LNG Industry September 2013

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September / October 2013

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CONTENTSISSN 1747-1826

ON THIS MONTH’S COVER

September / October 2013

14 LNGINDUSTRY SEP/OCT 2013

Middle EastThe

LNG STORY

SEP/OCT 2013 LNGINDUSTRY 15

W ith 43% of the world’s proven gas reserves, it may come as a surprise that some countries in the Middle

East import LNG. Yet despite the fact that the Middle East is abundant in natural gas resources, the gas supply and demand balance of each country in the region varies greatly, and in some cases is in a state of transition. A combination of factors, such as under-investment in the upstream gas sector, rapid energy demand growth, and high domestic gas consumption levels, have prevented the region from being as prolific an exporter of gas as it is with crude oil.

Apart from Qatar (the world’s largest exporter of LNG) and a few other cases (Oman, Yemen and Abu Dhabi), most states in the Middle East prioritise natural gas to meet domestic needs. For some, such as Kuwait and Dubai, LNG is imported to make up for domestic supply shortfalls.

The LNG story in the Middle East is therefore multi-faceted. LNG king Qatar faces a changing landscape in global gas markets with more competitors entering the scene; a new LNG exporting-hub is expected to emerge in the once resource-starved Eastern Mediterranean; and some states are expanding, or introducing, regasification

capacity to cope with growing energy demand. The Middle East LNG story may not always be a headline grabbing one, but there is a lot more to it than meets the eye.

Qatar: king for not much longerQatar benefits enormously from a generous endowment of natural gas reserves (885 trillion ft3 and the third-largest in the world behind only Iran and Russia). For a country of only 1.9 million residents (of which only 10 – 20% are Qatari citizens), it is not surprising that its oil and gas export revenue gives it the highest GDP per capita in the world. At the end of the last decade, it overtook three Asia-Pacific competitors, Indonesia, Malaysia and Australia, to become the largest LNG exporter. Qatar’s small domestic energy market enables it to primarily target export markets with its gas, although industrial expansion and the start-up of the Pearl gas-to-liquids (GTL) plant should double Qatar’s gas consumption between 2011 and 2018, according to the International Energy Agency. Qatar will still have no problem in supplying gas to export markets – even with its moratorium on further development of the giant offshore

Peter Kiernan, The Economist Intelligence Unit, UK, looks at the evolving tale of the Middle East LNG market.

SEP/OCT 2013

14

20 Changing landscapeNadja Kogdenko, Energy Delta Institute, the Netherlands, looks at the rapid transformation of the global LNG industry.

26 Missing piece of the puzzleTom Haylock and Inga Bettina Waldmann, KANFA Aragon, Norway, look at pre-treatment – the often overlooked piece in the FLNG puzzle.

33 Heating upRoly Juliano, Watlow, USA, discusses optimal design features for electric heaters in glycol reboilers.

39 Removing the guessworkRalph H. Weiland and Nathan A. Hatcher, Optimized Gas Treating, Inc., USA, explain how precision mass transfer rate-based simulation removes reliance upon ‘rules of thumb’ in glycol dehydration.

45 Expanding horizonsBill Howe, Geoff Skinner and Tony Maunder, Gasconsult Ltd, UK, discuss the development of new liquefaction technology.

51 Rocking & rollingGregory P. Wood, Ebara International Corp., USA, outlines how cryogenic pumps that have been used in land based installations are also suitable for FLNG vessels.

55 Modifying expectationsSteve Busby, Adanac Valve Specialities Ltd, UK, asks whether valve modification could provide the answer to the industry’s supply and demand concerns.

59 Insulation innovationsSteve Oslica, Pittsburgh Corning, USA, examines the developing challenge of material selection in the cryogenic insulation industry.

62 A long time comingErik Admiraal, Demaco, the Netherlands, outlines the benefits of vacuum insulated pipeline systems in LNG transfer.

66 Innovation through collaborationGeoff Sewell, Clinton Lourens and Brenton Keast, John Holland Minerals & Industrial, Australia, review the benefits of a ‘project specific – design for construction’ delivery model in executing the Curtis Island product loading jetties.

72 Ready, set, go!Laurent Poidevin, Nicolas Duhamel and Joel Fusy, FMC Loading Systems, France, offer an offloading solution to help prepare customers for upcoming markets.

77 Bridging the gapAnders Torud, NLI Innovation, and Peter Stockley, Wilhelmsen Technical Solutions, Norway, discuss how bunker design can facilitate the use of LNG as fuel.

81 Shipping solutionsJürgen Harperscheidt, TGE Marine Gas Engineering, Germany, looks at the challenges of supplying high pressure gas for two stroke engines.

85 The next step Brad Bodwell and Randy Hull, Prometheus Energy, USA, look at the accelerating market for off-highway LNG and its future use in fuelling fracturing operations.

89 Power in your handsOsvaldo del Campo, GNC Galileo S.A., Argentina, addresses the challenge of bringing LNG production into consumers’ hands.

93 Equatorial equationDhirav Patel, Tom Phalen and John Mak, Fluor, USA, explain why LNG vaporiser selection should be based on a site’s ambient conditions.

99 Listening to the earth Katherine Jeziorski, ESG Solutions, Canada, looks at ways to mitigate risk in natural gas storage using passive seismic monitoring.

105 Up in the cloudColin Watson, Symetri, UK, asks “What can the Cloud do for the LNG Industry?”

109 Know your neighboursLisa Hardess, Hardess Planning Inc., Canada, explains why a better response to Aboriginal concerns is needed for projects in Western Canada.

05 Comment07 LNG news14 The Middle East LNG story


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LNG exports from the US are finally gathering some momentum. In the last five months, the US Department of Energy (DOE) has granted three

companies approval to export LNG to countries that do not have a free trade agreement with the US (the fourth permit granted in total). The DOE approved each of the applications following careful consideration of economic, energy security and environmental impacts. It also sifted through public comments for and against each application, concluding that exports are not inconsistent with the public interest.

The importance of public opinion to the success of any project within the oil and gas industry has been highlighted recently by the intense anti-fracking protests witnessed at Cuadrilla’s test drilling site in Balcombe, West Sussex, UK. In August, the sheer number of protestors on site forced the company to temporarily halt its operations due to safety concerns. And although Cuadrilla’s recent decision to withdraw plans to extend drilling on the site has been attributed to legal ambiguity about underground boundaries, campaigners have greeted the news as a victory for them – a clear demonstration of ‘people power’.

Western Canada faces a similar challenge as it looks to ramp up development of its burgeoning LNG industry. Christy Clark, the Premier of British Columbia (B.C.), has heralded the LNG sector as critical to the region’s long-term economic well-being, suggesting that it could create up to 100 000 new jobs. However, reports suggest that there is growing unrest within local communities affected by proposed pipeline routes. As well as expressing concern

about the overall impact on the region, locals also complain that there has been a lack of consultation as crews begin to carry out ‘non-invasive’ work to assess possible pipeline routes from the northeast gas fields to proposed new terminals on the West Coast. To add to the complexity of the situation in B.C., those companies looking to develop LNG projects in the region must also consider the aboriginal communities located on potential pipeline routes. A legal precedent from the Supreme Court of Canada insists that there must be consultation and engagement with First Nations over projects that could impact their traditional territory. As such, the overall success of the LNG industry in B.C. is largely in the hands of its Aboriginal population.

In order to avoid opposition that could result in costly project delays, as witnessed at Cuadrilla’s Balcombe drilling site, it is essential that LNG project proponents take the initiative to build meaningful relations with the local communities that could be affected by their plans, right from the start. Starting on p. 109 of this issue, Hardess Planning Inc. takes a closer look at the delicate situation unfolding in Western Canada and offers some practical suggestions to help ensure that projects are granted a ‘social license’ to operate, as well as a government license.

On the topic of public opinion, following consultation with our readers, LNG Industry is delighted to announce that we will publish an extra three issues next year, taking our annual number of publications to nine. Keep your eyes on EnergyGlobal.com for our 2014 media pack, coming soon, as well as for news of another exciting development for LNG Industry...

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LNGNEWS


Australia

FLNG venture for Woodside

Woodside Petroleum has announced that the Browse Joint Venture participants have selected

the use of floating LNG (FLNG) technology as the development concept to commercialise the three Browse gas fields.

This concept involves using Shell’s FLNG technology and Woodside’s offshore development expertise for the Browse LNG development. The Browse Joint Venture participants have agreed to progress Basis of Design (BOD) work in relation to the selected development concept.

The BOD phase will determine the major design parameters for Front End Engineering and Design (FEED) of the proposed subsea and FLNG facilities and associated infrastructure.

The BOD phase will be executed by Woodside as operator of the Browse Joint Venture, with support from Shell as the FLNG technology provider, to enable the optimal development of the Browse resources.

Work will commence immediately to undertake all of the necessary studies and work required to place the Browse Joint Venture participants in a position to consider the commencement of FEED for the selected development concept in 2014.

The Netherlands

Gate terminal loads first tanker with small scale LNG for Eneco

For the first time in its history, a Gate terminal LNG tanker has been loaded with LNG. In early September,

the Coral Methane docked at Gate terminal on the Maasvlakte in Rotterdam. This first LNG export arises from a contract between Eneco and AGA Gas AB for the transit of LNG to Scandinavia.

Eneco considers LNG as a valuable addition to its existing gas portfolio. The use of LNG as fuel in the transport sector reduces particulate emissions and other

environmentally harmful substances. This market has great potential because of the stricter emission standards around European coastal waters.

The Gate terminal not only has the ability to transport natural gas to industries, power plants, and households, through the pipeline network in gas, but also to serve as a clean alternative to traditional transport fuels for shipping and heavy traffic. As a first step, Gate has erected scaffolding for receiving small/medium sized LNG tankers.

USA

Black & Veatch teams with Honeywell UOP

B lack & Veatch and Honeywell’s UOP have created an alliance to market and implement Black & Veatch’s

PRICO® E Pack plant, a standardised LNG production facility, for the rail, on-road, off-road, and marine industries.

The alliance pairs Black & Veatch’s patented, single-mixed refrigerant loop for natural gas liquefaction with Honeywell’s UOP Russell modular plant equipment and its gas processing technology. The combined offering allows North American clients to achieve savings through expedited delivery and construction time of the small scale LNG plant.

LNG is an ideal transportation fuel option. It has a high storage density that makes it a viable option to displace diesel for high horsepower or heavy duty vehicle applications. LNG can also be produced at a relatively low cost and is cleaner burning than traditional fuel choices. According to a press release on Black & Veatch’s website, the complete small scale LNG plant offering will be available this year.

“Natural gas as a transportation fuel provides clear economic and environmental benefits,” said John George, Vice President and Oil & Gas Manager for Black & Veatch. “Now that natural gas is more readily available, transportation companies can make the switch to LNG in a faster and more cost-effective manner with PRICO® E Pack.”

LNG_SepOct_2013_07-13.indd 7 25/09/2013 14:51

LNGNEWS

NEWS HIGHLIGHTS


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First FLNG turret sets sail to South Korea

General Electric to oversee diesel-LNG transitions

US LNG producers set to benefit from Panama Canal expansion

SwedenSkangass to supply natural gas to SSAB EMEA

Skangass AS has entered into a long-term agreement for the supply of natural gas to the Swedish corporation

SSAB EMEA AB in Borlänge. The natural gas will replace fuel oil in one part of the production process at SSAB.

The use of natural gas will lead to a considerable reduction in CO2 emissions in Borlänge, reported to be approximately 40 000 tpy. This is comparable to the emission size of 22 000 diesel vehicles annually driving 15 000 km.

The agreement includes building a regassification terminal at SSAB’s premises in Borlänge. The terminal will be owned by Skangass but will be built in close co-operation with SSAB’s own project group. The terminal will employ the hot water evaporator attached to the local district heating system. It will be completed in the second half of 2014. Natural gas will be distributed from Skangass to Borlänge by road.

Skangass produce LNG at its plant in Risavika, outside Stavanger. The LNG is distributed by its own vessels to distribution terminals in Scandinavia. The terminal in Lysekil will be the main LNG source for SSAB.

The Arctic

Safer Arctic passage for LNG tankers

In response to the demand for safer LNG transportation in the Arctic regions, Bureau Veritas (BV) has developed new

high-tech tools to monitor cargo sloshing in ice conditions. The company has also developed a probabilistic method for assessing ice loads on structure, which will shorten the time and data necessary to assess the structure of ships and tankers designed for heavy operation.

The IceSTAR ice load calculation tool is designed to analyse the kinetic energy imparted to the cargo by a collision with ice. The kinematics calculated by IceSTAR are then used together with CFD analysis to determine how the cargo will slosh and the extra loads this will impose on both the ship’s structure and the LNG containment system.

Director of Innovation at BV, Pierre Besse, stressed the importance of having the IceSTAR module in place as the probability of collision between cargoes and ice is high in the Arctic region. “When gas and oil cargoes begin moving regularly through the Arctic”, he said, “it is certain that ships and ice will interact. The energy from those collisions will cause the cargo to move violently, and we have to make sure the ships and especially LNG containment systems are built to withstand that.”

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LNGNEWS


DIARY DATES

14 - 16 October 2013LNG Tech Global SummitBarcelona, Spainwww.lngsummit.com

10 - 13 November 2013ADIPECAbu Dhabi, UAEwww.adipec.com

10 - 11 December 2013Tank Storage Asia Singaporewww.tankstorageasia.com

24 - 27 March 2014Gastech 2014Goyang City, South Koreawww.gastechkorea.com

12 - 13 November 2013European Autumn Gas Conference Brussels, Belgiumwww.theeagc.com

18 - 21 November 2013World LNG SummitParis, Franceworld.cwclng.com

Russia

Gazprom looks to build regasification terminal

Gazprom is looking to build an LNG regasification terminal on the Baltic coast of the Kaliningrad

Region.At the ceremonial event for commissioning the

Kaliningrad underground gas storage (UGS) facility (Phase 1), Alexey Miller, Chairman of the Gazprom Management Committee, and Nikolai Tsukanov, Governor of the Kaliningrad Region, signed an Agreement of Understanding and Cooperation in relation to the proposed regasification project.

Pursuant to the Agreement, the Regional Government said that it would provide assistance to Gazprom in obtaining the approvals required for the construction as well as in the land allocation issues.

An Investment Rationale is currently being carried out for this project and is set to be completed in 2014.

Gazprom had previously announced that it was looking into the possibility of building an LNG plant in the Baltic Sea that would produce the gas, rather than just regasifying it.

According to reports, the decision to build an LNG regasification terminal follows a disagreement with neighbouring Lithuania over gas prices and distribution.

Qatar

Qatargas and Petronas sign SPA

Qatargas 4 and Petronas LNG (UK) have singed a five-year Sales and Purchase Agreement (SPA) for an

LNG volume of 1.14 million tpy. This will be in effect as of January 2014, and will see LNG supplied from Qatargas 4 (train 7) – a coalition of Qatar Petroleum and Shell – and carried on Q-Flex LNG Vessels to Petronas’ UK base Dragon LNG Terminal.

Minister of Energy & Industry and Chairman of the Board of Directors of Qatargas, Mohammed Bin Saleh Al-Sada, signed the SPA for Qatargas. He said that the deal is “another milestone in Qatar’s standing as a reliable international energy supplier.” He hailed “a ground-breaking agreement between two well established and leading energy companies in the LNG sector”, and emphasised the resulting strengthened relationships between the two companies.

Qatargas CEO, Khalid Bin Khalifa Al Thani, expressed delight at the companies’ broadening its customer base and worldwide LNG reach. “We in Qatar are very proud to partner with Petronas and its subsidiary Petronas LNG (UK) for the UK market which continues to be one of the most important LNG markets in Europe. This SPA further demonstrates Qatargas’ commitment as a reliable LNG supplier to the world,” he said.

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LNGNEWS


IndiaIndian Railways to use LNG for locomotives

Indian Railways has begun plans to use LNG as fuel for its locomotives, which currently run on

diesel. The construction of a locomotive prototype which will run on LNG will be overseen by the Research Design & Standard Organization (RDSO), a research wing of the ministry of railways based at Lucknow. After completing and testing the success of the prototype, the company plans to build a further 20 LNG-based trains.

The move will reduce both regulated and unregulated emissions, e.g., NOx. It will also help eliminate visible smoke from the locomotives, according to a railway official.

A source close to Indian Railways said: “To make use of global reserves of natural gas, India is setting up infrastructure for import of LNG into the country [...] LNG terminals are in various stages of setting-up on the east and west coasts of India, all with railway connectivity.”

Currently, Indian Railways runs its trains on diesel and electricity, which, due to inflated crude oil prices, imported coal and depreciation of the Rupee, have become progressively more expensive.

Belgium

Port of Antwerp and EXMAR announce strategic alliance for LNG bunkering in Antwerp

The Antwerp Port Authority has selected EXMAR as its partner in developing LNG bunkering at the port in

Belgium. Construction of the ship is expected to begin in early 2014. Fuel studies will also be undertaken by both parties.

CEO of Antwerp Port Authority Eddy Bruyninckx, said: “The Port Authority wishes to not only encourage but also to facilitate the use of LNG as ship fuel because of the associated environmental and sustainable benefits. The Port Authority therefore wants to ensure that ships calling

the port of Antwerp are able to bunker LNG as ship fuel as from 2015.”

Nicolas Saverys, CEO of EXMAR, said: “EXMAR is very pleased to work together with the Port Authority on developing LNG bunkering in Antwerp. EXMAR considers LNG bunkering as a strategic target market for the coming years. Independent studies indicate that the LNG bunkering market has a worldwide potential of an additional tens of millions of tonnes of LNG per year by 2020.”

USA

Dominion LNG application approved by DOE

The US Department of Energy (DOE) has sanctioned Dominion Cove Point LP’s application to export LNG

to countries without a free trade agreement (FTA) with the US. Dominion Cove Point’s LNG unit on Cheapside Bay has been awarded conditional authorisation to export up to 0.77 billion ft3/d for 20 years.

Bill Cooper, President of Center for Liquefied Gas, said: “We welcome the announcement of DOE’s approval order for Dominion Cove Point LNG, which is a further step in the right direction towards realising the economic benefits expanded LNG exports will bring to the U.S. However, we urge DOE to continue the momentum and move forward with the 20 applications that remain pending. With a robust regulatory process in place and thorough review conducted, LNG exports will clearly be a win-win for our economy, industries and consumers.”

Dominion’s LNG liquefaction and export operations are due to get underway in 2014, once regulatory approval and permits have been ratified, with a view to completion by 2017. It is estimated that construction will cost in the region of US$ 3.4 – 3.8 billion.

Pacific Summit Energy LLC and Gail Global (USA) LNG LLC have both signed contracts that will see them operating at the terminal for 20 years, and render the terminal fully subscribed.

LNG_SepOct_2013_07-13.indd 12 25/09/2013 15:56

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Middle EastThe

LNG STORY

LNG_SepOct_2013_14-19.indd 14 24/09/2013 14:40


W ith 43% of the world’s proven gas reserves, it may come as a surprise that some countries in the Middle

East import LNG. Yet despite the fact that the Middle East is abundant in natural gas resources, the gas supply and demand balance of each country in the region varies greatly, and in some cases is in a state of transition. A combination of factors, such as under-investment in the upstream gas sector, rapid energy demand growth, and high domestic gas consumption levels, have prevented the region from being as prolific an exporter of gas as it is with crude oil.

Apart from Qatar (the world’s largest exporter of LNG) and a few other cases (Oman, Yemen and Abu Dhabi), most states in the Middle East prioritise natural gas to meet domestic needs. For some, such as Kuwait and Dubai, LNG is imported to make up for domestic supply shortfalls.

The LNG story in the Middle East is therefore multi-faceted. LNG king Qatar faces a changing landscape in global gas markets with more competitors entering the scene; a new LNG exporting-hub is expected to emerge in the once resource-starved Eastern Mediterranean; and some states are expanding, or introducing, regasification

capacity to cope with growing energy demand. The Middle East LNG story may not always be a headline grabbing one, but there is a lot more to it than meets the eye.

Qatar: king for not much longerQatar benefits enormously from a generous endowment of natural gas reserves (885 trillion ft3 and the third-largest in the world behind only Iran and Russia). For a country of only 1.9 million residents (of which only 10 – 20% are Qatari citizens), it is not surprising that its oil and gas export revenue gives it the highest GDP per capita in the world. At the end of the last decade, it overtook three Asia-Pacific competitors, Indonesia, Malaysia and Australia, to become the largest LNG exporter. Qatar’s small domestic energy market enables it to primarily target export markets with its gas, although industrial expansion and the start-up of the Pearl gas-to-liquids (GTL) plant should double Qatar’s gas consumption between 2011 and 2018, according to the International Energy Agency. Qatar will still have no problem in supplying gas to export markets – even with its moratorium on further development of the giant offshore


LNG_SepOct_2013_14-19.indd 15 24/09/2013 14:40


North Field – although, like its energy-hungry neighbours, it can curb domestic consumption with better efficiency measures and reducing energy subsidies.

A greater challenge for Qatar, however, is the emergence of new LNG-exporting hubs to meet rising global demand for natural gas. Australia will overtake Qatar as the largest global LNG exporter, with seven LNG plants under construction that will increase its liquefaction capacity from 24.3 million tpy to

85.6 million tpy by the end of this decade. Further capacity additions in Australia will dramatically slow down due to the high cost of constructing liquefaction plants, but Australia will displace Qatar as the prime LNG exporter just with projects already under construction.

North America will emerge as an LNG-exporting hub from the end of this decade, especially in the US. Unlike the pricing system used by most established LNG exporters such as Qatar,

The exportersThe Middle East has the largest LNG export capacity of any region in the world, almost all of which belongs to Qatar, which began exporting LNG in 1997. Between 2004 and 2011, both Qatargas and RasGas brought nine additional LNG trains online (six between 2009 and 2011) to boost Qatar’s total LNG export capacity to 77 million tpy, making it the largest LNG exporter in the world with 27.3% of total LNG liquefaction capacity of 282 million tpy in 2012. Three other countries in the region also export LNG, Oman (10.7 million tpy), the UAE’s Abu Dhabi (5.8 million tpy), and Yemen (6.7 million tpy), bringing the region’s liquefaction capacity up to 100.2 million tpy, or 35.5% of the global total.

The vast majority of Middle East LNG goes to Asian markets. In 2012, Qatar, Oman, Yemen and Abu Dhabi exported 65.7 million tpy of LNG to Asia (China, India, Japan, South Korea and Taiwan), or 70% of the total volume of LNG exported from the Middle East. Qatar also exported 22.7 million tpy to European markets, while a small volume (4.8 million tpy) found its way to the Americas. Abu Dhabi also sent a tiny amount of LNG to its Emirati neighbour, Dubai. Overall, Qatar, Oman, Abu Dhabi, and Yemen accounted for 40% of total LNG exports last year, with Qatar alone accounting for 32.3%.

The Eastern Mediterranean region will be a major exporting hub by the end of this decade, with Israel and Cyprus expected to cash in on big offshore gas discoveries by developing LNG for European and potentially Asian markets. Currently, Egypt exports LNG, although declining production and political turmoil has seen export volumes slump to well below capacity. Although Egypt’s two LNG terminals can export 12.2 million tpy, in 2012 Egypt exported less than half of that (4.7 million tpy).

With no liquefaction plants under construction, Middle East LNG export capacity will remain stable for the rest of the decade. Qatar has yet to lift its moratorium on further development of the North Field, while Abu Dhabi and Oman face growing domestic requirements for energy. Political instability in Yemen may discourage further exploration for gas, or to add LNG capacity.

The importersPersian Gulf gas consumption has doubled since 2000, and has increased rapidly in the two places that are currently importing LNG:

Kuwait and the UAE’s Dubai. In both cases, LNG is regasified on a FSRU that can be used when demand for gas peaks and supply issues become acute, such as during the summer months. FSRUs are small scale and more flexible than larger, fixed onshore terminals, and can be used on a seasonal basis, or temporarily as a stop-gap measure (Israel used a floating facility to import LNG before production at the Tamar field started up earlier this year).

The UAE emirate of Fujairah is constructing an onshore terminal with a capacity of 8.7 million tpy, while Kuwait plans to build on its import capacity through the construction of an onshore plant in two phases, which could add 22 million tpy to capacity by 2020. At the very least, 11 million tpy will be commissioned by 2018. Jordan, which has insignificant conventional oil and gas reserves, plans to construct a FSRU in the Gulf of Aqaba to compensate for loss of Egyptian pipeline supply, and to eliminate the need to import oil for power generation. Bahrain also plans to import LNG (although plans are not yet developed), while Egypt plans to import with the construction of a FSRU as gas production and upstream investment dwindles.

