LN G I N D U S T R Y | S P R I N G 2 0 1 2 w w w . e n e r g y g l o b a l . c o m Spring 2012 LNG_Spring2012_OFC.indd 1 16/03/2012 11:51 ©2010 Air Products and Chemicals, Inc. tell me more www.airproducts.com/improve Air Products has contributed to the success of more LNG operations than any other company. And we bring our full capabilities to LNG projects of any scale. From peak-shaving plants producing less than 0.1 MMTPA to the largest base-load facilities, on land or off-shore. Our LNG team can help you get a plant up and running at the highest efficiency–on time, on budget, and in any climate. To learn more, call 800-654-4567 (US), 1-610-481-4861 (worldwide) or visit us online. Big LNG expertise. Also available in small LNG plants. LNG_Spring2012_IFC.indd 1 14/03/2012 15:21 O N T H I S M O N T H ’ S C O V E R LNG Industry is audited by the Audit Bureau of Circulations (ABC). An audit certificate is available on request from our sales department. Copyright © Palladian Publications Ltd 2012. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without the prior permission of the copyright owner. All views expressed in this journal are those of the respective contributors and are not necessarily the opinions of the publisher, neither do the publishers endorse any of the claims made in the articles or the advertisements. Printed in the UK. Contents ISSN 1747-1826 03 Comment 05 LNG news 10 A tale of two gas markets Ng Weng Hoong, LNG Industry Correspondent, discusses the disparity between the Henry Hub price and the Asian LNG price. 18 A toast to 2011! Pat Roberts, LNG-Worldwide Ltd, UK, looks back at a successful year for the global LNG sector. 25 FLNG’s time to shine Victor Alessandrini and Mohamed Ould Bamba, Technip, Europe, discuss the increasing importance of the FLNG concept for offshore gas production. 30 Floating between islands Olaf Beyer, TGE Marine Gas Engineering GmbH, Germany, discusses the provision of engineering services to provide LNG infrastructure for Guadeloupe and Martinique. 37 Small scale solutions Moty Kuperberg, Dynamic Shipping Services, Israel, explains the benefits of using the small scale LNG feeder system to supply consumers spread over many destinations. 40 Shipping: awash with costs Lars Petter Blikom, DNV, China, examines how cost increases in the shipping industry are leaving shipowners searching for cost reduction measures. 45 Dropping the temperature Vasserman Aleksandr and Shutenko Maxim, Odessa National Maritime University, Ukraine, explain an alternative method of LNG transportation, which eliminates the need for an onboard reliquefaction plant. 47 Offshore storage solutions Stéphane Maillard, GTT, France, examines the benefits of using membrane tank systems in offshore FPSOs and FSRUs. 53 Agents of change Nick Elliott, Inchcape Shipping Services, UK, examines the role of shipping agents in the LNG sector. 58 Qatari shipyard goes global Rebecca Watson, Nakilat, Qatar, details the rise of the successful Nakilat-Keppel Offshore and Marine repair yard. 64 Getting it right first time Barbara Grant, International Paint, UK, describes the benefits of spending time and money on quality coatings to prolong the lifespan of ships. 72 Meeting the challenge Thierry Vermeersch, AVEVA, UK, examines current capabilities and trends in the integration of engineering, design and information management technologies between the plant and marine industries. 77 Storage challenges Mun-Seong Kim, Endress+Hauser, Japan, describes the intricacies of LNG storage solutions. 81 Sweet from sour Lorenzo Micucci, Siirtec Nigi, Italy, takes a holistic approach to sour gas treatment. 85 Scaling it down James Solomon, Jr., Air Products, USA, explains how small to mid-sized plants are likely to play a key role in servicing demand. 89 Vanquishing varnish Akram Reda, ExxonMobil Lubricants and Specialties, EAME, explains the benefits of choosing the right lubrication oil for gas turbines. 93 25 th World Gas Conference 2012: Exhibitor Preview LNG Industry presents a small selection of companies that will be exhibiting at the 25 th World Gas Conference, Kuala Lumpur, 4 - 8 June 2012. /SPRING2012/ L N G IN D U S T R Y | S P R IN G 2 0 1 2 w w w .energyglo bal.co m Spring 2012 LNG Spring2012 OFC indd 1 16/03/2012 11:51 CB&I was selected to provide front end engineering and design (FEED) services for the Yamal LNG project. The project encompasses production, treatment, transportation, liquefaction and shipping of natural gas and NGLs from the South Tambley field on the Yamal Peninsula in Northern Siberia, Russia. CB&I’s scope includes FEED development for a 16.5 million tpy LNG liquefaction plant, including LNG storage and loading facilities. 10 PAGE LNG_Spring2012_01-02.indd 1 16/03/2012 12:23 LNG_Spring2012_01-02.indd 2 16/03/2012 09:50 Comment /ANNA SCORDOS EDITOR/ C O N T A C T I N F O R M A T I O N Editorial/Advertisement Offices, Palladian Publications Ltd, 15 South Street, Farnham, Surrey GU9 7QU, ENGLAND, Tel: +44 (0) 1252 718 999 Fax: +44 (0) 1252 718 992 Website: www.energyglobal.com LNG Industry Subscription rates: Annual subscription: £40 UK including postage/£50/j 70 overseas (postage airmail)/US$ 70 USA /Canada (postage airmail). Two year discounted rate £64 UK including postage/£80/j 112 overseas (postage airmail)/US$ 112 USA /Canada (postage airmail). Subscription claims: Claims for non receipt of issues must be made within 3 months of publication of the issue or they will not be honoured without charge. Applicable only to USA & Canada. LNG Industry (ISSN 1747 - 1826) is published quarterly by Palladian Publications Ltd, GBR and is distributed in the USA by SPP, 95 Aberdeen Road, Emigsville, PA 17318. Periodicals postage paid at Emigsville, PA. POSTMASTER: send address changes to Palladian Publications Ltd, PO Box 437, Emigsville, PA, 17318 - 0437. Managing Editor James Little
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[email protected] Publisher Nigel Hardy I n December, I accompanied the Winter issue of LNG Industry to the World Petroleum Congress in Doha, Qatar. During my time in Doha I had the privilege of visiting Ras Laffan Industrial City, which was a unique experience. The site was astonishing in its scale, having been transformed from barren desert into a technologically sophisticated energy hub supplying all corners of the world. It is amazing to consider that the transformation of the Qatari economy on the back of natural gas has occurred in such a relatively short period of time; Qatar’s North gas field was discovered in 1971 and Ras Laffan Industrial City began operations in 1996. In that time frame, the country’s GDP has increased from approximately US$ 300 million in 1971 to US$ 110 billion in 2008. And they have plenty of shiny skyscrapers to show for it… Naturally, industry players spend a lot of time conjecturing which region or country is likely to be ‘the next big thing.’ Australia has taken the limelight away from Qatar somewhat recently, and continues to develop at a promising rate, with huge amounts of money being invested in ‘first-of-a-kind’ projects such as Shell’s Prelude FLNG project; the largest floating facility in the world. Inpex and Total are proceeding with their joint development of the Ichthys project – one of the largest onshore gas facilities in the world. The companies have arranged US$ 70 billion worth of sales agreements with Japan for 15 years worth of LNG production. BG Group has recently announced it will sell down its stake in the Queensland Curtis LNG project for up to US$ 2 billion. The company intends to sell approximately 20% of its existing 93.75% stake in the project, which is set to be the first in the world to produce LNG from coalbed methane. Demand for LNG from Asia continues apace; reports have claimed the region will expand its regasification capacity by almost 35% between 2010 and 2015. China aims to bring three LNG import terminals online in 2012 and in the same year Japanese demand for LNG is likely to increase by more than 25%. China is likely to be the second largest LNG importing country by 2020, after Japan. The world keeps looking for the next big supplier. But aside from Australia, another region that is gaining some attention as an emerging potential exporter is the eastern coast of Africa. Shell has recently agreed a £992.4 million bid for Cove Energy, a small oil and gas exploration company with interests in east Africa. Cove currently owns an 8.5% stake in a large gas field recently discovered offshore Mozambique. Anadarko Petroleum, Cove and Eni have all made huge gas discoveries in this area. According to Financial Times correspondent Guy Chazan, “Their two fields combined could contain up to 60 trillion ft 3 of recoverable resources of gas – nearly as much as Kuwait’s entire reserves. That should be enough to turn Mozambique into a key exporter of LNG, to China and India’s fast growing economies.” As the gas majors move into the area and buy out smaller companies such as Cove, the pace of exploration and LNG development in the region will inevitably accelerate. Chazan points out that, “Fewer than 500 wells have been drilled in east Africa, compared with some 20 000 in the north and nearly 15 000 in the west of the continent.” Maybe the LNG sector could start contemplating a new multi million dollar question: if Australia is the next Qatar, could Mozambique be the next Australia? We’ll have to wait and see… LNG_Spring2012_03-04.indd 3 19/03/2012 10:50 After 50 years of operation, the Groningen gas field in the Netherlands is now, and also for the coming decades, able to continue supplying its clients. The facilities have been fully modernized. One key success factor was the long- term relationship of the operating company NAM and its contractors. Siemens has updated the compression and www.siemens.com/oilandgas Solutions for the oil and gas industry variable-speed drive technologies to ensure the adapta- tion of the gas supply to fluctuating demand, to slash maintenance requirements, and to maximize environmen- tal performance. Highest availability and low power con- sumption of all units are the best basis for an eco-friendly and successful operation. Nothing can stop a real performer. Eco-friendly compressor technology boosts production E 5 0 0 0 1 - E 4 4 0 - F 1 4 0 - V 1 - 4 A 0 0 LNG_Spring2012_03-04.indd 4 19/03/2012 08:41 LNGNews Spring2012 / LNGINDUSTRY / 5 H öegh LNG has entered into a 10 year time charter for a floating LNG storage and regasification unit to be used as an LNG import terminal in Lithuania. The agreement is subject to the approval of the shareholders of AB Klaipedos Nafta. The Lithuanian state owns 70.63% of Klaipedos Nafta’s shares. Höegh LNG intends to use the second of the three new regasification vessels being built at Hyundai Heavy Industries Ltd in South Korea for this agreement, which will commence in the second half of 2014. The time charter is expected to give an EBITDA contribution of approximately US$ 50 million per year. Höegh LNG’s President and CEO, Sveinung Støhle, said, “We are delighted to have established a long term relationship with Klaipedos Nafta and we look forward to operating the floating LNG regasification terminal in the Port of Klaipeda.” The proposed FSRU would break up the Russian monopoly on gas imports to Lithuania. The deal with Höegh comes soon after Russian gas giant Gazprom has begun legal manoeuvres to protect its investments from changes to Lithuania's industry legislation. DENMARK Maersk sells LNG units LITHUANIA Höegh LNG to supply FSRU T he Danish company Maersk has released a statement regarding its recent sale of Maersk LNG to Teekay LNG and Marubeni Corp. “The agreement was subject to a regulatory approval and consents from Maersk LNG’s customers. These conditions have now been fulfilled. Accordingly, A.P. Møller-Maersk A/S has completed the sale of all the shares in Maersk LNG to Malt LNG holdings ApS, a company jointly owned by Teekay LNG Operating LLC and Marubeni Corp.” Under the terms of Maersk LNG’s partnership agreements with Société Generale and Qatar Shipping Co., each owning an LNG vessel, the sale of Maersk LNG triggered pre-emption rights to Maersk LNG’s partnership shares. Both partners have exercised the pre-emption rights and acquired Maersk LNG’s 26% ownership share in each of the limited partnerships on the same terms as offered by Teekay LNG and Marubeni Corp. “The sale of Maersk LNG generates an accounting gain for the A.P. Moller–Maersk Group in the order of US$ 80 million, including accumulated exchange rate differences previously recorded in equity,” Maersk added. GLOBAL LNG for HGVs? T he use of LNG by giant cargo vessels crossing the world’s oceans has been advocated for some time and has recently started to pick up steam. What might be less well known, however, is the small but growing trend towards using LNG for road haulage vehicles such as HGVs. Although the infrastructure is nowhere near as widely distributed as that provided for conventional fuels, companies in the USA, such as Encana Corp., have begun to make real inroads towards using LNG as the main fuel for their goods vehicles. Encana recently completed construction of its first LNG fuelling station and its partner, Heckmann Water Resources, has ordered 200 LNG fuelled vehicles, with 50 already operational. Executive Vice President of Encana, Eric Marsh, said, “This new station is a major step towards encouraging companies to convert their vehicles to run on affordable, environmentally-responsible natural gas.” In Europe, Volvo has promoted the development of ‘blue corridors,’ which would provide a network of LNG refuelling stations for goods vehicles across the continent. LNG_Spring2012_05-09.indd 5 16/03/2012 14:07 LNGNews 6 / LNGINDUSTRY / Spring2012 USA Cheniere secures funding CHINA CNOOC begins China's first FLNG project D I A R Y D A T E S 21 - 23 May 32nd Annual International Operating Conference & Trade Show www.ilta.org t: +1 703 875 2018 e:
[email protected] 04 - 08 June World Gas Conference www.wgc2012.com t: +60 3 2171 3500 e:
[email protected] C heniere Energy Partners has secured US$ 2 billion worth of funding as part of an exclusive deal with Blackstone Energy Partners L.P., Blackstone Capital Partners VI L.P. and certain affiliates, to fund the building of its planned LNG liquefaction plant at Sabine Pass LNG terminal and acquire the Creole Trail pipeline. Cheniere Energy Partners is moving towards a final investment decision on the first phase of its proposed liquefaction plant. The first phase will consist of two liquefaction trains with a capacity of 4.5 million tpy at a total cost of US$ 4.5 - 5 billion. Construction is expected to begin in the first half of 2012. Cheniere Energy Partners is looking to take advantage of high Asian and European LNG prices to export shale gas in the form of LNG. The liquefaction project is expected to be constructed with each LNG train commencing operations approximately six to nine months after the previous train. The company has already entered into a lump sum turnkey contract for the engineering, procurement and construction of the first two trains of the project with Bechtel Oil, Gas and Chemicals, Inc. Chairman and CEO of Cheniere, Charif Souki, said, "Obtaining this financing will be a significant milestone for the advancement towards construction of the first two liquefaction trains." Bringing you the power of information Energy Global For more diary dates go to... www.energyglobal.com/events C hina National Offshore Corp. (CNOOC) has begun the construction of China's first floating LNG (FLNG) facility in the city of Tianjin. More precisely, the development will involve the construction of a floating storage and regasification unit (FSRU). The groundbreaking project is set to cost approximately US$ 900.5 million and is designed to be able to manage 2.2 million t (or 3 billion m 3 ) of LNG per year. Other investors in the project include Tianjing Port and Tianjing Gas Group. CNOOC has also announced that it has plans for a second phase of the project, which will involve the development of a land-based LNG terminal capable of receiving 6 million tpy and due to be operational by 2015. Ever rising domestic Chinese demand for LNG delivered by tankers has seen a host of onshore LNG terminals enter operation along China's east coast. This demand has led to intense competition between Chinese industry giants with companies such as CNOOC, PetroChina Co. Ltd and Sinopec fighting for suitable terminal sites, which has led to a demand for FLNG facilities. LNG_Spring2012_05-09.indd 6 16/03/2012 14:07 INTRODUCING A MONUMENTAL BREAKTHROUGH. FOAMGLAS ® ONE ® INSULATION IS NOW 50% LONGER! NEW 18” x 36” FOAMGLAS ® ONE ® INSULATION SAVES TIME AND MONEY. We’ve expanded our FOAMGLAS ® ONE ® cellular glass insulation line to include an 18” x 36” inch size with thicknesses up to 7 inches. Our newest solution represents a 50 percent increase over the traditional 24-inch size to save labor and accessory costs while maintaining all of the physical and thermal properties our customers have come to expect. Specifiers, building owners and contractors have the opportunity to save even more money in both labor and accessory costs; savings that can represent hundreds of thousands of dollars in major installations. Worried about performance? Don’t be. Our industry-leading FOAMGLAS ® ONE ® insulation still offers the impressive long-term thermal efficiency, water vapor impermeability and high compressive strength and dimensional stability demanded by our customers. To learn how you can start saving money on your next project, contact our technical experts for information about FOAMGLAS ® insulation from Pittsburgh Corning. 