thermal loads on the structure surface and conduction/diffusion in the materials are calculated simultaneously with the flow distribution (the cold chamber).

Based on such calculations, the area for deformation and large stress development are studied for resistance analysis. The numerical diagnostic shows similar maximum bending and traction zones resulting on the several rupture incidents.

Applications to consequence modelling

in QRA and resistance of critical safety equipmentIn the process of layout qualification and for the regulatory reports, QRAs are produced and iterated for risk reduction. The examples given below outline the steps and benefits of using CFD modelling for the precise analysis consequences (e.g. toxicity, fire and explosion) on structural design and the distances at risk. The sequence of events can be described as follows:

Gaseous emission and/or pool formation and evaporation.

Dispersion of toxic and/or flammable gas.

Jet or pool fire.

Deflagration and/or detonation of the flammable gas.

Structural breakdown due to the overpressure wave.

CFD is a valuable tool in assessing the consequences of such a sequence of events as long as it features a good atmospheric boundary layer, a good evaluation of the local mechanical and thermal turbulence induced by the structures and processes, and an accurate description of the high-momentum jet. The CFD tools must provide an appropriate model for combustion, turbulent and flow/pressure, development in congested processes for the explosion and accurate solvers with non-diffusive properties for flow, reactive fronts and pressure fronts capture. For each of these steps, examples of how CFD can be put to use are detailed in this article. In the Fluidyn software series (with multiphysics modelling centred around CFD), several modules have been derived from the general simulation platform and dedicated to risk modelling applications such as:

Fluidyn-Panache – for the dispersion simulation.

Fluidyn-Ventfire – for the simulation of combustion of jet and pool fires.

Fluidyn-Ventex – for the simulation of explosions in confined and semi-confined spaces.

Fluidyn-MP-FSI – for the resistance analysis of structural design, with a coupling between pressure load (in the fluid, FV solver part) and stress and deformation (up to resistance thresholds for the FE structure solver part).

Flammable/toxic gas dispersionOffshore platforms and FLNG units are complex structures consisting of many layers and decks. The emerged part of the

Figure 4. Example of a 3D geometrical model of an FLNG unit (Fluidyn-Panache).

LNG_MARAPR_2013_111-116.indd 114 21/03/2013 16:14

platform is comprised of several working decks, where the extracted products are separated and treated.

In addition, normal operations produce plumes from vents and exhausts. High temperatures and fluxes are also observed at the generator exhausts located at or very close to the decks elevation. Moreover, the local wind flow and the overall inner ventilation in the decks depend on external direction, strength of the wind and (hot) air fluxes from stacks and exhausts.

Therefore, to produce an accurate representation of the plume expected from a gaseous jet source or from an evaporating pool, a model needs to feature a good atmospheric boundary layer, a good evaluation of the local mechanical and thermal turbulence induced by the structures and processes, and an accurate description of the high-momentum jet.

Traditional and integral modelling for dispersion could fail in this case because of the highly congested environment in which an accidental leak is expected to take place. The wind flow pattern could have complex patterns that can result in the accumulation of flammable gases in unexpected parts of the decks. Given the complexity of the layers, decks and processes, the modelling can only be tackled with 3D-CFD simulations (Figure 4).

On the other hand, even if CFD takes into account the main obstacles to the flow, the entire piping network cannot often be modelled explicitly due to mesh size considerations. In this case, the pipes and other processes can be approximated by a porosity volume factor, defined as the free volume over the entire volume and aspect ratio parameters. For such numerical objects, local drag and turbulence production/sink source terms are implemented in the Navier-stokes solution. The ability to mix different types of mesh results in an accurate description of the fine details of release and obstacles on a domain that can cover several hundreds of metres, or even several kilometres if the gas cloud is to be followed once it has left the platform, e.g. if it threatens a nearby platform.

CFD can also detail the characteristics of the release. For high momentum releases, the Navier-Stokes equations with a compressible regime governing the fluid behaviour are solved from initial 3D wind conditions.

Jet impingements and further spreading on the deck, along obstacles and through processes (treated as porous media) are calculated explicitly. In case of a two-phase release, models can be applied treating the two phases present at the same time (liquid through pools and aerosols or gas) and the subsequent phase change from liquid to gas that could fuel the release for a long time.

The transport of the toxic and/or flammable gas by convection (both forced and natural) and diffusion can therefore be modelled using CFD and a detailed analysis of the flammable cloud (concentrations between the flammability limits), toxicity levels and doses, or even visibility inside the plume, can be carried out in a straight forward manner.