Table 2. Middle East/East Mediterranean LNG exporters

Country Plant Number of trains Capacity (million tpy)

Oman Qalhat 3 10.7

UAE (Abu Dhabi) Das Island 3 5.8

Yemen Balhaf 2 6.7

Qatar Rass Laffan 14 ( 7 RasGas, 7 Qatargas) 14 ( 7 RasGas, 7 Qatargas)

Egypt Damietta, Idku 3 12.2

Source: International group of LNG importers

Table 1. Middle East LNG importers

Country Plant Capacity (million tpy)

Kuwait Jebel Ali FSRU 4.1

UAE (Dubai) Mina Al Mahdi FSRU 5.2

Under construction

UAE (Fujairah) 8.7

Planned

Kuwait 21.9 (phase one and two 10.95 each)

Bahrain n/a 3.6

Jordan Gulf of Aqaba FSRU 3.6 – 5.4

Egypt n/a 3.7

Sources: International group of LNG importers, and press reports

LNG_SepOct_2013_14-19.indd 16 24/09/2013 14:40

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US LNG export prices will not be based according to oil indexation. With oil prices high, the price of oil-indexed LNG is also high, but US LNG will be based on the cheaper US Henry Hub spot price. In August, the Henry Hub spot price was trading at around US$ 3.40/million Btu, which compares favourably to the average price of LNG for August delivery in Asia of US$ 15.46/million Btu. Asian LNG buyers are likely to seek LNG volumes from the US to ease reliance on the oil-indexed long-term contracts that suppliers such as Qatar normally offer. That said, oil-indexation does offer consumers stability in pricing while long-term contracts enable suppliers to make a return on the costly investments in liquefaction capacity. It is unlikely that these facets will disappear from the Asian LNG market altogether, although the prevalence of oil-indexed long-term contracts will be diluted somewhat should there be a splurge of US LNG reaching Asian markets.

To date, four companies have received approval from US authorities to export LNG to countries that do not have a Free Trade Agreement with the US, with the total capacity of these projects being approximately 46.5 million tpy. Canadian authorities have awarded export licenses to three LNG projects with a combined capacity of between 22.9 and 34.9 million tpy. Meanwhile, recent big offshore gas discoveries in East Africa have opened up the opportunity for LNG exports from Mozambique and Tanzania, most likely beginning in the early 2020s.

Despite these evolving trends, Qatar is not hitting the panic button. To date, the country has no plans to expand its liquefaction capacity, or revisit the moratorium on further development of the giant North Field (which has been in place since 2005). Furthermore, in 2012 Qatar continued to sign long-term supply and purchase agreements with Japanese, Korean and Thai customers. The emirate might appear relatively relaxed about its future role as a leading global LNG supplier, but it is likely that in future it will have to be more flexible in contract negotiations with potential customers. One advantage Qatar does have is that the cost of its LNG production is relatively cheap, especially compared to Australia, as well as to what will be supplied by emerging exporters such as Canada and Russia.

In addition to the emergence of new suppliers targeting the Asian market, Qatari officials will also be watching demand-side factors, such as the future of Japan’s reliance on nuclear power and how this will impact its LNG requirement, and how successful China will be in developing its own unconventional gas resources as it expands the role of natural gas in its energy mix.

Bounty in the Eastern MediterraneanMiddle East LNG has been focused on the Persian Gulf, but the Eastern Mediterranean has emerged as an exciting new frontier for the industry. Big offshore gas discoveries in Cyprus (Aphrodite) and Israel (Tamar and Leviathan) mean that both countries can develop LNG for export, given the quantity of supply that is expected to be available and the small size of their respective domestic energy markets. An Eastern Mediterranean gas-exporting hub, however, also brings with it some tricky geopolitical issues, given the state of Israel’s relations with its Arab neighbours, and the unresolved dispute between Turkey and Cyprus over the status of the northern part of the island that Turkey has occupied since 1974.

With several offshore gas discoveries, Israel will be able to eliminate the need to import gas and fuel oil for power

generation, and reduce usage of (imported) coal in the power sector. In addition, there will be reserves available for export markets, with LNG an option. The Israeli government has reserved 60% of the country’s estimated offshore gas reserves (900 billion m3) for the domestic market, allowing the remaining 40% to be exported. The issue of how Israel’s gas bounty should be used is a contentious one, and the Netanyahu government has adopted an interventionist approach by apportioning the majority of Israel’s gas reserves to meet domestic needs. Originally the Israeli government preferred a 50/50 split in gas reserves between the domestic and export markets, yet even a 40% share for exports would still leave an export quota of 360 billion m3 (260 million t).

Several options are being considered for the export of Israeli gas by Noble Energy and its partners that made the Tamar, Leviathan and other sizeable offshore gas discoveries. These include an onshore liquefaction plant in Israel, a floating LNG facility off the Israeli coastline, and an onshore plant in Cyprus that would be supplied by both Israeli and Cypriot offshore gas fields (Noble Energy also made the Aphrodite discovery in Cypriot waters). Less costly pipeline options have been mooted, such as linking Israeli gas directly to Turkey. Politically, the LNG option would be the most feasible for Israel, provided that the issue over which development option to use is resolved. But liquefaction will also be costly, and Noble Energy and its partners would be disappointed about the imposition of a quota that must be allocated for the domestic market. A domestic supply quota may also complicate efforts to lure potential investors, such as Australia’s Woodside, from partnering with Leviathan’s operators to develop LNG. Furthermore, the Israeli government is reportedly sceptical of plans to build a facility in Cyprus to liquefy Cypriot and Israeli gas, while there are likely to be environmental objections to locating an onshore plant on the densely populated Israeli Mediterranean coast, or at Eilat in the Gulf of Aqaba.

The pipeline option for Israeli gas exports will be cheaper compared to LNG, but it has its hurdles as well, which are mainly geopolitical. Turkey’s relationship with Israel is volatile, and a pipeline through the Eastern Mediterranean could arouse objections from Lebanon and Syria. Furthermore, Turkey’s opposition to Cyprus’ oil and gas exploration efforts would make it difficult for Ankara to accept gas from Israel if it engages in energy cooperation with Cyprus itself; such as joint development of Cypriot and Israeli gas fields.

The prospect of Israeli LNG entering the market at some stage is still strong, although to date, which LNG development option to push has yet to be decided. As of early August, Cyprus was reportedly pushing ahead in talks with Noble Energy for the construction of an LNG plant. By the beginning of the next decade, the Eastern Mediterranean will be another source of gas supply for export that will emerge, in addition to East Africa and North America.

The Middle East is an import market tooIf you exclude Qatar from the equation, the Arab Middle East will become a net importer of LNG by the end of the decade. This does not seem as ridiculous as it sounds. The Middle East does have plentiful gas reserves, but these are heavily concentrated among three countries: Iran, Qatar, and Saudi Arabia. Qatar is the only one of these that exports gas as LNG, while Iran and Saudi Arabia, due to their sizeable domestic gas markets, are unlikely to become LNG exporters anytime soon.

LNG_SepOct_2013_14-19.indd 18 24/09/2013 14:40

Saudi Arabia is prioritising upstream gas investment, but for the domestic market (to replace oil consumption in the power sector), and Iran faces sanction barriers to access the technology to develop LNG capability. Instead, Iran is focusing on regional pipeline export projects to Iraq and Pakistan (it currently exports pipeline gas to Turkey and Armenia).

This leaves other small Gulf States, which are not as well-endowed with natural gas reserves, as well as Jordan whose reserves of hydrocarbons are negligible. These states, which subsidise electricity prices to keep them cheap, face rapidly growing power generation needs, and in some cases are developing desalination and petrochemical projects. This has led to soaring demand for natural gas, beyond what some of the states can domestically produce. Low domestic prices have also meant that investment in the upstream non-associated gas sector has underperformed, leaving domestic output languishing. Combine this with rapid economic growth brought about by high oil prices, and states such as Kuwait suddenly find themselves needing to import natural gas to meet soaring domestic needs. Importing LNG may be expensive, at around US$ 13.45/million Btu, but the high price of oil means that it makes economic sense compared to burning crude oil for power generation; at least in the short to medium-term. Rather than burn valuable crude – which can fetch over US$ 100/bbl if it is exported – for domestic power generation, the use of gas for electricity frees up that crude oil for vital export dollars. Using natural gas can also help to develop the industrial base of Persian Gulf economies, e.g. through petrochemicals.

In the short to medium-term, the need for some Persian Gulf states to import LNG will remain. Indeed, before the end of the decade, Jordan, Bahrain, and the UAE’s Fujairah will join the ranks of LNG importers, while Kuwait plans to expand regasification capacity. Exporters such as Abu Dhabi and Oman also need to assess the desire to maintain LNG exports in the face of growing domestic requirements for gas. Meanwhile, Egypt, a declining LNG exporter, plans to build LNG import capacity with the construction of a floating storage and regasification unit (FSRU).

In the long run, however, importing LNG may become less viable. As a result, Persian Gulf states can take measures on the demand side to reduce reliance on regasification capacity. These include reducing energy subsidies, improving energy efficiency, developing other energy sources for power generation such as solar, and lifting the industrial price for gas. Prices that reflect market realities would also encourage investment in non-associated gas resources, boosting domestic production. That said, even if states took these measures, a turnaround towards a reduction in regional regasification capacity would only be seen in the longer term.

In conclusion, the Middle East LNG story is an evolving one. Qatar will remain a key LNG supplier but will have to watch the emergence of new exporters that will target the Asia-Pacific market, and the Eastern Mediterranean will become a gas-exporting hub as well. In the meantime, other Persian Gulf states will require LNG to meet their growing energy needs, although this can be alleviated with some effective demand-side policies.

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LNG_SepOct_2013_14-19.indd 19 24/09/2013 14:40


Nadja Kogdenko, Energy Delta Institute, the Netherlands, looks at the rapid transformation

of the global LNG industry.

CHANGINGLANDSCAPE

LNG_SepOct_2013_20-25.indd 20 25/09/2013 15:19


In the last decade, the global LNG industry has undergone a considerable process of alteration, changing business models

of energy companies worldwide. After strong demand growth in 2010, the LNG market experienced a glut. The US, previously a significant importer of LNG, now relies more on domestic shale gas production, transforming into a potential gas exporter and changing the global LNG trade arena. In addition, the consequences of the tragic earthquake in Japan (2011) led to a temporary shutdown of 54 nuclear power plants, leaving the country to rely on LNG to fill its energy gap. With the plans to phase out nuclear power in the next few decades, the role of LNG in Japan will increase even more. Meanwhile, growing concern about the environment, coupled with the need to enhance energy security, is driving countries to focus on LNG and increase their consumption of natural gas. Additionally, small scale LNG is increasingly discussed on political agendas of countries seeking to ‘gasify’ remote regions (such as Russia) and improve local energy supply. Rapid developments are also taking place in the use of LNG as a transport fuel (in heavy duty vehicles and marine transport). Who knows what changes are still to come in the LNG world?

This article gives a brief overview of the latest developments in the global LNG industry and some insights into future trends.

LNG – the fastest growing segment LNG has turned into one of the fastest growing segments of the global gas industry. In the last decade, global LNG regasification capacity has almost tripled, reaching 640 million tpy in 2011 compared to 251 million tpy in 1999.1 During the same time frame, the global liquefaction capacity doubled and a number of new countries

LNG_SepOct_2013_20-25.indd 21 25/09/2013 15:19


entered the global LNG business, reaching a total of 25 LNG importing and 18 LNG exporting countries.2 At the end of 2011 the world LNG trade reached 241.5 million t, growing by 8% primarily due to the sharp increase in demand from Japan as a consequence of the 2011 earthquake. According to market research performed by Ernst & Young,3 the global demand for LNG is expected to grow around 5 – 6% per annum over the next 15 years (faster than the overall gas market, respectively 2.5%), thus almost doubling by 2030. It is also projected that the number of countries with LNG import terminals could double by 2020 compared to 2012.

Emerging Asian markets and their thirst for LNGIn Asian countries, natural gas is increasingly viewed as a part of the solution to diversify energy sources in the region, secure rapidly growing energy demand and limit growth in carbon emissions and pollution in general. Since the opportunities for pipeline gas transportation in the Asia-Pacific region are rather limited for geographic reasons, LNG is seen as the most viable option for emerging energy demand. In fact, the Asia-Pacific region is already a major actor in the global LNG arena, accounting for over 63% of total global LNG imports in 2011. Japan and South Korea are the two largest importers of LNG, with 78.7 and 35.8 million tpy of imports, respectively, in 2011.4 Smaller Asian economies are also actively joining the LNG business due to a lack of domestic natural gas resources. The Economist Intelligence Unit estimates that natural gas consumption in the Asia-Pacific region will reach 800 billion m3 by 2014, compared to 558 billion m3 in 2010, exceeding gas demand in the US. The largest increase (over 50%) is expected to occur in China.5

China’s latest Five-Year-Plan foresees ‘gasification’ of the Chinese economy and therefore implies a significant increase of natural gas share in the country’s energy mix, rising from ~4% in 2010 to 8% in 2015, with a longer-term goal of 10% by 2020. The IEA projects that China’s natural gas demand could reach 545 billion m3 by 2030. For this reason, China is expected to be one of the biggest sources of additional LNG demand. There are seven LNG import terminals currently

under construction in the country and several others are in the planning stage.6

With regard to LNG supplies in the Asia-Pacific region, Malaysia, Indonesia and Australia are the largest ‘local’ suppliers, although Indonesia has recently approved plans to begin importing LNG to meet the country’s rising demand for natural gas. Qatar is still the single largest supplier to Asian markets and the number one LNG exporter in the world. However, Australia has been positioning itself to emerge as a leading player in the global LNG industry by the end of this decade.5 Currently, Australia has three operational LNG export plants with a total capacity of 24.3 million tpy, and seven other LNG projects (with a total additional export capacity of 61 million tpy), which are close to a final investment decision.6 Nevertheless, some of the proposed projects might be delayed or cancelled due to higher than anticipated development costs. According to McKinsey Global Institute, the costs of building new LNG projects in Australia is nearly 20% higher than in North America.7 Besides costs, other risks, such as scarce labour supply, infrastructure bottlenecks, tight environmental regulations, and the potential development of unconventional gas reserves in China and Japan, endanger the future of new LNG projects in Australia.

North American LNG export potential In the early 2000s, many investments were made in North America to expand LNG import capacity in order to meet increasing demand. At that time, domestic gas production was in decline and the potential for shale gas development was underestimated. There were about 47 LNG receiving terminals in the US in the permitting phase, three existing ones were re-commissioned and eight new ones were constructed.8 Domestic production of large volumes of shale gas in the US in the late 2000s has made most of these LNG terminals redundant for gas import. The ‘sudden’ glut of domestic natural gas drove the price for this commodity on the leading US gas trading hub, Henry Hub, significantly lower than in other parts of the world. In 2012, natural gas was traded

Figure 1. Indicative economics of LNG exports from the US.6 (Note: * Includes cost of pipeline transport to export terminal. ** Widening of the Panama Canal, due to be completed in 2014, will allow for more LNG tanker traffic.)

LNG_SepOct_2013_20-25.indd 22 25/09/2013 12:30

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on the Henry Hub at US$ 2.90/million Btu in June – the lowest price in the last decade, while the price for LNG in Asian markets reached US$ 16 – 17.5/million Btu.6 To put this into a broader perspective, the price for natural gas on British spot market in June 2012 was US$ 9.90/million Btu and US$ 12.0/million Btu for spot LNG in the Mediterranean.2,6

The existence of attractive markets (the Asian market in particular) has encouraged owners of the US LNG terminals to consider export of cheap domestic gas. According to Sheffield & Campbell9 , adding liquefaction to existing terminals is a low CAPEX option since about 50% of the LNG terminal value is already invested in the marine, storage and pipeline facilities. Figure 1 shows that the gap between the prevailing market price and estimated supply costs (i.e. net-back margin) is estimated to be more than US$6/million Btu for potential LNG export from the US to Japan. Even though this gap is expected to narrow to US$ 4.3/million Btu, it is still more profitable than LNG sales to Europe.6

Four LNG terminals have already received authorisation from the US Department of Energy (DOE) to export LNG to all countries, including those that do not have a free trade agreement (FTA) with the US (i.e. Japan, China and India). The first, Sabine Pass, is expected to be ready for export by 2016 and there are already four supply agreements signed (for the total of 18 million tpy) with BG Group, Gas Natural Fenosa of Spain, Gail of India and Kogas.4 The second, South Texas LNG, operated by Pangea LNG, received authorisation to export up to 8 million tpy of domestically produced LNG for a term of 25 years. In August 2013, the third DOE authorisation was granted to the Lake Charles LNG terminal in Louisiana (jointly owned by BG Group and Southern Union), for the export of 15 million tpy of LNG for 20 years. The most recent authorisation was granted to the Dominion Energy’s Cove Pont LNG (in Maryland), so far the only terminal near the Marcellus shale play. Cove Point LNG was conditionally authorised to export up to 5.3 million tpy of domestically produced LNG to all countries for a period of 20 years. However, three out of four terminals, Cove Point LNG, Lake Charles LNG and South Texas LNG, are still subject to environmental review and final regulatory approval from the Federal Energy Regulatory Commission.7

Besides the aforementioned LNG export projects, the US government is reviewing over 20 applications for LNG export terminals, received in recent months. Before any decision is made, the US government must first review the impact of LNG exports on domestic natural gas supply and prices. Sheffield & Campbell estimates the potential US LNG export at around 20 – 40 million tpy by 2035. As 40 million tpy represents around 8% of US gas consumption, exports on this scale would eventually influence national gas prices. Considering the fact that gas prices are expected to rise (Figure 1), it is quite unlikely that all of the envisaged export facilities will materialise.

Gas hydrate developments in JapanWhile much attention has been paid to shale gas developments in the US and the prospects for replication of this success elsewhere, there are several additional developments and innovations that may have a significant impact on the global LNG business.

In the beginning of March 2013, several articles appeared about Japan’s successful extraction of natural gas from so-called

‘methane hydrates’ (i.e. a ‘frozen mixture’ of methane and water molecules) deposits buried at the depth of around 1 km beneath the sea, offshore Japan. This is believed to be the world’s first successful operation of such a kind. Japan hopes to begin commercial extraction of such unconventional gas reserves within five years.10 If extraction of such gas proves viable, Japan could become the next ‘game changer’ of the LNG industry.

Innovation in LNG supply technologiesOne of the latest innovations, which is believed to become a major factor in the development of the LNG industry over the next 10 years, is floating LNG (FLNG). FLNG may prove an effective method to recover and monetise remote gas assets without the need for additional complex facilities, which are required if gas is brought onshore for treatment and liquefaction. Shell is working on the first FLNG project, which is to become the largest floating structure ever built – Prelude LNG. This is a pioneering FLNG facility (488 m long, 74 m wide, weighing 600 000 t), which will be permanently placed in deep waters for about 25 years. Construction of this facility has just started in South Korea and it is expected to become operational by 2017 – 2018, with offshore Australia being the main targeted operational area.3

Small scale LNG and LNG as a transport fuelAn increasing role of gas in the energy mixes of various countries in the world (coupled with environmental and health concerns and regulations), together with seasonal variations in gas demand and the scattered location of gas fields, has influenced several countries to consider development of small scale LNG terminals. Such terminals are designed for LNG carriers with a smaller size (from 7500 to 35 000 m3) compared to larger vessels used in the large-scale LNG business (70 000 to 265 000 m3). Small scale terminals are also characterised by a smaller LNG storage tank capacity, and a smaller send-out flow rate and send-out pressure than large scale LNG terminals.11 Current advances in gas processing technologies, increasing efficiencies in liquefaction, transport and regasification equipment, have reduced the cost of small scale LNG plants. It has also made their development more economical for gas deliveries in remotely located areas with low demand and without sufficient gas transport infrastructure or where pipeline gas supplies are not feasible. Small scale LNG will increase the market for natural gas by distributing LNG to the end-use from either a LNG plant, LNG import terminal, or directly from a LNG carrier, using a combination of both sea and land-based transport. Currently, small scale LNG is a hot topic on the political agendas of various countries and it is expected to experience rapid development in the coming decade, making natural gas a more accessible fuel.

LNG growth will also be driven by transportation. The transport sector is the single largest contributor to oil demand in many countries, consuming approximately one-fifth of global primary energy supplies.12 In the January/February issue of LNG Industry, Jay Copan mentions that emission requirements, coupled with a narrowing gap between operation costs of diesel fuel and LNG, are the primary factors driving growth for LNG as a transportation fuel. Marine transportation represents another potential market for LNG.

LNG_SepOct_2013_20-25.indd 24 25/09/2013 15:19

With the International Marine Organization introducing restrictions on emissions (coming into force in 2015 in the Emission Control Areas and 2020 for the rest of the world), LNG is becoming an alternative to current bunker fuel, due to its relatively low emissions. Copan reports that: “the use of LNG instead of diesel engines can reduce a ship’s CO2 emissions by 25% and cut its sulfur emissions by more than 80%”. Currently, five ports are busy developing LNG bunkering infrastructure in Sweden, Belgium, the Netherlands and Singapore. According to Lloyd’s Register, demand for LNG as a bunker fuel could account for as much as 8% of the global bunker fuel demand by 2025, but it will be highly dependent on the pricing of LNG and competing fuels.13

ConclusionRecent developments and trends mentioned in this article detail the emergence of a dynamic LNG industry, whose complexities and pace of development will continue to grow and fascinate. Driven by steadily rising global energy demand and environmental concerns, the fundamentals of the industry remain strong, and it can be expected that LNG trade will continue to grow, at least in the near-term. Many changes and innovations have taken place during the last decade, transforming the LNG business into what it is today. The American shale gas revolution, the potential development of other conventional and unconventional gas resources around the world, the growing role of Asian-Pacific markets in the global LNG trade, and technological

innovation, are all contributing to rapid change in the landscape of the global LNG industry with more yet to come.

References 1. ‘The LNG industry’, GIIGNL, 2011.

2. ‘World LNG report’, International Gas Union, 2011.

3. ‘Global LNG: will new demand and new supply mean new pricing?’, Ernst & Young, 2013.

4. Kiernan, P., ‘The Asian energy equation’, LNG Industry, January/February 2013.

5. ‘Tankers on the horizon: Australia’s coming LNG boom’, The Economist Intelligence Unit, 2012.

6. ‘World Energy Outlook 2012’, International Energy Agency, 2012.

7. ‘World energy news’, Financial Times, 2013.

8. Kenneth B. Medlock III, ‘Impact of shale gas development on global gas markets’, Natural gas & electricity, April 2011.

9. Sheffield, J., and Campbell, J., ‘LNG Global Survey’, LNG Industry, March/April 2013.

10. Theaustralian.com, Available at http://www.theaustralian.com.au/business/mining-energy/threat-to-lng-exports-as-japan-unlocks-gas/story-e6frg9df-1226596754089, 2013.

11. Andrieu, C., ‘Small-scale LNG import terminal: not as simple as a reduced one’, LNG 17 proceedings, Houston, Texas, USA, 2013.

12. Copan, J., ‘Turning the wheels’, LNG Industry, January/February 2013.

13. Lloyd’s Register, ‘LNG-fuelled deep sea shipping. The outlook for LNG bunker and LNG-fuelled newbuild demand up to 2025’, August 2012.

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Missing piece of the

PUZZLETom Haylock and Inga Bettina Waldmann, KANFA Aragon, Norway, look at pre-treatment – the often overlooked piece in the FLNG puzzle.

LNG_SepOct_2013_26-32.indd 26 24/09/2013 15:09


W ith three FLNG projects in execution (Shell Prelude, Petronas PFLNG 1 and Pacific Rubiales) and a raft of potential developments waiting in the wings, the technology focus

is often dominated by the liquefaction system and the question over which technology to apply. Such considerations are critical to any LNG development, but it is important that the pre-treatment and other field specific systems are considered in conjunction with the liquefaction technology so as to ensure that the efficiency and availability of the plant is maximised.

In order to select the overall best suited technology for FLNG it is hence necessary to take a step back and look at the overall process.

OverviewPre-treatment of the feed gas is a vital part of any LNG process. Pre-treating ensures conditioning of the feed gas to meet the LNG sales specifications. In practice, this means removing all unwanted components from the feed, while tailoring the combustion properties for the consumer market.

Pre-treatment of the feed gas is an interlinked chain of processes, arranged in a specific order. The pre-treatment design is very much dependent on the nature of the feed stream, and the end product requirements. The pre-treatment system can hence vary between highy complex and lean and mean.

LNG_SepOct_2013_26-32.indd 27 24/09/2013 15:09


Although not in the same league as the liquefaction system, the pre-treatment systems are also energy demanding. As with the liquefaction system, the challenge of designing the pre-treatment properly is not only to utilise the benefits of exchanging heat and mass transfer between the various steps in the process, but also to make the process and units themselves robust with respect to the offshore environment, availability and, importantly, safety.

Special considerations offshoreWhen designing a pre-treatment system for an FLNG plant, the basic functional requirements are more or less the same as an onshore LNG facility. What differs in FLNG design is that special considerations have to be made to adapt to offshore conditions. For example:

The process must be robust to vessel motions, while offering process simplicity.

Minimised weight and equipment count.

Simple operations and maintenance requirements.

Use of technology proven offshore.

Compliance with stricter offshore safety requirements.

Simple and durable technologies are most suited to FLNG applications and should be preferred over highly sophisticated process solutions in most cases.

General requirements The main purpose of the feed gas pre-treatment is to ensure that the natural gas is ready to be liquefied, i.e. it is free of impurities and meets the correct sales specifications.

Impurities that typically need to be separated from the natural gas feed include the following:

Components that form solid particles (ice) during the liquefaction process (H2O, CO2, aromatics, C5+).

Toxic components (H2S, R-OH).

Corrosive components (H2O, CO2, H2S, Hg).

Neutral gases (N2, O2).

Inorganic components.

Water (H2O), CO2 and mercury (Hg) removal are the standard pre-treatment systems found in all LNG plants. Both water and CO2 are common in natural gas and removal of these components is always necessary in order to avoid freezing and clogging of the heat exchanger(s) in the liquefaction process. Mercury is not always present in natural gas, but due to the corrosion effect it has on aluminium in the liquefaction heat exchanger, it is always necessary to have a certain level of protection included.

Acid gasAcid gases and organic sulfur components are particularly unwanted in LNG for various reasons, and include the following components:

CO2 – corrosive, freezes at cryogenic temperatures.