724-327-6100 º !oamglas.com/ihdusIry P itts b u rg h C o rn in g LNG_Spring2012_05-09.indd 7 16/03/2012 14:07 LNGNews 8 / LNGINDUSTRY / Spring2012 F airstar Heavy Transport N.V. has been awarded two transportation contracts for the giant Ichthys LNG project situated offshore Darwin, Australia. The contract, scheduled to begin in Q2 2014, will involve the use of two of Fairstar’s semisubmersible ships Forte, and Finesse for a minimum of 12 months each. This 12 month tenure is estimated to be worth US$ 56 million. Japan Gas Corp., the company that awarded the two contracts, has an option to prolong the two contracts by an additional six months, adding a further US$ 28 million to the contract value. The two vessels will travel between the Ichthys site and several different construction yards in Asia as they transport the components for the two LNG trains due for construction in Darwin. Fairstar CEO, Philip Adkins, said, “Fairstar will work closely with JGC to manage the safe and reliable delivery of the LNG modules for Ichthys and will be closely engaged with the JGC project Team in Japan.” S ingapore uses LNG to meet approximately 80% of its power generation requirements, most of which is piped in from Indonesia and Malaysia. However, growing energy demand in these two countries looks likely to reduce the amount of LNG that is available for Singapore to import. In an attempt to supplement its energy supplies in light of what appears to be an inevitable decline in imports from Indonesia and Malaysia, Singapore has constructed a new LNG terminal capable of managing imports of up to 15 million tpy. According to some analysts, this means that the terminal should theoretically be capable of supplying Singapore’s entire energy needs if the long term contracts with Indonesia and Malaysia were not to be renewed. The Chief Executive of Singapore’s Energy Market Authority, Chee Hong Tat, said, “Supply will come under pressure because of growing domestic gas demand in Malaysia and Indonesia. What we will do is ensure sufficient capacity to import LNG to meet all of our gas demand.” T he Spanish company has reported a 6.4% increase in its net income for the first nine months of 2011, bringing the figure up from g 1.786 billion to g 1.901 billion from the previous year. Total operating income for the company was recorded as g 4.01 billion; a 1% increase on September 2010. The most dramatic improvements were seen in the group's LNG division, with profits for the first nine months of 2011 rising a staggering 367.8% to g 276 million up from their 2010 value of g 59 million. The company attributes this rise to an increase in sales volumes. Other members of the group fared less well, with YPF reporting a decline in income of approximately g 200 million down to g 1.008 billion. Gas Natural Fenosa also posted a reduced income of g 712 million, down 4.9% on the previous year. The company announced that, "The 2011 earnings increase is mainly due to improved oil and gas prices [...] with a 13.4% and 14.8% increase respectively, this was boosted by the solid performance of the LNG division." AUSTRALIA Fairstar scores Ichthys contracts SINGAPORE LNG terminal imports to replace piped supply if needed SPAIN Repsol's income rises to W 1.901 billion LNG_Spring2012_05-09.indd 8 16/03/2012 14:07 Offshore LNG loading is like threading a needle on a trampoline: It takes highly specialized equipment. Almost a decade ago, we began developing the world’s first offshore LNG loading system. We designed it with constant motion swivels to handle rapid, unpredictable motions. We developed a patented cable targeting system to enable connection under these same conditions. And we helped make offshore LNG both practical and cost-effective. To see what we’ve done and how we’re approaching a next generation, worst-condition solution, visit www.fmctechnologies.com/offshoreLNG LNG_Spring2012_05-09.indd 9 16/03/2012 14:08 A TALE OF TWO GAS MARKETS Ng Weng Hoong, LNG Industry Correspondent, discusses the disparity between the Henry Hub price and the Asian LNG price. LNG_Spring2012_10-17.indd 10 13/03/2012 09:11 Spring2012 / LNGINDUSTRY / 11 A s US natural gas prices plunged below US$ 2.40 per mmBTU to their lowest levels in over a decade, LNG held firm near record levels in Asia, creating probably the greatest arbitrage trading opportunity in the history of any major commodity. But no one was taking advantage of this ‘sure win’ high-margin trade, (or likely will in the near term), to ship North America’s natural gas to Asia, which continues to pay between US$ 16 - 20 per mmBTU for its spot LNG cargos. In this strange tale of two markets for the same commodity, North America’s rising natural gas production and lack of export infrastructure could ensure that its overflowing supply continues to sell for an astonishing discount to Asian prices for a few more years. In the USA, weak demand, insufficient storage capacity and record production of over 23 trillion ft 3 last year, primarily from shale, drove natural gas prices down by a third from 2010. These trends are expected to continue through the rest of 2012 and even beyond unless the weather turns seriously cold and the economy recovers strongly. LNG_Spring2012_10-17.indd 11 13/03/2012 09:11 12 / LNGINDUSTRY / Spring2012 But in Asia, consuming countries can’t get enough supply from a handful of maxed-out regional producers, ensuring natural gas and LNG prices remain supported at or near current high levels. This is contributing to the worsening shortages and rising costs of electricity in the region. Led by Asia, global natural gas consumption will grow at an average annual rate of 2.1% through 2030, outpacing oil and coal, according to BP’s latest Energy Outlook report. BP claims that Asian LNG demand will constitute the fastest growing segment of the natural gas market. In response, annual global supply will grow by 4.5% to 2030, more than twice the rate of global gas production and faster than the 3% annual rate of increase seen for inter-regional pipeline trade, the report said. Growing at an annual rate of 7.6%, China’s gas use will reach 46 billion ft 3 /d in 2030 to match the size of the European market. The BP report raises the hopes of producers and traders hoping to exploit the widening Asia-North America price, predicting that the USA and Canada will be able to export 5 billion ft 3 /d by 2030. Paradoxically, the prolonged weakness in North American gas prices has created a powerful long term barrier, not incentive, to export. Large industrial consumers like power and petrochemical companies are opposed to exports that will raise their feedstock costs. The anti-export lobby cites recent studies by Navigant Consulting, Deloitte and ICF International showing that domestic US gas prices could rise by 15 - 20% from current levels if producers succeeded in exporting between 6 and 12 billion ft 3 /d. These price increases could hobble US attempts to revive its battered manufacturing sector. The debate over US LNG exports could become an important reference point for the future of Asia’s energy supply. Both sides have lined up powerful supporters, with producers like ExxonMobil and Chevron investing heavily to boost unconventional gas supply in favour of exports while chemical companies and industrial consumers argue that they need cheap energy feedstock to compete against low-cost Asian manufacturers. Asia dissipating global LNG supply glut, say two separate studies American fears are well founded according to two recent studies which found that fast-growing Asian demand is starting to impact the current glut in global gas supplies. A report distributed by consulting firm Research and Markets predicts that the glut will dissipate from 2014, with Asia-led demand expected to exceed supply by 75 million t by 2020. China, Japan, India, South Korea and Southeast Asia will use more LNG not only to fuel their economic growth, but also to try to displace coal and oil in their energy mix to reduce pollution. In the near term, the report said global LNG demand at 248.5 million t in 2011 will be boosted by the hurried closure of the majority of Japan’s nuclear power plants as well as plans for nuclear phase-out by several European countries. The report said another 17 countries will become LNG consumers and begin competing for supplies through the decade. Exacerbating the supply tightness, the report said many proposed export terminals in Asia and Australia will not be built in time as a result of insufficient funding and skilled labour shortages. In its latest annual survey, the France-based international association CEDIGAZ said that global LNG trade is ‘poised for rapid expansion in the short term’ after growing by 10% last year, partly due to a demand surge in Japan following the Fukushima Daiichi nuclear plant tragedy in March 2011. Rising demand in Asia helped offset the 9% plunge in Europe to boost global demand for 2011. On the supply side, it predicts growth in unconventional gas output and a 60% rise in global liquefaction capacity by 2020, laying the foundation for sustained growth in the international LNG trade. Asia’s regasification capacity to expand by more than a third from 2010 to 2015 Asia is expected to expand its regasification capacity by nearly 35% from 14.38 trillion ft 3 in 2010 to nearly 19.37 trillion ft 3 in 2015, according to a report by consultant GlobalData. Thanks to technological advancements, LNG has emerged as a viable option for importing natural gas to compete against piped gas. Since early 2008, the global LNG industry has been bolstered by rising demand, expanding supply from unconventional sources, and improved liquefaction and regasification technology. The report found that state-owned companies dominate the liquefaction industry, with just five companies accounting for approximately 36.8% of global liquefaction capacity in 2010. The regasification industry is more fragmented and diverse due to the low cost of building regasification plants. To meet the rising appetite for natural gas in most countries, more private companies are investing in regasification projects. The report said that global LNG liquefaction capacity increased from 121.71 million t in 2000 to 273.92 million t in 2010 while regasification capacity rose from 264.33 million t to 583.51 million t over the same period. Producing countries Qatar, Indonesia, Malaysia, Nigeria and Australia accounted for over 62.4% of the world’s liquefaction capacity while importers Japan, the USA, South Korea, Spain and the UK accounted for 78.6% of the total regasification capacity. For both natural gas producers and consumers, LNG offers greater flexibility compared to pipeline delivery. LNG_Spring2012_10-17.indd 12 13/03/2012 09:11 LNG_Spring2012_10-17.indd 13 13/03/2012 09:11 14 / LNGINDUSTRY / Spring2012 Another pipeline to deliver gas from Central Asia by 2013 China expects to start up its third West-to-East pipeline next year to deliver up to 30 billion m 3 of natural gas from Central Asia. Measuring a total of 18 104 km in length, the three pipelines that make up the West-to-East system will have a combined capacity to deliver 72 billion m 3 /yr of natural gas. The 5200 km third network will include one trunk and six branch lines, three gas storage terminals and an LNG terminal. Operator PetroChina plans to add two lines to this network after 2015, each with the capacity to carry approximately 30 billion m 3 of natural gas from Turkmenistan, Uzbekistan and Kazakhstan to China’s industrialised coastal regions in the east. According to the National Development and Reform Commission (NDRC), Central Asia now accounts for nearly half of the country’s natural gas imports, with LNG supplying the rest. The first WTE pipeline measuring 4200 km started up in October 2004 and has the capacity to supply 12 billion m 3 /yr a year from China’s western Xinjiang region to Shanghai. PetroChina started building the second 8704 km network in 2008, and expects to complete it in June 2012 with the capacity to deliver 30 billion m 3 . Shale to boost domestic LNG production China isn’t just counting on imports; it is also aiming to triple its domestic LNG production to 7.5 million tpy by 2015, according to the China Petroleum and Chemical Industry Federation. Speaking at the recent World Petroleum Congress in Qatar, Fu Chengyu, the Sinopec Group Chairman, predicted that China could overtake the USA in producing natural gas from shale and unconventional sources within 10 years. Rival China National Petroleum Corp. (CNPC) has signed a 30 year agreement with Shell to jointly develop and produce natural gas in the Sichuan province. The partners will appraise and look to develop unconventional gas reservoirs in a 4000 km 2 basin in the Jinqiu block. China National Offshore Oil Corp. (CNOOC), the nation’s largest offshore oil and gas company, has started seismic operations to explore for shale gas on a 4800 km 2 onshore block in eastern Anhui province. Following its recent acquisition of Chesapeake Energy assets in the USA, the Anhui project represents the company’s first onshore venture, signalling unconventional reserves as a new strategic target for future growth. The Chinese government has set a target for the industry to produce 6.5 billion m 3 from domestic sources by 2015 and 80 billion m 3 by 2020. Japan’s LNG imports up 12% six months after Fukushima Compensating for the loss of the bulk of its nuclear power capacity, Japan increased its LNG import by more than 12% to over 45.6 million t in the first six months of the 2011 - 2012 financial year to September 2011. According to official data compiled by consultancy GlobalData, Japan imported 45.606 million t of LNG for the March to September 2011 period compared with 40.686 million t for the same period the previous year. Japan has shut down more than 90% of its nuclear power capacity since March last year. Disillusioned and distrustful of the government’s mishandling of the crisis, the public has demanded the complete closure of the nuclear industry by this year. Pre-quake, Japan derived 29% of its electricity from nuclear power, and there were plans to raise that proportion to 40%. Now, Japanese demand for LNG could grow by more than 25% to over 100 million t in 2012 after surging by over 15% to a record of more than 80 million t in 2011, said a senior executive from the Japan Oil, Gas and Metals National Corp. (JOGMEC). Qatar and Australia are slated to become future major LNG suppliers with traditional suppliers Indonesia, Malaysia and Brunei playing support roles. Indonesia’s state energy firms preparing to import LNG Indonesia was, until recently, the world’s largest LNG supplier, but now faces the prospect of becoming a net importer later this decade as it is not finding and developing enough new gas reserves to meet its growing domestic energy demand. Its three main state energy companies, gas distributor PGN, power utility PLN, and oil and gas firm Pertamina, are preparing to start importing LNG. Pertamina and PGN have formed a 60/40 joint venture firm, Nusantara Regas, to own and operate the nation’s first two receiving terminals in West Java and North Sumatra. The priority will be to start up the first terminal, an FSRU, this year to serve Java, home to approximately 60% of the population. The three companies have been ordered to work on the 3 million tpy terminal on the western part of the island with Pertamina guaranteeing LNG supply from the Bontang export terminal on Kalimantan Island. Last April, Nusantara Regas signed a US$ 500 million deal with Golar LNG to charter the FRSU from a converted vessel to handle imports for an initial 11 year term with automatic conditional extension options up to 2025. Golar expects to complete the conversion and deliver the 125 000 m 3 vessel, Khannur, this quarter. Khannur will deliver up to 500 million ft 3 /d or 3.8 million tpy of LNG through a Nusantara Regas pipeline to two power plants owned and operated by PLN. Last December, a joint venture between Japan’s Mitsui OSK Lines Ltd and Indonesian shipping firm PT Trada Maritime Tbk secured the contract to ship LNG from Bontang to the FSRU. Nusantara Regas is looking to start work on the second terminal in Arun city on Sumatra Island by 2015. LNG_Spring2012_10-17.indd 14 13/03/2012 09:11 OIL-FREE . 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In the near term, however, Pertamina faces difficulty getting the approval of the government, which is focused on completing the FRSU project on West Java and PGN’s plan for a 140 million ft 3 /d unit in Belawan in northern Sumatra Island. Pertamina is not giving up the fight. For now, it is cutting back on exports and redistributing LNG from within its system to meet the estimated 10 million tpy demand of its domestic customers including fertiliser manufacturers in Aceh. Under the 2001 oil and gas law, Pertamina and other companies are mandated to allocate a quarter of their production to domestic users. The pro-export faction said Indonesia should honour its supply contracts as well to earn hard-currency revenues from LNG sales instead of subsidising domestic consumption. Nevertheless, oil and gas regulator BPMigas has been warning its international customers to brace for further cutbacks as the country’s natural gas production is forecast to fall by another 28% in 2012. Indonesia’s three main LNG export terminals at Bontang, Arun and Aech may be able to produce a total of only 262 cargos in 2012, down from last year’s 365 cargos. With 30 cargos already allocated to domestic customers this year, Indonesia will have only 235 cargos to meet the needs of its term customers in Japan, South Korea, China and Taiwan. China to pay at least 50% more for Tangguh LNG cargos China’s CNOOC will have to pay at least 50% more for its LNG supply from the Tangguh export terminal in Papua province, said BPMigas. In its negotiations with CNOOC, BPMigas wants to raise the contract price from US$ 3.35 per mmBTU to between US$ 5 and US$ 6; still substantially less than the recent Asian spot price of over US$ 16. CNOOC helped launch Tangguh back in 2002 when it signed on as a foundation customer by agreeing to pay US$ 2.60 per mmBTU for its annual supply of 2.6 million t of LNG when crude oil was languishing at less than US$ 30/bbl. Four years later, CNOOC, which owns a 13.9% stake in Tangguh, agreed to the first price revision by pegging LNG to a basket of crude price of US$ 38/bbl., up from the original price of US$ 25, set in 2002. The agreement allows for price reviews every four years. With UK major BP as Tangguh’s operator owning a 37.16% interest, Indonesia has secured five long term LNG supply contracts from the 7.6 million tpy terminal. Tangguh’s other customers include Sempra Energy, which lifts 3.7 million tpy while Japan’s Tohoku Electric Power imports 125 000 t. South Korea’s Posco and K-Power each have annual contracts for 550 000 t and 600 000 t respectively. Thailand to fast forward construction of second LNG import unit at Rayong Thai state energy company PTT is aiming to complete the expansion of the country’s second LNG import terminal by 2014 - 2015 instead of the original target deadline of 2016. Citing faster than expected growth in the country’s natural gas demand, the company said the new 5 million tpy plant at its Map Ta Phut, Rayong terminal, approximately 220 km southeast of Bangkok, will have to start up soon in anticipation of the completion of new gas-fired power plants. The new US$ 400 million plant will enable Thailand to double LNG imports to 10 million tpy. The US$ 900 million Rayong import terminal, which started up last September, making it the first in Southeast Asia, comprises two tanks each with a capacity to hold 160 000 m 3 of LNG. The Thai government has had to back away from building more coal-fired plants in the face of environmental opposition while quietly dropping plans for nuclear energy following the disaster in Japan. The government is expected to sharply raise the share of natural gas in Thailand’s energy mix in its upcoming revision of the country’s long term power supply master plan, or the Power Development Plan (PDP) later this year. The previous plan, which included nuclear energy and an expanded role for coal, had envisioned natural gas use to grow by 6 - 7% a year to meet 40% of the nation’s energy demand. These rates will have to be raised by at least 50%. Vietnam seeks LNG from Australia and Qatar Vietnam looks to be joining the growing Asian bandwagon to import LNG from Australia and Qatar. Traditionally an energy exporter, Vietnam is facing shortages of coal and fuel as its energy demand is growing at a faster rate than its domestic production and reserves. State PetroVietnam subsidiary PV Gas recently met with officials of Australia’s Queensland state and Qatargas as part of its plan to build two terminals in Vietnam to import LNG. PV Gas is aiming to build a 1 million t capacity terminal along the Thi Vai River in southern Vietnam and a 3 million t capacity terminal in Binh Thuan in central Vietnam. The Thi Vai terminal is expected to start up by 2014, while the larger terminal is due to come onstream a year later. India expects LNG import