Fire, explosion and structural integrityIn a worst-case scenario, the flammable gas can be ignited. The difference between a jet fire and a deflagration is mainly based on the ignition. If the ignition is immediate and occurs

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right at emission, the scenario will turn into a jet fire and the gas will be depleted at the origin of its emission. If the ignition is delayed and a flammable gas cloud has the time to form, a deflagration, or even a detonation (depending on the ignition strength and the confinement of the cloud) will occur.

An example of the simulation of a jet fire is shown in Figure 5. In this example, a turbulent combustion model called the Eddy Dissipation Concept (EDC) and a soot model based on the EDC were used. The turbulence model was the two-equation k-є model.

These congested environments are also the primary location where an explosion could occur, first by providing ignition points and secondly by accelerating the flame until it reaches deflagration speed.

When assessing the risk associated with the accidental dispersion of a flammable gas, the consequences of a deflagration on the platform and its effects on the integrity of the entire structure need to be assessed and faced.

The need for a numerical tool lies in the simulation of the mechanical and thermal interaction between fluid (in which the pressure wave will propagate) and the structure (in which the stresses will be built at the wave passage). Fast, transient phenomena involving compressibility of the air are efficiently solved by the strong coupling between the finite element method for the structural computation, and the finite volume method for the fluid dynamics method. An example of the deformation expected on a piping network and supporting system is shown in Figure 6 for two distinct dates during the front propagation.

Conclusion The increase in computing power and the development of efficient solvers and meshing methodologies have finally allowed CFD to show its full potential in process design, diagnostic and optimisation tasks, as well as in the risk assessment strategies.

3D modelling based CFD tools can provide a valuable input both in the design phase, to ensure that the layout does not favour any avoidable and undue accumulation, and in the risk assessment phase to provide input to the quantitative risk assessment and emergency system survivability assessment.

In addition to the simulations briefly described here, other uses of CFD in offshore platforms and FLNG can be found.

One such use could be health and safety issues for workers. Indeed, on an offshore platform, the vents and exhausts of potentially toxic pollutants may produce poor air quality and health/safety issues for workers and operations. Air intakes (HVAC inlets), heli deck, doors to living quarters, walkways and generator exhausts are possible locations where a detailed analysis of pollutant concentrations should be undertaken to reduce hazards. The concept of natural ventilation can also be assessed.

On accidental scenarios, CFD can also help define the most suitable locations to place monitoring stations, which could warn of a possible leak on the platform as well as the escape routes for the personnel, offering sufficient time to escape or get equipped with respiratory devices in case of the accidental release of toxic gases.

Figure 6. Deformation of pipes after a pressure wave (Fluidyn-Ventex) at two positions of the front propagation (not shown). The initial state is shown in grey, with the maximum deformation in red.

Figure 5. Thermal plume (isosurface of temperature) (left) and thermal fluxes (isosurface as kW/m2) from a jet fire (Fluidyn-Ventfire) (right).

LNG_MARAPR_2013_111-116.indd 116 25/03/2013 12:06


Simulation technology can, quite literally, be a life saver for all industries where the safety stakes are high. Airline pilots, for example, are able to practice emergency

landings and other potentially dangerous manoeuvres in a simulator so they know exactly what to do if a similar incident occurs when hundreds of lives are really at risk. Likewise, simulation modelling in the LNG industry can test critical processes, enabling engineers to try ‘what if’ scenarios and assess the impact.

Engineering simulation of 3D digital prototypes of plants, machinery, equipment and individual products and their components in the design office can play an equally key role in

the long-term safety and efficiency of the industry. The ability to analyse and test the performance of a design, not just to check how it works mechanically, but also to measure how it will stand up to the subsea environment, harsh weather conditions or other demands, can be an important preliminary to routine safety and quality testing further downstream. It can also be used to investigate and remedy the failure of existing equipment.

It makes perfect sense to test a design in the virtual world to the limits before it is built, especially in the oil and gas industry where products are often huge, complex and expensive. The serial design-prototype-test-redesign model

Colin Watson, Symetri, UK, looks at how the cloud and

other advances in engineering simulation could benefit the

LNG industry.