H2S – corrosive, highly toxic.

Mercaptans (RSH) – toxic and malodorous.

COS – may be removed to meet total sulfur content.

Typical LNG specifications are shown in Table 1. After the liquefaction system, the CO2 removal system is the most critical system with respect to heat and material balance, CAPEX and reliability. Proper design and technology selection is hence

crucial. Significant energy is required to remove these components almost independent of technology selection, and not meeting guarantee removal levels will, for example, cause lower LNG production capacity, as more frequent shutdowns are required for de-icing activities.

Several technologies are available with many already proven offshore:

Membranes.

Amine-based absorption processes (DEA, MDEA, mixed solvent).

Physical absorption.

Carbonate processes.

Adsorption technology (molsieve, silica gel).

Scavenger/solid bed.Figure 1. A simplified overview of a typical FLNG process plant (image courtesy of KANFA Aragon).

Table 1. Typical removal requirements

Component Concentration in LNG

H2S 5 mg/Nm3 (3 – 4 ppmv)

Mercaptans (S from RSH) 6 mg/Nm3

Total sulfur 25 mg/Nm3

CO2 50 ppmv

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The removal requirement of 50 ppmv is, however, much stricter than typical oil and gas export projects with removal requirements of 2.5 mol%, and a regenerative absorption based technology with amine or mixed solvent is typically required for polishing. Non-regenerative scavenger and fixed-bed type technologies can also meet the removal requirements, but the often high removal capacities required on an LNG FPSO, together with the operational costs and challenges, makes them unattractive.

Regenerative technologies require a large amount of heat, which can be a challenge. If gas turbines are selected as drivers onboard, this energy demand can easily be provided through waste heat recovery units. If, on the other hand, steam turbines are selected as direct drives, which is often the case when a complex, large, one-train liquefaction technology is selected, any efficiency benefits of the selected liquefaction system can be lost, as additional fuel gas must be burned in order to produce heat for the amine system.

For up to 2 – 5 mol% CO2 in the feed gas, amine-based systems are generally the only required system. However, many of the fields contain large amounts of CO2 and other impurities, such as H2S and mercaptans (R-OH). To find the most suitable design and technology it is important to look at the effect of the overall topside system, particularly the limitations in utility systems. As mentioned earlier, CO2 removal using amine requires a high heating medium demand while membranes, which are often considered ideal for bulk removal, require additional power consumption due to recompression requirements. H2S and mercaptans handling will also add significant complexity and CAPEX, as the typically preferred method for CO2 removal does not necessarily also remove sulfur and mercpatans down to the required level and additional add-on systems or unproven technology must be selected.

Motion consideration is also critical. The gas contactor in the amine-based system is vulnerable to vessel motions and the degree of removal (99.9%) can be affected if not designed correctly. Any slip-through of untreated gas will cause off-spec outlet concentration and risk of icing and clogging of the cold box.

WaterIn current oil and gas offshore plants, water is typically removed to 20 – 40 mg/Sm3 in order to avoid hydrate formation during export of the gas in pipelines. For these applications, technologies using absorption into tri-ethylene-glycol (TEG) is widely applied. For liquefaction of natural gas, however, almost all traces of water in the natural

gas must be removed (<0.01 ppmv), in order to avoid icing and clogging in the liquefaction heat exchanger. For these removal requirements, a TEG dehydration system is not efficient enough; an adsorption process into solids (molsieve) is the only suitable technology.

There is some perception in the industry that when liquefying pipeline gas, as is the case for many FLNG projects in the US, there is minimal requirement for water removal, as the gas is already pre-treated to pipeline quality. This is, however, a misconception, as the upstream amine system, required for acid gas removal, is saturating the gas with water. Hence the dehydration requirements are independent, whether it is a pipeline or offshore project.

Dehydration in molsieves is a regenerative thermal swing system. Typically, there will be three adsorption beds: two on-stream and one undergoing regeneration. Molsieve systems have offshore references, and have the advantage of not being influenced by the motion of the ship. However, for a floating liquefaction plant, the gas feed rate is larger than for most normal FPSO applications, and it is critical to understand the layout and margin required in order to minimise the weight of the system. Other special considerations include the following:

Free liquids in the feed gas will contaminate the molsieves and reduce lifetime.

OPEX vs. CAPEX – by nature, the molsieves will gradually degenerate over time due to the regeneration process. The time between change-out must be evaluated against the weight.

The molsieve beds inlet piping segments that can contain stagnant feed or regeneration gas must be designed in such a way that no accumulation of condensed liquids will occur.

Figure 2. A 2 million tpy Sevan Marine FLNG solution utilising KANFA Aragon liquefaction technology and pre-treatment design (image courtesy of Sevan Marine AS).

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Selection of molsieve vendor and type must include evaluation of the disposal of used molsieves. Environmentally friendly solutions should be preferred.

Dehydration itself does not affect the overall fuel gas efficiency, but the regeneration process effects must be taken into consideration as the regeneration gas requires heating to above 290 °C in order to properly remove water from the beds. Finding an optimal split between waste heat and electrical heating is often a challenge.

Pre-treatment’s potential impacts to NPVThe financial outcome for a project is dependent on many controllable and uncontrollable factors. Controllable factors are typically product quality, production rate, availability and system efficiency.

Fuel gas consumption on an offshore FLNG unit does not affect a project’s net present value (NPV) in great detail. However, it can affect the lifetime of the field.1 This also results in liquefaction cycle efficiency having a reduced impact to NPV in FLNG projects. However, should the LNG not be on specification and to the correct quality, then the project’s economics are affected greatly due to the impact to revenue. It can then be argued that the traditional focus on liquefaction cycle efficiency onshore can be a risk to the

NPV of an FLNG project, and that considering the total picture is more important.

ConclusionPre-treatment is an equally critical aspect to an FLNG development as the liquefaction system, but one that can be overshadowed by discussions on liquefaction technology selection. As with liquefaction technologies, pre-treatment solutions from onshore cannot simply be transferred offshore blindly, but thankfully onshore technologies are a good starting point, which is often not the case for liquefaction technologies. Many of the pre-treatment systems are also proven offshore. By taking account of the unique requirements for offshore together with the stricter pre-treatment requirements of LNG, a simple and robust system can be designed that is an integral part of the overall plant. This allows optimal uptime and avoids unwanted impacts to production and project revenue. The challenge is often having an understanding of both offshore and LNG to be able to address these issues.

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

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Natural gas is considered to be the most important energy source of the future because it is environmentally friendly and naturally abundant. It usually contains significant

quantities of water vapour, which must be removed in order to protect systems from corrosion and hydrate formation. This process is called ‘dehydration’, and its benefits include the following:

Preventing hydrates from forming. Hydrates have similar structures to ice and natural gas is trapped inside these structures. When hydrates are formed, they will clog pipelines and cause operational disruptions.

Increasing the heating value of natural gas. Typical commercial gas requires water content between 5 – 7 lbs/million ft3. Natural gas prior to dehydration may contain 25 – 100 lbs of water per million ft3.

The most common practice for dehydrating is the use of an absorbing media, such as the glycol family. The members of this family are: monoethylene glycol (MEG), diethylene glycol (DEG), triethylene glycol (TEG) and tetraethylene glycol (T4EG).

Roly Juliano, Watlow, USA,

discusses optimal design features for

electric heaters in glycol reboilers.

LNG_SepOct_2013_33-38.indd 33 24/09/2013 15:12


TEG represents about 90% of these dehydrators. It is estimated that there are more than 40 000 TEG dehydrators in North America and more than 100 000 globally.

The two key stages in dehydration of natural gas are the absorption of water by the lean TEG (‘lean’ after water has been removed at the reboiler) at the contactor column, after which the lean TEG becomes rich (with water). The second stage is when the water content of this rich TEG is boiled off in the reboiler.

The TEG reboilerIn the reboiler, the rich TEG is heated to about 200 °C (390 °F), which is very close to the breakdown temperature of 207 °C (405 °F), to achieve a purity of 95% or higher for better water absorption. Because of the close temperature range between the process and the decomposition, the heat flux of the reboiler heater or heat exchanger is critical since the surface temperature of the heat source will affect the rate of decomposition of the TEG.

Methods of heating include: Gas/oil-fired burners through

fire tubes of heat exchangers.

Steam heat exchangers.

Oil heat exchangers.

Electric heaters.

Electric heatersThe Australia Pacific LNG (APLNG) project – a joint venture between Origin, ConoccoPhillips and Sinopec, located in Brisbane, Australia – is the largest producer of coal seam gas (CSG). Origin Energy commented that where power is readily available, the electric heater has been the preferred heat source for reboilers at the company’s processing plants due to their reliability. It also allows APLNG to conserve and process natural gas to be sold rather than to be burned in the reboilers. Meanwhile, in offshore operations, the heat management system is simple and easy to operate as the electric heater reboilers have their own thermal loop.

Figure 1. Water content of hydrocarbon gas. (Source: ‘Natural gas hydrates: A guide for engineers’, John Carroll, p. 132).

Figure 2. Estimated electric heater duty for TEG reboiler.

LNG_SepOct_2013_33-38.indd 34 24/09/2013 15:12


The typical benefits of electric heaters include the following:

Reduced coking: electric heaters provide uniform heat flux along the length of the heater bundle. This allows a more uniform temperature of the TEG on the surface of the heater and thereby results in minimal degradation of TEG or reduced coking. In some large reboilers, there could be more than one heater bundle to create a more uniform temperature of the TEG.

Reduced emission: as mentioned in the report by the Environmental Protection Agency (EPA), Inventory of US Greenhouse Gas Emissions and Sinks 1990 – 2005. In April 2007, 17 billion ft3 of natural gas was released from dehydrators and pumps. A portion of this comes from the gas-fired reboilers where the typical efficiency is 70% or lower. Electric heaters have no emissions and have typical efficiency close to 90%.

Large turndown: electric heaters powered by silicon controlled rectifier (SCR) units can have a turndown from 100% to 0%, which will allow better thermal system control. Turndowns of that extent are impossible with fired heaters.

No open flames: open flames are not allowed in hazardous locations.

Sizing the electric heaterThe heater duty required for the reboiler is calculated by the energy needed to separate the water from the glycol, expressed as wattage (kW). This consists of wattage 1 (required to raise the temperature of the TEG from the heat exchanger to the operating temperature in the reboiler), plus wattage 2 (required to vaporise the water in the reboiler), plus wattage 3 (to cover heat losses).

The TEG coming into the reboiler is the rich glycol preheated at the heat exchanger plus some condensing TEG as a result of the reflux at the still column. Typically, the temperature of the rich TEG after the heat exchanger prior to entering the stripper column will be around 150 °C (300 °F).

Wattage 1 is calculated with the following formula:

P 1 (kW) = WcpΔT/3412

Where: W = mass flow rate of TEG in lbs/hr. cp = average specific heat of TEG based on inlet at outlet temperature in Btu/lb-°F.

ΔT = temperature difference between inlet and outlet of reboiler in °F.

3412 = converts Btu/hr to kW.

The amount of water to be vaporised by the reboiler will be the sum of the water removed from the natural gas and the water condensed at the reflux column.

The water content of natural gas absorbed by the lean TEG can be estimated from the chart by the McKetta & Wehe curve, which is widely accepted in the industry (Figure 1).

As an example, natural gas at 38 °C (100 °F) and 500 psia will have 100 lbs of water per million ft3. If the gas has to be delivered with only 7 lbs of water per million ft3, the amount

of water that will have to be vaporised at the reboiler will be 93 lbs/d (if flow rate is per day), showing the relationship of TEG temperature and pressure at the reboiler, plus the water condensed at the reflux column.

Wattage 2 to vaporise water can be shown as follows:

P2 (kW) = Whv/3412

Where: W = weight of water being evaporated/hr plus weight of water from reflux in lbs/hr.

hv = heat of vaporisation of water (app. 970.3 Btu/lb). 3412 = converts Btu/hr to kW.

Wattage 3 for compensation of heat losses can be assumed to be 10%.

From actual heater duties of electric heater reboilers based on flow rates of TEG, Figure 2 can be used as a quick estimate for heater duty.

Heater heat flux (watt density)The typical watt density, expressed by watts per square inch (WSI), used by the industry, is between 8 – 14 WSI. Most common is 12 WSI.

The watt density is critical to push the temperature of the TEG to higher purity. The typical operating temperature for TEG reboilers is 204 °C (399 °F), required to achieve the highest purity. However, this operating temperature is very close to the decomposition temperature of 207 °C (404 °F). Careful heat management in the reboiler is therefore critical, in particular to maintain a good convection of the TEG during the water evaporation in order to avoid local overheating of the TEG.

Figure 3. The classic indicator of susceptibility to chloride-ion stress corrosion cracking is the boiling 42% magnesium chloride test. The test has shown that alloys containing more than approximately 45% nickel are resistant to chloride stress cracking. (Source: www.specialmetals.com).

LNG_SepOct_2013_33-38.indd 35 24/09/2013 15:12


The heater sheath temperature at 12 WSI can be estimated from a combination of the TEG and water natural convection flow. The TEG will not undergo phase change, whereas the water will. The estimated temperature of the heater surface at 12 WSI will be very close to the decomposition temperature of 207 °C (404 °F). However, the great advantage of electric heaters is that this temperature can be precisely controlled and maintained, thus local overheating can be avoided.

Higher heat flux will result in faster decomposition and coking of TEG on heater sheath. If the heater management is not good enough, it results in failures.

Heater sheath material selectionNatural gas carries various contaminants. Over time and after many circulation cycles, the concentration of these contaminants will induce corrosion. Most prominent contaminants are H2S and salt (typically NaCl). Sodium salts are less soluble in hot TEG and as a result they precipitate and could deposit on the surface of the heating elements.

Therefore, high chrome nickel alloys are the recommended materials for the heater sheath.

The chart (Copson curve) in Figure 3 shows that higher nickel content of the sheath material will have a better resistance to stress corrosion cracking.

Additional design features

Heater electrical enclosure protectionMost installations are considered hazardous locations due to the treatment of natural gas. The most common method of electrical enclosure is explosion proof type (NEMA 7 or Ex “d”) or increased safety enclosure Ex “e”.

Heater over temperature protectionThe heater bundle should be protected from low liquid level or dry fire conditions by attaching a high limit thermocouple to the heater sheath. The thermocouple should be attached to the heated section that will be exposed first in case of low liquid level. This thermocouple can either be welded or clamped onto the heater sheath (if desired to be replaceable). Figure 4 shows a thermocouple welded to the heater sheath.

Control The best method of control is a PID process controller or DCS system in combination with the variable time base zero cross SCR. Where three phase power is supplied, the two leg, three phase SCR provides the best value. This method of control provides the best thermal management of the reboiler and results in improved heater reliability.

Trouble free operationAfter the proper design of the heater and its installation, the final step is to develop a good preventive maintenance programme. An annual inspection of the electrical termination should be considered. It is important to look for signs of overheating (indicated by discolouration of lead wires and heat stains of the electrical hardware) and corrosion. Electrical terminations of offshore heaters can be very susceptible to rusting because of the salty environment. This will result in blown fuses at the SCR or short to ground (see Figure 5).

For prolonged shutdown, it would be best if purged gas (nitrogen or instrument air) is supplied to the electrical enclosure to maintain positive pressure and avoid moisture entering the heaters. If this is not possible, heater manufacturers can include an anti-condensation heater in the electrical enclosure.

ConclusionThe growing demand for clean energy will drive the growth of the LNG industry and the need for more processing plants for dehydration. Considering all factors involved in the design, operation and maintenance of a glycol reboiler, an electric heater seems to be the best choice. It is a proven technology that is easy to operate, with minimal maintenance needs and reduced risks.

There is no open flame and the precise controllability allows it to work slightly under the decomposition temperature of the glycol while avoiding degradation.

Figure 4. Thermocouple welded to the heater sheath.

Figure 5. A rusted termination.

LNG_SepOct_2013_33-38.indd 36 24/09/2013 15:12

Call Watlow today for the best thermal solution for your energy process application.European Technical Sales Offices

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Structured packing has been successfully leveraged in many

applications to drive higher unit capacity, reduce pressure drop, or handle low liquid loads. These factors all come into play with the glycol dehydration process. However, similar to amine units and sulfur plants, glycol dehydration units have been historically viewed as ‘utilities’. In the past, overdesign of columns using 6 – 8 bubble cap trays was the mainstay. However, with revamps becoming increasingly more prevalent and increasing offshore applications, the penalties for over-design are amplified. In particular, the rocking motion in FPSO applications demands a better option than conventional trays.

Until very recently, estimating the height of packing required to achieve a given gas dryness level has been done using rules of thumb for heights equivalent to a theoretical plate, without much certainty as to the impact of packing type, brand and size. These methods work fine in the world of overdesign, but new applications require more precise

engineering. Mass transfer rate-based modelling uses proven engineering science to provide the precision needed to reliably and consistently meet engineering and plant objectives without recourse to the height equivalent to a theoretical plate (HETP) or height of transfer unit (HTU) estimates and other rules of thumb.

There are numerous commercial software packages capable, at some level, of simulating glycol dehydration along with a host of other

separation processes including conventional, azeotropic, extractive, and three-phase distillation, gas absorption and liquid extraction. Simulation of any process for separating chemical components between immiscible phases rests on two central foundations:

Knowing the distribution of components between the phases at equilibrium.

Modelling how the separation takes place in the piece of equipment itself.

Ralph H. Weiland and Nathan A. Hatcher, Optimized Gas Treating, Inc., USA, explain how precision mass transfer rate-based simulation removes reliance upon ‘rules of thumb’ in glycol dehydration.

LNG_SepOct_2013_39-44.indd 39 25/09/2013 12:42


Phase equilibrium is a question of equilibrium thermodynamics and models for the individual phases sufficient for adequately representing solution and phase non-idealities. Models for the phases can range from ideal gas and ideal solution approximations to equations of state and activity coefficient models complete with interactions between different molecules. Phase equilibrium is in some ways least taxing; modelling the separation process itself is the real challenge.

The actual separation brought about by the phase contacting action of the equipment can be modelled in one of two different ways:

As a set of countercurrent equilibrium stages that, conceptually at least, can be stepped off on an equilibrium diagram.

Using a more scientific approach grounded in the concept of the mass transfer rate process as opposed to an equilibrium stage process.

Phase equilibrium in glycols has been addressed in some detail elsewhere,1 particularly in the context of dehydrating streams with very high acid-gas content. The

model presented there was quite general and accounted for all the vapour and liquid phase interactions and nonidealities and it compared favourably with data from the Engineering Data Book, GPSA (2004).2

The authors note in passing that glycol dehydration is not usually considered part of an LNG train liquefaction process; rather, it is used to treat gas following acid gas removal. This permits the gas to be moved by pipeline in the relatively dry state so that condensation and subsequent corrosion do not occur. However, if extra water can be removed using glycol, less water will have to be removed in the liquefaction train.

Mass transfer rate modelMass transfer rate modelling is a relatively recent (mid-1980s) departure from the classic ideal- or equilibrium-stage model of McCabe-Thiele vintage. Over the past 30 years, this type of model has gained increasing acceptance as ‘the right way to do things’, especially amongst the distillation fraternity. It takes advantage of modern high-speed computing power to calculate directly the transfer rates of components from one phase to another. Its closest analog is heat transfer, which uses film coefficients on the two sides of the rigid heat transfer surface (tubes or plates). There are extensive correlations of film coefficients for heat transfer that enable heat exchangers to be designed, not on the basis of hypothetic, ‘thermal-equilibrium stages’, but by actually calculating heat transfer rates at points along the length of the exchanger. The mass transfer analog is a very close one, more complex because many components (not just heat) cross phase boundaries that are themselves flexible and moving, not rigid. Modern digital computing makes the computations a non-issue. And today there is a good database of mass transfer coefficient information for various types of tower internals as functions of process flows and phase properties – certainly sufficient to permit accurate prediction of mass transfer rates and, therefore, an accurate prediction of the separation that a given tower will produce under actual process conditions. For a more detailed discussion of the mass transfer rate model, please refer to Weiland et al.3

Using structured packingIn the last few years, engineers have shown increasing interest in using structured packing in various gas treating applications. Consequently, structured packing is being applied more widely. Nevertheless, the idea is still new enough that questions are often asked as to whether structured packing should or should not be considered in a given application.

One of the most obvious application areas is where the columns are subject to periodic tilting motion as on floating structures such as FPSO and FLNG platforms. Structured packing resists liquid maldistribution brought about by rocking motion better than random packing. Trays have very poor resistance to the sloshing and seiching induced by lateral back and forth motion. In offshore applications, structured packing should always be considered, especially in the context of periodic tilting motion. However, care must be taken to use the right kind of liquid distributor. The distributor should have no free liquid surfaces and should be high pressure drop type, not a gravity flow device such

Figure 1. Water removal depends on packing size and packed bed depth. Dehydration of water saturated methane at 500 psig.

Figure 2. Dehydration of water saturated methane at 1500 psig.

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as a trough distributor. This also mandates that solid unit hygiene be practiced (i.e., filtration and corrosion management).

There are few reasons to exclude structured packing from consideration. One reason, however, is fouling. If the system is a fouling one, the deposits that will inevitably occur on the surfaces of the packing will be almost impossible to remove and operations may soon become plagued by plugging problems. On the other hand, unless structured packing is used too close to the flood point where liquid holdup becomes high, it is naturally resistant to the generation and maintenance of foam. It should be recognised, however, that if the system is a bad foamer, structured packing may not be the answer; rather, the root cause of the foaming should be determined and alleviated.

In a revamp for higher capacity, the naturally higher vapour handling ability of structured packing may be recommended as a way to achieve higher capacity in the same shell. Except in sulfur plant tail gas treating and acid gas enrichment, pressure drop is not usually an issue. However, if it is, structured packing can almost always be made to work at lower pressure drop. To that end, the largest possible crimp consistent with being able to achieve the target separation within the height of the existing tower shell should be used. Again, finding out what that crimp size is can be facilitated greatly by using mass transfer rate-based simulation. There are several reasons why packing may be preferable to trays:

Pressure drop is usually lower.

Tower capacity is often higher.

Foaming is usually not as big a problem.

In applications subject to rocking motion such as FPSO and FLNG, structured packing offers better resistance to upsets caused by periodic tower tilt.

Low water-content glycols are extremely viscous, which recommends against using trays.

The advantage of increased gas handling capacity can be a significant factor in high pressure towers in situations where excessive weight and footprint have severe cost

penalties. This is particularly the case in FPSO and FLNG, where tightening a design can yield large cost advantages. Reducing column diameter is certainly beneficial, but so is using only the packing depth actually required. Tower diameter is determined by hydraulics, and hydraulic performance is well documented and well understood. The same cannot be said for packed bed depth – this is determined by mass transfer, and the mass transfer performance of structured packings (especially with chemical reactions) is still viewed by some as a rather specialised area, if not an art.

Packed columns always seem to have presented a challenge to designers, perhaps because there are so many varieties, types, and sizes of packing, and because the experience base is so small, especially in gas treating applications such as amine treating and glycol dehydration. Traditionally, these units have been viewed as utilities, and in years past, building in over-design was not critical in grassroots situations. Offshore units and revamps are another matter. Here the penalty for over-design can be much more costly or just simply not practical.

However, today there is no reason why packed columns cannot be designed with just as much certainty and confidence as trays. The processes taking place in absorption and regeneration towers are mass transfer processes, and as long as one has access to the basic mass transfer characteristics as embodied in mass transfer coefficient correlations for the particular internals of interest, packed columns are no harder to specify and design than their trayed counterparts. The fundamental correlations contained within the ProTreat® simulator’s information base have been developed from literature, vendor and research data, and have been shown repeatedly to allow accurate and reliable predictions of column performance without recourse to estimating artificial parameters, such as tray efficiencies or meaningless residence times of theoretical stages.

Process simulationAttention is restricted to the use of structured packing in glycol dehydration. Until now only an equilibrium stage

Figure 3. Depth of mellapak structured packing required to achieve various dryness levels. a) Dehydration at 15 psig (left). b) Dehydration at 500 psig (right).

LNG_SepOct_2013_39-44.indd 42 25/09/2013 12:42

model has been available for calculations involving the performance of structured packing. However, the HETP of the particular packing must surely be related at least to packing size and type. For structured packing, size can be expressed in terms of specific surface area and crimp size, characteristics that are geometrically related. Under otherwise identical process conditions, one should expect that use of large crimp packing will require a deeper bed to give the same performance as a relatively short bed of small crimp packing, if for no other reason than because the surface area (for mass transfer) of the small crimp material is so much larger.

The rest of this article uses a case study to elucidate how packing size and bed depth affect the performance of a particular structured packing in a glycol dehydration application. Packings from the Sulzer Mellapak X-series were selected without prejudice for this study. Simulations were run for treating gases at low pressure (15 psig) and higher pressures (500 and 1500 psig) saturated with water at 120 °F.

The absorber was set up to dehydrate 49 000 lbmol/hr of wet sweet methane (trace CO2 and H2S) using slightly more than 3 US gallons of 99.95 wt% TEG per pound of water removed. This TEG dryness of 99.95 wt% represents the approximate upper end of practical glycol purity in an application using stripping gas for solvent regeneration. Simulation results are discussed from two perspectives:

Figure 4. GPSA Data Book Example 20-11.

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How gas-phase profiles of water content vary with position across the height of packing.

The actual depth bed of various packings needed to achieve a given gas dryness.