capacity to more than quadruple by 2020 India is planning to raise its LNG import capacity from 13.5 million tpy now to 47.5 million tpy by 2016 and 62.5 million tpy by 2020, said Petronet, the country’s sole natural gas importer and LNG terminal operator. The company is building a second receiving and regasification terminal at Kochi in Kerala state to add to its existing facility at Dahej in Gujarat. LNG_Spring2012_10-17.indd 16 16/03/2012 15:08 Spring2012 / LNGINDUSTRY / 17 Petronet could soon face competition from GAIL Gas Ltd, a wholly-owned subsidiary of GAIL, which is working with the Andhra Pradesh state government to set up an FSRU along India’s southeastern coast that will also import LNG. The partners are aiming to start up the Rs 50 billion facility by 2014 with the capacity to import up to 5 million tpy of LNG. Separately, privately owned Reliance Industries and UK major BP have received approval from the Indian government to invest a total of US$ 1.5 billion to further develop the country’s largest natural gas block in the Bay of Bengal. The partners are aiming to produce 10 million m 3 /d from four new satellite fields in the KG-D6 block from 2015. The block is producing less than 40 million m 3 /d of gas and is in rapid decline after peaking at approximately 60 million m 3 /d in June 2010. The Indian government wants oil and gas companies to find and develop domestic reserves to reduce import dependence. IOC awards contract for LNG terminal in Tamil Nadu state Engineering giant Foster Wheeler AG said subsidiary Foster Wheeler India Pvt Ltd has won a contract to develop a new (5 million tpy) LNG receiving terminal in Ennore city in the Indian state of Tamil Nadu by 2016. Australia’s rise as ‘world’s LNG supermarket’ Despite worries over rising cost, labour shortages and a new carbon tax from July this year, Australia looks set to maintain its run as one of the biggest winners of the global LNG boom that began a decade ago. With at least eight projects underway worth a total of AU$ 175 billion and another seven being planned, the country’s natural gas production is expected to triple to over 5700 billion ft 3 over the next decade, said energy economics group EnergyQuest. (US$ 1 = AU$ 0.97). Speaking at the recent Australia Gas 2011 conference, EnergyQuest CEO Graeme Bethune said Australia is in a strong position to lead as well as benefit from what the International Energy Agency (IEA) has called the coming ‘golden age’ of the natural gas industry. “When the current eight projects are completed, Australia will be supplying 10% of China’s gas needs, 20% of Japan’s needs and 30% of Korea’s needs, with major economic and environmental benefits for those countries,” he said. However, Australia has to ‘lock down’ as many of the projects as possible while conditions are favourable to ensure long term survival and profitability, said Dr Bethune. He warned that some projects were already behind construction schedule and over budget, while competitors were accelerating their plans to develop LNG export terminals in the USA and Canada. Government policies, natural disasters and environmental restrictions are also presenting challenges to Australia’s natural gas and LNG project developers. Acknowledging the industry’s growing worries, Federal Resources Minister Martin Ferguson hinted the government may delay its approvals for new LNG projects. Ratings agency Fitch has given Australia’s booming oil and gas sector a negative credit outlook this year while Deutsche Bank said the country’s workers in the resources sector are probably the world’s most expensive, earning twice as much as the global average. China, Japan step up investment flows into Australia’s LNG sector For now, Asian investors are showing little concern about this rising wall of worry. In January, Asia’s two largest economies lifted their involvement in Australia’s LNG sector. China’s Sinopec Group has agreed to raise its previous 15% holdings in a US$ 20 billion LNG project in Queensland state to 25% while a consortium led by Japan’s Inpex announced it would invest US$ 34 billion to develop the Ichthys project in the Northern Territory state. Sinopec Group, which paid US$ 1.5 billion for its initial 15% stake in the Australia Pacific LNG Pty Ltd (APLNG) project in April, will acquire its additional shares from consortium partners US ConocoPhillips and Australia’s Origin Energy Ltd. As part of the first deal, the consortium agreed to supply 4.3 million tpy of LNG to Sinopec. In the latest deal, Sinopec will purchase another 3.3 million tpy of LNG from 2016 to 2035, said Origin Energy on behalf of the consortium. APLNG’s export-oriented LNG project includes the development of its substantial coal seam gas resources in the Surat and Bowen Basins over a 30 year period, a 530 km transmission pipeline, and a multi-train LNG facility on Curtis Island, near Gladstone. The project was sanctioned in July last year for an initial LNG production train and infrastructure to support a second train. Separately, Inpex and France’s Total had given their final approval to proceed with their joint development of the US$ 34 billion Ichthys project. The port city will be the site of the one of the world’s largest onshore gas facilities to process and produce 8.4 million tpy of LNG, most of it for export to Japan, from the end of 2016. The terminal will consist of two LNG trains at Blaydin Point, with additional land already made available by the Northern Territory state government for the possible addition of another four trains. Gas from the offshore Ichthys field in the Browse Basin off the coast of Western Australia will be delivered via a 889 km pipeline to the onshore terminal in Darwin. Ichthys holds an estimated 12.8 trillion ft 3 of gas and 527 million bbls of condensate. Inpex and Total recently concluded US$ 70 billion worth of sales agreements with Japanese customers for the bulk of the project’s entire LNG production for 15 years from 2017. As one of the world’s largest LNG facilities based on an estimated 40 years of gas and condensate reserves from the Browse Basin, Ichthys will also produce 1.6 million tpy of LPG and 100 000 bpd of condensate at peak. LNG_Spring2012_10-17.indd 17 13/03/2012 09:11 2011! A toast to LNG_Spring2012_18-24.indd 18 13/03/2012 09:50 Spring2012 / LNGINDUSTRY / 19 L ast year will be remembered as a very successful year in the LNG industry. The global industry grew its sales by an estimated 9% to 240 million tpy. Several markets increased their LNG demand. Notably the UK (mainly supplied from Qatar), India, China, Korea and Argentina collectively imported approximately 15 million t more in the first nine months of 2011 than in the same period in 2010. An unexpected test for the industry came from Japan following the earthquake and tsunami in March. A sudden increase in LNG demand followed the shutdown of 11 Japanese nuclear units (12 GW). By the end of last year, it is estimated some 10 million t of additional LNG will have moved from Asia, the Middle East and the Atlantic Basin to Japan. This extra LNG demand is expected to continue whilst several nuclear units remain shut down for prolonged maintenance and until the country’s nuclear policy becomes clear. The consequential increased demand on shipping put an upward stress on charter rates to approximately US$ 100 000 per day, with virtually the whole fleet deployed. In turn, Asian spot LNG prices became much higher than Atlantic Basin markets with premia of US$ 8 - 13/mmBTU. These price differentials are some of the highest levels we have seen for some time and they look set to remain for the short term at least. LNG sellers demonstrated that with the growing volume of divertible LNG and spare shipping, it can be effective in responding to sudden supply challenges and provide supply reliability when and where it is most needed. New supply capacity came onstream in Qatar; all the new mega trains have now reached (and exceeded) their design outputs. In total, Qatar added 19.5 million tpy of new supply to the market. Short term LNG sales rose to approximately 20% (48 million t) of the global market and last year was a year of high value arbitrage trading for the market players who, by contract, control the destination of the LNG they purchase. Commercial opportunities to import and re-export from the USA at regas terminals in Louisiana and Texas continued and indeed similar activities developed in Mexico, Belgium and Spain. Overall, 1.5 million t of LNG was re-exported in the first nine months of the year. Pat Roberts, LNG-Worldwide Ltd*, UK, looks back at a successful year for the global LNG sector. LNG_Spring2012_18-24.indd 19 19/03/2012 08:57 20 / LNGINDUSTRY / Spring2012 Market fundamentals will be more complex to assess At a macro level, the Eurozone crisis, the Japanese earthquake, its impact on the nuclear industry worldwide, and the Arab Spring all demonstrate that we operate in a complex environment for forecasting LNG supply, demand and pricing developments. More dynamic forecasting is needed to incorporate all the uncertainties arising from the business environment. This is becoming an important feature of our business. On the demand side, the world’s largest LNG consumer, Japan, suddenly has a lot of variability in its demand, varying from 63 - 92 million tpy depending on assumptions over the period 2012 - 2020. Also, most of the new LNG demand growth is associated with countries in Asia whose demand is very sensitive to price. Depending on outright pricing, wide variations in demand are evident in countries like China and India. Overall, demand forecasting will be more complicated and more variable. To make it internally consistent, it is necessary now to recognise there is ‘tiered’ LNG demand. Some LNG is ‘must buy’ whereas other demand is ‘price sensitive’, and sustained high prices will limit the development of much of the new market demand. Coupled with the fact that the supply of new LNG is linked to a variety of projects with very different cost stacks, it means that simple volume charts showing supply and demand growth are of little use in determining the commercial features that will drive supply and demand and in devising robust business plans. Throughout the year, the prospect of North American LNG exports has been growing as a credible option to resolve some of the key supply, demand and pricing uncertainties. We end the year with the Cheniere project at Sabine Pass having signed three conditional agreements with BG Group, Gas Natural Fenosa and GAIL (India) Ltd. As a result, a new round of economic and regulatory risk modelling needs to be undertaken before we can assess the volume of North American LNG supply that could be expected to develop by 2020. Gas pricing differentials between markets was a common theme. Understanding US shale economics, new LNG cost stacks and the ability of markets to support prices linked to oil have all been discussed. Throughout the year the price differentials have widened. It is this inter-regional spread that supports long term North American exports. Charles River Associates coined the phrases ‘Pacific Shale Spreads’ and ‘Atlantic Shale Spreads’ to refer to the arbitrages between Asia and the US, and Europe and the US, gas markets. It has been too early to forecast the consequences on these spreads as North American exports develop, but it is clear there are definite price risks to manage, either through the physical business or through locking in future spreads by hedging. In addition, it raises the issue of whether North American exports will lead to the US Henry Hub index developing as a new market index for LNG prices in other regions. Demand growth to 2020 is expected to remain strong, but needs to be matched with new supply cost control and continual commercial innovation The industry has doubled roughly every 10 years and the prospects remain good that it will almost double again to 400 million tpy by 2020. A new round of expansion is well underway with 12 projects (76 million tpy) currently under construction, mostly centred on Asia Pacific supply (Australia) to Asian markets. There are also several other projects that may mature. Globally, projects totalling 280 million tpy have been announced as being ‘under active development’ and include Tanzania and Mozambique as potential new sources. In 2012, some 70 million tpy of projects are targeting a final investment decision (FID) and the majority is focusing on supplying the Asian market. It is difficult to see how all these projects can take FID further in 2012. So the race is on. However, positive demand prospects alone will not drive the business forward at its recent growth rates. Not least, since much of the new LNG demand growth is expected to be in Asia’s price sensitive markets. Collectively, the industry will need continuous improvements coming from technological and commercial innovations to deliver a cost-effective gas supply to customers. In addition, LNG will need to be price competitive with other gas supplies and other fuels to ensure it builds market share. This is nothing new of course, but the current global uncertain economic times and sustained energy inflation makes supply cost control harder. Yet it is increasingly central to any credible investment plan. The LNG sector is collectively relying on two major pillars of support for its plans: Technical and commercial innovations The LNG industry has been innovating continuously over the last 50 years. It will remain a key success factor for the future. 2011 has been an outstanding year for technical innovation. Notably: Shell has taken FID on its Prelude floating liquefaction project in Northwest Australia to prove its concept of a mobile liquefaction plant as a way of monetising smaller scale reserves. Two more coalbed methane sourced LNG plants have taken FID in Queensland (Gladstone LNG and APLNG). Excelerate Energy has considerably shortened the lead times to complete an FSRU project in Argentina. Small-scale liquefaction (and modular builds) are under active development. Figure 1. Summits throughout the year questioned the speed with which more trading would develop. LNG_Spring2012_18-24.indd 20 13/03/2012 09:50 We’re developing oil and gas technologies to power the world. At GE, the future is at work. Powering LNG_Spring2012_18-24.indd 21 13/03/2012 09:50 22 / LNGINDUSTRY / Spring2012 Technically challenging Arctic plans are under development. US regas terminals are developing plans to add liquefaction capacity and provide bi-directional terminals. The outlook presented last year was more innovation and new supply growth of 150 million tpy by 2020. Within this there is likely to be a variety of technologies and ongoing cost control. Unconventional feed gas for LNG plants looks as though it will grow progressively over the period. In parallel to technical innovations, a sustained drive to develop innovative commercial propositions is needed. Companies who can successfully combine cost-effective supply growth, whilst retaining as much commercial flexibility in their transactions will develop an important competitive edge. The word ‘flexibility’ has been central to everyone’s aspired business model. It has been the value added feature in several growth plans for buyers and sellers alike. Flexibility to divert long term sales of LNG to other markets, or trade some LNG on a spot basis is likely to lead to an increase in market liquidity of both volumes and players open to trade. However, the barriers to LNG being a global traded commodity remain strong. It would need a fully liquid market, spare open access at terminals, spare shipping, standardised contracts and balanced risks and rewards. These criteria are not all in place, but there are signs the markets are adapting to incorporate more short term sales. Summits throughout the year questioned the speed with which more trading would develop. Times are changing and countries like Singapore and Thailand are building spare regasification capacity to offer new services to customers, whilst several LNG companies are opening regional offices in Asia to prepare for more short term trading and optimisation activities. Challenges ahead It is clear that the next phase of growth isn’t going to be all plain sailing. As the industry grows, the challenges facing the industry are evident and serious: Delivering the current 12 new LNG supply projects under construction on time and on budget; some have already announced they are delayed and over budget. This level of concurrent building has never happened before, particularly since seven of the projects (53 million tpy) are in Australia. The new supply projects are getting more complex. For example, they involve large scale CO 2 sequestration, coalbed methane as feed gas and floating liquefaction. In addition, the Australian projects are competing with each other for labour and resources. Whilst these challenges are being addressed, a further challenge will be the impact that unconventional gas may have on the need for new LNG. The view that ‘all gas is good’ voiced by a variety of IOCs masks the fact that some LNG growth may be stymied by the development of unconventional gas supplied by pipeline. Notably in China (one of the most important markets for new LNG growth), growth in unconventional gas supply has largely been assumed will take place post-2020. However, if this were advanced successfully, it could substantially reduce China’s need for LNG and significantly change demand assumptions. Successful business models (for both buyers and sellers) will incorporate flexibility and be fast to react to change. The general consensus in 2011 was that flexible business models would be the best means of managing uncertainty for buyers and sellers alike and generate and protect value. At first sight, it is difficult to imagine how both buyers and sellers can have flexibility in their LNG business models at the same time. Yet each party claims this is needed if their growth targets are going to be met. Market price differentials over the last seven years have made everyone aware of the tremendous value available from arbitrage if companies have access to sufficient infrastructure and divertible LNG to respond quickly to short term spikes in demand. Sellers have made it clear that flexibility comes at a price for buyers. The tension we will be seeing over the next few years will be the extent to which both buyers and sellers can extract value from their portfolios and manage risks effectively. Success isn’t just going to be measured by price alone, but also the wider operational flexibility negotiated in the supply arrangements. Much of the new buying interest will come from buyers who are likely to find the traditional terms of long term purchase quite onerous, such as: high take or pay, limited operational flexibility, limited destination flexibility and long lead times for scheduling cargos. LNG exports from North America operating on a FOB business model may address many of the concerns of new buyers. However, it is clear that flexibility will come at a price. In this case, the long term monthly payments of a fixed capacity charge. It is too early to say which players Figure 3. Last year was a successful one for the global LNG sector. Figure 2. Industry leaders gathered at the annual CWC World LNG Summit in November last year. LNG_Spring2012_18-24.indd 22 16/03/2012 15:11 are best suited to manage these risks, but the companies that can manage the shale spread price risks, could see a fast track approach to securing new LNG. Throughout 2011, summit speakers from across the value chain described how their business models are being developed to operate across a broad supply chain. The evidence of this happening in 2011 comes from Chinese and Japanese companies taking more upstream positions in LNG supply projects. More similar activity is expected in 2012. The midstream is another area where we should expect new business to develop. 2012 - 2013 will see midstream players offering infrastructure services (provided capital costs can be covered adequately). As a result, new liquefaction tolling, regas terminal storage break bulk, reloads and perhaps bunkering for LNG fuelled ships services are likely to grow. Some wildcards to look out for in 2012 Some ‘wildcards’ which could seriously affect the future LNG supply and demand growth were identified in 2011. Supply side issues which may surface: Unconventional gas goes global much faster than had been thought. Examples were China and Indonesia being two countries whose upstream developments could change the supply/demand balance in Asia faster than expected. EPC costs stay stubbornly high, slowing new growth and stalling the development of price sensitive markets. Demand side issues which may surface: A double dip recession – particularly starting in Europe and impacting the global economy. Consumers who are continually experiencing rising fuel bills, a rising US dollar vs. the Euro, may respond through more energy efficiency and savings than currently forecast. To conclude, it is evident the industry has to live with more uncertainty, change and risk. Yet as an energy sector, LNG remains a very attractive energy business. The talent pool is increasing and the prospect of working in an industry where LNG is a big part of the energy solution is key to making the industry a premium place to work. Note *Pat Roberts works closely with CWC’s gas and LNG Summits (LNG World Series: Asia Pacific Summit, LNG Americas and World LNG Summit) which aim to bring together the industry’s leading players to address the key issues facing the sector, developing knowledge and providing commercial solutions. Figure 4. The outlook presented last year was more innovation and new supply growth of 150 million tpy by 2020. Industrial Gas & LNG Croygenic Insulation For Technical information please contact Anatoli Kogan at +1-518-880-1959 /