SIMULATION

SIMPLIFYING

LNG_MARAPR_2013_117-120.indd 117 21/03/2013 16:44


can be long and costly and, for suppliers, can mean missing an opportunity if competitors get their product onto the market first. Simulation can help reduce costs too. By being able to experiment within certain set parameters, designers can avoid over-engineering or test the impact of replacing one material with a less expensive alternative.

So, ideally all designers should be able to use simulation tools as early as possible in the design process. However, until now there have been some major barriers to this scenario.

Not just for expertsComputerised physics-based simulation has been available for around 40 years. 3D finite element analysis (FEA) meshes could be built manually and applied to 2D drawings. However, the analysis of even a simple component could take a month or more, and was often used only after a component had already failed.

Not surprisingly, since then this response time has improved considerably. However, until recently, simulation skills were regarded as almost wizardry with intricate formulae used to conjure up results. Consequently, in many quarters it is reserved for certain projects and is carried out in an inefficient serial design-prototype-test-redesign cycle, a time-consuming and costly way of working.

There have been attempts to introduce simulation skills to mainstream design engineers, but often these tools could only carry out simple linear analysis on single components and the experts dismissed them as over-simplified. Only those that could force the technology to fit their needs were successful, and typically this would exclude smaller companies, such as specialist suppliers.

Meanwhile, engineers continue to make design decisions every day. There are still many that make their choice the traditional way, either by ‘rule of thumb’ or by calculations aided by engineering handbooks. There is much ‘erring on the

safe side’, which often means wasted materials for the manufacturer and higher prices for the end user.

So what is changing this situation? Steady technological progress means that the factors are now all in place to open up the world of simulation to a far wider market, enabling firms of any size to take advantage without a substantial capital investment.

The first of these was the growth of digital prototyping. Now, 3D models can be created that not only look like the real thing, but also act like it too with the utmost accuracy.

The next step forward was the integration of simulation tools within mainstream geometry creation software. For example, the 3D geometry that enables digital prototyping can, in most cases, be used by the automatic meshing tools in finite element analysis (FEA) software. Further analysis tools such as computational fluid dynamics (CFD) have now also been added

Working with integrated CAD and simulation tools enables associativity; that is, when the model is changed, the FEA model and analysis are revised accordingly. This immediately opens up the ability to experiment with different design variants, without going through a lengthy updating process throughout the entire design and documentation process.

In the past, some firms have hesitated before integrating engineering simulation into the design process because of perceived costs and delays associated with lengthy training processes. However, integrated CAD-simulation tools have the same user interface, making them relatively straightforward to learn. Users can begin with mainstream FEA analysis and then later expand their skills to include CFD, dynamic simulation and mechanical event simulation (MES).

When mesh generation is automatic, the only thing the user needs to do is to select the material from a digital library, define the supports of the structure and apply loads to the FEA model. Point, line or surface loads are defined in a graphical environment, directly within the familiar CAD software. The FEA analysis is started just by clicking a button and in a few minutes the results are displayed.

Colour-coded models identify areas and levels of stress, and can be manipulated so that they can be inspected in detail from every angle. Potential problems can be rectified on screen and with a further click the model will be revised to reflect these changes.

Often there are multiple physical effects interacting simultaneously. Integrated solutions automate the transfer of results among multiple analyses. For instance, the forces resulting from a dynamic simulation can be used as an input for an FEA analysis. Close integration of this kind helps engineers focus on product performance rather than the mathematical calculations of advanced numerical methods.

But one of the main advantages of these integrated tools is that simulation can be carried out far earlier in the design process than previously. As a result, rather than being a check at the end of the process when change might need to be kept to a minimum to avoid further cost and delay, simulation analysis results can now be used to influence the design.

Enter the cloudHowever, there is a final piece of this particular jigsaw that looks set to drive the widespread use of engineering simulation more than ever before.

Figure 1. Simulation CFD 2012 hero image. Rendering of an electronics enclosure with infrared thermal profile and flow lines. Designed in Autodesk® Inventor® software. Simulated in Autodesk® Simulation CFD software.

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The mobile revolution followed by the emergence of cloud technology has lifted the expectations in the consumer and commercial worlds alike. The use of mobile technology has affected every business sector in every part of the globe. The relatively staid world of heavy engineering may believe itself to be immune to the growing use of the cloud, but there are good reasons why it may come to recognise that the use of cloud-based resources is an unstoppable trend.

The first simulation in the cloud solution was launched onto the market in 2012. The cloud means that instead of relying on the conventional server-based set up, simulation tools can be offered as a service, sitting on someone else’s server.