Figure 1 shows the water content of the intermediate-pressure gas (500 psig) at various positions along the height of a column containing 40 ft of packing. The glycol flow was 12 US gal/min and the tower diameter for 50% flood ranged from 2.2 to 2.8 ft depending on the packing size. It is evident that after traversing the bottom 20 ft of M350.X packing, the gas is nearly as dry as 99.95 wt% TEG at 100 °F can get it, certainly below 1 lb/million ft3. With M125.X packing on the other hand, it takes 35 ft of packing to achieve the same dryness and water is still being removed even after the gas has passed through the full 40 ft bed. Regardless of what level of dryness is to be achieved, twice the height of M125.X packing is required compared with M350.X packing for the same water removal. (In this example, the water content of the inlet gas was 176 lb/million ft3 in all cases.) So the required bed height is very much a function of the packing size. However, it is not in simple linear proportionality to the specific surface area of the packing. It is not that rules of thumb cannot be made to work; rather, it is that the right rules of thumb, at least for packing, depend on too many parameters (not just packing type and size, but also on the gas and solvent fluxes through the column, and fluid properties) and this makes them rough at best and unreliable at worst. Until now the answer to this dilemma has been to over-build the columns; however, in a competitive environment, being able to avoid over-design gives the knowledgeable contractor and the astute internals vendor a commercial advantage. Mass and heat transfer rate-based simulation is the precision tool that allows this to be done.

Figure 2 shows similar profiles of the gas water content for dehydration of water-saturated gas at 1500 psig. The required glycol flow is lower in this case (5 US gal./min vs. 12 US gal./min at 500 psig) because there is less water to remove from such a high pressure gas – the saturated water contents are 176 and 75 lb/million ft3 at 500 and 1500 psig, respectively. At 1500 psig only 14 ft of M350.X packing are needed to achieve 1 lb of H2O/million ft3 of gas; whereas, 19 ft are needed for the same gas at 500 psig. However, once again nearly twice the bed depth of M125.X packing is required to achieve the same result.

Figure 3b (right) shows results corresponding to the same conditions as for Figure 4, while Figure 3a (left) corresponds to dehydration of the same gas at only 15 psig. This form of presentation is more directly related to the design question: ‘how much packing of what type is needed to achieve a stated dryness?’

At 15 psig, the specific area of Mellapak M125.X is so low that no reasonable amount of this packing will come even close to reaching anything like the 4 lb/million ft3 dryness possible with 99.95 wt% TEG. On the other hand, M2.X needs about a 35 ft bed while M350.X needs only 25 ft. Choosing the wrong packing size can result in a requirement for significantly more packing, or maybe even setting up an impossible design if the packing is just too

coarse. All of this begs the question of even estimating the required bed depth at all from rules of thumb applied to ideal stages. For example, it should be quite apparent that using a rule of thumb for the HETP developed for dehydration at low pressure will give completely the wrong answer at high pressure. A real mass transfer rate-based simulation provides an accurate bed depth with great ease, something that is quite impossible using ideal stages and rules of thumb to estimate HETP values.

ConclusionReliance upon rules of thumb in glycol dehydration is no longer a necessary handicap with the availability of precision mass transfer rate-based simulation, such as that available in the ProTreat® simulator. As this article has suggested, size does matter in the context of structured packing. Quoting or recommending a single HETP or HTU in these cases would have been nonsense. The right value depends on the particular packing brand, size, as well as on the operating conditions and the gas dryness sought. When dealing with rules of thumb, the rules may simply not apply, or they may be misapplied because their basis is not well enough understood. A well-known example from the tray literature on dehydration uses a blanket tray efficiency of 25% (suggested in the GPSA Engineering Data Book, 2004), which is close to the truth only some of the time. But in deep water removal, 25% is optimistic and unless one adds several additional ‘safety’ trays, failure will threaten. The situation with random or structured packings is much worse. For example, the same GPSA Engineering Data Book suggests an HETP value without even referring to the packing type, let alone its size. Rules of thumb once had their place when the best one could do was an equilibrium stage calculation, and reliance had to be placed on experience as expressed (and mis-expressed) in such rules of thumb.

With a true rate-based heat and mass transfer approach to simulation, one never has to worry about guessing tray efficiencies, phony residence times, HETPs, HTUs, and other approximations, estimates, and arm waving. The mass transfer rate-based approach to modelling does not use rules of thumb – it uses science and good sound engineering to predict performance. As with all well-based mass transfer rate calculations, these results were obtained without any correction factors whatsoever. They are true out-of-the-box predictions in every sense of the word and do not leave the process engineer wondering whether their design is even adequate, let alone optimal.

References1. Carroll, J.J., Hatcher, N.A., and Weiland, R.H., ‘Glycol

Dehydration of High-Acid Gas Streams’, PTQ Gas, 43, 2011.

2. Engineering Data Book, Gas Processors Suppliers Association, 12th Edition, Vol. II, 20, 2004.

3. Weiland, R.H., Sivasubramanian, M.S., and Dingman, J.C., ‘Effective Amine Technology: Controlling Selectivity, Increasing Slip, and Reducing Sulfur’, paper presented at the Laurence Reid Gas Conditioning Conference, Norman, Oklahoma, USA, February 2003.

LNG_SepOct_2013_39-44.indd 44 25/09/2013 12:42


Bill Howe, Geoff Skinner and Tony Maunder, Gasconsult Ltd, UK, discuss the development

of new liquefaction technology.

This article describes the development of Gasconsult’s ZR-LNG™ dual methane expander cycle liquefaction technology and its fit with current trends in LNG project

development.Most LNG production takes place in large scale plants with single

train LNG outputs up to 7.8 million mtpa. All are characterised by a high degree of complexity to maximise energy efficiency and/or co-product value realisation, and carry the knock-on burdens of high capital cost and extended project schedules. Demanding planning approvals and high labour cost inflation have also been a feature of some recent developments.

Over the past decade, interest has developed in so-called mid-scale LNG for exploitation of smaller gas fields with reserves of around 1 trillion ft3, and offshore opportunities unable to support the pipeline capital cost to a land based liquefaction plant. Of necessity, these smaller gas monetisation prospects required lower capacity and lower capital cost plants than current base load schemes. Despite initial interest in the mid-scale sector, little materialised,

LNG_SepOct_2013_45-50.indd 45 24/09/2013 16:52


particularly in respect of FLNG. Strong interest is only now resurfacing.

A feature of the current committed and planned FLNG facilities has been the increase in envisaged plant capacity. Most oil majors are now talking of facilities producing circa 4 million mtpa, which would likely require single train capacities of a minimum of 2 million mtpa. The move to this larger capacity is driven by superior project returns; it also requires no more internal resources to get a 4 million mtpa project through the major’s capital approval systems than a 1 million mtpa plant.

A further feature is a marked preference by certain operators for elimination of liquid hydrocarbon refrigerants offshore. Higher molecular weight hydrocarbons, particularly propane, are extremely hazardous and represent an explosion/fire risk when accumulating in confined spaces.

For safety reasons, a level of support has thus developed for nitrogen expander processes for FLNG applications.

Power consumption for nitrogen cycles is high compared with mixed refrigerant processes, and the inherent large gas recirculation rates also lead to larger line sizes and heavier plants. These factors put nitrogen cycle schemes at a disadvantage, particularly for the higher plant capacities now under consideration. Even with a low cost energy source there are strong arguments for pursuing high process efficiency. Lower power consumption reduces the size of the compression equipment, the CAPEX of the plant and associated CO2 emissions.

DevelopmentGasconsult’s ZR-LNG process was originally conceived in the mid-2000s. Extensive engineering development was completed on early versions of the technology on a 1 million mtpa modular train for FLNG application. Capital costs and power demands for the latest patented variant are presented in the case studies included later in this article.

Recent developments have seen Gasconsult address further market opportunities, which arise from the advantageous CAPEX and OPEX characteristics of ZR-LNG. This is for a larger single train nominal capacity of 2 million mtpa for greater capital efficiency; whilst simultaneously achieving the low power demand required for larger LNG schemes. This opens up the possibility of deploying expander technology on higher capacity plants based on multiple 2 million mtpa trains. Details of this development are provided later in this article.

ProcessThe need to reduce the power demand for an expander based process while preserving the safety and simplicity of the nitrogen cycle led to the development of the ZR-LNG process. In this process, the refrigerant is methane derived from the feed natural gas. ZR-LNG can achieve a net liquefaction unit drive power of 260 – 320 kWh/tonne of LNG (depending on the feedstock composition, pressure and ambient conditions). This low power demand is achieved without the additional process complexity arising from feed gas pre-cooling. A schematic of the process is shown in Figure 1.

Liquefaction is achieved through the use of two separate expander refrigeration circuits indicated in red and blue. Typically, 35% of the compression power requirement to operate the process is recovered through the gas phase expanders. A further reduction in energy demand is effected by a turbine on the liquid product run down to storage.

With its low energy consumption and low capital cost, ZR-LNG is suitable for both onshore and offshore application up to a capacity of 2 million mtpa per train and can operate on a full range of hydrocarbon gases, including very lean feeds containing insufficient C2+ for production of a hydrocarbon refrigerant.

Design simplicity is encapsulated in ZR-LNG; a typical plant comprising only two compressor packages plus eight major equipment items. The cold box has only three passages (or four when pre-condensation of NGLs is necessary); all passages in the heat exchange cores having vapour phase feeds. As the process has no external cryogenic refrigerant cycle and no liquid or nitrogen top-up system, equipment items are eliminated, together with

Table 1. Basis of designGas composition Mol% CH4 95%, C2H6 4%, C3H8 1%Gas pressure at liquefaction inlet 60 bar gSea water temperature 13 ˚CIndirect cooling – sea water/circ water

3 ˚C approach

Process streams cooled to 20 ˚CHeat leak to cold box 0.5%Minimum cryogenic approach temp. 3 ˚CRecycle gas compressor polytropic 85%Expander adiabatic 87%

Table 2. Basic operating parameters

Online factor 345 d/yr

Flow rate 121 mtph

Main recycle compressor power demand 54.7 MWe

Flash gas compressor power demand 3.4 MWe

Total power 58.1 MWe

Expander power recovered to process 21.4 MWe

Net power 36.7 MWe

kWh/t of product 305

Figure 1. ZR-LNG schematic.

LNG_SepOct_2013_45-50.indd 46 24/09/2013 16:52

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associated bulk materials and their fabrication and construction. The focus on simplicity achieves a significant reduction in capital cost.

Three factors contribute to ZR-LNG’s other key attribute – its significantly lower power requirement relative to nitrogen cycles. The main contributing factor is the higher molar specific heat and lower molar compression power requirement of methane. This yields lower recycle flow rates and attendant lower power demand. A second factor is that liquefaction of part of the feed gas occurs in the liquefying

expander, converting latent heat directly into mechanical work. The third factor is that with methane refrigerant, it is convenient to condense the feed at -120 to -130 ˚C and to flash the resulting condensate to the required product temperature, usually -160 ˚C. The resulting flash gas is recovered through the methane recycle compressor. With typical nitrogen cycles, it is necessary to cool the feed to a much lower temperature to minimise the amount of flashed vapour, as its recovery is not possible through the nitrogen compression system.

Gasconsult has quantified the benefits of the above factors. Several dual expander nitrogen cycle configurations were evaluated on the same basis as ZR-LNG with respect to ambient conditions, machine efficiencies, loop pressure drops, heat exchanger temperature approaches and heat in-leakage. Hysys simulations indicate ZR-LNG has up to 30% lower suction compressor volumes and over 20% lower aggregate machine kW than nitrogen expander schemes.

Case studiesTwo case studies are presented below. Figure 1 provides the basic ZR-LNG flow scheme applicable to these 1 million mtpa FLNG schemes.

1 million mtpa FLNG modular schemeThe basis of the design is recorded in Table 1 and the related power demands are recorded in Table 2. The power consumption of 305 kWh/tonne is achieved by ZR-LNG in its basic form, and with no feed gas pre-cooling.

The cost estimate using pre-fabricated liquefaction modules for FLNG application is provided in Table 3. This estimate, based on vendor quotations against fully detailed equipment specifications, covers an EPIC work scope and is provided on a 2013 instant execution basis. It relates to the liquefaction unit only and excludes the vessel, feed gas purification, NGL fractionation, utilities, LNG/NGL storage, flare and owners costs.

Design excursion – revised process conditionsRecognising that plant performance is impacted by project specific factors, ZR-LNG was modelled using various revised process conditions. Specifically, this design excursion allows for the use of low temperature deep sea water cooling as proposed by some industry professionals for FLNG applications. Power demand was then calculated for various liquefaction operating pressures. Feed gas pre-cooling was not considered because of the wish to avoid increased plant complexity and the growing concern within the industry regarding liquid refrigerant safety issues.

The outcomes are provided in Table 4. Projected power demands are in the range 255 – 270 kWh/tonne without feed gas pre-cooling.

Development of 2 million mtpa trainWith the realisation that some oil majors are showing preference for larger FLNG schemes, and recognising that power demands in the range of 255 – 305 kWh/tonne (see Tables 2 and 4) repositions expander technology for larger capacity plants, Gasconsult developed a conceptual design

Table 3. CAPEX estimate – 2013 (US$ millions)

Equipment supply plus spares 62.8

Bulks supply 14.8

Installation/construction/fabrication 18.9

Transportation 1.9

Plant total 98.4

License fee/insurance/certification 6.0

Project management/engineering/commissioning

28.1

Total engineering plus fees 34.1

Contingency 19.9

Total 152.4

Table 4. Revised designSea water termperature 4 ˚C

Power consumption kWh/t

ZR-LNG 80 bar liquefaction pressure – no pre-cooling 255



Table 5. CAPEX estimate – 2013 (US$ millions)

Equipment supply plus spares 105.2

Bulks supply 24.9

Installation/construction/fabrication 31.6

Transportation 3.2

Plant total 164.9

License fee/insurance/certification 11.4

Project management/engineering/commissioning

47.2

Total engineering plus fees 58.6

Contingency 33.5

Total 257

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LNG_SepOct_2013_45-50.indd 49 24/09/2013 16:52


for a nominal 2 million mtpa single train ZR-LNG plant. Technical feedback and pricing from equipment suppliers indicates that it is a feasible and attractive proposition.

A leading supplier has proposed a compact single casing recycle compressor with power in the range of 70 – 80 MW. This compressor can be driven by an industrial-type gas turbine such as Hitachi H-80. Alternatively, and particularly for FLNG applications, two aero-derivative gas turbines, such as GE LM6000 or Rolls-Royce Trent, may be used. Two or three expanders would be required, depending on the suppliers’ designs.

A schematic of a candidate compressor/expander configuration for the 2 million mtpa scheme is shown in Figure 2. This is based on the basic process data provided for the 1 million mtpa FLNG modular scheme and achieves a liquefaction power demand of 300 kWh/tonne. Figure 2

shows the arrangement of the main compressor drives only (excluding supplementary drives).

In addition to the compression equipment, the cold box design has been verified by a leading manufacturer. Based on vendor budget quotations for all major equipment, this larger ZR-LNG module appears competitive for medium-size production; and in multiples as a building block for larger LNG projects both on land and offshore. Table 5 provides the cost estimate using pre-fabricated liquefaction modules for FLNG application for a 2 million mtpa plant. This estimate covers an EPIC work scope and is provided on a 2013 instant execution basis. It relates to the liquefaction unit only and excludes the vessel, feed gas purification, NGL fractionation, utilities, LNG/NGL storage, flare and owners costs.

The expander envelopeGasconsult has modelled the generic dual expander nitrogen and single mixed refrigerant (SMR) cycles against ZR-LNG. Figures 3 and 4 depict the relative combined annual cost of the fuel and capital amortisation for the liquefaction units of a 2 million mtpa LNG facility.

The figures exclude the CAPEX and OPEX of utilities and gas pre-treatment, which are assumed equivalent and assume factors such as maintenance, staffing, insurances, etc. are equal for all the technologies. Figure 3 relates to a typical stranded gas cost of US$ 2/million Btu and Figure 4 to anticipated longer term US gas costs for export projects of US$ 6/million Btu. Fuel consumption data is based on the use of aero-derivative gas turbine drives.

The charts indicate the high influence of capital cost on the overall liquefaction cost for plants operating on low cost feed gas, and the significant increase in influence of energy efficiency on overall costs as the gas cost increases. At the lower stranded gas cost there is little to choose between the SMR and dual expander nitrogen processes at the 2 million mtpa capacity level. For US market conditions, SMR achieves lower overall costs than the nitrogen system. This reflects SMR’s superior energy efficiency. The ZR-LNG combined fuel and capital cost is lower than both SMR and dual nitrogen under all gas pricing and capacity criteria by 20 – 25%. It enables expander technology to be applied in areas where the SMR process previously held a competitive advantage.

ConclusionIn the mid-scale single train capacity range up to 2 million mtpa, the ZR-LNG process is positioned as a simpler lower capital and operating cost process than both nitrogen expander cycles and SMR schemes. The significant reduction in complexity and cost is achieved with a quite limited sacrifice of energy efficiency compared to existing base load plants. ZR-LNG repositions expander technology; widening its application envelope to larger capacity and higher gas cost schemes, whilst securing a CAPEX, OPEX, and operational advantage for the small to mid-scale market. For FLNG applications, ZR-LNG offers efficiency and CAPEX advantages, whilst preserving the operational benefits of nitrogen cycles including safety, tolerance to ships motion, rapid start-up and reduced flaring.

Figure 2. Schematic – drive configuration.

Figure 3. Gas cost US$ 2/million Btu.

Figure 4. Gas cost US$ 6/million Btu.

LNG_SepOct_2013_45-50.indd 50 24/09/2013 16:52


Rocking & rollingThe new Floating LNG (FLNG) vessels

require the same type of cryogenic LNG pumps that have been used in land

based installations for over 40 years. The land based type of pump installed on FLNG vessels will now be exposed to ship motion. This article will explain why ship motion does not cause new issues such as unseating, free spinning, and bearing damage during non-operation.

Ship motion is three dimensional and is described in linear and rotational terms (Figure 1). Each type of ship motion introduces its own force and direction impact on the vertical in-tank pumps. For some motions, the location of the pump in the vessel will also result in different force amplitudes and direction. The worst case combination of ship motion and pump location is used in the technical calculations.

Ship motion will be based on worst case scenarios and sinusoidal waves. The sinusoidal wave condition is based on 50 – 80 ft wave motion over typical 8 – 20 secs producing 0.13 – 0.05 Hz frequencies. Longer wave frequencies are not considered since they reduce the impact on the pump.

Pump installation and operationFLNG vessels use in-tank mounted vertical centrifugal submerged motor cryogenic pumps (Figure 2). They also use a Thrust Equalizing Mechanism® (TEM®) to balance the axial thrust

loads and weight forces during pump operation, eliminating all axial loads on the main ball bearing. During non-operation, the main ball bearing carries the axial weight of the rotating components. The pump is installed into a spring loaded suction valve that seals the column from the tank when the pump is not installed. The pump fluid discharge goes directly into the column and is separated from the tank inlet by a static face type seal between the pump and the suction valve.

During non-operation, gravity secures the pump onto the suction valve seal and the rotating elements are allowed to rotate freely. During pump operation, the column fluid pressure applies additional force to the pump weight that is applied to the suction valve seal.

Operating pumps are not subject to ship motion damage. During pump operation there is a large amount of force on the suction valve seal from the pump discharge fluid pressure.

Gregory P. Wood, Ebara International Corp., USA, outlines how cryogenic pumps that have been used in land based installations are also suitable for FLNG vessels.

LNG_SepOct_2013_51-54.indd 51 24/09/2013 16:54


This force is many times the pump weight, overcoming any tendency for the pump to unseat or tilt with regards to the suction valve seal. During pump operation, the TEM balancing forces are many times greater than the weight of the rotating element, eliminating any possibility of loading the main ball bearing as a result of ship motion.

During non-operation, the pump is seated on the suction valve seal plate using pump weight and the rotating elements are resting on the main ball bearing. There is concern that adding ship motion to this traditional land based pump technology can cause issues such as unseating and/or tilting from the suction valve, free spinning of the rotating elements, and bearing damage due to excessive axial loading. Each of these potential impacts on the in-tank mounted vertical centrifugal submerged motor cryogenic pumps will be analysed individually.

Heave motionPump unseating from the suction valve would be the result of ship heave motion. The pump rests on the suction valve seal with a force equal to the weight of the pump minus the upward force of the suction valve springs. The typical spring force is equal to 25% of the pump weight. The sinusoidal wave characteristics are shown in Figure 3. The peak acceleration for sinusoidal wave motion based on sea conditions must exceed 24.2 ft/sec2 to unseat the pump from the suction valve. The maximum acceleration of 15 ft/sec2 is much less, concluding the pump will not unseat from the suction valve from ship heave motion.

Roll motion Pump tilting is based on ship roll movement. The pump is loose in a column and the pivot point is the suction valve seal. The centre of gravity (CG) for typical in-tank vertical pumps is about 40% of the total pump length away from the seal plate pivot point (Figure 4). Based on this CG location, when the ship rolls to some angle and combined with the angular momentum, the pump will tilt. The tilt stops when the guide pads on the side of the pump make contact with the column wall. This small movement would cause the pump to suction valve seal to lose contact. Losing seal contact does not cause any immediate issues since the column is not sealed from the tank while the pump is installed. The seal would have to be damaged, however unlikely, to compromise pump performance to a Figure 3. Sinusoidal wave motion.

Figure 1. Linear and rotational ship motion.

Figure 2. In-tank mounted vertical centrifugal submerged motor cryogenic pump installation.

LNG_SepOct_2013_51-54.indd 52 24/09/2013 16:55

noticeable degree. Even though this does not represent a high risk for premature pump failure, it is not a desirable condition.

Yaw motionYaw motion is centred on the vertical axis and is the only force that could potentially cause a pump to free spin. A pump would have to be located close to the ship yaw pivot axis to see the full effect from ship yaw motion. The pump must be exposed to rotational acceleration greater than the frictional starting torque of the rotating elements. The friction coefficient for a deep groove ball bearing is 0.0010 to 0.0015. The typical yaw movement for large marine vessels is small with low acceleration and is considered to be a sine wave type motion.

Assuming the yaw rate correlates with the wave period as a worst case, the maximum angular acceleration is relatively low. Friction torque is greater than or equal to yaw torque to ensure the pump rotating element does not spin. The pump rotating elements will not begin to rotate on the main bearing unless the yaw motion exceeds 6° in 8 secs at a minimum, essentially eliminating this possibility.

Main bearingThe potential of brinelling the main bearing is based on ship heave motion. The typical main bearing is a deep groove ball bearing size 6320 constructed of 440 C stainless steel. An axial force of 23 000 lbs is required

to brinell the bearing races. The maximum vertical force the pump would be exposed to is less than 1 G and it would take 12 Gs to cause bearing brinelling on a typical pump. False brinelling is caused by minute high frequency oscillations of the bearing balls displacing grease, resulting in surface oxidation that creates indentations over time that look like brinelling. The combination of stainless steel bearings, low frequency vibration, thin fluid, and an oxygen free environment eliminates this possibility.

There are thousands of LNG marine cargo pumps in active service, with some exceeding 30 years of active service. The rigidly mounted marine cargo pump designs (Figure 5) are essentially the same as a land-based pump with no additional protection systems. These pumps are used specifically for offloading LNG from cargo ships. Therefore, they do not operate during sea transit between ports continuously exposing them to wave motion conditions. There have been no reported bearing failures or degradations due to ship motion.

Pump protectionBefore any pump protection design is implemented, it would be prudent to determine if protection is necessary for the targeted failure mode. Ship motion analysis concludes that there is no pump unseating or bearing damage potential. A protection system can add weight, cost and complexity. If the decision is made to add

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protection to a pump from ship motion, several options may be considered.

Rigid retraction systemA rigid retraction system is designed to eliminate any axial pump movement such as unseating or tilting. It is a retraction system constructed of rigid pipe sections instead of cables. The rigid pipe sections transcend from the pump to the head plate. A constant down force is applied to the rigid pipe from springs located on the head plate, eliminating any need for external control. In addition to a down force, the springs allow for coefficient of thermal expansion differences between the aluminium pump and stainless steel piping and column.

Low centre of gravity pump seatingLowering the CG relative to the suction valve sealing plate will restrain the pump from tilting as a result of ship pitch and roll. The CG is lowered by lengthening the suction valve to reduce the pump sealing plate to pump CG distance (Figure 6). The low CG pump seating effectively combines the pump weight and friction factors to ensure the pump remains seated. If the ship were to roll significantly, the pump will slide on the polytetrafluoroethylene (PTFE) seal until the aluminium

bumpers make contact with the stainless steel column and the aluminium pump makes contact with the aluminium suction valve. The pump weight, suction valve spring force, roll angle, and coefficient of friction are used to calculate the unseating force. The pump PTFE seal will slide on the seal plate starting at 12° roll. The friction forces between the column and bumpers keep the pump from unseating through 90° of roll. The low CG pump seating system ensures positive pump seating during ship motion, eliminating the need for a more complex rigid retraction type system.

Shaft brake systemIf desired, there are two types of shaft brake systems. One system presses a pad against the shaft to keep it from rotating. The other lifts the shaft off the main bearing and presses against the shaft to prevent it from rotating and moving vertically. Each system uses nitrogen actuated pistons, which are actuated after the pump comes to a complete stop.

ConclusionShip motion does not cause free spinning and bearing damage during pump non-operation. Therefore, the pump life expectancy is not impacted. Adding additional equipment, such as a rigid retraction and brake system to protect the in-tank pumps from free spinning and axial load bearing damage, adds complexity, cost and weight. The only recommendation for vessel mounted in-tank cryogenic pumps is a low CG suction valve to eliminate pump tilting during significant roll conditions.