[email protected] Designed for Performance º E/:ep||c|a||] u|||c|r º 0 2 :crpa||o|e & \c|-1arrao|e º U|||a |||| & ||¸||We|¸|| º Oceº |c| º|urp, ºe|||e c| :crpa:| c.e| ||re º |rp|c.ed ra|u|a:|u|||¸ |||cu¸|pu| |eep ]cu| pa]|cad Colder...Longer! Cryogenic Lab º P|cdu:| :|a|a:|e||/a||c| º A:|ua| uºe :|]c¸e||: :c|d|||c|º º Sc|u||c| |e:crre|da||c| Complete Product Portfolio LNG_Spring2012_18-24.indd 23 13/03/2012 09:50 IT’S A BIG NUMBER, HOWEVER YOU LOOK AT IT www.energyglobal.com * VISITS TO DURING FEBRUARY 2012 Bringing you the power of information Energy Global LNG_Spring2012_18-24.indd 24 13/03/2012 09:50 L NG is a marine industry, and yet, with the exception of a few reception terminals located close to shore, all LNG facilities are onshore. All offshore gas fields in production today have been developed by piping the gas to an onshore plant where the gas is cleaned up and then liquefied when LNG is the desired product. This is about to change. What is FLNG? FLNG is the gas equivalent of an oil FPSO such as Akpo. The designs use a purpose built ship-shaped hull that can store large amounts of LNG at approximately -160 ˚C and atmospheric pressure in highly insulated tanks. All facilities for receiving the raw gas, treating it to remove undesirable components and finally liquefying it are located in the topsides. The LNG is offloaded to shuttle tankers through specially developed systems designed to operate safely in the open sea. FLNG’s time to shine Victor Alessandrini and Mohamed Ould Bamba, Technip, Europe, discuss the increasing importance of the FLNG concept for offshore gas production. Figure 1. Prelude FLNG (Courtesy of Shell). LNG_Spring2012_25-29.indd 25 13/03/2012 10:49 26 / LNGINDUSTRY / Spring2012 Why now? The possibility of transferring a liquefaction plant to a floating facility located directly above the offshore gas field was first seriously considered 35 years ago, but it was more a matter of wishful thinking, since, at that time, there were no subsea wellheads, no flexible risers, no multipath rotary joints, no knowledge of motion effects on process equipment, no FPSOs and no known means of transferring LNG to a shuttle tanker out at sea. The requirement for innovation in the 1970s was just too high but the progress made in sister industries has meant that as time has passed, these technological barriers have progressively been lifted, creating the conditions that led to the advent of FLNG today: Subsea production of oil and gas and FPSOs have become mature technologies and several mega FPSOs (topsides >30 000 t) are in operation. Computer modelling of floating structures and the effects of motion have progressed enormously. Open sea transfer of LNG has now been made possible with several qualified technologies such as Technip’s Amplified LNG loading system (ALLS). In parallel with technological progress, other trends have developed that are favourable to FLNG: New fields tend to be in deeper water and further from the coast as gas reservoirs in shallow waters have been depleted. This makes a pipeline solution much more expensive. For example, the pre-salt fields in Brazil are typically 300 km offshore in more than 2000 m of water. Pipelines of up to 1000 km are planned in Australian waters. Rising HSE and labour standards are raising the cost of construction in remote areas. LNG trains are now among the largest industrial plants, and building them onshore in remote locations is increasingly costly, requiring many skilled tradesmen and supervisory staff recruited from a global market. Safer, faster, cheaper The principle advantages of FLNG are: Better HSE construction takes place in a highly organised shipyard that will benefit from repeat orders. Shorter schedules, no site preparation, no onshore permitting, and no community relocation. Lower project cost: Building an FLNG vessel in a shipyard provides access to highly skilled and productive labour. No long distance pipelines. No marine terminal. No site infrastructure such as roads, residential areas or temporary facilities such as construction jetties, workshops, housing. Challenges remain FLNG presents numerous new challenges that have all been addressed and at least one solution found. Among the key technical challenges, the following can be highlighted: The effect of motion on processing Whilst oil and associated gas systems have operated successfully on floating systems for over 25 years, LNG process equipment is more sensitive to motion. Motion mainly affects the operation of equipment where there is liquid distribution under the effect of gravity. When accelerations due to motion are superimposed, liquid misdistribution could occur, potentially leading to a loss of mass or heat transfer efficiency, off-specification product, process upsets, etc. For columns, the industry has feedback from floating processing platforms and laboratory tests. Structured packing is favoured. Distribution of liquid is critical, for example; shallow open pan distributors are avoided. Specialist suppliers in internals for mass transfer have done a lot of work on this topic by themselves and with the process technology licensors. Technip’s first specially designed fractionation columns for the NGL extraction and LPG fractionation units of the N’kossa project (Congo) have been in operation for over 15 years. Other examples are fractionation columns on the Sanha LPG FPSO offshore Angola and the Belanak FPSO in the Natuna Sea, Indonesia. However, the recognised challenge that is specific to liquefaction is distribution of liquid over all the tubes of the coil wound exchangers used to condense and sub cool the LNG. To minimise the effects of motion, the columns, critical tanks and cryogenic heat exchangers are located as close as possible to the ship’s centre of gravity. Internal baffles minimise the sloshing of liquids, and special distributors minimise the risk of misdistribution of liquid in the equipment. When appropriate, motion-insensitive gas phase processes are selected. Energy efficient processes of this type have been developed. The design of topside equipment requires the collaboration of an entire team Figure 2. Total Akpo FPSO. LNG_Spring2012_25-29.indd 26 13/03/2012 10:49 www.strabag-international.com YOUR WORLDWIDE LNG EXPERT Almost 50 years of successful records can’t be wrong: Since 1968 DYWIDAG has a well respected name for providing high-quality LNG engineering, consultancy and construction services to a wide range of clients. From small to big tanks, from export to import terminals, from experimental to peak shaving tanks, at various environment and soil conditions with and without piling and isolators. Today DYWIDAG LNG Technology is part of STRABAG SE, one of Europe’s largest construction groups, which is active worldwide and maintains permanent offices amongst others in Abu Dhabi, Doha, Seoul, Singapore, Shanghai, Perth, Dar-es-Salam, Algiers, Tripoli and Jubail. As part of STRABAG group, DYWIDAG LNG Technology can take on even the biggest and most complicated construction challenges. The group can utilize over 600 experienced engineers and scientists with a long history in civil engineering and building construction through to the construction of transportation infrastructures. This dedication, our experience and knowhow make us your LNG expert, worldwide. STRABAG International GmbH DYWIDAG LNG Technology Mies-van-der-Rohe-Str. 6 80807 Munich/Germany Phone +49 89 360555-2310 www.strabag-international.com LNG_Spring2012_25-29.indd 27 13/03/2012 10:49 28 / LNGINDUSTRY / Spring2012 of naval architects, piping, process and equipment engineers, critical equipment suppliers, installation specialists and engineers skilled in advanced numerical modelling. Accelerations are quantified and loads on mechanical equipment checked with vendors. The effects of hull motions on gas/liquid separation in process equipment are studied when necessary with process licensors and suppliers. Large gas volumes through swivels FLNG requires larger volumes of high pressure gas to be brought onto the vessel deck than previously experienced. In a harsh environment the FLNG vessel must weathervane to minimise motions and mooring loads. With oil FPSOs the proven solution is generally a swivel device that has multiple flow paths for the gas, chemicals, hydraulic fluid and signals for operation of the wells. Cargo containment system There are two acceptable technologies available in the market: membrane tanks (commonly used for LNG carriers) and SPB tanks (fewer references, but originally developed for arduous service). A cargo containment system must resist sloshing loads in partially filled tanks and be able to operate for 20 - 30 years without dry docking. There is a tendency to consider that solutions with membrane tanks present some cost and schedule advantages. The ultimate choice is usually a question of client preference. LNG offloading Two configurations are today considered as applicable: Side-by-side. Tandem. The availability of side-by-side loading using articulated loading arms is reduced compared to a shore berth operation. The governing criteria for availability are the prevailing metocean conditions, especially the wave conditions (height and period), wind and relative heading. As for oil side-by-side operations (see OCIMF guides), typical limits appear when the wave height exceeds 3 m for head sea conditions. Again, availability very much depends on site conditions and on the presence of acceptable wave conditions that are persistent enough to cover the entire length of the offloading operation. The vendors have had to demonstrate that their technology can be operated safely in these offshore conditions and have had to assess the quantity of reinforcement to be added on LNG carrier manifolds to sustain the loads developed during operation. Specific locations, such as Brazil, require tandem systems due to frequent cross sea conditions. Using expertise combined from flexible pipe design/ manufacturing, LNG and offshore expertise, Technip developed ALLS, which uses Technip’s cryogenic flexible pipe to allow ship-to-ship LNG transfer in the open sea. When it is reel-mounted, the pipe is installed on the stern of the FLNG vessel to allow it to tandem offload its liquefied gas cargo onto the bow of a modified LNG tanker. Technip is also developing a floating hose that will enable unmodified LNG carriers to receive the LNG cargo via their mid-ship manifolds whilst still in a tandem configuration. Safety: cryogenic and hazardous fluid risks The challenge for the layout of an FLNG facility is the large process area and the relatively high congestion of modules in a reduced footprint. A risk-based approach is needed to assess potential consequences and associated frequencies to derive appropriate safeguards and mitigation measures. Among process risks (fire and explosion) and non-process risks (ship collision, dropped object, etc.), the risk of exposure of personnel and the facility itself to cryogenic fluids in the event of a spill is a hazard that is specific to FLNG. The objective is to develop the design to minimise the potential for escalation and promote safe escape and evacuation with provisions for rescue of personnel in the event of major accidents. Naval architecture Naval architects have to address several new challenges: Sheer size: larger than existing FPSOs. Harsh environmental conditions. Weathervaning systems suitable for extreme storms. LNG cryogenic transfer between two floating units in the open sea. Figure 3. Total N’kossa FPU. LNG_Spring2012_25-29.indd 28 19/03/2012 09:58 Accommodating a wide range of LNG and LPG carriers. The development of the turret, mooring and riser system requires the combined marine/metocean expertise of all parties including the topside contractor, operator turret contractor and shipyard. Design solutions can be confirmed with the help of two tests: Wind tunnel tests to derive the wind and current loads on the FLNG with and without the LNG carriers present. Wave basin model tests with FLNG and LNG carriers covering: Mooring in design storm conditions. Decay and motion response tests. Berthing and mooring and the equipment required between the two vessels. The loads generated when towing. Shell’s FLNG The LNG world changed when in May last year, the Technip Samsung Consortium (TSC) was given notice to proceed with the construction of Prelude FLNG, the first floating LNG facility in the world, to be located offshore Australia. This key chapter of the FLNG story starts when in mid-2009, Shell awarded the TSC a 15 year Master Agreement for the design, construction and installation of multiple FLNG facilities. Technip, acting as leader, and its partner, Samsung Heavy Industries (SHI), first executed the FEED for a generic solution with a capacity of 3.5 million tpy. In March 2010, Shell awarded the contracts for the FEED and EPCI for Prelude with the latter becoming effective after FID. The Shell Prelude FLNG facility will be the largest floating facility in the world, at 488 m from bow to stern; longer than four soccer fields laid end to end. When fully loaded, it will weigh approximately 600 000 t; roughly six times as much as the largest aircraft carrier. Some 260 000 t of that weight will consist of steel; approximately five times the amount of steel used to build the Sydney Harbour Bridge. It is designed to operate under harsh ocean conditions and to process a wide range of gas compositions. The facilities will be capable of producing 3.5 million tpy of LNG, plus associated LPG and condensate with total liquid production potential of over 5 million tpy. Other FLNG programmes Many operators are now considering offshore gas field developments with FLNG. Some observers consider that about 5% of LNG production could be produced offshore by 2020. Floating LNG is now a viable alternative to traditional onshore LNG plants, providing a commercially and environmentally attractive approach for monetisation of offshore gas fields. Do you get shivers everytime you have to select a valve for cold box applications? Cool down ... with SAMSON’s Type 3248 Cryogenic Valve, tem- peratures down to –321 °F will be covered. With an extended isolating section, the actuator and accesso- ries are protected from catching a cold. And thanks to the service-free bellows seal, all maintenance can be done with a cool smile. 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[email protected] · www.samson.de SAMSON GROUP · www.samsongroup.de V isit u s a t O TC H o u sto n 2 0 1 2 B o o th 4 5 2 7 -1 8 LNG_Spring2012_25-29.indd 29 19/03/2012 09:59 LNG_Spring2012_30-36.indd 30 13/03/2012 10:56 Spring2012 / LNGINDUSTRY / 31 H ighly polluting or expensive fossil fuels such as heavy fuel oil (HFO) or diesel oil are nowadays used for electric power generation in isolated power plants, e.g. on islands. The use of natural gas as a fuel is a cost-efficient alternative and at the same time enables significant reductions in atmospheric pollution. On the other hand, isolated locations are typically unconnected to natural gas pipeline grids due to challenging terrain or losses in economy of scale due to F L O A T I N G B E T W E E N I S L A N D S O laf Beyer, TG E M arine G as Engineering G m bH , G erm any, discusses the provision of engineering services to provide LN G infrastructure for G uadeloupe and M artinique. LNG_Spring2012_30-36.indd 31 13/03/2012 10:57 32 / LNGINDUSTRY / Spring2012 small volumes. Existing LNG infrastructure is sized to handle much larger volumes than needed for these consumers. TGE Marine Gas Engineering has developed cost-efficient small to mid-scale import solutions comprising shuttle tankers and floating storage facilities for such markets. TGE Marine’s fellow company Gasfin Development SA is currently evolving an LNG infrastructure project with EDF (Eletricité de France) to supply natural gas to EDF’s power generation facilities in Martinique and Guadeloupe. Gasfin is an independent developer and infrastructure service provider of mid-scale LNG and natural gas solutions. TGE Marine has been selected by Gasfin to supply the FEED package comprising hull and gas handling system design for the shuttle tanker and the FSRUs. Bureau Veritas (BV) acting through its subsidiary Tecnitas was identified as the third party technical advisor for the project and has carried out risk studies and independent reviews and assessments to assure a high level of safety. BV will also be the approving classification society for the FSRUs and the shuttle carrier. The project objective is to deliver natural gas to the power plants as a replacement fuel for HFO. For that, the existing diesel engines will be retrofitted to dual fuel engines. In addition to realising material cost savings, the fuel switch will enable the plants to reduce emissions of CO 2 and NOx by up to 30% and 85% respectively. Sulfur and particulate emissions will be virtually eliminated. High overall availability of the power generation system is assured, as the existing fuel system acts as reserve fuel in case of LNG supply shortage. The objective was to design an integrated LNG delivery service scheme for both islands using right sized infrastructure based on proven and safe technology. The infrastructure will comprise a new mid-sized 20 000 m 3 LNG carrier and two purpose built 25 000 m 3 floating storage and regasification units (FSRUs). It is envisaged to supply LNG directly from Trinidad or to re-export via one of the regional terminals. The FSRUs will be moored close to shore in the vicinity of the power plants. The LNG will be vapourised on the FSRUs and sent to the consumers via flexible risers and a short subsea pipeline. When implemented, this project will be a world first in terms of using floating LNG infrastructure to facilitate economically viable international deliveries of LNG and supply natural gas to markets of this size, which presently do not have a viable means of accessing international markets. The envisaged supply scheme provides a continuous supply over a period of more than two weeks without reloading based on annual LNG demands of approximately 200 000 t for each of the islands. In Guadeloupe, the FSRU will be moored in a protected bay approximately 6 km offshore the Point-à-Pitre power plant at 25 m water depth. The favoured location for the Martinique FSRU is situated on the calm, leeward side of the island approximately 2 km offshore the Bellefontaine power plant at a water depth of 350 m. Both sites are located at a safe distance from marine traffic lanes and the public. Figure 2. FSRU receiving LNG. Figure 1. FSRU portside. LNG_Spring2012_30-36.indd 32 16/03/2012 15:16 LNG_Spring2012_30-36.indd 33 13/03/2012 10:57 I NTERNATI ONAL OPERATI NG CONFERENCE & TRADE SHOW 32ND ANNUAL SAVE THE DATE MAY 21-23, 2012 www.ilta.org Hilton Americas-Houston George R. Brown Convention Center HOUSTON, TEXAS