Simulation can be very heavy on computing power and testing multiple design versions can take time, which previously may have required investment in high performance hardware. However, when these tasks are transferred to the cloud with its virtually infinite computing power, complex multiple simulation tasks can be carried out in parallel, enabling engineers to study a large number of design alternatives. The analysis of design variations can run on a large number of computers in the cloud. In almost the same amount of time that a single analysis would take on a desktop, the cloud delivers results for all iterations providing extensive scope for design optimisation.

Because cloud capacity is bought on a pay as you go basis it can be far more economic and affordable. Rather than involving high-level management meetings and presentations to justify capital investment, it can be switched on by the engineers themselves and paid for as an operating cost. There is also no lengthy implementation process – only the need to

purchase pre-paid ‘cloud units’, which give access to a range of multi-physics simulation tools without the need for specific licences

But perhaps one of the main benefits of cloud-based simulation is that it can be accessed remotely from anywhere in the world. This holds great promise for global operations where, say, the design team are in the UK and the facility in the Middle East. There is even a simulation app for iPads – a mechanical statics application.

Operations that have already adopted integrated CAD and simulation tools have reported some impressive results. For example, one manufacturer that used to outsource FEA analysis, but now carries it out in-house using integrated tools, says that it has slashed the time and cost for design validation by 50 to 60%.

The advantages are already being seen before taking simulation to the cloud. In future, using cloud-based tools such as Autodesk Simulation 360, the savings are likely to be multiplied further.

Some industries will benefit from this ‘democratisation’ of simulation more than others. Symetri believes there will be big benefits for the LNG industry, for reasons of safety and risk minimisation but also to help businesses become more competitive.

There will always be room for experts, and simulation specialists will always be needed for in-depth analysis on certain equipment and machinery. However, adopting this new generation of ‘always on’ simulation tools will result in high quality designs across the board.

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A rguably, the hallmark of a civilisation is the creation of standards. These may be standards of speech such as language, or the standardisation of value

through money. With such standards, meaningful dialogues and transactions can be held with your neighbour. This article describes a problem that is common to standardised industrial processes, with particular emphasis on LNG-related fields, and suggests a process for resolving it.

James R.C. Garry, Red Core Consulting,

Canada, examines the efficacy of standards

governing the LNG industry.

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Standardisation: brieflyAlmost everyone uses products that in some way have been designed or built to a criterion established by a standardisation body. In today’s industrialised world it is expected that when one buys an item, such as a length of pipe, then that item will have been made and qualified in compliance with a standard of some type. Material or devices with higher cost, or greater impact on human and non-human life, tend to be more tightly controlled. Such is the case for tasks associated with LNG projects. The feedstock is of high economic value and its physically challenging properties make its movement and storage a task that demands precision, accuracy, and robust engineering margins. Efficient and safe procedures for handling LNG are most easily achieved by following the best practice in the industry, which means adhering to standards that reflect the hard-earned lessons of countless earlier engineers.

The origins of such standards in the modern era can be traced to the founding of the International Bureau of Weights and Measures (BIPM) in 1875. This marked the first coherent attempt to forge international standards for trade and research. Similarly, in other fields, agencies arose to take on the role of curating and developing sets of standards for electrical and chemical industries. The last century saw the birth of three types of agency: national agencies (JIS, BSI, DIN, etc.) that govern

standards for a nation’s industries, international corporate entities such as ASTM, and governmental international organisations such as ISO. The upper half of Figure 1 shows the familiar non-governmental standards agencies to which contractors and persons can belong, and in the lower half the more rarefied transnational agencies. These are fundamentally a different class of organisation in that their membership consists of national entities, drawn from each member country.

It should not be thought that these agencies curate a static collection of standards – far from it. Standards are regularly reviewed by an agency’s members and it is recommended that the interested reader take some time to investigate how they might join a non-governmental body and witness at first hand the evolution and growth of a standard.

What can be standardised?The simple answer is that the ingenuity of humanity is the sole constraint. For example, ASTM International (the American Society for Testing and Materials) currently coordinates and maintains around 12 000 standards, ranging from D3751 that describes how furniture polish may be tested, to C0696 which specifies a protocol for testing uranium dioxide pellets used in nuclear reactors. The existence of multiple agencies, each coordinating a myriad of standards, means that a manufacturer is faced

with a difficult choice, namely, which standards should they choose? For a given property of any item, such as the tolerances of a bolt, there might be intra-company standards, national standards, and international standards that all address the same matter but in different ways (Figure 2).