Figure 6. Low centre of gravity system.Figure 5. Marine cargo pump cutaway (left) and cargo pump ship mast installation.

Figure 4. Typical pump centre of gravity in relation to the suction valve seal.

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The liquefaction of natural gas has offered significant storage and transportation advantages in recent years. This has led to substantial growth in the LNG and industrial gases market, and inevitably

has turned the heads of a number of the world’s oil and gas giants. Subsequently, this has seen heavy investment in the industry on a global scale. As a result of this phenomenal growth, there has been increased demand for equipment suitable for use in cryogenic applications – a demand that manufacturers of such equipment often struggle to service, thus providing a daunting challenge for procurement staff to obtain such products. Cryogenic valves are a product that falls into this category.

Problems for procurementSourcing cryogenic valves can prove even more difficult when such products are required on short lead times, e.g. for end of project or maintenance requirements, or if the design is particularly non-standard, such as a customer specific bonnet extension length. In Adanac’s

Steve Busby, Adanac Valve Specialities Ltd, UK, asks whether valve modification could provide the answer to the industry’s supply and demand concerns.

Figure 1. A cryogenic gate valve being cryogenically tested.

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experience, there have also been situations where a particular design of valve is obsolete. This could be due to the fact that the valve that needs replacing is situated on a plant built many years ago, or where valves were originally purchased from manufacturers that are no longer in existence. This example raised its head fairly recently in an enquiry Adanac received from a large global supplier of industrial gases.

The products that the customer was seeking to purchase were fully extractable cryogenic gate and globe valves, for use in cold box applications on air separation plants. Fully extractable valves are vital components in the design of cold box assemblies, as, once the box is installed, the cost to access the valves within can be substantial. The design of the valve is critical as it allows for maintenance of the internals through an extended body design without the need to remove the valve from the pipeline, or access the cold box. The customer urgently required the valves, as its supplier had gone out of business. However, whilst delivery was critical, quality of product could not be compromised under any circumstances.

Cryogenic modifications are commonplace at Adanac, using extended bonnet designs. Providing an extension allows for safe operation of the valve as the handle, handwheel or actuator are a sufficient distance from the cryogenic media running through the valve. Where this requirement differed was the extended body design, which meant that the valve bonnet sits outside of the cold box so that any maintenance can still take place, as the internals can be extracted with relative ease. Following extensive discussions to clarify the technical requirements of the valve, Adanac submitted a design that utilised standard stock, gate and globe valves modified with a cryogenic extension. The design was accepted and, upon receipt of the order, Adanac set to work on the manufacture of these valves, with the first batch supplied on a four week turnaround – a timescale beyond the expectations of this customer, and one that enabled them to supply the finished product to their customer without the concern of late delivery charges.

Given the urgency of this requirement, Adanac’s customer was expecting to pay a substantial premium for valves to be supplied in their required delivery timescale, but this was not the case. Valve modification of standard product allowed for all valves to be delivered on time and for a price comparative to the customer’s previous supplier.

This example highlights the benefit of valve modification.

Valve suitabilityCircumstances such as these have, on certain occasions, allowed for sub-standard process equipment to be purchased for use in critical applications, creating an

obvious and potentially disastrous safety concern. For safe and efficient operation, valves required to work at cryogenic temperatures need more than just an extended bonnet. In reality, extensive knowledge of material suitability, and sufficient understanding of production and manufacturing techniques are the minimum required to produce a suitable product. Adanac has invested heavily in R&D to identify materials and fine tune its manufacturing techniques to produce valves suitable for cryogenic applications. Materials that perform adequately at ambient temperature may not necessarily be suitable for use at low temperatures, and, in addition, selection of suitable materials is dependent upon the application. Therefore, correct material specification is of paramount importance.

Cost concernsUnfortunately, availability of product is not the only reason for the supply of sub-standard process equipment. Cost is a necessary consideration. With procurement departments under constant pressure to reduce financial outlay, equipment price is an inevitable and understandable issue to be considered. However, safety should never be compromised under any circumstances. The long-term financial and safety cost for fitting a product not fit for purpose also requires serious deliberation.

Stock availabilityThe lack of availability of cryogenic valves stems from a lack of stock. This is not only due to the costs involved in piecing together a stock profile, but is also down to the endless

configurations of valves that are available, in any given range of valves.

Each configuration is determined by a number of factors: the valve design; the pressure rating; the body, trim, seat and seal materials; the required flow rate; and the end connections required. The list of possible valve design configurations is limitless and any proposed stock profile would inevitably fall short of any one customer’s particular requirements.

Whilst project procurement allows for sufficient lead times, emergency maintenance and those ‘forgotten few valves’ towards the end of a project remain a problem for engineers. With commissioning deadlines and maintenance timescales to meet, the costs soon mount up for every hour that production is halted or delayed due to a lack of availability of cryogenic valves.

Top entry ball valves and LNGPreviously, cryogenic valves required in small quantities would have been sourced where possible directly from the manufacturer, but in many instances these valves are only available on extremely long lead times and often at unacceptable prices due to the small numbers involved. Most large valve manufacturers are not in a position to

Figure 2. A cryogenic top entry ball valve.

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produce small quantities, nor do they wish to be, as they are equipped to manufacture valves in large volumes, so quoted delivery times are often based upon the next occasion that a particular type of valve is due for mass production.

A prime example of this is the top entry ball valve. It has historically been the preferred valve type for use with LNG as its design lends itself to critical applications. The valve body is manufactured in one piece, minimising leak paths whilst still allowing for maintenance of the internals in-line through the bonnet, without removing the valve body from the pipeline. This ensures that replacement of the ball, seats and seals becomes a relatively simple task, as removal of the bonnet is all that is required to access the components within. A top entry ball valve with butt weld end connections would have no mechanical joints in the pipeline, with no pipeline stresses on the bonnet connection, and therefore has minimal potential leak paths. Whilst this design is favoured by site engineers, stock availability is virtually nonexistent, and manufacturer lead times are often quoted in months. On occasion, this has forced the hand of many engineers to accept three-piece or split body flanged ball valves in the absence of available stock of the top entry design. Where product is required desperately to replace a leaking valve or if some valves were not ordered with the project requirement, end users simply cannot accept manufacturer lead times, and thus they have no option but to deviate from the site, and indeed the industry standard.

Due to a lack of availability, Adanac has worked closely with Conbraco, a US valve manufacturer, to produce a top entry cryogenic ball valve, which has been Firesafe tested to API607, and is available on appealing delivery times. The short lead times are made possible by converting the standard ‘off the shelf’ Conbraco Apollo top entry ball valve, to extended bonnet for cryogenic duty down to -196 °C. The extended bonnet conversion designs include BS6364: 1984 and other end user specifications, such as Shell 77/200.

This example provides a useful insight into the difficulties experienced by site staff required to obtain specific types of valves needed for critical applications, and on short delivery times – an unenviable position in which they find themselves, but it also highlights where valve modification can resolve certain valve procurement issues.

Valve modification – a viable optionMany engineers and procurement staff alike see the original valve manufacturer as their only source for this type of product, but, as detailed earlier, this need not be the case. Modification of standard, off the shelf valves to be suitable for cryogenic applications is a viable alternative, eliminating the long delivery times quoted by manufacturers. However, modification of valves raises the inevitable issues of quality and reliability. Advanced manufacturing techniques need to be developed to enable any kind of standard valve to be modified for safe and efficient use in cryogenic applications. Approval by the original valve manufacturer is also necessary and it is essential that the manufacturer understands the benefit of modification services. Many are happy for modification to take place on their valves, by

approved modification houses, as this ensures that their valve remains the site standard, without needing to service short lead time and small quantity requirements.

Approved manufacturing and quality proceduresWhilst modification is a viable alternative to manufacturer supply, ensuring that the modification house in question has the correct approvals and manufacturing procedures is imperative. Most respected valve manufacturers would audit the quality and production procedures and processes of the modification house, thus ensuring that the required quality standards are reached and also enabling the supply of CE marked valves where required, in accordance with the Pressure Equipment Directive (PED) 97/23/EC. BSI certification and a quality management system approved to ISO 9001:2008 are also vital components to manufacture products in accordance with the PED.

To ensure that the valves are fit for purpose, some end users insist upon a low temperature test. Shell, for example, send a number of valves to Adanac’s Testing and Cryogenic Services facility (ATaCS) for low temperature testing to standards such as 77/200 or 77/306, and fugitive emissions testing to 77/312 or BS EN 15848.

What valves can be modified?Since its foundation in 1986, Adanac has been involved with cryogenic valves. During this time-period it has studied the science behind how materials behave when operating at such extreme temperatures, and subsequently supplied some of the world’s largest producers of LNG and a number of LNG receiving terminals. Each of these end users has seen the benefit of valve modification.

As mentioned previously, top entry ball valves tend to be specified for use with LNG, but modification of other valves is also possible. End users of cryogenic valves specify a variety of valve types, which has resulted in the modification of three-piece and split body flanged ball valves, gate valves, globe valves, needle valves and butterfly valves, all for cryogenic use, and in a number of applications. A large percentage of valves supplied by Adanac are intended to operate with low temperature or cryogenic media, such as LNG or liquefied gases like oxygen and nitrogen. However, it also supplies valves that see extreme external temperatures, for instance valves supplied to the Karachaganak project in Kazakhstan where ambient temperatures can fall to below -40 °C.

LNG industry opportunitiesWith the ever growing popularity of LNG due to the ease of storage and transportation, the industry has seen rapid growth in recent years globally. This has provided significant opportunities for a number of high quality valve manufacturers to supply cryogenic valves. However, whilst supply struggles to keep up with demand, and with the constant requirement for maintenance and quick delivery valves, modification can offer a viable alternative to the original valve manufacturers, without having to compromise on either quality or safety.

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The last 20 years or so have seen an evolution of material selection from one based almost solely on performance priorities to one that

focuses on a balance between ‘performance’ and ‘first cost’ priorities. During this time, the first cost pressures associated with construction budgets forced owners and their EPC contractors to make selections outside of their typical cellular glass specifications, while at the same time understanding that they may be making some performance sacrifices.

Pittsburgh Corning’s management team was tasked with either retaining or regaining market position, while still providing the long-term performance windows its clients had come to expect. This was no easy task as the cost of glass manufacturing, being highly energy driven, continued to rise and exhibit some instability.

INSULATIONSteve Oslica,

Pittsburgh Corning, USA, examines the

developing challenge of material selection in the

cryogenic insulation industry.

innovationsSteve Oslica,

Pittsburgh Corning

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Affecting the solutionIt was evident to the technology professionals within Pittsburgh Corning that a change in footprint had to be achieved to transfer savings to the LNG pipe. These changes could be in the form of thicker cellular glass blocks or a longer format, increasing the block length from 24 in. (610 mm) to 36 in. (914 mm). In the case of thicker blocks, going from a maximum of 6 in. (150 mm) to 7 in. (175 mm), and then most recently to 8 in. (200 mm), the cost of fabrication would be reduced in some cases because there would be a reduction of the required fabrication joints during billet construction. However, transferring the cost savings directly and measurably to the pipe required a different approach.

Consultations with several large industrial insulation contractors that specialise in LNG terminal construction yielded some major potential benefits from the idea of the longer footprint cellular insulation blocks. It was universally agreed that the savings could be significant due to the following factors:

Less handling time because of the 50% larger pieces.

Fewer accessories due to a 33% reduction in the amount of radial joints.

It was also agreed that Pittsburgh Corning should stay with the same glass technology, producing the same material in a larger footprint with the same core thermal and physical properties (Table 1).

The initiative to modify the basic block size to the larger footprint was in direct response to the ‘first cost on the pipe’ requirements of the company’s clients. Several test manufacturing runs were completed, which showed that the manufacturing processes could be controlled and the extended product would still exhibit the desired physical and thermal properties as previously listed. It is important to note that several EPC contractors and facility owners insisted that Pittsburgh Corning retain the ‘same glass, same properties’, but larger footprint approach, so specifications would not have to be changed.

Establishing the evidenceThe cost savings testing would have to be accomplished in two ways. The first was an in-house comparative application test, which was conducted at the Pittsburgh Corning’s corporate research centre. The second, and more important, was an actual

Table 1. Critical physical and thermal properties for cellular glass

Property Test/ASTM Test/EN Results

Moisture absorption C 240 1609/12087 <0.2% by vol.

Permeability E 96 Wet Cup 12086/ISO 10456 0.00

Combustibility E 136/E 84 ISO 1182 Non-combustibleFlame spread index 0Smoke dev. index 0Euro Class A1

Compressive strength C 165/C240/C552 826 (method A) 90 lbs/in.²

Service temperature -268° – 482 °C-450° – 900 °F

Thermal conductivity C177/C518/C335 12667/12939 BTU-in-hr-ft.²-°F0.28 @ 50 °F0.29 @ 75 °F

Figure 1. Typical complicated LNG pipe configuration.

Figures 2 and 3. Pre-coated fabricated cellular glass insulation after fabrication and at the construction site – Isle of Grain LNG (UK).

LNG_SepOct_2013_59-61.indd 60 25/09/2013 12:44

field test of the larger footprint fabricated pipe insulation at a project site. The results were more positive than anticipated, with significant savings in labour and accessories usage.

Results and progress The additional savings demonstrated by the in-house and field testing yielded a great deal of interest in the larger footprint block size. It is a particular advantage in long pipe runs on which there is a significant amount of same size pipe segments with little modification to those segments during installation. The net savings to the owner is estimated to be as much as 20% or more, depending on the pipe configurations.

The final conclusions about the larger footprint, based on internal and external testing, can be summarised as follows:

A significant reduction in joint sealant is realised with the larger footprint as radial joints are reduced by 33%.

The resulting reduction in joints also improves the overall project performance potential as there are fewer areas for moisture or moisture vapour intrusion.

Application labour savings of up to 20% or more because of a significant reduction in handling time.

All of these points are combined into what is a technically superior project, accompanied by significant ‘first cost’ reductions.

Other cost saving initiativesPittsburgh Corning is committed to improving (and combining) the simultaneous benefits of cost reduction and long-term performance, as demonstrated when it initiated the ‘pre-fabricated pre-coated’ insulation segments from its European fabrication operations.

The savings provided by these systems justified a spec adjustment from three layer polyisocyanurate fabricated insulation systems to a two layer pre-coated fabricated FOAMGLAS® insulation system. The results were similar to the larger footprint initiative:

Technical improvement of insulation system performance.

Cost reduction of up to 19% because of one less layer of insulation and half the application steps.

Significant reduction in insulation accessories requirements at the job site.

Another cost reduction initiative was a complete review of the company’s guide specifications. This review was directed at cost reduction with the same historical performance in mind. An example of the specification adjustments for cost benefits relates to the use of contraction joints, which is no longer called for in the guide specifications and is now subject to the judgment of the project engineer.

The cost of making cellular glass is unlikely to be reduced in any large measure any time soon. So the continuing challenge will be to bring the material to the job site and onto the surface in a manner that provides the necessary cost reductions. The above initiatives, individually and collectively, provide those kinds of cost reductions, at both module yards and project sites. The ‘first cost’ needs of the end user clients will remain unlikely to change.

www.dpharp.com

High Performance

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LNG_SepOct_2013_59-61.indd 61 25/09/2013 08:36


For many years, LNG has been transferred by conventionally insulated pipeline systems. Only over the last decade have vacuum insulated pipeline (VIP) systems gained popularity within this market. Why is it that it took so long before this happened?

Only recently have the bigger industrial gas companies, such as Linde, Air Liquide and Air Products started their own activities within the LNG sector. Within the industrial gas market it has been conventional to use VIP for the transfer of cryogenic liquefied gases such as nitrogen, oxygen and hydrogen, etc. However, within the oil and gas market, only ‘proven technology’ has been used, which probably slowed down the introduction of VIP.

For optimal insulation, there are three ‘roads’ of heat transfer that need to be blocked: conduction, convection and radiation. A VIP blocks all of these ‘roads’ in the following ways:

Conduction: pipe in pipe system with a minimum of contact points. Where contacts are necessary, they are either lengthened with heat bridges or materials with the lowest thermo conductive properties are used.

Convection: the space between both pipelines is vacuumed to a static vacuum better than 1 x 10-5 mbar. There are hardly any particles left to transport the heat loads. A long-lasting high insulation vacuum level is kept by means of getter materials.

A long time coming

Erik Admiraal, Demaco, the Netherlands, outlines the benefits of vacuum insulated pipeline systems in LNG transfer.

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Figure 1. Welding of the process line of the VIP.

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Radiation: around the process line, a highly reflective foil is wound with multiple layers (MLI). This creates a radiation shield reflecting the infrared radiation.

Aside from superior insulation values, there are other factors that encourage the use of VIP.

Energy efficiencyReduced loss of LNG due to heat in leak will provide a more energy-efficient system. This will subsequently save day-to-day costs for the operator and result in significant savings on the lifetime of the terminal.

Short installation timeConventionally insulated pipeline systems are historically field fabricated. This usually adds months to the installation schedule. Since the VIP is being pre-fabricated in spools up to 30 m, the installation period is significantly shortened with only the field connections between the spools to perform.

Small footprintThe space on the pipe racks at LNG terminals is always limited. The VIP only has a 2 in. wider jacket line than the process line. Comparing this to the thick layers of conventional insulation, it is clear that there are significant space savings. The support structures for the VIP are also smaller and low cost compared to the bulky supports used on the conventionally insulated lines.

EnduranceConventionally insulated pipelines start to deteriorate from the moment they are in use. The cryogenic LNG will create tensions in the insulation when cooling down and heating up. This cycling

will create cracking of the moisture barrier, allowing moisture in, which freezes at cooling down and will initiate further cracking. This will result in further maintenance costs. VIP has no deterioration at all due to its stainless steel design, while the getters and molecular sieves keep the vacuum level consistent for optimum insulation.

Secondary containmentThe pipe-in-pipe system provides a secondary containment for the LNG. The jacket line is also constructed of stainless steel, capable of keeping the LNG inside.

When the public thinks of LNG, the word hazardous immediately springs to mind. A secondary containment certainly provides ease of mind for both the operator and the public.

EnvironmentMany LNG terminals are being constructed in environmentally sensitive coastal areas. The VIP is

Figure 3. First transport of the VIP to Lysekil LNG terminal.

Figure 2. Multiple sections at the final evacuation stage.

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a stainless steel construction, which requires little local work and keeps environmental disturbance to a minimum. It is also recyclable. Another future development is the sub-sea VIP, which will offer environmental advantages as it will not be necessary to create the jetty within an entire harbour.

Example projectsThe use of VIP has led to Demaco being awarded several larger LNG transfer projects recently.

Lysekil LNG terminalDemaco has acquired an order to build LNG transport pipelines for the largest LNG receiving terminal in Scandinavia, to be built by Cryo AB for Skangass in Lysekil (100 km north of Gothenburg). Besides delivery of LNG to a refinery, a truck loading facility will be built in connection to the terminal. The terminal will also become an important hub for distribution of LNG as fuel for ships. The gas will come from the LNG plant at Risavika near Stavanger. LNG will be delivered to Lysekil using the Skangass LNG carrier, Coral Energy. Demaco will build 1.7 km of VIP with inner diameters ranging up to 12 ft.

Risavika LNG ferry terminalDemaco has acquired an order to build the LNG transfer lines for a ferry bunker system operated by Skangass. The system will be realised in the Norwegian port of Risavika. The company will bring its cryogenic expertise to the project and will be responsible for engineering, producing and installing vacuum insulated transfer lines within the LNG bunker system. Demaco will help set up a system for Skangass to facilitate the loading of ferries that sail between Norway and Denmark. These ferries use LNG as fuel for their propulsion systems. Before the end of this year, the company will supply

and install approximately 0.75 km of transfer lines in Norway.

ConclusionWorldwide, the LNG business is growing both upstream and downstream. LNG is being recognised as an extremely economic energy carrier and alternative to the energy mix. In addition to this, many countries prefer to be independent from a pipeline. Now that the technology is available, LNG imports are an excellent option.

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INNOVATIONTHROUGH COLLABORATION

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Figure 1. Overview of construction works on the Queensland Curtis LNG jetty.

Curtis Island is situated off the central Queensland coast, in Gladstone harbour, Australia. Working on and around Curtis Island has significant challenges

logistically and environmentally.John Holland is currently working on several of these

complicated projects in a constrained space, which poses unique challenges for the teams involved. In conjunction with its design partner Arup, the company has developed a number of innovative solutions to address the logistical

challenges of working around and over water and within the environmentally sensitive constraints imposed on the Curtis Island LNG jetty projects. This has involved multiple LNG loading jetties and two material offloading facilities (MOF). The success of the projects can be attributed to the close collaboration between the design and construction teams to produce a construction orientated design. This approach streamlines the construction phase, minimising the impact of anticipated construction constraints

Geoff Sewell, Clinton Lourens and Brenton Keast, John Holland Minerals & Industrial, Australia, review the benefits of a ‘project specific – design for construction’ delivery model in executing the Curtis Island product loading jetties.

LNG_SepOct_2013_66-71.indd 67 25/09/2013 12:46


(environmental, logistical, etc.) while reducing the significant costs linked with marine works. The result on Curtis Island has been a reduction in anticipated project costs.

Environmental challengesThere are stringent environmental regulations surrounding movements and works on and around Curtis Island, as all works fall under the Environmental Protection and Biodiversity Act 1999. In addition to these regulations, Queensland’s Coordinator General imposed further conditions through an Environmental Impact Statement, including:

Zero damage to mangroves.

No impact to the tidal mudflats.

Limited number of anchor drops.

No discharge into the water (including spills from pile drilling).

Restricted size of laydown areas onshore.

Abiding by these regulations has limited traditional construction techniques and methodologies. Working in close consultation with its designer, John Holland has successfully been able to develop innovative construction techniques, which are reflected in the design of the jetties, to abide by all of the environmental constraints imposed.

Case study 1: environmental considerationThroughout the construction of the jetties, the imposed environmental restrictions of no discharge into the water, zero damage to the tidal mudflats and mangroves constrained the methodology approach. Conventional jetty design utilises raked and vertical piles with a drive-drill-drive installation process as this provides maximum design strength per unit of material. This technique requires a marine vessel (e.g. self-elevating platform, barge) to be moored adjacent to the pile to support the large drilling equipment, especially on raked piles. This process was not possible in this situation as it would require the vessel to be in heavy contact with the mudflats (and possibly mangroves), causing significant damage, and breaching the environmental constraints.

SolutionWorking closely with Arup, John Holland was able to develop an innovative construction solution/design which utilises the company’s over-the-top (OTT) travelling gantry construction method and cutting edge drilling techniques, negating the need for large drilling apparatuses and the associated enabling plant. To implement the OTT gantry, the use of raked piles had to be eliminated for a purely vertical pile jetty design. This design incorporates additional piles to compensate for lost structural strength, but the benefits of using the OTT gantry include faster piling cycle times, reduced construction costs, zero impact on the tidal mud flats, and no damage to the surrounding mangroves, as seen in Figure 2. John Holland was able to minimise the environmental impact window on the shoreline to only 15 m (width of the jetty). As all the piles are now vertical, the company was able to implement the use of a fly drill (new technology), which is smaller in size (compared to conventional pile drilling rigs), and produces faster drilling cycles and zero discharge into the water.

Logistical challengesOvercoming logistical challenges in and around Curtis Island is paramount due to the large number of simultaneous construction projects underway within the LNG facilities. Besides the marine traffic for John Holland’s five marine infrastructure projects, there is local traffic resulting in 600+ barge movements in Gladstone Harbour per day. The high level of marine traffic generates the necessity for all marine movements to be pre-planned and coordinated with the port logistics hub.

The environmental constraints imposed have significantly affected the logistical approach the project has taken; limited materials can be stockpiled onshore, there is restricted access to marine on-loading facilities and there is a limited number of anchor drops.

Throughout the majority of the project, the wharf and dolphin structures will be isolated from the mainland, requiring all material and personnel transport via barge.

Case study 2: isolated work frontsThe Queensland Curtis LNG jetty scope requires the construction of six mooring dolphins and four berthing dolphins. Each dolphin contains 33 t of reinforcement and 154 m3 of in-situ concrete, which translates to 26 trucks

Figure 2. Vertical piles utilising OTT methodology.

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At Demaco, it’s all about ‘Cryogenius’. Specialism, knowledge and craftsmanship when delivering high-quality cryogenic infrastructures. With a team of cryogenic specialists and all-rounders who are ahead of the market. Who determine the standard on the upper level. For big international parties. For local, specialised players. A ‘Cryogenius’ is always at work. Always improving. It’s all about Cryogenius. Whether it’s Food or LNG.

� www.demaco.nl

LNG_SepOct_2013_66-71.indd 69 25/09/2013 08:54


of concrete per pour. Each dolphin platform is 9 m above the lowest tidal point and dimensionally 8 m (width) x 8 m (breadth) x 2.4 m (height).

As the jetty is not constructed yet, each individual dolphin is completely isolated, approximately 200 m offshore. The pouring of the concrete cannot wait for the jetty to be complete, as the multiple concurrent work fronts are crucial to meet the project schedule.

A time restraint is implemented for this entire process due to the inherent setting times of concrete. The transportation of all concrete loads to the dolphin must be fast enough to be within the setting time (approximately 90 min). In addition, all subsequent loads must be within the same timeframe to ensure that the surface of the previously poured concrete remains live.