[email protected] | +1-703-875-2011 KEYNOTE SPEAKER Dan Burrus Technology futurist, business strategist and best-selling author During the keynote address entitled “Flash Foresight: Powerful Personal Strategies for Shaping Your Future,” Burrus will provide an exclusive perspective on the future of technological change and give specific insights into the opportunities that will be made possible by these changes and what ILTA conference attendees can do to capitalize on them. LNG_Spring2012_30-36.indd 34 19/03/2012 10:32 Spring2012 / LNGINDUSTRY / 35 Technical concept: FSRU hull The FSRUs will be designed as a permanent installed (non- propelled) offshore service barge with an uninterrupted service life of 25 years. The LNG will be stored in two cylindrical tanks arranged parallel along the vessel’s longitudinal axis. At both locations, the FSRUs will be permanently moored to the seabed by a spread mooring system. Anchor chains will secure the vessels to the seabed using high holding drag embedment anchors or driven piles. The system is designed to withstand severe hurricane conditions with a 100 year return period, which has been derived from site-specific metocean data. The hull of the FSRU is a single deck design with a deckhouse at its aft end. The deckhouse accommodates service and control rooms as well as living quarters. In the cargo area the hull will have a double bottom and double side shell. The general subdivision of the vessel is in accordance with the requirements of intact and damage stability criteria of the IGC Code. The main dimensions are 116 m overall length, 38.8 m breadth and a scantling draught of 8.60 m. The shuttle carrier will berth at the FSRU in a side-to-side modus. To assist in a safe approach of the LNG carrier, the FSRU will be equipped with a suitable fendering and a berthing aid system. Quick release hooks will ensure unobstructed departure of the carrier in an emergency. Technical concept: FSRU process The general design basis with few exceptions as detailed below, is valid for both Martinique and Guadeloupe. The intent is that both units will have a common design, with modifications limited to the mooring and subsea system. The storage volume of 25 000 m 3 covers approximately 2.5 weeks sendout at the normal expected annual consumption. The LNG transfer system will consist of two loading arms, one liquid arm and one vapour return arm at portside. The vapour return arm will be designed as a spare liquid loading arm. An alternative solution for the transfer of LNG in the form of cryogenic flexible hoses is being investigated. The FSRU will have two cylindrical IMO type C storage tanks, i.e. self-supporting pressure vessels of 12 500 m 3 volume each, which offer specific advantages. There is no secondary barrier required, there are no restrictions regarding partial filling allowing the FSRU an unobstructed top deck for the arrangement of the vaporiser process. Furthermore, the elevated working pressure provides a higher operational flexibility. In case of prolonged sendout interruptions, e.g. due to hurricanes, the tanks can retain the boil-off gas, which is permanently generated in the storage tank by inevitable ambient heat ingress, for three to 10 weeks, depending on the tank filling level. TGE Marine owns a patent for LNG specific design, which enhances a typical type C LPG tank bearing arrangement to withstand the higher thermal movements in LNG service. Unlike typical LPG/ethylene tank foundations, the patent incorporates the foundation to allow uniform shrinkage and load distribution. The tanks will be equipped with submerged motor type sendout pumps with variable speed drive. Ambient air vaporisers (AAV), which use ambient air as heat source, have been chosen as a means for regasification of the LNG at a pressure of 15 barg. The LNG flows through the stainless steel pipes of the AAV and heat is transferred directly from the surrounding air through the fins of the vapourisers to the cold LNG. The vapourised gas is delivered to the consumers onshore via a flexible riser and a subsea pipeline. A branch flow is taken from the sendout stream as fuel gas for the FSRU`s power generation. The boil-off gas is removed from the tanks by piston compressors and added to the sendout stream. Environmental impact The use of heat from ambient air results in lower operating costs and lower environmental impact than other regasification methods like open loop seawater vapourisers or combustion vapourisers. The main environmental impact is the formation of fog as the cold air discharge from the AAV arrays mixes with warm and humid air. Appearance of fog largely depends on environmental conditions (air temperature, humidity, wind speed etc.) and the actual load of the plant. To verify the actual situation, an extensive study has been carried out on the potential for the fog cloud to be a visual impact or to affect the shipping activities in the vicinity of the FSRU. In addition, a worst case scenario considering the most unfavourable ambient conditions and maximum load typical scenarios of load environmental conditions was looked at. The investigation was based on different theoretical models of fog formation as well as on a computational fluid dynamics (CFD) analysis. For the actual maximum continuous load and average ambient temperature, humidity and wind speed conditions fog appears only in the vicinity of the vapourisers. Based on these results the appearance of fog can be regarded as a relatively low probability event of local impact on the immediate surroundings of the FSRU. Figure 3. IMO type C tanks. LNG_Spring2012_30-36.indd 35 19/03/2012 10:59 B a se d o n i ts p ro ve n a n d p a te n te d LN G typ e C ta n k te ch n o - lo g y, TG E M a ri n e p ro vi d e s sto ra g e a n d tra n sp o rt so lu ti o n s th ro u g h o u t th e e n ti re sm a ll to m i d -sca le LN G ch a i n . S to ra g e b a rg e a n d ca rri e r d e si g n s ra n g e fro m 1 , 0 0 0 m 3 to 5 0 , 0 0 0 m 3 . R e g a s syste m s m a y b e p ro vi d e d b a se d o n se a wa te r, i n te rm e d i a te cycle o r a i r va p o ri ze r te ch n o lo g y. LN G F S R U s LN G F P S O s C a rri e rs: LN G o r m u lti p le ca rg o e s LN G sto ra g e b a rg e s M id sca le flo a tin g LN G so lu tio n s LN G lo a d i n g syste m LN G F P S O LN G sto ra g e syste m LN G F S R U w w w . tg e -m a ri n e . co m As the cloud will also under unfavourable conditions not exceed the exclusion zone around the FSRU, shipping traffic will not be affected and due to the minor height of the cloud there will be practically no visual impact. Technical concept: LNG carrier The shuttle carrier is designed for the dedicated trade between the LNG supply terminal and the two FSRUs. An important design request related to economic operation is to enable berthing at the FSRU without the need for tug boat assistance. The carrier’s transport capacity of 20 000 m 3 limits the frequency of calls at the LNG loading terminal to approximately 50 per year to cope with the limited berthing slot availability. Aft and bow thrusters together with a high lift rudder will be provided to accomplish the high manoeuvrability needed. The main dimensions are 160 m overall length, 24 m breadth and a scantling draught of 7.20 m. The design service speed is 15 kn. The technical concept of the LNG storage system is basically the same as for the FSRU. Cylindrical IMO type C cargo tanks will provide high operational flexibility whilst the boil-off gas is used for the gas-fired propulsion system. The compatibility of the mid-scale carrier with regional LNG terminals has been assured for all ship-to-shore interfaces. Project status and outlook To date, the engineering of the topsides, LNG containment system and processes has been completed along with the FSRU structural and naval architectural design as well as anchoring and side-by-side mooring layout. HAZID and HAZOP, collision risk analysis and several risk assessment workshops have been executed and the results have been implemented into the design. The basic design for the shuttle tanker is available and the compatibility with the loading terminals has been confirmed. Permitting documents including the Safety Dossier according to French regulations (Etude de Dangers) and the environmental impact assessment (EIA) for both locations have been finalised and submitted to the local authorities. An ongoing process is the design approval by BV, which is expected to be completed in the first quarter of 2012. An array of further detailed studies is under way, including a detailed reliability, availability, maintainability (RAM) study to confirm the results of the initial study as well as a fire and explosion risk assessment (FERA), which has to verify structural design loads of the FSRUs. Model tests will be carried out to assure the results of the numerical studies to verify the anchor loads under hurricane and side-by-side mooring conditions as well as the excursion of the FSRUs needed as input for the final riser design. Gasfin expects to finalise the development phase at the end of Q2 2012. Subject to the permitting duration, a final investment decision could be achieved in the second half of this year allowing the first delivery of gas in 2015. LNG_Spring2012_30-36.indd 36 19/03/2012 10:32 Spring2012 / LNGINDUSTRY / 37 W ith LNG now commonly referred to as the ‘fuel of choice’, and with the best shipping system of lightering/feeding proven over decades for all liquid fuels; the question we should deal with is not what it is or how it works, but why LNG feeder tankers are not commonly seen in the LNG sector. Why has it not entered into widespread usage wherever it is needed so it can be available within a relatively short time for any small or medium sized energy consumer? There are now 19 LNG exporting countries with supply available ex-train, and 23 more countries with supply available out of their dozens of receiving terminals spread all over the market. The potential market is destinations where no grid is available or possibly too expensive or technically too complicated to build (the Norwegian coastline for example). LNG feeder tankers are LNG tankers sized between 1100 m 3 (operated in Norway) and 20 – 30 000 m 3 that can serve destinations and customers that require up to 1 - 1.5 billion m 3 /yr. Good examples are the six Japanese-built 18 800 – 22 500 m 3 LNG tankers shipping small volumes of LNG from Malaysian and Indonesian LNG production trains directly to power plants and other gas utilities. Other smaller size tankers of 1500 – 2500 m 3 serve small gas companies in the coastal waters of Japan, taking their LNG from the large receiving terminals (ex-hub). The LNG feeder tankers need Moty Kuperberg, Dynamic Shipping Services, Israel, explains the benefits of using the small scale LNG feeder system to supply consumers spread over many destinations. LNG_Spring2012_37-39.indd 37 13/03/2012 11:05 38 / LNGINDUSTRY / Spring2012 limited land space and limited supply chain links of storage and regas systems that are compact and much more economical to build and operate. This way, a typical Japanese small scale terminal will use just 35 000 – 90 000 m 2 of land to handle up to 410 000 tpy. While an average large terminal needs 200 000 m 2 to handle 1.5 million tpy, 1.2 million m 2 to handle 6 million tpy, and the largest one will use 1.93 million m 2 of land to handle 8 million tpy. Smaller size terminals, which consist of a small jetty to allow the 1100 – 2500 m 3 feeders with their 3.6 – 4.2 m draft to dock and discharge their LNG load into 500 - 1500 m 3 storage tanks are a common sight now in Japan and along the Norwegian coastline. Japan is leading the way with small scale LNG feeders, as well as land based distribution. There are now more than 50 satellite terminals in operation in Japan. The same system is widely used in many countries that import or export LNG, from the USA through to Norway, Turkey and other countries. Three case studies Turkish coastal waters Turkey has a large road tanker LNG distribution fleet serving hundreds of customers with satellite terminals spread from the Marmara and Izmir receiving terminals across the whole country. This land based distribution system is operated by 10 companies using a fleet of 250 trucks that travel on average approximately 700 km to supply LNG. In some cases the trucks travel more than 1000 km with their 20 - 25 t loads of LNG. In total they supply approximately 0.5 billion m 3 /yr. The land transportation adds approximately 20% to the delivery price of the gas. The national gas company has been looking into using LNG feeder tankers to supply a few coastal locations to cut down transport costs and increase the reach of the trucking fleet at the same time. A feasibility study carried out back in 2005 provided better economic data on two main routes. The first from Marmara to three destinations along the Black Sea northern shore, spread from the Samsun area to Rize, close to the Georgian border. The second route is from Marmara to three more destinations spread from Antalya to Adana on the southeast Mediterranean coast. The intention was to feed several communities that were out of the grid and out of any planned grid. The initial plan was to start with a capacity of 0.25 billion m 3 and increase it to over 1 billion m 3 after five years, then gradually continue to grow to over 1.5 billion m 3 after a further 10 years. This way, the ‘long range’ travelling trucks could feed many more customers out of the new small scale regional hubs to be built for the feeders. Caribbean Sea The region, with its islands and close supply hubs is an ideal area for the LNG feeders. Trinidad and Tobago are LNG producers and the two existing receiving terminals can serve as regional hubs for distribution into the islands and neighbouring coastal countries. This way, more Central American countries like Panama, Costa Rica and the rest can benefit from the available gas. Other directions that were studied were local LNG small scale production of 0.5 – 1.0 billion m 3 /yr serving neighbouring countries. The full range of the Caribbean Sea could be covered within one to three days sailing time for an LNG feeder tanker. If we add to it the developing LNG export options out of the US Gulf, there is a lot of potential to grow the market. European coastal waters and waterways The pioneers in Europe were the Norwegians back in 2004, introducing another potential concept for LNG feeders – a small scale production plant near Bergen, serving the nearby coastal region. What started with a 40 000 t plant is now growing and spreading further south from the Norwegian western fjords into the Baltic Sea. When the new emission control limitations come into force, more gas will be needed for more and more applications. One of the major applications in Europe will be shipping propulsion. This will add vessels that will require LNG bunkering barges. The Baltic and Norwegian coastal trade and offshore industry already operate some LNG driven vessels. On another feasibility study carried out a couple of years ago into European waterways, some length/beam/draft and air draft limitations were crucial to allow the required LNG volume of the project to be carried. Together with TGE Marine Gas Engineering, a special shallow draft design was introduced to give the best carrying capacity for that restricted waterway. Road map to success of feeder project Several feasibility studies were carried out and a number of required parameters were developed. The company used the following criteria and parameters when delivering solutions to customers over the last few years: Time frame. Schedule as set by suppliers (of LNG, land based infrastructure, vessel availability, yard availability). The suggested solutions: size and general design for vessel and receiving terminal/storage. Budget and economics of the vessels. Fleet requirements: number of vessels, other types required, their general design (GA – General Arrangement). Safety: local regulations, class requirements, worldwide standards. The next stage: pre-FEED, FEED, selecting yard/EPC company, negotiation, contract for first vessel – first type, order and supervise. First vessel delivered. Continue to the second one, if required, and onward to establish a strong operating fleet. Further co-operation: fleet management, supply of LNG to other destinations, ‘franchising’ the concept in other places as an ‘off the shelf solution’. The ‘intentions and plans/methods’ can consist of regional distribution of LNG, distribution and further downstream operation, trading hub, bunkering and more. Then the vessel size, number of units, storage size, required LNG volumes, destinations, time frame, storage days required and all other requirements. The company also took into consideration load and discharge port limitations (for example what maximum draft is allowed or possible at the ports, length restrictions, air draft). In one recent project the company carried out, there were draft limitations on LNG_Spring2012_37-39.indd 38 13/03/2012 11:05 an inner waterway of 3.5 m; the company produced a design to cover that. Then attention is paid to linking supply chain parts – production, load port and jetty, discharge port and jetty, storage, regas. It is a very detailed feasibility study that lays the foundation to continue into a firm project. It provides all the necessary tools to make decisions toward further development of the customer’s LNG supply programme. From a successful feasibility study, the next stage is to develop the project for