The LNG field has been relatively immune to this multiplication of standards, as much of the early commercial technology was developed by a handful of countries. But the designer of, for example, a static LNG storage tank is still presented with over half a dozen standards from an alphabet-soup of organisations, which all ostensibly discuss the same thing, as is shown in Figure 3.

The same problem arises for almost every imaginable link in the LNG chain. While the technology and engineering principles remain the same, countries may adopt different models to suit their own markets and manufacturers. But much of this complexity is superficial. Manufacturers exist in the ebb and flow of the marketplace and the users of an item or a material rapidly discover which standards are the most useful for solving the problems that they encounter. If a standard confers concrete advantages to both the manufacturer and the user then its use is likely to spread, and one might liken this ideal situation to that of a beneficial phenotype in a heterogeneous population.Figure 1. Illustrating the two different classes of standardisation entities.

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LNG/LCNG fueling stations

Storage filling

Mobile delivery transfer

Hydrogen fueling stations

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This idealised scenario relies on several assumptions, namely:

The standards themselves are pertinent and are in accord with legislation and the industry’s best practice.

The users find that the standards give a real benefit by reducing uncertainty in a design or process and so yield savings of time or money.

The standards are adhered to by the manufacturers of the item, or the test-laboratories that they employ.

The first point is the responsibility of the agencies that maintain a given standard. If the standard is superseded by developments in materials or methods, then its usage

withers and new standards may be created. One can point to relatively few examples of LNG practices displaying such ‘evolution of fitter standards’, given the comparative youthfulness of the field.

We would hope that meaningful and legal standards would deliver tangible advantages, otherwise what would be their purpose? Before such benefits are realised it is critical to ensure that the third assumption is valid – that the standards are implemented accurately. But how does one prove that a testing agency is both honest and competent? One might appeal to the use of accreditation services that, for a fee, establish whether a given company is compliant with standards such as ISO 9001 or ISO 17025.* But again, that does not resolve the problem of verification. It simply

moves the burden of trust again to another entity and the fact that a laboratory is accredited by an agency does not automatically mean that it performs as it ought to in the rough and tumble of the commercial world.

One might argue that the problem of verification is the customer’s concern alone. After all, as the standards are readily available from the agencies that coordinate them, surely the user of a tested material could check that the delivered service or item conforms to the necessary standards? If the standard describes a bolt’s tensile strength or geometry, this could be quite easy to check. But if the standard described a process involving the handling of cryogens, sensitive electronic monitoring, and finely machined components, then the end-user cannot be expected to verify that the standard was adhered to. And that is the crux of the problem. Entities, including standardisation organisations (ASTM, ISO, etc.), do not and cannot police the implementation of the standards they control. Thus, the user is left with little choice but to either accept what they are given, or take another leap of faith and request that the item be retested by a third-party test house. This, for those with a classical bent, is neatly encapsulated by Agrippa’s Trilemma. One either endlessly seeks confirmation of test data by another test house (which is then itself critiqued and tested), or one accepts without reservation possibly flawed data, or one arbitrarily decides at some point to stop asking questions.

This discussion may be thought to be overly wrought. One has to employ trust at some point and surely a commercial entity would be guilty, at most, of unwittingly deviating from a standard? After all, standards are written to be clear and unequivocal and the presumption that a test house is deliberately overlooking parts of a standard is but a short step away from unwarranted and damaging paranoia.

Can standards be trusted?Some years ago, Red Core Consulting made enquiries about the state of thermal testing in the field of LNG, and as its background is in cryogenics and instrument design it knew what to ask for. There are three main standards for determining the thermal conductivity of insulators for cryogenic applications and with little effort it found certificates from seven

Figure 2. A bolt and a small fraction of the standards that may apply to it.

Figure 3. An LNG tank designer’s dilemma.

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laboratories, specifically three companies and four research institutes. All seven certificates purported to adhere to ASTM C177, a standard that describes a fundamental test of an insulator’s thermal conductivity. The company purchased a copy of the ASTM C177 standard and found that none of the certificates were fully compliant. Of the seven entities, one firm’s certificate failed to comply with 15 mandatory clauses and yet that company promoted itself as being ISO 17025 accredited. The most common failure was the presentation of data without uncertainty figures, giving the client no way of judging how reliable their thermal conductivity data were. This is not a trivial matter. Telling a machinist that you want a length of steel rod cut to be exactly 50 mm long elicits a very different reaction (and cost) than telling them that it can be 50 +/- 5 mm.