SolutionThe methodology implemented involved concrete trucks (full with concrete) being transported to the dolphin structure in lots of ten via a 90 m x 30 m barge. Significant logistical planning was required to ensure the concrete plant was producing at an acceptable rate: correct time off-sets were implemented to ensure the concrete remained live, and interfacing with other projects and local bodies to avoid all possible delays with onshore and offshore traffic was also initiated.

The ordering of loading trucks onto the barge became important to ensure the most critical concrete load (closest to

setting) was unloaded first while maintaining an equal weight distribution (equal full and empty trucks each side) on the barge to prevent capsizing. The magnitude and ordering of trucks can be seen in Figure 3.

ScheduleTo maintain the tight project timeframe, the exploitation of multiple concurrent work fronts is vital. The major benefits of constructing a marine structure with multiple work fronts are the flexibility provided when rescheduling for revised or unforeseeable changes (e.g. inclement weather) and the ability to continually progress in different areas when a single work front is experiencing issues.

ConclusionWhen a project has numerous challenging constraints including time, environmental conditions and logistical limitations, a conventional isolated approach towards design may not produce the most efficient time or cost based outcome. It is near impossible to integrate such constraints without the input and expertise of the contractor who will be responsible for delivering the work due to the tight relationship between design and methodology. The design and construct option is used by clients to de-risk their projects by allowing the subconsultant and contractor to determine and warrant the best solution for the project. This approach, together with a competitive market, will drive down overall costs and construction timeframes.

Figure 3. Concrete pour of a dolphin structure.

LNG_SepOct_2013_66-71.indd 70 25/09/2013 08:54

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Laurent Poidevin, Nicolas Duhamel and Joel Fusy, FMC Loading Systems, France, offer an offloading solution to help prepare customers for upcoming markets.

READY, SET, GO!

The recent development of the offshore FLNG market and the upcoming small/

mid scale LNG market has led FMC to develop a new generation of offloading arms to meet customers’ expectations: the Offshore Loading Arm Footless (OLAF).

There are many similarities between the current ‘offshore’ requirements and potential jetty requirements in the near future. The common parameter is the high vertical distance to be accommodated by the loading arms and this is linked with the range of vessel sizes becoming bigger. Customers are looking for flexibility with regards to their fleet and this is even more valid with the emergence of the gas spot market and LNG bunkering.

This article aims to develop this topic, covering some history in the first part, using a specific project case in the second part and finally reviewing how to extrapolate this case for the upcoming market expectations.

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Figure 1. OLAF (Offshore Loading Arms Footless).

LNG_SepOct_2013_72-76.indd 73 25/09/2013 08:57


Background The LNG industry is built on a strong heritage, which is several decades old. The industry has demonstrated an outstanding safety record, by applying a cautious approach to change and integrating lessons learnt. FMC has used similar thinking prior to developing solutions for the offshore and small/mid scale market.

All LNG terminals in the world, whether export or receiving terminals, are equipped with rigid articulated marine loading arms (MLAs). FMC Technologies pioneered this equipment with the first ever export terminal, Camel Arzew, in 1963.

The company’s core competency and expertise is the use of a full bore, rigid cryogenic articulated pipes design, ensuring limited LNG pressure loss and boil off generation. Based on this philosophy, FMC has developed a large range of offloading solutions for onshore and offshore applications for more than 50 years.

Numerous vessel mounted Chiksan® MLAs have been in service since the mid-1970s for various products, handling crude oil, LPG and even LNG since 1979.

FMC Technologies’ offshore transfer solutions have been tested either to full or reduced scale, and in dynamic conditions, so that operational and environmental conditions were specifically reproduced to verify operational behaviour and maintainability of the systems in offshore conditions.

Vision for the futureThe LNG market has undergone an extraordinary expansion in the past few years, with new applications such as offshore FLNG and small/mid scale transfer including bunkering.

FMC has concentrated a lot of effort to bring solutions to customers for the offshore LNG transfer. Operating in more hostile conditions, such as the offshore environment, led the company to develop a new generation of side-by-side offloading such as the OLAF.

The use of LNG as a fuel is drawing a lot of attention to the industry and the company is proposing OLAF type solutions to cope with the reach of lower manifolds required by the bunkering of a vessel on a conventional jetty.

This new technology helps to override the limits of conventional offloading, imposed by allowable loads on the carrier manifolds, and consequently limited geometrical constraints.

Prelude project case studyFaced with rough seas off the coast of Western Australia and tight operating constraints, creating a loading arm solution for Shell’s ground-breaking FLNG platform was a tall order in every sense, resulting in the OLAF design.

When Technip – the prime contractor for engineering, construction, procurement and installation services on Shell’s Prelude FLNG platform – needed an innovative approach to a large scale engineering challenge, it turned to the field-proven solutions of FMC Technologies.

Prelude’s FLNG is not only the first of its kind, at 488 m (1600 ft) in length, it is also the largest floating offshore structure ever built. When operational in 2016, it will produce an estimated 3.6 million tpy of LNG plus 1.3 million tpy of condensate and 0.4 million tpy of liquefied petroleum gas (LPG). It will be situated in the Browse Basin, in the often turbulent waters off Western Australia.

The challengeWhile doubtlessly impressive, the Prelude FLNG posed a significant problem for conventional marine loading arms. Primarily, the extreme height of the deck on which they must be mounted means that the arms must be capable of operating some distance below the level of their base in order to reach shuttle tankers that may be up to 10 m (33 ft) below.

FMC Technologies’ Loading Systems team, based in Sens, France, and part of the Energy Infrastructure business segment, was, at the time, already working with Shell on the Articulated Tandem Offshore Loader (ATOL) loading arms for tankers connecting to the FLNG in tandem (sometimes necessary in harsh conditions). When asked to provide a loading system for the side-by-side approach – preferred because existing LNG carriers can be loaded without modification – the team began by attempting to adapt the existing Chiksan design, but it quickly became apparent this would not work.

Conventional loading arms were simply not specified to operate at such a low level and any adaptations would have meant including a much longer loading arm, which, in turn, increased the load on the carrier manifold beyond its specified tolerance.

The solutionThe riser block or ‘foot’ on the conventional arm was replaced with a deck-level turntable, bringing the mechanical assembly down closer to the water. Because of this, the balancing mechanism had to be relocated from the back of the inboard arm, on a separate standpost installed on the same turntable and with an additional link.

The targeting system – vital for ensuring a smooth and safe connection at sea – was, rather radically, moved from the riser block to the hull of the FLNG itself. A sophisticated control system then anticipates dynamic motion between the vessels, while the arm itself has six degrees of freedom, allowing it to move in any direction without additional strain.

Finally, all maintenance can be carried out with the unit in place, with no additional heavy lifting equipment required; another key requirement of the project.

The resulting design, dubbed the OLAF, was qualified by Shell in 2011, before being successfully presented to Technip for consideration on Prelude. The platform will soon boast seven OLAF units: four for LNG and three for LPG.

Shell has indicated its long-term intention to create more FLNG platforms around the world.

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The majority of the parts used on OLAF are standard and field-proven. But the design meets every challenge of this application – it is safe, easily maintained, and does not require any modification of the LNG carriers.

Meeting expectationsThe FLNG/FSRU market is expanding with a high diversity of FLNG sizes, a large range of carrier sizes, and the potential relocation of this FLNG for a ‘second’ life with minor upgrade. This means that interface equipment such as the offloading system should allow flexibility in terms of operating envelope without being over conservative.

OLAF is not only a solution for major FLNGs in harsh environments but also one for projects being relocated or facing a larger range of LNG carriers. It ensures flexibility in the range of offloading requirements, offering a larger envelope range with standard carrier’s manifold, which allows customers to cope with spot market requirements in the course of the project life.

On the same expansion trend, jetty installations are facing a larger range of carrier sizes that require either dedicated jetties per size or flexibility in the offloading system constraints, in terms of geometry and manifold reach. OLAF offers an alternative on its own or as part of a set of conventional arms.

Worldwide, there is increasing interest in LNG fuelling. Ports and transport companies are preparing for the fact that upcoming regulations and LNG bunkering would require dedicated infrastructure in ports such as jetties or a bunkered vessel. OLAF offers the flexibility of allowing the reach of manifolds and consequently a wider range of vessels in terms of operating envelope. Retrofitting an OLAF in place of a DCMA-S, or installing it as a full new set, can ensure this.

ConclusionThe OLAF is opening the door to a new type of installation with a larger operating envelope, which is able to accommodate constraints from the offshore market to the bunkering market. OLAF is a patent of FMC and is available in several different types of design.

Figure 2. Existing DCMAs and DCMA-OLAF differences.

www.energyg loba l . com/news

READ about the latest developments in the LNG industry on Energy Global

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T he use of LNG as marine fuel is a topic that continues to inspire headlines and debate. As the shipping industry investigates the use of alternative fuels to help control costs and reduce CO2 emissions, the discussion on how to turn theory into

reality has intensified.Until recently, the number of ‘real life’ LNG as fuel projects has been limited by a

combination of factors. These typically include technology, bunkering infrastructure, the evolution of regulation and training, as well as commercial considerations.

LNG as fuelRecent significant announcements from regional and coastal operators in the US indicate a concerted shift towards the use of LNG. European and Asian owners are also looking more

GAPAnders Torud, NLI

Innovation, and Peter Stockley, Wilhelmsen Technical Solutions,

Norway, discuss how bunker design can facilitate the use

of LNG as fuel.

BRIDGING THE

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seriously at the subject with projects at the design stage that look increasingly likely to make it off the drawing board.

But for LNG as fuel to fully take hold, shipowners need to know that they can build designs that safely integrate LNG fuel tanks. They need to bunker without technology, compatibility or personnel issues. They need to understand how to manage bunkering logistics, locations and regulations before projects can be structured correctly.

Another critical factor in the adoption of LNG as marine fuel is that owners need to know that fuel will be available where and when it is needed. This is moving forward at some ports, but LNG terminal development can face regulatory hurdles and questions as to how the introduction of LNG storage is viewed by local stakeholders and port operators.

These issues were uppermost in the minds of engineers at NLI and Wilhelmsen Technical Solutions (WTS) when designing and developing a solution for LNG storage. Was it possible to design a tank of a sufficient scale and operating profile to provide a viable LNG as fuel option? Could the concept be developed further, partnering with industry peers to offer the missing link of next generation fuels: a large scale, low cost bunkering barge?

Research indicated significant interest from potential customers who were planning to build land-based terminals and infrastructure but needed to manage their project risk. By renting a tank, or tank barge on a long or medium-term contract, they would be able to provide LNG even during the time needed to make the investment decision on a permanent facility.

The LNG tank conceptThe LNG tank concept originated within NLI some years ago, but not originally with the shipping industry in mind. NLI works regularly within the offshore and oil and gas markets and the original requirement considered was whether it was possible to design a large prismatic tank for a floating LNG installation. This

would need to be designed to allow for partial filling and a flat production deck above the tank. The first criteria ruled out the typical membrane LNG tanks because these cannot be partially filled, and the second ruled out the traditional dome shaped Moss tank design.

NLI embarked on initial research with TI, part of the Wilhelmsen group, to analyse potential LNG storage options. Between 2009 and 2011, a joint research and development project with TI, Liquiline, DNV and Marintek was conducted, partly financed through the Norwegian Research Council’s MAROFF programme.

As the project became more focused on marine use, including bunkering and small scale LNG distribution, further alterations were made for application specific use. The research examined issues around machining the shield plating, calculation of cracking forces, the cryogenic expansion/contraction effects and support systems to ensure the tank would not float upwards and cause structural damage in case of water ingress.

The design that resulted from this collaboration is a prismatic low pressure IMO type ‘B’ tank, whose construction principles and dimensioning ensure that it has high integrity but is lightweight. One of the key elements to the design is that the tank is a loadbearing structure comprised of a ‘sandwich’ of steel and insulation. This means that it does not require any supporting steel underneath the structure, which makes it lighter than it would have been with steel legs.

The tank was designed in various sizes. In the first case study, the partners looked at a 800 m3 tank for shipboard use. A 4000 m3 tank was then studied for use in bunkering applications.

Validation of the design was achieved when Norwegian class society Det Norske Veritas (DNV) granted NLI and TI an Approval in Principal (AiP) in June this year.

The resulting design was then used as the basis for a case study examining application as a fuel tank onboard a large ro-ro car carrier, where the owner was looking at options for dual fuel propulsion. With a successful conclusion to the case study, considerations began in regard to the integration of the tank into wider marine applications.

Bridging the LNG infrastructure gapIt was obvious that the NLI tank design would lend itself to multiple uses beyond onboard fuel storage. As the core of a powered LNG bunkering barge it would not only take risk out of building onshore facilities but could be used to provide bunker firms and port authorities with a concept that could be realised in the short-term and at reasonable cost.

Given the stop/start development of LNG bunkering noted above, a clear need for a bunker barge to fill the LNG infrastructure gap was recognised. A further study was then undertaken into the feasibility of an LNG barge design, with the following partners sharing specific responsibilities:

Rolls-Royce – responsible for design, Bergen gas engine, pod drives and bridge systems.

TI Marine Contracting (part of WTS) – responsible for insulation systems.

NLI – responsible for tank, LNG/gas systems, bunkering systems.

DNV – evaluation of the barge concept with respect to limitations and possibilities within the existing codes and regulations.

Figure 1. The NLI LNG tank design was first developed as an offshore solution before being adapted to marine application.

Figure 2. The NLI-WTS LNG bunker barge concept makes the use of cleaner fuel practical and affordable for ports and shipowners.

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During the course of the study, it was found that previous projects had approached the problem by designing small scale LNG carriers. But this is far from the optimal means of achieving the goal. Applying an LNG carrier approach would prove expensive and impractical for delivering bunkers in ports with very high traffic density.

The project started with a clean sheet of paper and a list of requirements. The barge would need to be able to carry a 4000 m3 tank, buffer and handle boil off gas either for use onboard or for delivery to the shore. For safety, the barge needed to be highly manoeuvrable, most likely using podded propulsion with an advanced bridge system for early collision detection. Fuel loading/off-loading systems and equipment, and how to make these compatible with shore and ship, was also considered.

The size of the barge also needed to be scalable. While 2000 m3 might be enough for some ships, for another, 4000 m3 might be too little. The design needed to feasibly expand to carry 6000 m3 or even 8000 m3 to fulfil demand in some ports. In the short-term it was concluded that 4000 m3 would be the baseline capacity, though each construction will be project specific as different ports will have specific parcel sizes in mind.

Having completed the barge concept design, discussions are continuing with DNV as to how it will fit within the existing regulations. Understanding of whether a shipbuilder could receive design approval within existing rules was needed. It was also important to discover what alterations might be required or whether new regulations need to be in place before the vessel could be approved.

Preliminary work from DNV pinpointed potential areas of risk. It seems likely that the vessel could be approved within existing regulations, meaning that the design could be quickly turned into a full scale vessel.

Bringing product to marketInitial feedback from the market to the tank design and barge concept has also been encouraging. Shipyards are keen to get into the LNG as fuel market to be able to offer a complete package of propulsion solutions.

New vessel designs will increasingly need to switch between fuel oil and LNG propulsion and buyers want to have a good idea of operating costs before they build the ship. A dual fuel or LNG powered vessel can capitalise on low gas prices and is also in a position to comply with future regulations. Shipyards recognise that the NLI tank gives them an approved concept that they can take to the market with and sell to shipowners.

Some smaller, more specialised shipyards are looking specifically at using the tank for inland waterway vessels. Such vessels resemble the bunker barge in general layout and the potential of a large LNG powered cargo barge, as well as a bunkering vessel itself, is interesting to builders and operators alike.

Shipowners are also enthusiastic about the concept and the next stage will be identifying a customer that is willing to take part in a full-scale project. NLI-WTS can build the tank for the first time, either as a customer requirement or a part-financed proof of concept.

ConclusionThe evolution of LNG as fuel in the marine industry is set to continue and there are still challenges to overcome before adoption is widespread. However, a major stepping stone has been laid with the development of the NLI-WTS tank and barge concepts, allowing shipyards, shipowners and bunker suppliers to work towards a cleaner future for shipping.

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LNG as a ship’s fuel is developing fast, especially in those areas where emission restrictions meet acceptable LNG prices, such as North America and Northern Europe. The reason behind that development is the current and upcoming limitations on the emission of sulfur oxides (SOx), nitrogen oxides (NOx), particulate matter and

greenhouse gases (CO2, methane). LNG as fuel is one out of a number of solutions to meet the limits due to the following reasons:

There is no sulfur in LNG, as it has been removed during treatment upstream of liquefaction. Therefore no SOx are emitted when burning natural gas.

Temperature and pressure inside the combustion chamber are responsible for the formation of NOx. Gas engines of the various types all have lower NOx emissions than corresponding diesel engines; however, ME-GI engines following the diesel cycle require additional means, such as exhaust gas recirculation (EGR) or selective catalytic reduction (SCR), to meet IMO Tier III level.

SHIPPING SOLUTIONSJürgen Harperscheidt, TGE Marine Gas Engineering, Germany, looks at the challenges of supplying high pressure gas for two stroke engines.

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Particulate matters are mainly produced by the unburned part of hydrocarbon chains. As the components of natural gas do not form long chains, almost no particulate matters are generated during combustion.

Looking at the fuel itself, natural gas produces 20% fewer CO2 emissions as the ratio between hydrogen and carbon is much better compared to oil. Unfortunately, a certain portion of unburned methane passes the engines as ‘methane slip’, which deletes a good part of the CO2 advantage. For Otto cycle engines there are studies available that result in approximately 5 to 10% total advantage over fuel oil in greenhouse equivalent along the value chain from well to funnel. For diesel cycle engines, such as ME-GI, the methane slip is close to zero, so total greenhouse balance is much better, perhaps close to 20%.

The LNG as fuel development started mainly in Norway over a decade ago driven by the NOx-tax and NOx-fund. Ferries and offshore vessels were equipped with four stroke gas engines (spark ignited Otto cycle) or four stroke dual fuel engines (pilot fuel ignited Otto cycle). Today, all of the major marine engine suppliers have included engines to their programme that can burn natural gas following one of the above principles.

In the existing world fleet, the majority of vessels are driven by two stroke engines, mainly due to high efficiency and relatively low maintenance costs. If LNG as fuel is to have a global perspective for larger vessels, there is no way around solutions for gas-fuelled two stroke engines. The ME-GI by MAN Diesel & Turbo SE is the first one ready for the market today.

Using the diesel principle, these engines open the injection valves after compression and shortly before

ignition by pilot fuel. At that point in time, the high pressure inside the cylinder requires even higher gas pressure to feed the gas into the cylinder. That is the reason why up to 300 barg of pressure is mandatory to supply fuel gas to the ME-GI.

In addition to the pros and cons in terms of emissions, there are two further items to be mentioned for the comparison of diesel type dual fuel engines against Otto type dual fuel or gas engines. The first is the high efficiency based on the thermodynamic advantages of diesel cycle, and the second is the fact that the methane number does not affect diesel engines, whereas Otto engines will derate or even switch over to fuel oil at low methane numbers.

The following article highlights some of the challenges and solutions when supplying high pressure gas to the ME-GI.

Basic principles of high pressure systemsIn principle there are two ways to achieve the required pressure of up to 300 barg: pumps or compressors. For LNG carriers the focus is on compressors, as they need to burn their boil-off gas (BOG) in the engines, which is already in a gaseous state. These compressors are huge pieces of equipment and their energy consumption is about one order of magnitude higher than those of the pumps at the same mass flow.

For the majority of merchant vessels, it is clear that reciprocating piston pumps are the best way to pressurise the LNG in its liquid state and then heat up the pressurised fluid to the required temperature. The principle of this system is shown in Figure 1. Tanks will usually be equipped with in-tank pumps to feed the high pressure system and vaporisers of the low pressure system for

auxiliary engines and/or boilers. An example layout for a high

pressure supply system using HP pumps on the deck of a LNG carrier is shown in Figure 2. The image includes a suction buffer vessel (not required in case of C-type LNG tanks) and the steam heated water-glycol cycle for LNG vaporisation on the skid together with high pressure pumps and vaporisers.

Another example layout for below deck installation on a merchant vessel is shown in Figure 3. This includes a C-type fuel tank and the (simplified) high pressure systems, as well as a water glycol heating system arranged in a room on top of the tank hold space.

ChallengesAt first glance, it looks like a simple task to provide a certain stream of LNG at a dedicated pressure and temperature. But there are some issues that require detailed evaluation to make the system run reliably and fulfill the demanding requirements of the engine.Figure 1. Schematic diagram of HP fuel gas system for two stroke engines (image

courtesy of TGE).

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HP piston pumps for cryogenic liquids have been used in onshore applications for decades, but now they are installed in a marine environment. That requires a closer look at critical items such as changing loads on bearing due to ships movement, corrosion due to salty atmosphere and the feed conditions to avoid cavitation in spite of the accelerations on a moving platform.

There are tough requirements to follow the MAN set up, such as low pulsation, fast reaction to load changes, and quick ramp-up/ramp-down of gas supply. The only parameter supplied from the engine to the supply system is the required pressure, which is related to the engine load. The gas supply control system needs to match that pressure regardless of the required flow in a short period of time, which requires fast reacting control equipment and a corresponding system philosophy.

Safety is always a challenge, and a flammable gas under high pressure inside a ship presents a number of hazards including jet fires, pressure shock waves, cold brittleness and fire in general. Several safeguards are in place to ensure safe operation of such systems, i.e. double wall or other secondary barriers, gas detection and ex-proof equipment.

TGE Marine has taken the challenge to develop a system to meet the above requirements. Extensive work has been undertaken to ensure that the above challenges

are met and the risks are mitigated. The entire system has been modelled and evaluated in detail with simulation tools to a high degree to investigate system response under different conditions. Results have been aligned with testing as far as possible to verify the model. As an outcome of various risk assessment procedures, general approvals by several class societies are in place. Finally, a close cooperation with MAN ensures that the interface is covered well and systems work together smoothly.

What about BOG?In spite of efficient insulation around the LNG tanks, there is always some heat ingress due to the high temperature difference between the tank and the environment. This heat makes LNG temperature rise so that the liquid expands and a certain amount of LNG evaporates (the tank pressure slowly increases over time).

Some vapour, which comes back from the HP piston pumps as a slip stream from the piston rings, settles on top of natural BOG. This vapour adds to BOG by heat ingress and speeds up pressure increase inside the tanks.

Most vessels powered by two stroke engines have a fuel demand that does not allow for tank design pressure higher than 4 barg for large IMO type C tanks. Therefore, sailing time would be limited by BOG, unless it is treated in a safe manner. The easiest option is to burn it in auxiliary engines, such as gensets or dual fuel boilers, if available. Depending on tank design pressure and required inlet pressure of the consumers, this may require low pressure compressors, switched on occasionally to utilise the gas. Gas combustion units (GCU) are also technically feasible, but wasteful and should only be a rarely used back-up.If low pressure consumers are unavailable (e.g. for

vessels using main engine plus shaft generator), the use of HP compressors is generally possible, even though investment and power consumption are quite high. Another high cost option is a small reliquefaction system.

ConclusionTechnical solutions for high pressure gas supply to ME-GI engines are available and the first orders for vessels with such propulsion system have been placed.

There are some challenges related to the properties of LNG in general, particularly high pressure applications and ME-GI requirements, which have been addressed. Solutions have been developed and verified.

With further progress of emission regulation, the pressure on the shipping segment will rise to find the right answers to the question of future ship propulsion. A wide variety of different options are on the table and it will not be easy for owners to decide about the right solution for their vessel and the trade routes to be covered. Although not the ideal solution for all vessels, a good portion of deep sea vessels will sail on LNG in the future, using two stroke dual fuel engines. Development of future gas price relative to oil price and the availability of bunker infrastructure are the major issues to be solved to make LNG the right fuel for a wider range of ships.

Figure 3. Artist’s impression of HP fuel gas system for two stroke engines (image courtesy of TGE).

Figure 2. Artist’s impression of HP fuel gas system for two stroke engines (image courtesy of TGE).

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Natural gas is revolutionising fuel use in off-highway applications, enabling lower fuel costs and reduced air emissions. As a clean, abundant, and local fuel alternative, natural gas is poised to become a leading choice among

high horsepower (hp) fuel consumers in North America. Prometheus Energy has pioneered the use of LNG as a fuel for off-highway

applications. Since serving the first LNG fuelled natural gas drilling rig in July 2010, it has seen compounded growth in delivery volume of 80%/year. This year, more than 60 – 70 electric rigs used for horizontal drilling will convert to natural gas service. That represents about 6% of the entire electric rig fleet in about three or four years. Adoption of natural gas for drilling is shifting into a new gear. There could be as many as 600 – 700 rig conversions completed in the next five years (see Figure 1).

Drill rigs are the first wave. Hydraulic fracturing spreads will soon follow. With over 15 million hp in deployed fracturing pumps, the market is significant. Currently,

Brad Bodwell and Randy Hull, Prometheus Energy, USA, look at the accelerating market for off-highway LNG and its future use in

fuelling fracturing operations.

NEXTSTEP

THE

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several leading operators and service companies are testing natural gas fuelled hydraulic fracturing spreads to assess engine technologies and natural gas delivery modes. The remainder of this article reports on Prometheus’ experience and its perspective on the issues facing decision makers.