commissioning within 24 months or earlier: The method of work is an open mutual hands-on work on all required issues. It is a truly tailor made solution, based on LNG experience in similar projects. One of the main achievements of such a study is the possible smooth continuation into implementing it. Together with the customer, the company dictates missions and intentions and works to execute them. The future: More locations and destinations to build regional distribution, including upriver consumers of gas. Serving regional distribution out of FSRUs and FLNGs. Bunkering. Conclusion The LNG small scale feeder system is a proven way to supply LNG to small and medium size consumers spread over many destinations. It is ideal for consumers of up to 1 million tpy over any range between 200 nautical miles or less, and up to 1000 nautical miles range. The beauty of it is the full package is available with a very small footprint; much more economical to build and operate to serve those markets in comparison to other alternatives. LNG has many advantages as a fuel over other liquid fossil fuels as it is clean burning and readily available, and the technical delivery method is not too different. If an island generates its electricity from coal, heavy oil or gas oil that is supplied with small LPG or crude tankers, then an alternative LNG feeder operation would be much the same for them. As ‘security of supply’ becomes a much more important aspect of any energy market, natural gas and LNG feeders will have important roles to play in supplying energy markets. More gas will soon become available out of the planned floating LNG projects that will bring more ‘stranded gas’ to market and there are new suppliers of unconventional gas sourced LNG. LNG feeders will have their important role to carry some of that gas to nearby markets. The combination or integration of floating LNG and feeders will contribute to the small and medium size markets. In a way this article is a ‘wake up call’ for the many consumers of other fossil fuels to upgrade their energy sources, economy and environment, regardless of their size, to adopt what the LNG small scale system can provide for them. HOT WORK Needs a SafeHouse Habitat The Only lnternationally ATEX accredited 'Hot Work' Habitat LNG_Spring2012_37-39.indd 39 16/03/2012 15:19 LNG_Spring2012_40-44.indd 40 14/03/2012 09:02 Lars Petter Blikom, DNV, China, examines how cost increases in the shipping industry are leaving shipowners searching for cost reduction measures. I t is evident that the shipping industry is undergoing difficult times. In general, day rates have been on a downward slope for a long time, while costs have been increasing. This is not a healthy combination of developments in the long run. And unfortunately, the light at the end of the tunnel is not yet to be seen. Particularly on the cost side, there are significant additional expenses lurking on the horizon. And it does not seem likely that exemptions from future legislation is going to be a viable strategy; governments and other authorities are unlikely to move backwards when it comes to combating environmental issues. LNG_Spring2012_40-44.indd 41 14/03/2012 09:02 42 / LNGINDUSTRY / Spring2012 One upcoming cost item is the installation of ballast water treatment systems. The shipping industry is transporting huge amounts of ballast water across the oceans, and this ballast water contains various forms of marine life that may have negative effects when discharged into waters with different ecosystems. The requirements for ballast water treatment will be stepped up gradually to eventually include all ships from 2018. The cost of the system is somewhat uncertain, but it can be expected to add at least 2 - 3% to the price of a ship. Another upcoming cost item is scrubber systems to meet future limits for SO x content in the exhaust gas. From 2020, the limit for SO x content in the fuel is 0.5%. For vulnerable areas, designated as Emission Control Areas, the requirement will be even stricter at 0.1% from 2015. An alternative strategy for meeting these requirements is to replace the existing fuel qualities with low sulfur fuels, but this is expected to be a significantly more costly strategy than to install scrubbers. Again, the cost implication is uncertain, and highly dependent on ship type, but it is safe to say that the impact of the SO x regulations will be even more severe than that of the ballast water treatment systems. There are several aspects that render the impact of these regulations very uncertain; it is unclear how much low sulfur fuel the refineries will be able to produce and at what price. It is uncertain how many scrubbers the suppliers and the yards will be able to manufacture and retrofit, and there is also uncertainty about how to deal with the special waste produced by the scrubbers. For new ships constructed after 2016, there will also be limits on emissions of NO x . For conventional marine engines, installation of a catalyst reduction system is necessary in order to significantly reduce the emissions. These systems are currently being developed and tested, so cost figures are difficult to obtain, but significant figures can be expected. It is also worth observing that the catalysts will use some of the power produced by the engine to clean its exhaust. This of course leads to higher fuel consumption with its direct follow-on consequences of higher fuel costs and more CO 2 emissions. On top of these introductions of more complex technology comes the simple fact that the oil price seems to continue on its upward slope, resulting in higher costs for all qualities of marine fuels. In order to understand how important fuel prices are for shipping, we can have a look at the contributions by main cost items for four typical ships; this is illustrated in Figure 1. The main observation is that fuel cost represents between 58 - 78% of total daily costs. In other words, fuel cost is by far the most important cost driver for any ship type. It is also interesting to observe that the service of Capex investments is a fairly small portion of the daily costs, indicating that there should be a willingness to accept up-front investments in order to reduce the much bigger cost item of fuel. The carbon costs, ranging from 7 - 9%, are based on expectations of a future carbon tax regime. Based on this cost picture, it is a clear conclusion that competitiveness in the shipping industry to a large extent will boil down to consumption volumes and fuel prices. Outlook The problem with calculations of daily costs, net present values, return on investment, etc. is that they are based on project economics. And this is not normally how things are done in the shipping industry. There are two aspects that complicate the matter; the first is that often the charterer pays for the fuel, which means that the shipowner does not have any direct incentives to invest in reduction of fuel consumption. The second aspect is that often the shipowner wants to make the profits by selling the ships secondhand when the markets are good. If this is the plan, of course the appetite for up-front investments is smaller. Even when project economics is used as the basis for an investment decision for ship orders, there is a complicating factor: the overshadowing parameter is the uncertainty in future fuel prices. For all practical purposes, the oil price has proved impossible to predict. And when the most important parameter is impossible to predict, people become worried. This is not new to the shipping industry, it has been the case for many years, but the difference is that earlier, the fuel price fluctuations impacted all shipowners equally hard. Now that another fuel source has entered the picture, shipowners will be unequally impacted. This new fuel source suddenly available to ships is LNG. Over the past 10 years, LNG has been proved as a technically viable and safe marine fuel for practically all ship types. The consequence of this is of remarkable financial interest to the shipping industry, as it creates a source of competitive differentiation for the most important cost driver. A few percentages difference in the price per energy content for oil versus natural gas will create a massive difference in cost of ship operation. As mentioned previously, the fact that fuel suddenly becomes Figure 1. Shares of daily costs. LNG_Spring2012_40-44.indd 42 14/03/2012 09:02 chart-ec.com 1-281-296-4027 Delivering ‘Concept to Reality’ process driven system solutions for mid-scale LNG. Chart Energy & Chemicals has applied its knowledge and experience of cryogenic liquefaction technology to develop the Integrated Pre-Cooled Single Mixed Refrigerant (IPSMR®) process to provide improvements in operating efficiency and power savings, thereby lowering the cost per ton of LNG produced. Contact Chart Energy and Chemicals today to learn how IPSMR® can optimize your natural gas monetization needs. LNG_Spring2012_40-44.indd 43 14/03/2012 09:02 the most important differentiating factor in shipping competition will have a big impact on the decisions that are being made in the near future. The value of a ship will not just be a matter of today’s day rates and availability of tonnage anymore; it will also reflect the future compliance and fuel consumption of the ship. What should shipping companies do? First, it should be fairly safe to predict that with ever increasing fuel bills the charterer will bring this back to the shipowners at some point asking for improvement. Blindly expecting charterers, who are also hard pressed by weakening growth in most regions of the world, to pick up larger and larger fuel bills without asking any questions would be foolish. Even if charterers don’t start to question this practice, the punishment for inefficient operations will come in the form of future emissions taxes. So, shipowners should acknowledge early on that they are likely to be held accountable for their future fuel performance, one way or the other. Secondly, analysts have a proven track record of consistently failing to predict future oil prices. This task is now complicated further; they need to predict the relative price difference between two ‘independent’ energy sources (‘independent’ is not entirely true, hence the inverted commas). No shipowner should bet his or her company on analysts succeeding in this task. And as they will not be able to make better predictions themselves, they should adopt other ways of planning for the future. There are many tools available; for example real option valuation and scenario planning. What these tools have in common is that instead of making single point forecasts about what the future will hold, they consider the much more interesting question of, ‘what if I make the wrong decision?’ Thirdly, as most shipowners now see this coming, it can be predicted that we will see many LNG fuelled ships in the future. It is the cheapest insurance towards sky-rocketing oil prices. If the prices develop such that the natural gas price is much lower than oil, the implementation of LNG fuelled ships will be fast. If the prices develop such that the price difference is small, the implementation will be slower. In any case, the demand for LNG as a marine fuel can be expected to grow significantly, creating new market opportunities and premium prices for LNG sellers. Just to indicate the potential: if the entire global shipping fleet converted to run on natural gas, it would consume approximately 1.5 times the global output of LNG. For more information visit www.abc.org.uk or email info @ abc.org.uk Test a publisher’s statement of circulation. In today’s business climate you can’t afford not to. Our ABC Certificate provides accurate, independently verified circulation figures, giving you confidence in your advertising investment. LNG_Spring2012_40-44.indd 44 14/03/2012 09:02 Spring2012 / LNGINDUSTRY / 45 P resently, LNG is transported by sea in tankers at atmospheric pressure. Boil-off gas is either burnt in the tanker’s main engines or condensed in an onboard reliquefaction plant and then returned into tanks. 90% of the existing fleet burns boil-off gas, while the majority of newbuilds recondense it. The burning of boil-off gas implies the use of steam turbines for the vessel’s propulsion, which are characterised by low fuel efficiency. Another shortcoming is the reduction in the quantity of LNG delivered to the port of destination. Fitting the tanker with a reliquefaction plant solves these two problems, but the plant is quite expensive: approximately 10% of the vessel’s construction cost. An alternative way to absorb heat inflow into the vessel’s tanks is to cool LNG below its saturation temperature at atmospheric pressure 1, 2 . During the voyage, the temperature of the LNG will be rising gradually and will reach saturation temperature upon arrival at the port of destination. As far as the authors are aware, such a solution was never discussed for LNG transportation. A probable reason for this is that the pioneers of the LNG industry copied solutions used by 19 th century scientists for storing relatively small quantities of liquefied gases at atmospheric pressure. The large quantities of LNG carried by tankers enables them to use its enormous heat capacity to absorb heat inflow. The corresponding increase in the temperature of the LNG will be 4.5 ˚C for a typical 20 day voyage by a 150 000 m 3 tanker. The method In the proposed method of LNG transportation, LNG is cooled prior to its loading into tankers Vasserman Aleksandr and Shutenko Maxim, Odessa National Maritime University, Ukraine, explain an alternative method of LNG transportation, which eliminates the need for an onboard reliquefaction plant. DROPPING the temperature LNG_Spring2012_45-46.indd 45 14/03/2012 09:14 46 / LNGINDUSTRY / Spring2012 to a temperature that is lower than the saturation temperature at atmospheric pressure. During the voyage, heat inflow is absorbed by the LNG’s gradual heating to saturation temperature. LNG is not boiled off so it is not necessary to use a reliquefaction plant onboard the ship. The LNG is cooled by a shore-based liquefaction plant, which uses cheaper electricity than a ship-based reliquefaction plant. Moreover, powerful shore-based plants use more efficient thermal schemes (AP-X, C3-MR, cascade) 3, 4 , than ship-based ones (N 2 ). For this reason, shore-based plants consume per kJ of withdrawn heat no more than 70% of the mechanical power required to drive a ship-based plant 4 . Due to the economies of scale, capital expenses per kW of withdrawn heat also favour shore-based plant (one typical shore-based liquefaction plant produces a quantity of LNG that can be transported by 16 constantly operating tankers). Tankers carry large quantities of LNG so the level of subcooling from saturation point will be small. For example, the daily boil-off on a 150 000 m 3 capacity LNG tanker, which carries its cargo at 0.103 MPa is 0.15 % 3 or 94.9 thousand kg. The heat of vaporisation is 509.9 kJ/kg 5 , so the heat inflow is 48.39 million kJ/day. The mass of LNG in the vessel’s tanks is 63.27 million kg, the isobaric heat capacity of liquid methane is 3.424 kJ/kg 5 , so subcooling by 0.22 ˚C is sufficient to compensate daily heat inflow. When the basic duration of the voyage is 20 days, the subcooling of LNG required to absorb heat inflow is 4.5 ˚C. The subcooling temperature drop between environment and LNG will result in a corresponding increase of heat inflow. The temperature drop between environment (15 ˚C) and LNG at saturation temperature (at atmospheric pressure) is 176 ˚C. Because of subcooling, the average increase in temperature drop will be 2.3 ˚C, i.e. 1.3%. Methane vapour in the ship’s tanks above the LNG surface will arrive at thermodynamic equilibrium with liquid. The temperature of subcooled LNG is lower than its saturation temperature so after completion of loading it is necessary to mix methane vapour in tanks with inert gas (e.g. nitrogen). The content of each component should be selected on the basis of equality of the sum of partial pressures to atmospheric pressure. In the course of the voyage the temperature of the LNG will be rising and partial pressure of methane in the mixture of gases will be rising correspondingly. Excessive parts of the gas mixture from tanks should be released into the atmosphere or burnt in the ship’s propulsion plant. In the case of methane, with subcooling of 4.5 ˚C, the partial pressure of its saturated vapour will be equal to 0.070 MPa 5 and the partial pressure of nitrogen will be 0.033 MPa 6 . Costs and savings The application of the method to an LNG tanker with a capacity of 150 000 m 3 and an onboard reliquefaction plant will produce the following results: The cost of power for maintaining the LNG in a liquid state during ocean transportation will decrease by US$ 430 000 per year. For a ship that does not use a reliquefaction plant, at the commencement of ballast passage it will be necessary to leave LNG heel in tanks in order to keep them cold until the end of the ballast passage. This will increase fuel expenses for the ship’s propulsion plant by US$ 640 000 per year but will decrease fuel expenses for the reliquefaction plant by US$ 670 000 per year. The cost of the additional energy required for LNG subcooling before its loading on the tanker amounts to US$ 60 000 per year. All of the above will reduce operational expenses by US$ 400 000 per year. Capital expenses are reduced because the increases in the capacity of a shore-based liquefaction plant will cost US$ 3.4 million but there is a possibility of saving US$ 20 million for an onboard reliquefaction plant, which will become redundant. For ships with reliquefaction plant, application of the method on or before the stage of the vessel’s construction will reduce both operational and capital expenses. Application of the method to existing ships is not justified. For the same LNG tanker without a reliquefaction plant, the results will be as follows: Fuel expenses will be reduced by US$ 640 000 per year due to the use of heavy fuel oil instead of boil-off natural gas in the vessel’s propulsion plant. The cost of additional energy required for LNG subcooling before its loading on the tanker amounts to US$ 60 000 per year. Capital expenses arising because of an increase in the capacity of a shore-based liquefaction plant will be US$ 3.4 million. Thus, for an LNG tanker without a reliquefaction plant the basic return on investment taking into account annual depreciation of 7% will be 10 years. LNG subcooling implies the use of heavy fuel oil for the vessel’s propulsion. For LNG tankers without a reliquefaction plant there is a possibility of replacing steam turbines (with 30% thermal efficiency) with slow speed diesel engines (with 50% thermal efficiency). For existing tankers the feasibility of such a replacement should be decided on a case-by-case basis. For new tankers the replacement of steam turbines with slow speed diesel engines will always be feasible because all new vessels with reliquefaction plants (which also make it possible to use heavy fuel oil for propulsion) are fitted with diesel engines, not with steam turbines. References 1. Shutenko Maksym, Vasserman Oleksandr. Method of liquefied gases (primarily LNG) transportation at the temperature below saturation temperature. PCT application PCT/IB2011/000623. International filing date 23 March, 2011. www.wipo.int (In English language). 