A more pertinent example for the LNG field would be a lack of uncertainty data for the thermal conductivity of a storage vessel’s wall material. Boil-off-rates (BOR) for mid-size LNG tankers and storage tanks are not insignificant, and can be of the order of 0.1% by volume per day of use. The uncertainty in BOR is directly proportional to the uncertainty in thermal conductivity of the vessel walls, which is dominated by the performance of the insulation. But what client would accept a predicted BOR figure without a sense of how accurate it was? Should one assume perfection in the data? Or perhaps a 1% error?** Maybe 10%? Red Core Consulting knows of at least four laboratories that cannot tell you. With the present softening of gas prices there should be little acceptance of such ambiguity in the performance of a critical component such as cryogenic insulation. The whole LNG economy only works because there is a sufficiently well understood performance margin in the transportation and processing systems for profit to be realised. An unspecified certainty for any item in an error budget should not be acceptable as it exposes the user of those data to a risk of unknown magnitude. However, the utility of uncertainty budgets in forecasting is not universally recognised in large-scale engineering and Red Core Consulting suspects that many firms consider such matters to be needless frippery.

Without a widespread recognition of the need for uncertainty data, duplicitous or incompetent entities can prosper. Standardisation agencies have no protocols for admonishing failing laboratories and customers have no recourse against the purchase of services from a non-compliant laboratory. In serious cases, the non-compliance might be treated as fraud and civil laws might be invoked; such cases are not as rare as might be thought. 1,2,3

This situation is not desirable, but it can be changed. This article presents a three-part scheme that puts the customer’s interests first, and which places only a minimal burden on the test house and the relevant standards agency.

Prevention – a step towards a cureThis scheme is not a panacea, but it offers a path by which end-users can have contractually-supported certainty as to how the work that they are paying for was performed. Firstly, it is proposed that where practicable, committees of

standardisation agencies should promote the inclusion in their standards of a clause similar in nature to that found in ASTM C177; “[…]where deviations from the specifics of the test method existed in the tests used to obtain said data, the following statement shall be required to accompany such published information: ‘This test did not fully comply with following the provisions of Test Method C177.’ This statement shall be followed by a listing of specific deviations from this test method and any special test conditions that were applied.”

With such a clause in place a company that performs the test but deviates from the standard must state that fact to the prospective customer.*** By itself, deviation is not a negative criticism of a laboratory’s work; the customer may request non-standard processes or there may be other circumstances that make it unavoidable. But at present it appears that one can deviate from a standard without having to report that fact.

Secondly, customers who employ a company to perform a test should be willing to ask the company for evidence as to how they implement a given standard. This gives the customer visibility of the mandatory stages of the test, and provides insight about the chosen laboratory’s methods.

Thirdly, to complement the previous point, companies performing standardised tests should prepare and maintain a document that shows how they implement the mandatory features of a standard.

These three points by themselves do not prevent fraudulent transactions, nor do they add value or competence to a test house’s activities. But these considerations would force a test house to make clear, documented, and unequivocal statements that can be referred to in a contract. A company that adheres to an international quality standard, such as ISO-9001 or ISO-17025, would have their critical processes documented already. One would hope that the effort needed to build a convincing fake explanation of a test’s implementation would be less than that needed to actually perform the task.

Any one of these measures can be independently introduced and would go some way to improving the quality of reporting in the field of industrial testing.

References1. Testwell Laboratories, Inc. vs. New York City

Department of Buildings, 7 December 2010.

2. New York City Department of Buildings vs. Stallone Testing Laboratories Inc., 26 August 2009.

3. Schneider, K., “Faking it: The Case Against Bio-Test Laboratories,” The Amicus Journal, pp. 14 – 26, Spring 1983.

Notes* The ISO 17025 standard is somewhat like ISO 9001, in

that it is designed to help maintain the quality of a test laboratory’s work.

** Typically, uncertainties presume Gaussian distributions and are quoted such that 68% of the data fall within that quoted range – the ‘one sigma’ error range.

*** Surprisingly, clauses of this nature are extremely rare in ASTM and ISO standards. Of the dozen or so standards examined by Red Core Consulting, none but ASTM C177 has such a requirement.

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LNG Industry March 2013