Hydraulic fracturing pilot experience To date, Prometheus has supplied LNG to one dual-fuel fracturing spread in the Marcellus basin (Pennsylvania, West Virginia) for a major integrated petroleum company, and is currently actively running LNG supply for two other fracturing spreads. One of these is a 100% dedicated gas-fuelled operation using vaporised and pressurised LNG to supply gas turbine driven hydraulic pumps in the Eagle Ford basin (Texas) with the same integrated producer. The other is a dual-fuel operation in Colorado, utilising standard reciprocating diesel engines supplying a large independent oil and gas operator. In addition, Prometheus is supplying LNG to another fracturing project in Colorado with a large oil services firm utilising their labour and equipment. Prometheus is working with CUDD Pressure Services, Greenfield Energy Services and two of the larger oilfield service companies. There are also several other projects where operators and their oil service suppliers use field gas to supply their dedicated or bi-fuel fuelling operations.

Key issues Use of natural gas in fuelling fracturing operations is in the very early stages of development. The current split between LNG and field gas use is about 50/50. Decision makers need to consider the advantages and disadvantages of each. In summary, while LNG is always a more expensive variable cost fuel option, field gas will always require more capital investment and planning on

the part of the operator. Frequently, due to field gas quality (H2S, availability and/or presence of significant NGLs), it will not work due to complexity and cost of a field gas treatment solution.

The benefitsNatural gas is a clear winner economically and environmentally. Savings on variable fuel costs generally range from US$ 1 – US$ 1.50/diesel gallon equivalent for LNG. The savings are even greater when field gas is accessible. These savings help pay the capital costs for converting engines and the equipment for delivering gas. To date, customers have typically seen net savings against diesel fuel of as much as 15 – 20%. This results in simple paybacks in the range of 9 - 18 months for dual fuel conversions.

Adding the environmental benefits of natural gas combustion vs. diesel to the equation makes the case for natural gas even more clear-cut. With virtually no particulates, a 60 – 70% NOx reduction and 20 – 25% CO2 reduction, natural gas provides the best environmentally sensitive solution. The future case for natural gas use in hydraulic fracturing, whether in raw field gas mode or the LNG supply mode, looks extremely promising.

Issues for decision makers

Total cost of ownershipA number of factors drive total cost of ownership (TCO) for a natural gas solution beyond the price of fuel and the equipment rental day rate. These include equipment utilisation, field labour utilisation, mobilisation, move and demobilisation costs. Prometheus’ project experience indicates that the time between well completions can be as little as 12 hours or as long as a week. Efficiently deploying safe and reliable equipment and labour resources will determine the ultimate success of the project.

Coverage radiusField gas and LNG introduce delivery risks since supply points are less numerous than diesel fuel ‘racks’. Prometheus provides its customers with multiple LNG supply points within an economic delivery radius of 300 – 450 miles. Field gas typically requires a gas clean-up skid and a pipeline connection that must be planned and installed before the well is drilled. If gas is not available at the site, another alternative is to tap into market gas at a gas processing facility. In this scenario, a fleet of compressed natural gas (CNG) tube trailers that operate within a delivery radius of less than 100 miles between compressor station and the well pad can be used. If the distance to the compressor is greater than 100 miles, the size of the tube trailer fleet increases proportionally.

MobilityFracturing spreads are highly mobile and may move to new pad locations every month or less. LNG mobility is quite high, requiring only the repositioning of three to four trailers. Field gas requires re-routing and re-connection of the gas supply pipeline. If market gas/CNG are being used

Figure 1. Adoption of natural gas drill rigs (as a percentage of US electric rigs). (Source: Prometheus Energy data and analysis).

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instead of a pipeline, any change in delivery radius will require rebalancing of the number of tube trailers required.

Footprint and trafficPad size and traffic on local roads are key considerations in many basins. A typical dual fuel fracturing spread requires one fuel delivery per ‘fracturing day’. Field gas, delivered as CNG, would require five to six deliveries for the same volume of delivered gas in steel tube trailers typically available for use today. The footprint for LNG equipment in this example is two storage trailers and two vaporisation and control trailers. This configuration allows for two to three days of continued operation if deliveries are interrupted. Field gas delivered as CNG would require deployment of six tube trailers plus control and regulating equipment to meet the demand of a single fracturing day.

Flexibility and redundancyWith its on-site storage advantage, LNG has the flexibility to withstand unexpected outages of individual supply locations and of delivery equipment. This inventory buffer has enabled Prometheus to maintain a 99.9% success rate in keeping customer storage tanks from running dry. Delivering field gas to a site through a pipeline is also quite reliable. However, if a CNG compressor and tube trailers

are required, the system becomes less flexible. Freshly filled trailers would need to be dropped off, and empties returned, every two to four hours. If the gas is compressed at a single point of supply, redundant clean-up and compressor skids are needed to maintain high reliability. Furthermore, provision of spare tube trailers is also needed to keep up the cadence in the case of a mechanical problem or a flat tyre.

ConclusionThe use of natural gas as fuel for high horsepower engines is now well established technically and economically. Drilling rigs have been the ‘test bed’ and are now entering a phase of rapid adoption. Many of the same ‘early adopter’ operating companies are testing natural gas for hydraulic fracturing. The economics and environmental benefits of natural gas are clear. A key issue is how to best deliver the gas to the fracturing sites. Clean and dry field gas is the lowest cost option where it is readily accessible. Introduction of gas clean-up skids, long pipeline runs or CNG compressors and fleets of tube trailers can increase the range of field gas, but reduces its TCO attractiveness. LNG offers a flexible and operationally robust solution that should be a significant component of any operator’s fuel portfolio.

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Unique solutions for industrial processes

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LNG was originally developed as a means for transporting natural gas across markets. Within this conception, once it arrives at processing terminals, LNG is sent through

underground pipelines and distribution networks to supply cities and industries, as well as for vehicle fuel use. Only to a small extent has LNG been adopted as fuel for long distance heavy vehicles, or for road supply to small urban centres and industries that do not connect to the natural gas network.

The problem with this model is that LNG production is concentrated at a single point, while its consumers can be widely dispersed across a great distance. This results in considerable rigidity, typical of large-scale production, and high costs associated with transportation. Both factors deprive consumers of the cost savings that could result from the higher energy density of LNG and its inherent environmental benefits.

In addition, the storage of large volumes of LNG at the point of consumption involves, in many cases, a high degree of boil-off and,

Osvaldo del Campo,

GNC Galileo S.A.,

Argentina, addresses the

challenge of bringing

LNG production into

consumers’ hands.

LNG_SepOct_2013_89-92.indd 89 25/09/2013 10:13


consequently, emissions. This operational aspect, designed to relieve the LNG transportation logistics, poses a clear environmental problem, which has also prevented a wider spread of LNG.

A decade ago, Galileo developed the Virtual Pipeline® – a road transport system that makes it possible to carry natural gas to communities and industries in the form of compressed natural gas (CNG), when it is not profitable to do so by pipeline and underground networks of distribution. After ten years’ experience in the operation of this system, Galileo decided to rethink its design through what has been called ‘distributed LNG production’.

The challenge was to place the production of LNG near the point of consumption, that is, in the consumers’ own hands. To achieve this, it was necessary to reach LNG production levels that would match the cost and volume of industrial applications, community and transport fuel use, whose consumption levels are well below the levels of volume generated by the existing LNG plants.

Until recently, the LNG production plants were only large-scale and their efficient liquefaction cycles generated millions of gallons per day. In recent years, new plants have been developed that the market has named ‘LNG production mini-stations’, as their capacity was reduced to several hundred thousand gallons per day. These plants are also well above the needs and financial capacity of any private or small community.

In Galileo’s view, the solution for consumers lay in the development of ‘nano LNG production stations’, modular in nature, capable of providing up to 7000 gal/d (4480 GGE/d or 12 tpd) per unit. In these nano LNG-stations, modularity was a key aspect, as the progressive addition of modules would allow its growth to be directly proportional to the demand. Thus, the fuel consumption variable could contribute to the feasibility of any project, since it would be possible to avoid unnecessary infrastructure costs in the preliminary stage, minimising financial risk and keeping the cost per unit volume produced at the same rate.

It is also worth stating that LNG is available as a fuel at a low cost due to the availability of natural gas, as is the case in the US and importing countries. Last but not least, LNG can be used to reduce the levels of harmful emissions, resulting in tax benefits granted by state policies.

Configuration and application universeIn the face of this panorama, Galileo has developed its first Cryobox® nano LNG production stations. Its 20 years’ experience in CNG compression, through the production of its line of packaged compressors ‘box’, has contributed to the development of Cryobox®. This new equipment shares most of its components and platform with those of packaged Nanobox®, Microbox® and Gigabox® CNG compressors.

Several features in common include plug and play, its small size, its portability, low noise and vibration levels, operational autonomy, and its automatic and remote monitoring.

Cryobox® is defined as a plug and play because its installation does not require the completion of specific works and the set-up of extra components, as everything is included in one single unit. Its installation and implementation only require level ground for its direct settlement and connection to the utilities available, such as power lines and gas mains. All this involves a cost reduction in the installation of the equipment, as well as a significant drop in the amount of labour required.Figure 2. Actuated valve with manometer.

Figure 1. Actuated valves and coalescent filters.

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Its compact format (39.370 ft long x 7.976 ft wide x 9.596 ft high) allows the equipment to take up a small installation area and it is easily transportable on a trailer for future multiple relocations. Mobility is a key factor, especially when the gas should be extracted after liquid separation from a wellhead at a mature and distant field of associated natural gas.

After the well has been depleted, the equipment can be relocated to operate in a new well, repeating this cycle as often as is necessary. Galileo’s nano LNG-station offers an extra environmental benefit when it transforms the contaminant venting into LNG. It also offers an economic advantage by making assets profitable that would otherwise have remained untapped, due to distance and/or the inconsistency between the cost of the pipeline installation and the profit obtained.

To operate in the bleak scenarios associated with the oil and gas industry, which lack power lines in most cases, Cryobox® offers a version that generates its own electricity from the natural gas obtained for its own process, ensuring full operational autonomy.

From these isolated wells, LNG can be transported by road to consumption points located at more than 250 miles through the Virtual Pipeline® system. The distribution of modular container trucks on a daily basis replaces the supply through underground pipes. Currently, this CNG mode is being used for shorter distances to supply power plants in gold and silver mines in Patagonia, households in remote villages in Argentina, resorts in the Dominican Republic, and small and medium industries in Borneo, etc.

In favourable environments, where electricity supply is possible, the equipment autonomy in the processing of gas allows for savings in the heavy consumption of energy. However, with an installed capacity of 500 KW, both the electric and gas-powered versions are designed to keep operations efficient, with minimal energy consumption.

Regarding the composition of the gas, Cryobox® has been designed to operate with commercial quality gas, and also has internally inert separation systems. However, for greater application flexibility, Galileo provides complementary modular plants which precondition almost any gas composition to suit the requirements of Cryobox® liquefaction.

It is noteworthy that the nano LNG-station can operate at pressures of 11 bar (195.5 psi – 160 psi) input, allowing for connection to any industrial network without the need for high pressure pipelines. It also allows for direct connection to wellheads, even if the level of maturity registers very low operating pressures after its treatment.

Its low noise and vibration levels ensure operation within environmental restrictions for urban residential scenarios. This is a significant advantage when the equipment should be installed in vehicular fuelling stations located within or on the outskirts of cities. Additionally, since such stations may have a limited area, low vibration level Cryobox® enables installation height, allowing for other services in the lower areas of the structure, such as the improvement of drivers and passengers’ comfort, and the ease of freight logistics.

In terms of vehicle supply, Cryobox® is a dual equipment because, besides LNG, it also generates up to 560 GGE/h (2000 Nm3/h) of CNG, depending on demand. This allows the simultaneous availability of adequate fuel for every need: CNG for urban vehicles, which profit from the low cost of this fuel, and LNG for heavy transport and long distances, including boats, where saving is linked directly to the performance and autonomy originated in the higher energy density of the fuel. The same concept can be applied to the Virtual Pipeline® system, where the the best alternative is CNG up to 250 miles, and beyond that distance, LNG.

Table 1. General specifications

Inlet pressure Flow LNG delivery conditions Transfer method to the storage tank

Compact design

Maximum: 50 bar/725 PSI 7000 gal/d (4480 GGE/d or 12 tpd ) of LNG + 560 GGE/h (2000 Nm3/h) of CNG

Pressure: 2 bar R Differential pressure, no need for venting or pumping

39.370 ft (12 000 mm) long

Minimum: 11 bar/195.5 – 160 PSI

Temperature: -153 °C/-243 °F

7.976 ft (2431 mm) wide

9.596 ft (2925 mm) high

Figure 3. Coalescent filters for liquid separation.

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Automated operation of the equipment is monitored in real time by the company’s web based supervisory control and data acquisition system (SCADA), which allows monitoring and real time control of all systems from anywhere. This system keeps a historical record of the operating data and alarms, such as commanding starts and stops of the compressors based on inlet pressure of expected demand. This results in maximum control and reduced response times from Galileo’s technical service personnel, ensuring the equipment’s long life and optimal operating performance. In terms of frame monitoring, SCADA is able to measure several operating parameters, including the following:

Compressor’s inlet and outlet gas pressure.

Suction and discharge gas temperature in each cylinder.

Suction and discharge gas pressure in each cylinder.

Each main bearing and each crosshead guide temperature.

Engine RPM.

Explosive atmosphere.

How does it work?Natural gas coming from a pipeline or a wellhead is first processed to reduce carbon dioxide, hydrogen sulfide and water vapour to desirable levels in a treatment and separation modular station, before gas is fed into the Cryobox® nano LNG-station.

Once inside, natural gas is compressed at high pressure by a multistage compressor with inter-stage and

after-stage coolers, turning it into CNG, which is then transformed into LNG at very high pressure in a propietary technology Coldbox® system. Once this last stage is finished, the pressure of the LNG is reduced and delivered to low pressure storage tanks.

In addition, any boil-off coming from the main storage systems is recycled to the ColdBox to be re-processed. This automatic boil-off recovery system eliminates the venting and loss of fuel traditionally associated with LNG storage. This multi-stage compression process produces LNG efficiently and in compliance with all the safety and environmental protection requirements.

Economic benefits In terms of savings, it would be appropriate to compare these equipments with the ‘mini LNG production-station’ due to their size, production volume of LNG, investment and operating costs. In that case, while the latter requires a capital investment (CAPEX) of around US$ 310/t of LNG, the nano station requires only a US$ 170/t of LNG. If the annual operating expenditure (OPEX) is considered, the comparison is of US$ 390 – 210/t. Therefore, the use of a nano

LNG production station, such as Cryobox®, allows savings of 50% in CAPEX and 40% in OPEX per annum.

Success storyAs from November 2013, seven Cryobox® nano LNG-stations will produce 49 000 gal/d of LNG for the Francisco, the world’s first high speed passenger ship powered by gas turbines fed on LNG, which will cross the River Plate between Argentina and Uruguay on a daily basis. It will also be the first time that a sea transportation company, such as Buquebus, becomes its own self supplier of LNG.

The LNG consumption of this ship has posed a great challenge on account of its 100 m length and capacity for 156 cars and 950 passengers.

The nano stations, located on the outskirts of Buenos Aires, will run in parallel and will be connected to the urban gas network. From that location and on a daily basis, two trucks will transport LNG to the Buquebus dock at the city port, for the ferry to meet its two daily frequencies, which will involve an operating speed of 50 knots.

ConclusionLNG production nano stations, as is the case with Cryobox®, bring LNG to private companies and remote communities with clear economic benefits for themselves and for the environment. The Buquebus experience will demonstrate that LNG is the cleanest and most appropriate alternative energy due to its superior energy density, which makes LNG the most suitable fuel to meet long distances and high consumption.

Figure 4. Views of the Cryobox® Nano LNG-station designed and manufactured by Galileo.

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Dhirav Patel, Tom Phalen and John Mak, Fluor, USA, explain why

LNG vaporiser selection should be based on a site’s ambient

conditions.

Equatorial equation

Traditionally, base load regasification terminals have used two types of vaporisers: 70% use the open rack vaporiser (ORV), 25% use the submerged combustion vaporiser (SCV). The remaining 5% use the

intermediate fluid vaporiser (IFV). Other types of vaporisers, such as the ambient air vaporisers (AAV), have been used in smaller regasification plants and peak shaving facilities.

LNG regasification terminals are built where there is a shortage of gas supply. With the growth of shale gas in North America, the countries where these new regasification terminals are located can be broadly classified into two regions. First, there are the equatorial countries, where the site ambient temperatures are fairly constant and do not fall below 18 °C. Second, there is the sub-equatorial region, where the site ambient temperatures can fall below 18 °C during winter months.

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The following countries fall under the equatorial region definition:

Asian countries (southern India, Indonesia, Thailand, Malaysia, Singapore, Philippines).

North American countries (Mexico).

South American countries (Brazil).

Whereas the following countries may fall under the subequatorial definition:

Asian countries (China, Vietnam, Mid-West and Mid-East of India).

South American countries (Chile, Argentina).

European countries (Spain, UK, France).

Currently, there are other proprietary and more advanced vaporisation systems, but they are excluded from this evaluation.

Types of vaporisersORVs and SCVs are the most common vaporisation methods in existing regasification terminals, which have generally been located in the subequatorial region. Recent LNG receiving terminal activities have been shifting to the equatorial region where the weather is warmer, and the use of IFVs is found to be attractive. Important factors that should be considered in the LNG vaporiser selection process include the following:

Site conditions and plant location.

Availability and reliability of the heat source.

Customer demand fluctuation.

Emission permit limits.

Regulatory restrictions with respect to the use of seawater.

Vaporiser capacity and operating parameters with respect to expansion.

Safety in design.

Operating flexibility and reliability.

Capital and operating cost.

Open rack vaporiser (ORV)LNG receiving terminals are generally located close to the open sea for ease of access by LNG carriers. Seawater is usually available in large quantities at low cost as compared to other sources of heat, and is the preferred heat source. An ORV is a heat exchanger that uses seawater as the source of heat. ORVs are well proven technology and have been widely used in Japanese, Korean and European LNG terminals. The preferred seawater temperature for ORV operation is above 5 °C.

Submerged combustion vaporisers (SCV)A typical SCV system is shown in Figure 2. LNG flows through a stainless steel tube coil that is submerged in a water bath, which is heated by direct contact with hot flue gases from a submerged gas burner. LNG vaporisation using fuel gas for heating typically consumes approximately 1.5% of the vaporised LNG as fuel, which reduces the plant output and the revenue of the terminal. Due to the high price of LNG, SCVs are only used during winter months to supplement ORVs, when seawater temperature cannot meet the regasification requirement.

Figure 1. ORV flow scheme.

Figure 2. SCV.

Figure 3. Typical AAV.

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Ambient air vaporisers (AAV)Air is another source of ‘free’ heat and avoids the use of fuel gas and the generation of greenhouse gases from SCVs. Direct ambient air vaporisers are used in cryogenic services, such as in air separation plants. They are vertical heat exchangers and are designed for icing on the tube side and require defrosting. Automatic switching valves are installed to allow automatic defrosting using timers. They have been used for peak shaving plants and smaller terminals. When compared to other vaporiser options, they require more vaporiser units and more real estate.

A typical AAV design configuration is shown in Figure 3. AAV consists of direct contact, long, vertical heat exchange tubes that facilitate downward air draft.

Intermediate fluid heatingThis LNG vaporising via intermediate fluid utilises heat transfer fluid (HTF) in a closed loop to transfer heat to vaporise LNG. Three types of HTFs are typically utilised for LNG vaporisation:

Glycol-water.

Hydrocarbon based HTF (propane, butane or mixed refrigerant).

Hot water.

Glycol-water intermediate fluid vaporiser (IFV)This system typically uses glycol-water as an intermediate heat transfer fluid. A simplified process sketch of these various heating options is shown in Figure 4. The IFV is a conventional shell and tube exchanger, which is also known as shell and tube vaporiser (STV). There are several options to warm the glycol-water solution prior to recycling it back into the shell and tube LNG vaporisers, such as:

Air heater.

Reverse cooling tower.

Seawater heater.

Waste heat recovery system or fired heater.

Intermediate fluid (hydrocarbon) in rankine power cycleThis system uses propane, butane or other hydrocarbon refrigerant as an intermediate HTF. This vaporiser arrangement can be used to produce electric power while allowing the use of cold seawater as low as 1 °C to minimise fuel consumption.

LNG heating is achieved using two heat exchangers operating in series: a first LNG evaporator exchanger that uses the latent heat of propane condensation to vaporise LNG, and a second heat exchanger using seawater to further heat the vaporised gas to the final temperature. The second exchanger is also used to vaporise propane that is used to provide heating in the first exchanger.

Since the heating by seawater is used for natural gas superheating and occurs only in the second exchanger, it avoids direct contact with cryogenic LNG, and hence freezing of seawater can be avoided. For this reason, seawater close to the freezing temperature can be used in this configuration. The basic flow arrangement is illustrated in Figure 5.

Figure 4. Glycol-water intermediate fluid vaporiser integration with different heat sources.

Figure 5. IFV LNG vaporisers in rankine cycle

Figure 6. SCV power plant integration.

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Heat integration with power plant Where the regasification facility is located close to a power plant, a hybrid type system using the waste heat from the power plant and SCVs for trim heating can increase the thermal efficiency and improve the economics of the regasification process.

The concept is shown in Figure 6. The hot exhaust gases from the gas turbine pass through a direct contact heating tower, which raises the temperature of a hot water circuit. This hot water is used in the water bath of the SCVs instead of using fuel gas for heating.

The chilled water from the SCVs can be advantageously used to lower the gas turbine air temperature in the power plant. A lower gas turbine inlet temperature increases the power output, which is important during summer operation.

Comparison of vaporiser optionsThe choice of an LNG vaporisation system should be based on an economic analysis in maximising the project’s net present value and meeting local emissions and effluent requirements. They can be categorised into six different options, as shown in Table 1, which compare their applications; operation; maintenance; utility

and chemical requirements; environmental impacts; and relative plot sizes.

The six options considered in this study are: 1. The use of ORV as in existing regasification terminals.

2. The use of propane as the intermediate fluid with seawater as the heat source.

3. The use of glycol water as the intermediate fluid with air as the heat source.

4. The use of glycol water as the intermediate fluid with seawater as the heat source.

5. The use of fuel gas with SCVs and waste heat from cogeneration plant as depicted in Figure 6.

6. The use of direct ambient air vaporiser (AAV).

Rankings of vaporisers

Warm ambient locationsIn warm ambient locations, for site locations in the equatorial zone, the AAVs or the air heated intermediate fluid type vaporiser units can provide the full LNG vaporisation duty without trim

Table 1. LNG vaporisation option qualitative comparison

Options 1 2 3 4 5 6

Heating medium

Seawater (SW) Propane (C3)/seawater (SW)

Glycol-water (GW)/air

Glycol-water (GW)/seawater (SW)

Hot water (HW) fuel gas (FG)/waste heat (WH)

Air

Feature Direct LNG vaporisation using seawater

Indirect LNG vaporisation by condensing propane which is heated by seawater

Indirect LNG vaporisation by glycol, which is heated by air fin exchanger

Indirect LNG vaporisation by glycol, which is heated by seawater

Indirect LNG vaporisation by hot water, which is heated by waste heat and SCV

Direct LNG vaporisation using air

Major application

70% base load plants use ORV

Cold climate application and avoid freezing of seawater

For warm climate application. IFV makes up 5% of base load plants

Similar to option 3 except sea water is used as the source of heating

For energy conservation with use of waste heat. SCV is used in 25% of base load plants

For warm climate application, peak shavers and where real estate is not a constraint

Operation and maintenance

Seawater pumps and filtration system. Maintenance of vaporisers and cleaning of exchangers

Similar to option 1 with addition of a glycol loop and propane system

Similar to option 2 with a glycol loop and use of air as the source of heat

More complex, requiring coordination with power plant

More complex control. Need to balance waste heat and fuel gas to SCVs. Require coordination with power plant operation

Cyclic operation, requiring adjustment of the defrosting cycle according to ambient changes

Utilities required Seawater and electrical power

Seawater and electrical power

Electrical power only

Seawater and electrical power

Fuel gas and electrical power

Electrical power only

Chemicals Chlorination for seawater treatment

Similar to option 1 but lower chlorination

None Similar to option 1 but lower chlorination

Neutralisation required for pH control and NOx reduction by SCR

None

Emission and effluents

Impacts on marine life from cold seawater and residual chloride content


No significant impact on environment except dense fog


Flue gas (NOx, CO2) emissions and acid water condensate discharge

No significant impact on environment except dense fog

Safety Leakage of HC from ORV to atmosphere at ground level

Leakage of HC to atmosphere at ground level. Operating a propane liquid system is an additional safety hazard

Leakage of HC to glycol system, which can be vented to safe location via surge vessel

Leakage of HC to glycol system, which can be vented to safe location via surge vessel

Leakage of HC to water system, which can be vented to safe location via the SCV stack and surge vessel

Leakage of HC from AAV to atmosphere at ground level

Plot plan Medium size Medium size Large size Medium size Small size Large size

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heating. In addition, there is potential revenue to be gained by collecting and marketing the water condensate from the air.

The six options in Table 1 are ranked for their performance in terms of environmental impacts, system operability and maintenance requirement. The ranking system is based on a score of 1 to 6, with 1 being the most desirable and 6 the least desirable. These scores are summed and the one with the lowest score is considered the most desirable option. The rankings are divided into two regions. Table 2 is for vaporisers in the equatorial zones where ambient temperature is always greater than 18 °C and Table 3 is for vaporisers that operate in the subequatorial zones, where ambient is less than 18 °C.