2. Vasserman A.A., Shutenko M.A., Method of transportation of liquefied gases at temperature below saturation temperature. Application for patent of Ukraine a 2010 12221. Filing date 15 October, 2010. www.ukrpatent.org (In Ukrainian language). 3. Tusiani M.D., Shearer G., LNG: A Nontechnical Guide. Tulsa, Oklahoma, USA, PenWell Corp., 2007. p. 436. 4. Bronfenbrener J.C, Pillarella M., Solomon J., review the process technology options available for the liquefaction of natural gas. ‘Selecting a suitable process’, LNG Industry, Surrey, UK, Palladian Publications, 2009. 5. V.V. Sychev, A.A.Vasserman, V.A. Zagoruchenko, A.D. Kozlov, G. Spiridonov, V.A. Tsymarny. Thermodynamic Properties of Methane. Hemisphere Publ. Corp. New York, 1987. p. 341. 6. V.V. Sychev, A.A.Vasserman, A.D. Kozlov, G.A. Spiridonov, V.A. Tsymarny. Thermodynamic Properties of Nitrogen. Hemisphere Publ. Corp. New York, 1987. p. 341. LNG_Spring2012_45-46.indd 46 14/03/2012 09:14 Spring2012 / LNGINDUSTRY / 47 T he recent worldwide increase in the consumption of natural gas has in turn led to a significant change in the requirements and in the corresponding solutions required to meet these new demands. These past years, the LNG business has increasingly taken a fresh look at offshore operations. GTT, as a designer of membrane containment systems, has been continuously adapting its technologies to meet these new challenges. Particularly, on the offshore side, challenges for FLNG units cover several fields never explored up to now. These units require continuous production, entailing both onsite maintenance (no regular drydocking as for LNG carriers) and operations with partially filled tanks. Adaptation of the cargo handling system must also be addressed to meet production and maintenance requirements. Stéphane Maillard, GTT, France, examines the benefits of using membrane tank systems in offshore FPSOs and FSRUs. Figure 1. Regasification vessel. LNG_Spring2012_47-52.indd 47 14/03/2012 09:42 48 / LNGINDUSTRY / Spring2012 Tank design General arrangement The tank arrangement of an offshore unit takes into account several factors. Concerning the storage capacity, apart from the production (liquefaction or regasification) flow rate and the size and turnover of the shuttle vessels, some margins in the overall storage capacity are considered, for example: Due to potential delay in the ship-to-ship operations. Due to the actual operating range (filling levels) of the tank. Due to the maintenance at sea of the tanks. Once the storage capacity is fixed, one may opt between a one-row (like LNG carriers) and a two-row design. The first possibility is identical to the standard design of an LNG carrier, that is to say that all the tanks are successively along the ship’s axis (only one tank abreadth of the ship), each tank being separated from the other by a transverse cofferdam. The second possibility is to split the breadth of the ship into two segregated rows of tanks. This implies using a longitudinal cofferdam on the ship’s centreline. This second option brings some advantages both in terms of support for the topside and sloshing issues. Liquid motion analysis Liquid motions inside the cargo tanks are investigated for each new project, in order to assess the ability of the containment system to withstand impact pressures from sloshing. Such a study is based on onsite environmental conditions, barge motions representative of the whole operation (i.e. all loading cases from the operating sequence are investigated) and tank response. Liquid motions within the tank are a function of: The environmental conditions. The barge design (unit main dimensions, sea-keeping characteristic, tank geometry, tank position etc.). The barge operational profile (filling level, relative ship/wave heading etc.). The methodology used by GTT for all projects (LNGCs, FSRUs, FPSOs) can be summarised by three main aspects. The load evaluation aims at defining the relevant sloshing loads to be considered for design purposes. It is based on the latest state-of-the-art model tests, and statistical post-processing. All parameters of influence on the sloshing activity are thoroughly screened. In parallel, the various failure modes of the containment system are defined and the associated ultimate strength under in-service conditions including both thermal and dynamic effects is calculated. The assessment is finally based on a reliability approach. Reliability methods require acceptance criteria in term of annual probability of failure (based on the structure considered and the consequences of the failure). A design is deemed acceptable when the calculated probability of failure of the design remains below the admissible values. Containment system reinforcements Several levels of reinforcement have been developed for the containment systems. For NO96, the reinforcements are based on the thickness increase of the plywood in adequate locations of the insulation boxes. For example, primary boxes have been designed with an additional top cover (making two successive top covers of 12 mm or 15 mm) and secondary boxes have been designed with thicker internal partitions, additional combs or one additional internal bulkhead. Subsequent improvements such as increasing the staple density (for a better connection of all subcomponents) were also introduced. The two Invar membranes remain identical on all designs. For Mark III, reinforcements for the membranes concern firstly, the possibility to apply ribs and wedges for the primary membrane to limit/avoid the eventual deformations of the corrugations; secondly, the possibility to apply polyurethane glue for the bonding of the secondary membrane (supple Triplex on rigid Triplex) to provide increased strength to the bonded joint. Finally, increasing the foam density induces an increase in the foam compressive strength, making it able to withstand very high pressures. Some of these developments are already applied on LNGCs, and if necessary, the flexibility of membrane systems makes it easily possible to design further reinforcements for both systems as appropriate, based on the liquid motion analysis results. Two-row arrangement By adding a longitudinal cofferdam on the ship’s centreline, the tank breadth of a two-row arrangement is divided by two compared to an equivalent one-row design. From a liquid motion point-of-view, the transverse natural period of the liquid has thus been divided by approximately two. As a result, the liquid natural period has been shifted towards the low barge response area, significantly reducing the liquid motion activity. The benefits that a two-row arrangement can bring compared to a single row can be summarised as follows: Large range of fillings free of sloshing impacts: due to its narrow breadth, a two-row arrangement will experience a large filling range without any sloshing activity in almost any sea state. Only large wave heights may induce sloshing initiation: basically, the wave height for which the first sloshing loads (not necessarily critical) may be observed is higher than the wave height for an equivalent one-row design. This leads to a much reduced potential span of sea states that may induce sloshing. Due to the adequate ratio between breadth and length of the tank, and due to the barge motions in both transverse and longitudinal directions, the highest sloshing activity has always been observed in beam seas. Longitudinal waves within the tank have never been observed during model tests. Figure 2. Typical cross-section for one-row (left) and two-row (right) designs. LNG_Spring2012_47-52.indd 48 16/03/2012 15:54 LNG_Spring2012_47-52.indd 49 14/03/2012 09:42 50 / LNGINDUSTRY / Spring2012 The two-row arrangement has already been tested for several projects, for several tank dimensions, barge designs and site conditions anywhere in the world and is well representative of offshore opportunities for FLNG units. These studies, reviewed by Classification Societies, have always concluded to full operability onsite (no filling restrictions or limitations in the operations), even in harsh conditions (wave heights above 11 m). Cargo operations The purpose of a standard Cargo Handling System is to perform the following functions: Prepare the tanks to be used for commercial operations. Receive LNG. The loading operation requires mainly piping and monitoring equipment such as level, temperature and pressure indicators. Maintain LNG at stable conditions for storage. Unload LNG. This operation involves the major part of the equipment installed in the cargo tanks. Prepare tanks to be inspected during dry-dock maintenance. Filling operations Two devices can be used to fill the tank with LNG: a bottom filling device (as for an LNGC) and, as an option, a top filling device. It should be noted that, as it is assumed that the produced LNG is always cooler than the stored LNG, the top filling device allows a better phase separation of the flash gas and an enhanced homogenisation of LNG inside the storage tank. Emptying operations Emptying operations can imply two types of pumps: The main cargo pumps whose role will be to unload the tanks to load an LNGC (FPSO application) or to feed the regasification plant with LNG (FSRU application). The stripping pump, whose role is to empty the tank as much as possible (before decommissioning operations for example). Typically for an LNGC, the cargo pumps are fixed to the pump tower. For this type of pump, other elements are essential such as electrical cable ways and pump supports. For offshore units, adaptations of the pump tower have been made to be able to implement retractable pumps if required (removal of cable ways, increased diameter of pump wells, etc.) for pump maintenance without tank decommissioning. A foot valve device at the bottom end of the pump well is provided in order to isolate the pump column from the tank storage. Tank commissioning and decommissioning Most of the operations for the commissioning and the decommissioning of the tanks are based on the replacement of the gas phase in the tank by another gas phase compatible with the next step. In order to avoid mixing of the phases and to obtain reasonable operating times, the injection of the gas is made so that the two phases act as heterogeneous components. This phenomenon based on the difference of density between the phases is called the ‘piston effect’. Unless otherwise required by the project specification, onboard an FLNG using GTT membrane designs, one or several tanks can be temporarily decommissioned for maintenance purposes while other tanks can be kept operating normally, including NG network feeding, LNG production, and (ship-to ship-transfer) STS. For each operation, GTT defines the criteria to ensure that the considered step has been successfully completed. The requirement of the client regarding the duration of each step will impact the size and capacity of the various auxiliaries that can be involved (compressors, heaters, etc.). Nevertheless, it should be noted that membrane systems have the fastest cooling down and warming up durations compared to any self-supporting tank technology. Instrumentation and protection systems Apart from the density control, all instrumentation and protection systems presented hereafter are already in place on LNG carriers, but some points can be specific to FLNG units. A liquid level control, coupled with several levels of alarm, for both low fillings (to protect the pumps) and high fillings (to prevent overfilling). A pressure control: tanks are equipped with safety valves (pressure relief valve and vacuum relief valve) and several levels of alarm protect the tanks from over-pressure and vacuum. A temperature control: the tank, the insulated spaces and the inner hull are equipped with temperature sensors. Some are located on the pump tower, and are used to check the correct cooling down of the tank. A gas detection system: the gas content within the insulated spaces is permanently checked, at a maximum interval of Figure 4. Inside an LNG membrane tank with NO96 system. Figure 3. Effect of a two-row arrangement on resonance period. LNG_Spring2012_47-52.indd 50 14/03/2012 09:42 GTT at the heart of LNG GAZTRANSPORT & TECHNIGAZ • 1 route de Versailles, 78470 Saint-Rémy-Lès-Chevreuse - France • Tél : (33) 130 234 789 • E-mail :
[email protected] www.gtt.fr MARK III FLEX NO 96 EVOLUTION GTT is ready to work with you on the optimization of its well known NO96 and Mark III systems in order to adapt them to new operational conditions, thereby offering improved economies and flexibility. LNG_Spring2012_47-52.indd 51 14/03/2012 09:42 52 / LNGINDUSTRY / Spring2012 30 min., according to the IGC Code. In case of gas ingress, gas detectors located on top of the tank (as methane is lighter than nitrogen) will warn the operators immediately. A draining system: secondary barrier space bilge wells are provided with a water ingress detection system with alarm. Bilge wells are fitted with two liquid sensors in order to detect the leakage from ballast tanks. A density control: a density gauge is required if stratification is considered as a plausible scenario in offshore cases. This device is implemented on the liquid dome in addition to the level gauging systems. The density gauge also provides information on level and temperature. Maintenance made easy Contrary to LNGCs for which maintenance is scheduled during drydock, maintenance policy for offshore units has to include the possibility to perform all controls and eventual repairs offshore. Control and repair methods currently in service for the maintenance of conventional LNG carriers have been used by GTT for several decades and have been refined accordingly. Several analyses have been performed by GTT to analyse the various failure modes that can be encountered with membrane systems. Formal Safety Assessment and Maintenance Analysis (FSAMA), Failure Mode Identification and Risk Ranking (FMI and RR) were performed on the maintenance operations for an offshore unit. These analyses have received a Statement of Endorsement from Class, showing the suitability of membrane systems for offshore applications. Control and inspection During the standard maintenance phase, testing of the tightness of the membranes, visual inspection of pump tower, of containment system and maintenance of cargo pumps are performed (in case of fixed pumps). Methods are made available to detect and localise any defect of the containment systems. Some methods are performed when the tank is in-service to avoid any downtime of the tank. For example, GTT systems are equipped with a primary membrane control system based on gas concentration measurement. The integrity of the primary membrane is thus checked continuously when the tank is in service. This system is in use on more than 250 membrane vessels and is working perfectly on each vessel (oldest vessels are 42 years old). A helium test is the common procedure to localise a defect in the primary membrane if it occurs. Similarly, for the secondary membrane, the recently introduced Thermographic Assessment of Membrane Integrity (TAMI) aims at monitoring the secondary membrane when the tank is in service. The cargo tank is used as a cold source and slightly pressurising the primary space (compared to the secondary space) forces the cold nitrogen of the primary space to flow in the secondary space through an eventual defect. The inner hull temperature will thus decrease locally (where the defect has occurred) and temperature differences as low as 1 ˚C can be detected. Other control methods are available when the tank is under maintenance. Mainly based on vacuum tests, these tests are the same as that for LNG carriers. Repair If repairs have to be carried out, the same practices, expertise and sometimes same procedures as building methods are used. Due to the thickness of the membrane, the repairs mainly consist of welding a new piece of membrane where required. Patches of various shapes and sizes are available to repair the membrane locally. Tests to check that the repair has been correctly executed are then performed (dye penetrant test, vacuum box test, etc.). If the insulation has been damaged, methods are available to repair locally one part of the insulation. The complete replacement of a box/panel can be carried out if required. The size of such elements is sufficiently small to be inserted inside the tank through the standard tank openings (manhole, material access hole). Finally, repairs on the hull can be performed (welding) even with the containment system in place. Access Tank access requires that the tank should be emptied, warmed up, gas freed and its atmosphere made safe for human entrance. As damage is mainly due to human presence inside tanks, repairs are mostly performed in the lowest (accessible) parts of tanks. Nevertheless, access to upper areas, although very unlikely to be necessary, is provided. Depending on the location of a defect, scaffolding could be erected if necessary. This scaffolding is based on existing proven technologies and adapted for moving platforms: it is specially designed to cope with the exact dimensions of the tank and the site specific motions. Conclusion LNG carriers equipped with membrane systems have several advantages recognised by all industrial players: compactness, simple but strong hull structure, fast construction time, cost-effectiveness, etc. Membrane systems have already demonstrated their suitability for offshore applications, through the 10 RVs already in service; two membrane LNGCs are currently used (after conversion) as FSRUs moored at a quay and two additional membrane vessels are currently under conversion into FSUs. Five additional newbuilt FSRUs are currently on order with membrane systems. Concerning LNG-FPSO; many studies have been launched so far. Many oil and gas majors and shipowners have been investigating the possibility of using membrane systems; many of them led to Front-End Engineering and Design (FEED) studies to ascertain the feasibility of such platforms. Public information allows us to confirm that Excelerate, Höegh LNG and Petronas/MISC are considering GTT technologies for their units. Finally, up to now, only one LNG-FPSO has been firmly ordered so far. This giant floater, ordered by Shell for its Prelude project offshore Australia features the GTT MarkIII system. Figure 5. Double row concept of tank for offshore application. LNG_Spring2012_47-52.indd 52 14/03/2012 09:42 Spring2012 / LNGINDUSTRY / 53 A s a shipping agent, Inchcape Shipping Services (ISS) attends LNG tanker port calls and canal transits across its global network, notably in North, Central and South America, Japan and the Middle East. Because of the specialist nature of the trade, particular considerations apply to the handling of these ships. Here we take a snapshot of some operations around the world. North America Prior to the recent discoveries of significant shale gas in the USA, several large LNG receiving terminals were built, mostly on the US Gulf Coast. Two such facilities are located Nick Elliott, Inchcape Shipping Services, UK, examines the role of shipping agents in the LNG sector. LNG_Spring2012_53-57.indd 53 16/03/2012 15:58 54 / LNGINDUSTRY / Spring2012 in the Calcasieu Waterway leading up to Lake Charles in Louisiana – 36 nautical miles inland. The Trunk Line Terminal was completed in 1981 while the newer Cameron LNG Terminal opened for operations in 2009. The