For the hot climate zone, the environmental score for air heating is the top two most desirable (option 3 and 6) followed by seawater options (1 and 4). Option 5 uses fuel gas for heating in the SCV, which generates emissions and is therefore the least desirable. The use of propane for the rankine power cycle (Option 2) is potentially very energy efficient but would require the most operation and maintenance attention, and also ranked low in the rating.

For operability and maintainability, air heating (options 3 and 6) is the simplest to operate and maintain. Option 3, using an intermediate fluid with air heater exchangers, eliminates the cyclic defrosting operation required for direct AAV. For this reason, option 3, the use of glycol and air heating, is considered the most desirable. However, the score is only marginally higher than the AAV option. The final selection depends on other factors, such as plot space requirement, capital and operating costs.

Cold ambient locationsIn cold ambient locations (site locations in sub equatorial zones), heating medium systems using seawater or air alone may not be sufficient to meet the vaporisation duty. When the site ambient temperature is below 18 °C, external heating is required and supplemental heating integrated with SCVs or fuel gas heaters must be used during winter months.

Option 5, which uses waste heat from the power plant, is the most desirable in the environmental ranking. However, this option requires coordination with the power plant and is more complex in terms of operability and maintainability. Therefore, it is the least desirable.

In the cold climate areas, ambient air temperature is typically more severe than seawater, and the air heated options are likely to use significantly more fuel in the winter time. The rankings of air heating (option 3 and 6) are less favourable than the seawater options (option 1 and 4) because of the longer period of operating with the SCV or FH fuel gas heating. Therefore, in cold climate operation, the use of seawater heating in combination with SCVs ranks the most desirable.

The environmental and operability criteria ratings for Tables 2 and 3 are different, mainly due to the fuel gas consumption when using SCV or FH for the two different climatic regions. For the maintenance criteria, the rating was left unchanged between the two site conditions, as the only difference is the use of SCV or FH, which is common for all options.

Option 5 in warm ambient locations is ranked 1 (the most desirable) in the environmental category as the integration will

eliminate fuel gas usage when the power plant is operating. However, the SCVs must be provided to support the regasification duty in case the power plant is down for maintenance.

ConclusionFor fuel savings and minimising greenhouse gas emissions, use of ‘free heat’ from ambient air or seawater ranks the most desirable. The vaporiser design selection is dependent on the ambient temperatures. For the equatorial regions, the use of ambient air is the optimum choice. Air heating can be integrated with a heat transfer fluid using an air fin exchanger, or with the direct AAVs. For the subequatorial regions, seawater heating has an advantage over air heating as seawater heaters can operate for longer periods without trim heating. Considering today’s smaller regasification terminals, the selection of vaporiser design must be carefully evaluated and the results can be quite different from existing larger terminals.

Table 2. Vaporiser rankings for ambient above 18 °C

Option Vaporiser/heat transfer fluid

Environmental Operability Maintainability Total Rank

1 ORV (SW) 4 3 3 10 Third

2 IFV (C3/SW) 5 5 5 15 Fifth

3 IFV (GW/Air) 2 1 1 4 First

4 IFV (GW/SW) 3 4 4 11 Fourth

5 SCV (HW (FG) /WH)

6 6 6 18 Sixth

6 AAV (Air) 1 2 2 5 Second

Table 3. Vaporiser rankings for ambient below 18 °C

Option Vaporiser/heat transfer fluid

Environmental Operability Maintainability Total Rank

1 ORV (SW) 2 1 3 6 First

2 IFV (C3/SW) 4 5 5 14 Sixth

3 IFV (GW/Air) 5 3 1 9 Third

4 IFV (GW/SW) 3 2 4 9 Second

5 SCV (HW (FG) /WH)

1 6 6 13 Fifth

6 AAV (Air) 6 4 2 12 Fourth

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Due in part to the rapid expansion in unconventional natural gas production, and helped by its reputation as a cleaner burning

lower carbon fuel, global consumption of natural gas continues to rise. In countries unable to produce domestic natural gas, LNG imports provide a rapid and cost effective means of incorporating natural gas into the domestic supply. For countries actively producing natural gas from shale and other unconventional reservoirs, a push to export has seen the addition of liquefaction capabilities to existing LNG terminals. Key to managing domestic natural gas supplies is adequate storage. Domestic access to gas storage can help balance supply and demand, guarantee energy security and optimise gas infrastructure and production. Worldwide, there are hundreds of commercial and state owned sites where

Listening to the earthKatherine Jeziorski, ESG Solutions, Canada, looks at ways to mitigate risk in natural gas storage using

passive seismic monitoring.

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surface-based and underground storage of hydrocarbons are either in operation or under development.

For storage and transport in liquid form, LNG facilities are typically located close to major markets, and can provide a reliable source of delivery capacity. At liquefaction terminals, LNG is cooled to temperatures of approximately -160 °C (-260 °F) and stored in heavily insulated tanks before export by specialised tanker. Similarly, at receiving and regasification terminals, the LNG is stored until it is returned to a gaseous state for distribution to customers via pipeline. Storage in above-ground tanks near sea-side terminals may be less attractive in some countries where land is scarce. Underground storage facilities such as natural or mined caverns are often explored as a more economical option; however, considerable challenges arise when storing cryogenic material within unlined rock. As LNG is injected into a cavern, the surrounding rock experiences tensile failure as it shrinks in response to the cold temperatures, creating pathways through which LNG may leak. Situating a cavern deep enough that geostatic stresses counteract the cooling induced tensile stresses is one solution, however the added expense of this deep construction may eliminate any cost savings associated with shifting the storage underground.

Research focused on the design of membrane lined underground caverns appears to be promising. Pilot projects are underway, utilising the development of an ice-ring that encapsulates an excavated underground cavern. In the meantime, natural gas is easily stored underground in gaseous form within depleted hydrocarbon reservoirs, aquifers and salt caverns. Underground reservoir storage typically follows a seasonal cycle, while caverns within salt deposits can offer rapid deliverability of smaller volumes to meet peak demand.

In all cases, operators need to ensure that sequestered gas is well contained, so as not to pose health, safety or environmental risks. In general, accidents at natural gas storage facilities are rare; however, risks associated with leakage do exist and sites must be carefully monitored during all stages of operation. While direct monitoring of large, inaccessible underground structures is often difficult, microseismic monitoring can be successfully used to monitor the structural integrity of a variety of storage facilities, providing an early warning system for gas storage operations around the world.

Vibration thresholds for above-ground LNG storage tanksAt LNG liquefaction and gasification terminals, LNG is stored within specialised cryogenic tanks to maintain the cold temperatures required to keep the gas in liquid form. The location of these tanks above-ground provides easy access to monitor and visually inspect the tanks for potential natural gas leaks or fires. In its liquid state, LNG poses minimal risk of explosion or fire. However, in the event of a leak, rapid vaporisation and exposure to air presents a strong risk of ignition.

Passive seismic monitoring is often employed at LNG terminals to evaluate storage tank integrity, particularly in seismically active regions. Vibrations associated with strong magnitude events such as earthquakes may impact the integrity of the structure, causing cracks in foundations or walls, or sudden settlement or subsidence beneath the structure.

Building codes stipulate that the construction design must withstand a certain threshold of vibration, which is often characterised by levels of peak-particle velocity (PPV) or acceleration (PPA). It is essential that operators have the ability to monitor generated frequencies to help mitigate risk of their operations. Using seismic equipment, it is possible to measure PPV and PPA values associated with any seismicity near the storage tanks, and trigger an alarm if thresholds defined as critical to the structural integrity are exceeded. Alarms can be configured to activate relays, lights and audible warning devices, or to send emails or text messages to appropriate personnel.

In a project at an LNG receiving and gasification terminal along the Atlantic coast of North America, two triaxial force-balanced accelerometers were installed in order to accurately evaluate the PPA levels (Figure 1). The sensors are connected to a single junction box containing a Paladin digital seismic recorder, where seismic events are triggered and processed automatically to determine measured PPA. The system is configured using a WebRelay to activate an alarm at various threshold settings in the event that

Figure 2. Microseismic events generated during steam injection in a hydrocarbon reservoir. The size of the event (moment magnitude) is reflected by the colour.

Figure 1. A plate-mounted seismic sensor secured to a concrete platform and surrounded by an enclosure to shield the sensor from excessive surface noise.

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vibration thresholds of the LNG tanks are exceeded. PPA values measuring 1 m/s2, 1.8 m/s2 and 2.5 m/s2 will distribute alarms labelled as ‘moderate’, ‘severe’ and ‘excessive’, respectively, so that operators can initiate a visual inspection of the tank structures as required.

Microseismic monitoring of underground storage facilitiesWhen natural gas is required to be stored underground in gaseous form, such as in depleted reservoirs, aquifers and salt caverns, maintaining the integrity of all components of the storage system is essential. In the event that hydrocarbons migrate from their storage container, movement tends to follow the path of least resistance. Conditions that may provide migration pathways for natural gas outside of the containment volume include failed well casings or concrete, the inability of the cap rock to provide

an effective seal, and the activation of pre-existing faults and fracture networks. Wells are rigorously monitored (i.e. pressure, temperature, noise/sonic measurements, casing inspections, etc.) during all stages of operation. However, microseismic monitoring can also serve as a useful tool to provide additional information on the status and integrity of storage sites.

In response to the injection or removal of fluids from a reservoir during underground gas storage (UGS), changes in stress conditions may induce rock failures similar to small micro-earthquakes. These failures emit seismic waves detectable by sensitive recording instrumentation positioned around the monitoring zone. Typically, induced seismicity is measured on a micro-scale at levels equivalent to very small earthquakes measuring from -3 to +1 on the moment magnitude scale. Triangulation of microseismic event signals interprets the arrival times of compressional and shear waves (P- and S-waves) along with formation velocities to locate, visualise and interpret seismicity within the formation. Figure 2 depicts microseismicity in a reservoir following injection activities, where each coloured sphere represents a single microseismic event.

Microseismic sensor arrays consist of geophones or accelerometers. Depending on available infrastructure, sensor arrays for gas storage applications are deployed in offset monitoring wells and/or on the surface. The sensor arrays aim to provide adequate coverage of the zone of interest and may be deployed temporarily or permanently for periods of a few weeks to several years. Analysis of microseismic data can provide important feedback on the degree of stability of a gas storage structure during operation. Real-time evaluation of microseismic activity above or within the cap rock may identify a breach in the overlying rock layers or a leak in the well casing. Unusual clustering of microseismic events or the occurrence of larger magnitude induced seismicity (magnitudes above 0) may indicate the activation of a fault, prompting further investigation into the nature of the activation using advanced techniques. Microseismic data may also trigger alarms to notify operators to perform corrective actions to ensure the safety and integrity of storage operations.

Depleted hydrocarbon reservoirs are desirable for UGS for their porosity and permeability, as well as their demonstrated ability to retain hydrocarbons over geological

time. As pressure increases in response to natural gas injection, a reservoir can expand and deform, exerting stress on overlying cap rock. Gas production and declining pore pressures allow the reservoir to relax. Repeated loading and unloading of the storage reservoir causes expansion and compaction of the formation. At the surface, this behaviour can manifest as uplift and subsidence during the production cycle. As the reservoir and cap rock are cyclically inflated and deflated, new micro-fractures may develop in the cap rock or faults and fracture networks may be reactivated, acting as conduits for gas migration. When this happens, seismicity associated with new fracture generation may be observed to track upwards from the cap rock boundary.

Figure 4. Microseismic event associated with a suspected casing failure a few hundred metres above the target formation.

Figure 3. Microseismic events were observed to grow vertically into the cap rock layer following injection activities. The blue wellbores are monitoring wells and contain microseismic arrays, while the red wellbores are used for injection.

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Figure 5. Deployment of a downhole sensor array to monitor seismicity near a salt cavern.

Figure 3 illustrates an example where a reservoir experienced vertical event growth above the cap rock following injection activities.

As a second consequence to the cyclic deformation, well infrastructure may be subjected to harmful shear stresses, weakening the well casing or concrete. Casing failures may result from thermal, chemical or mechanical fatigue coupled with shear deformation, often as the result of reservoir deformation during cyclic injection and production cycles. Depending on its proximity to a microseismic recording array, a well casing failure may be detected as a larger magnitude seismic event close to the wellbore and above the injection zone, coupled with distinctive signal characteristics. During injection operations, a suspected casing failure was detected as a larger magnitude event a few hundred metres above the target zone (Figure 4). Examination of the accompanying microseismic signal exhibited larger than normal P-waves consistent with tensile failure of the steel casing.

In salt cavern storage, salt creep and well casing integrity are the primary concerns related to containment of the injected material. Salt is impermeable to hydrocarbons, offering a very good seal, however its visco-plastic properties cause salt to ‘flow’ when subjected to unconstrained stress. Once a cavern has been solution mined, it is important that equal pressures be maintained within the cavern and the surrounding salt deposit, to prevent salt creep from encroaching on the volume of the

cavern. Micro-fractures that may form at the edge of the cavern will heal. However, the integrity of the cavern roof and well casing may still be vulnerable. Issues may also arise if caverns are developed too close to the edge of the salt dome or if too many caverns are created within one dome.

To monitor the integrity of an operational salt cavern in the US and to help diagnose stability issues at the site, ESG deployed a 12-level geophone array down an adjacent vertical well. The available infrastructure at the site required that a temporary array be deployed down the wellbore for an extended period; however, the cost of using traditional wireline equipment was prohibitively expensive for the desired monitoring period. To address this challenge, ESG’s SuperCable was deployed for a period of five weeks, and used to record seismicity within a monitoring zone encompassing the cavern and surrounding salt dome (Figure 5).

Regardless of the storage method, ensuring containment integrity for stored hydrocarbons is essential to protect the health and safety of workers and nearby residents, as well as the surrounding environment. Direct monitoring of large underground reservoirs and caverns is often difficult. However, remote methods such as microseismic monitoring present an opportunity to listen to the state of the surrounding rock mass or storage structure, and operators can benefit from early warning of abnormal conditions that may impact containment integrity.

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If you happen to have the time or the interest to read any IT websites, magazines, or the technology pages of the nationals, you could be forgiven for

thinking that the cloud is the next best thing since, if not sliced bread, at least the invention of the worldwide web itself. It must be one of the most over-hyped new technologies ever. But is it all hot air? Or does it really have relevance to the LNG industry?

There is one industry area where the cloud has the power to transform working practices – and that is the design office. Here, the cloud has the potential to make computing-heavy, cumbersome tasks, lighter, quicker and more flexible. Consequently, applications that were once expensive, highly specialised and time-consuming, are now more affordable and easier to buy and maintain. The cloud can also reduce the time taken for some tasks to minutes rather than days or even months.

Digital design – and digital prototyping in particular – has streamlined the way design engineers work. However, design of machinery and components in this

Colin Watson, Symetri, UK, asks “What can the Cloud do for the LNG Industry?”

CLOUD

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industry is typically complex and large scale. 3D digital models are data rich and put high demands on computing power.

This means that analysing 3D models, and especially simulating their performance to test reliability and safety standards, can still be slow. Highly sophisticated mega-sized designs sometimes have tens of thousands of components with multiple teams of suppliers. Designers, therefore, find it difficult and long-winded to test multiple varieties of a design to reach the optimum version within their given parameters.

High levels of computing power are needed to perform these multi-physics analyses – often exceeding the scope of the desktops and workstations used by most engineers. The analysis of even a single component in the traditional way can take a month or more, and is often only performed after the product has failed. Consequently, only the largest of organisations have been able to afford full-time simulation specialists to develop the right methods for their own particular products.

Infinite powerChanges to this situation have happened in stages with the rise of digital prototyping and the integration of simulation tools within mainstream geometry creation software. But one of the main advances has come with the cloud. Simulation in 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.

The cloud offers almost infinite computing power, negating the need for high performance hardware. Complex multiple simulation tasks can be carried out in parallel, enabling users to study a large number of design alternatives. This analysis can run on a large number of computers in the cloud so that, in 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, using it for simulation is far more affordable than previous methods. It can be switched on by the users 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 requiring specific licences.

Perhaps one of the main benefits of cloud-based applications is that they can be accessed remotely from anywhere in the world. This makes them ideal for helping multi-national teams collaborate on the development of designs and gain the buy-in of widespread stakeholders.

While experts will always be needed for in-depth analysis of certain products, opening up simulation to a wider market can only be good news. The ability to bring better quality products to market faster is key in today’s volatile market. Now every business, large or small, has the opportunity to achieve this goal.

A new style of PLMThis paves the way for the opening up or ‘democratisation’ of a number of otherwise high-level industry applications, making them available to all sizes of business. One of these that works particularly well in the cloud is product lifecycle management (PLM).

PLM appeared to hold great potential when first introduced to manufacturers and machine builders around three decades ago. They liked the idea of having a view of a product and the processes used to create it from the concept stage to the end of its life, and believed this would bring significant benefits in speed, efficiency and quality. However, this early promise was not realised and old-style PLM never filtered through to smaller engineering firms.

It could easily be argued that the industry needs PLM today more than ever. The LNG industry has always been global by nature, but there is an increasing expectation that working across

Figure 1. Rendering of a processing plant featuring major equipment, structural steel and piping, designed in Plant Design Suite.

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international boundaries and timelines should take no longer than working with someone in the same office. But, at the moment, because data across multiple locations and from different technology platforms is based on varying criteria, it is difficult to integrate and time-consuming to compare and contrast in any meaningful way.

Yet, suppose all data from, for example, a large subsea structure could be held in one central location, integrated in a meaningful way and made available to any authorised person across an organisation to access wherever and however they wished.

Thankfully, the cloud breaks down all the barriers and enables this to happen. As with simulation, it facilitates a lighter, more flexible version that can be switched on instantly and off again if no longer needed. As a result, it can be used for specific projects only if required.

Cloud-based PLM typically covers all product and design related functions from project management engineering to sales and marketing, and can be easily customised and integrated with existing business systems. It is infinitely scalable, which means that extra computing power is available without the usual capital investment required. Backups, managing performance, upgrades, and other IT housekeeping are all the responsibility of the vendor, so no overheads are required to support the system.

Used wisely, information captured from requirements onwards through the development of a concept to production and marketing can be used to great advantage during service and even for retirement, recycling or disposal. It can also be used as the basis for future designs. Not least it can lead to better-informed decision-making across the entire lifecycle of the product.

Integrated and centralised information can be accessed from any location and on any device, including smartphones and tablets. The important aspect here is that knowledge can be captured as well as data. So, for example, if a valve or pump needs to be modified by a team across the globe from the one that designed it originally, they can learn why it was put in a

certain place, or designed in a particular way in the first place and so avoid making expensive errors.

Because PLM in the cloud has a user-friendly interface, making it easy to enter and navigate, sharing data across an enterprise becomes simpler. Research shows that whereas on average only eight people per application need to access data management systems, for PLM systems this number rises to 20 per application. As long as the right controls and security are in place, an easy flow of information across departments means earlier availability of data for supply chains and sales and marketing, and more input to designs, leading to closer interpretation of needs and faster approvals. In short, significant acceleration of time to market.

Some believe that PLM in the cloud could become a working tool that people will log-in to every day in the same way that they now log-in to their email. In fact, it could be integrated with email, or replace it altogether. It could be task-driven to minimise the need for meeting after meeting. This way it could totally change the working day – and all enabled by the cloud.

Earlier this year, Symetri held a round table discussion about the cloud and PLM. Among the guests was a PLM expert, business consultant Nina Dar. She described how when she was first introduced to PLM around 2006: “On paper it was a no-brainer […] but I slogged away at it for five years and in the end much of what I was doing (for her clients) was recovery work.” However, Dar’s attitude has changed having tried the new cloud-based version. “At last someone has listened to what business needs in this area,” she said.

Traditional PLM never made the same inroads into the gas industry that it did in, say, the automotive sector. There were many good reasons for this; after all, PLM in its previous form had many opponents because of the time and resources it took to implement, maintain and use. But to ignore PLM in the cloud is to miss an opportunity.

So, for all the talking-up, the cloud can actually be a highly useful technology – even away from mainstream IT applications.

Figure 2. Oil and gas rendering of an offshore oil rig platform, designed in Plant Design Suite.

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One of the current hot spots for LNG activity in Western Canada seems headed for a difficult time, unless changes are made in the way project proponents address the concerns of some of the people who could be most impacted by

the projects.There are currently several proposed pipelines to export natural gas, extracted

partly through hydraulic fracturing, from the fields in Northeast British Columbia (B.C.). Pipelines will need to cross several mountain ranges to the Pacific Ocean coast, about 1000 km by road. There, the gas will be liquefied at plants on the coast

KNOW YOUR NEIGHBOURS

Lisa Hardess, Hardess Planning Inc., Canada, explains why a better response to Aboriginal concerns is needed for projects in Western Canada.

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and carried by tanker, in many cases through narrow channels between islands, to global markets. While there is an agreement with coastal First Nations regarding the construction of a LNG plant, communities along the pipeline route are raising concerns about impacts and lack of consultation.

Along the way, the proposed pipeline routes pass through the territories of many First Nations. Aboriginal Peoples in Canada include First Nations, Métis and Inuit.

Due partly to unique aspects of Canadian colonial history, these Nations assert that they never ceded control of their territory to the colonial or Canadian government. In the majority of B.C., there are no treaties with the Crown (the federal and provincial governments) as there are in other parts of Canada.

Canadian law and customs grants First Nations considerable autonomy over their affairs, and informs the need for community engagement and consultation when decisions being considered have the potential to negatively impact Aboriginal rights (for example, the right to carry out traditional activities including hunting and fishing). While economic development associated with LNG offers opportunities, First Nations are clear that this should not be at the expense of the environment and future generations, as well as native title rights. Although many consultation obligations, particularly those related to infringement of rights, rest with the Crown, industry has an important role to play.

Wise resource companies, including LNG project proponents, will need to respect the need for meaningful engagement if they are to be successful. Those that do, and learn to understand and address the concerns of First Nations in B.C., will have learned useful skills that they can apply elsewhere in the world.

Risk concernsOne of the main pipeline-related concerns of First Nations in what is called ‘the central interior’ (i.e. not on the Pacific coast of B.C.) has to do with catastrophic events, particularly leaks and explosions. Despite industry plans for risk management, many people do not believe that these can be avoided. The expectation is that incidents, possibly serious incidents, are inevitable.

This means that project proponents have quite a bit of work to do to convince communities along their proposed route that the risks from the project are being effectively managed.

This article includes some practical suggestions on how to build good relations with First Nations in B.C., which have application elsewhere in Canada, as well as internationally.

Build relations right from the startMany companies seeking to extract gas, pipeline it and liquefy it are reluctant to invest in building community relations until they have determined the exact location of the various project elements, such as the pipeline route. Yet current trends are such that if people in the local community see too many unfamiliar pickup trucks and aircraft, they will become concerned. Those concerns can ripen into hostility and opposition that can cause delays, higher costs and even stop development.

However, there are many ways that resource companies can build good relations right from the beginning, and they do not have to be excessively costly.

In the initial stages of planning, when it is uncertain if the company will even be working in the area long-term, it is important to find out which Aboriginal Nation’s traditional territory one is on. The company should send a letter, followed by a phone call to introduce its plans and explain what the next steps could be (e.g. route selection). It is important to respect protocol and the company’s Chief Executive Officer should reach out to their Chief.

Second stageIf planning moves forward, it is essential to start building a relationship. Although the company may have a permit from the respective government granting agency, it still requires a ‘social license’ to operate.

A process and predictability should be created where it does not formally exist, in order to avoid work stoppages that could dwarf those caused by environmental or licensing delays. A company should explain what it does and how it is good at it – what the extraction, construction and transportation processes involve, and how water concerns are addressed. It is also useful to provide examples of other projects.

Make a tripIn most cases, this second stage will involve a trip to the community, and it is important to make this trip count.

A company should research who the First Nation are, what language they speak (many First Nations have their own language, which they may prefer to English), and what is happening in their community. This will help to make a better first impression and demonstrate respect for First Nations’ unique status in Canada. One should speak in plain – not industry – language, and dress nicely but casually for the weather.

Understand that First Nations are interested in revenue sharing, not handouts and a new school. Their people are also looking for meaningful ways to be part of the proposed project. In

Figure 1. Tankers carrying LNG to markets will need to traverse some challenging coastal waters. First Nations and others dependent on fishing are concerned about the cumulative impact of this traffic, as well as the threat of collisions, unplanned gas releases and explosions.

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addition to trucking and labour jobs, a company should consider a track that would lead to community members working in management roles, learning skills they can use elsewhere. First Nations groups will be interested in construction-type jobs, as well as pipeline inspection, maintenance, monitoring and emergency response. They will also be interested in economic spin-offs including contracts for companies owned by the Band, or by members of the community.

Project proponents should also consider bringing a hostess-type gift, since the Aboriginal community is being asked to play host. This could include refreshments for the meeting or a big tin of coffee. In many cases, the communities will be remote and grocery store food and supplies will be expensive. The company should ask its contacts what the community would like and pack it along. On a recent trip, the author was asked to bring USB keys for staff to use and as door-prizes for the youth.

If people in the local community speak their local language, it may be possible to pay for a translator (someone they have identified in the community) for the meeting. It is also a good idea to pay a respected local Elder to open and close the meeting.

ConclusionIn short, it is vital to treat a trip to a First Nations community in Canada much as you would an international visit. If one is knowledgeable of local culture and protocols, as well as the issues that the community is facing, it should be possible to present ideas in an appropriate and effective manner.

Figure 2. The challenging terrain in the British Columbia interior poses

difficulties for pipeline builders and operators with regards to emergency

response. Fast and effective response to incidents and catastrophic releases

is of high concern to First Nations communities.

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