ISS Lake Charles office handles a significant amount of this trade. The Calcasieu Waterway is shared by the shipping industry, sportsmen and recreational boaters alike. The ship channel has a project depth of 40 ft and a bottom width of 400 ft. The Gulf Intracoastal Waterway intersects the ship channel 12 miles south of the city docks. The port of Lake Charles is the 11 th largest in the USA, encompassing a variety of terminals that move an array of cargos including crude oil, chemicals, aggregates, bulk pet-coke, bulk agriprods, wood products, project cargos of all types, and of course LNG. The LNG vessel makes its voyage from loadport into the Lake Charles area where the pilot boards outside port limits. The transit time from Pilot Station to Trunk Line LNG is between seven and seven and a half hours and around an hour less to Cameron LNG. Often, the USCG will perform an Offshore Security Boarding procedure and most LNG vessels (depending on what port they have sailed from) are required to go through this before being permitted to proceed to the terminal. Offshore Security Boarding only operates during daylight hours. Upon clearance, the vessel will commence the transit with the US Coast Guard restricting all other movements in port. Vessels have to maintain a three mile safety zone behind any LNG carrier going into or out of the Trunk Line and Cameron LNG Terminals. If a vessel requires a Certificate of Compliance (CoC) inspection, a Coast Guard requirement for all tank vessels, then the USCG will conduct this boarding at the dock during daylight hours only. During this period the vessel is permitted to connect one vapour line only to help control the LNG vapour. Once the CoC has been completed, the Coast Guard will advise all parties the vessel is cleared for discharging. In certain cases determined by the vessel owner/operator, LNG vessels must have escort tugs for the inbound transit day or night. Each terminal has contracted tugs that they utilise for docking and undocking and standing by the vessel during cargo operations. Vessels calling at Cameron LNG must have dedicated tugs for the entire duration of the vessel’s port stay while alongside, as well as assisting vessels passing by the facility. Each terminal has different requirements for delivery of bunkers. At Cameron LNG, bunkers are permitted on a case by case basis. If permitted, the bunker barge is Figure 1. The launch fleet attends tankers at anchor off Fujairah and Khorfakkan. Figure 2. Personal basket transfer. LNG_Spring2012_53-57.indd 54 14/03/2012 09:47 For more information, visit www.uop.com/LNG. © 2011 H oneyw ell International, Inc. A ll rights reserved. perfect ft With offshore gas processing solutions that can cut your overall footprint as much as 50%, UOP technology fts right into place. For decades, UOP gas processing technology has been proven in land applications. Now, with new lightweight, compact designs, UOP solutions can help your offshore gas processing plan come together. Modularized units house all needed technologies, and the small footprint is the optimal size for offshore applications. From acid gas removal and dehydration to removal of mercury and other contaminants, UOP’s proven processes will increase your revenue from gas streams — which means UOP solutions are also the ideal ft for your bottom line. LNG_Spring2012_53-57.indd 55 14/03/2012 09:47 56 / LNGINDUSTRY / Spring2012 required to be alongside and the bunker hose connected before cargo arms or cargo operations can commence. Only after completing bunkering will the terminal commence cargo operations. At the Trunk Line terminal no bunker barges are permitted alongside at any time. This creates a dilemma for vessels coming in on long transits that are in need of fuel to undertake their next voyage. Both terminals allow stores, provisions and spare parts to be delivered; however, only via launch, which must arrive and depart the vessel prior to the cargo arms and cargo operations commencing. Normal discharging time for an LNG vessel at any berth is between 18 - 24 hours. The agent’s role on an LNG vessel is unique to this type of ship. Particularly when it comes to the additional requirements and regulations for the US Coast Guard and towage. Some of the newer North American LNG facilities are joint ventures with their own dedicated tugs serving each facility – typically four tugs on permanent station used for docking and undocking, standing by during cargo operations, assisting passing vessels in the channel adjacent to the terminal and sometimes on other jobs where time permits. In the past, such tugs have been used to rescue nearby vessels in difficulty. The cost for these towage services is footed by the joint venture partners along with the vessel owner/operator calling at the particular terminal. As there are multiple players involved, the role of a Marine Co-ordination Agent was conceived following discussion with various companies. The main purpose of the MCA is to co-ordinate the towage operation, including the accounting and other information regarding the towage contract; acting as a go-between with the LNG partners and the towage contractor. The MCA also co-ordinates Marine Working Group meetings between the various parties where port operations are discussed including towage, pilotage, government regulations and more. In essence, the MCA role serves as a neutral party between all partners involved in the port call. Partners at the Cameron LNG terminal are Sempra LNG and ENI and partners at the Energia Costa Azul LNG terminal are Sempra LNG, BP Tangguh, Shell and Gazprom. As an important footnote, the discovery of shale gas in the USA has prompted existing as well as potential new facilities to be built with liquefaction capability, radically altering the balance of trade. Where several billion dollar facilities have been developed over recent years for the import of LNG based on the fear of shortages, these are now being transformed into export facilities with US government approval. This in turn has resulted in a transitional lull in business until conversion work is completed – still two years or more away. Middle East and India LNG loading operations in the Middle East are principally centred on Abu Dhabi, Oman and Qatar where port agency work is traditionally handled by state or local agents. However, due to restrictions on vessel husbandry at most of the load terminals in the region, LNG tankers carry out survey work and crew changes and take on spares and supplies at Fujairah, either when in transit to or from the loadport or while waiting at the Fujairah anchorage, which is the major husbandry point in the Middle East for this kind of business. The company handles such calls from a variety of owners including such major operators as Mitsui OSK Lines and BW Gas, with the companies launch fleet based out of Fujairah and Khorfakkan, servicing such husbandry requirements. A further operation for ISS on behalf of global clients such as Teekay LNG Partners and Exmar, is the servicing of floating regasification units operated from ports in Kuwait and Bahrain. And across the Arabian Sea, the Petronet regasification plant at Dahej in Gujirat, India, also places demand for agency services. Japan ISS Japan maintains a full database of port information for customers. The data is regularly updated giving a comprehensive guide to the berths, wharves and terminals of Japan. This includes not only port information but also weather data and LNG market news. The basic service is of course to set up the ship’s in and out port call in the most effective way with minimum turnaround time. In conjunction with local parties, the agency proactively avoid delays with careful planning before the ship’s arrival. Key features of maritime service include: Proactive port information with precise ship movements and prospects advised well in advance. Weekly congestion/line-up reports for all vessels in ports. Close supervision of terminal port agents to achieve quick dispatch of the vessel. Proactive minimising of port costs and time in port. Close contacts within the shipping industry including authorities, cargo suppliers and importers. Regular LNG market news provided to LNG customers. Marine superintendents available on demand to attend any type of vessels including LNG tankers at any port. Australia On 13 January the Japanese company Inpex along with French project partner, Total, made its final investment decision to secure a AU$ 33 billion LNG project, representing a huge boost for the port of Darwin. As was the case in Aberdeen in the 1970s, there are plans to extend the port infrastructure and introduce a high tech VTS among other improvements to deal with the resulting increase in shipping traffic. It is hoped that the project will eventually make Australia the world’s largest exporter of LNG. www.energyglobal.com/events SEARCH hundreds of international industry events on Energy Global LNG_Spring2012_53-57.indd 56 16/03/2012 12:04 The Marshall Islanos Registry ··r.i.· ooc ¸oolit, or· oit/io ,or r·o./ International Registries, Inc. io offliotio oit/ t/· Mor·/oll I·looc· Moritio· C Cr¡rot· Jcoioi·trotr· tel: -1 713 o27 99¯¯ | houston ¸ register-iri.com www.register-iri.com LNG_Spring2012_53-57.indd 57 14/03/2012 09:47 Rebecca Watson, Nakilat, Qatar, details the rise of the successful Nakilat-Keppel Offshore and Marine repair yard. LNG_Spring2012_58-63.indd 58 14/03/2012 10:45 Spring2012 / LNGINDUSTRY / 59 Q atar-based LNG repair yard Nakilat-Keppel Offshore & Marine (N-KOM) has had a highly successful year. With over 50 projects under its belt, including 19 LNG vessels, N-KOM has created a thriving shipyard in a country where previously there had been no marine industry. But how does an LNG repair facility come from nothing to attract business from around the world? Several factors can help explain N-KOM’s success. N-KOM’s prime asset is its location. The repair yard is located in the Port of Ras Laffan, situated on the northeastern tip of the Qatar peninsula, at the heart of the Arabian Gulf and on the doorstep of the gas terminal serving Qatar’s North Field; source of one-third of the world’s LNG. This location is a major advantage. Figure 1. Repairs going on full-swing. Figure 2. Simaisma, the first LNG carrier to be dry docked and repaired in Qatar. LNG_Spring2012_58-63.indd 59 14/03/2012 10:45 60 / LNGINDUSTRY / Spring2012 Another key advantage is facilities. Purpose built from scratch, the Erhama Bin Jaber Al Jalahma Shipyard where N-KOM operates offers 43 ha. of state-of-the-art workspace designed to accommodate the world’s biggest gas carriers. The yard’s shore power rating of 1200 A., its water ballast facilities and cranage are all designed for work on Q-Max and Q-Flex vessels. At 53.8 m wide, the Q-Max type LNG carrier is the largest in the world. The yard’s cranes have a reach of 100 m allowing double banking of these goliaths of the gas shipping industry. Testing of LNG carrier cargo pumps is possible at quayside. An extensive cryogenic facility of 390 m 2 allows for the simultaneous repair of more than one set of cargo pumps. N-KOM also leverages on its parent companies’ experience and reputation in the industry: Qatari gas shipper Nakilat and Singaporean ship repairer and builder Keppel Offshore & Marine. Shipping company Nakilat owns and operates the largest LNG fleet in the world; a total of 54 vessels including 14 Q-Max, 31 Q-Flex and nine conventional carriers, representing approximately 16% of global LNG tonnage. Now producing 77 million tpy of LNG, Qatar is the world’s biggest supplier of gas and Nakilat’s fleet is the energy-rich country’s ‘floating pipeline’, with Qatar’s two gas producers Qatargas and RasGas chartering the fleet. Investment in maintaining this crucial economic asset seemed like an obvious next step for the state of Qatar. Nakilat sought a partner for the project, not simply to run a repair, maintenance and conversion yard, but also to help establish a maritime industry in Qatar. Keppel Offshore & Marine was chosen for its reputation and industry experience and thus N-KOM was created; a joint venture owned 79% by Nakilat, 1% by Qatar Petroleum and 20% by KS Investments Ltd, a wholly-owned subsidiary of Keppel Offshore & Marine. Building work The deal was struck in May 2007, but the shipyard would not officially open for another three and a half years. The 43 ha. facility had yet to be built. The land upon which the shipyard would be built had yet to be reclaimed from the sea, the Southern Breakwater at the Port of Ras Laffan. Prior to opening for business, the yard had already commenced the fabrication of its own drydock gates. Completed in October 2010, the two gates used a total of 2700 t of steel and were stepped into the L 400 m x W 80 m x D 12 m and L 360 m x W 66 m x D 11 m drydocks in time for the inauguration of the shipyard on 23 November, 2010 by His Highness the Emir of Qatar Sheikh Hamad Bin Khalifa Al Thani. At its opening ceremony, N-KOM welcomed its first LNG carrier, the Q-Max Mozah, flagship of the Nakilat fleet and named in honour of Her Highness Sheikha Moza Bint Nasser Al-Missned, wife to the His Highness the Emir, whose vision for a Qatari marine industry was crucial in the creation of the N-KOM yard. Mozah, being the first vessel to berth at Qatar’s new ship repair facility, demonstrated that creation of the shipyard facility was an important step in the diversification of the Qatari economy. The first drydocking to take place at N-KOM was also that of a Nakilat LNG carrier, Simaisma (see Table 2), in March 2011. Since then, N-KOM has gone on to deliver a total of 19 LNG projects during its first year of operation. Highlights include Al Wakrah in May 2011, the first of the gas carriers managed by Mitsui OSK Line (MOL) to be drydocked at the yard, which underwent general repair and maintenance and was delivered three days ahead of schedule and Ejnan in July. Managed by NYK LNG Shipmanagement, Ejnan became the first LNG carrier to have the global acoustic test done for its membrane tank Table 1. Yard information Name N-Kom (Nakilat-Keppel Offshore and Marine). Location Erhama Bin Jaber Al Jalahma Shipyard, Port of Ras Laffan, Qatar. Date inaugurated November 2010. Size 43 ha. Activities Repair, maintenance and conversion for a range of vessels and on and offshore structures. Facilities Two dry docks (L 400 m x W 80 m x 12 m and L 360 m x W 66 m D 11 m); four 400 m piers (all L 400 m x D 11 m); two quays (both L 400 m x D 11 m); cranes with reach for double banking of Q-Max; shore power with a 1000 A. rating; 390 m 2 cryogenic clean room; electrical, pipe, mechanical and steel workshops; blast and paint chambers. Future developments Floating dock (L 375 m x W 66 m) for delivery in 2013. Accreditation ASME, ISO 9001, OHSAS 18001 and ISO 14001. Table 2. Milestone project: Simaisma Vessel name Simaisma. Owner Maran Gas Maritime, Greece/Nakilat, Qatar. Operator Maran Gas Maritime. Charterer RasGas. Built Daewoo, Korea. Delivered 2006. DWT 84 863 t. Length 286 m. Breadth 44 m. Capacity 146 000 m 3 LNG. Arrived at N-KOM March 29, 2011. Days in dock 20. In March 2011 the yard docked Qatar’s first LNG carrier: RasGas-chartered conventional carrier, Simaisma. LNG_Spring2012_58-63.indd 60 14/03/2012 10:45 LNG_Spring2012_58-63.indd 61 16/03/2012 10:04 while visiting N-KOM, in addition to the general repairs carried out during its drydocking. The acoustic equipment, in addition to other leak test kits, has since been stored in the yard for future use. N-KOM has extended its range of services to over 40 vessels while at anchorage. At its opening, the shipyard facility garnered a multitude of service agreements with various major fleet owners, including a three year ship repair arrangement with Shell International Trading and Shipping Co. Ltd (STASCo). N-KOM had also entered into a Memorandum of Understanding (MOU) with Gulf Drilling International (GDI) and letters of intent with Idemitsu Tanker, Mitsui O.S.K. Lines, NYK Line, Kawasaki Kisen Kaisha, Lino Lines and the Marine Contracting Association (MARCAS), to provide shipyard and drydocking services for their vessels. The future With its network of over 20 shipyards worldwide and its track record of LNG repairs, Keppel began its relationship with Qatar in the 1990s. Keppel Shipyard in Singapore docked Qatargas-chartered and MOL-owned LNG carrier Al Zubarah in June 1999 for a guaranteed repair of the Japanese-built vessel. Since then, Keppel Shipyard has successfully carried out dockings for the majority of the Qatargas fleet, building a strong relationship that led to the signing of an Alliance Service Agreement in 2006 for the drydocking of a fleet of Moss type LNG carriers chartered by Qatar Liquefied Gas Co. Ltd for a period of five years. Collaboration between Keppel’s rig building division, Keppel FELS, and Qatar Petroleum joint venture Gulf Drilling International (GDI) has also paved the way for N-KOM to begin work on offshore structures alongside its ship repair business. By 2020, 4000 ships are expected to call at Ras Laffan every year. 2012 will be a busy year. The first generation Q-Flex and Q-Max vessels will commence their special survey dockings at N-KOM and as the yard’s facilities continue to expand; a floating dock of L 375 m x W 66 m is currently on order. With over 50% of all LNG carriers servicing the Arabian Gulf, LNG will form a significant part of business in this region, despite Qatar’s marine industry being relatively new. Table 3. N-KOM project track records LNG 19. LPG 1. Tankers 4. Containers 5. Support vessel/tug 11. Jack-up rigs 5. Others 5. Total (as of January 2012) 50. SIGN UP to Energy Global’s RSS feeds to receive up-to-the-minute news alerts www.energyglobal.com/sectors LNG_Spring2012_58-63.indd 62 16/03/2012 16:06 LNG_Spring2012_58-63.indd 63 14/03/2012 10:45 64 / LNGINDUSTRY / Spring2012 Getting it right first time Barbara Grant, International Paint, UK, describes the benefits of spending time and money on quality coatings to prolong the lifespan of ships. LNG_Spring2012_64-65.indd 64 14/03/2012 11:39 B ooming demand for LNG is proving to be the catalyst for a surge in vessel contracting. 52 vessels were ordered throughout last year, mostly in South Korea, compared with just five in 2010 and none at all the year before. Today’s order book now stands at close to 60 vessels. Not all the contracts have been placed by the relatively small number of specialist LNG operators who populate this highly sophisticated niche market. There are fears that some of the newcomers may not employ the top grade ship specifications that have traditionally ensured the continued operational safety and longevity of the world’s 360 or so carriers. Bill Wayne is general manager of the Society of Gas Tanker and Terminal Operators (SIGTTO). He points out that this specialised shipping sector’s unblemished safety record is crucially important to maintain. ‘The safety record of the LNG industry has been almost without comparison in commercial industry,’ he declares. ‘It is a direct result of the care and attention paid to the design, operation and maintenance of the ships. It is, in effect, our licence to operate.’ There are ships operating today that are more than 35 years old, but are still providing a high standard of service, and are operating as safely as they did on their first day of service. LNG_Spring2012_64-65.indd 65 14/03/2012 11:39 66 / LNGINDUSTRY / Spring2012 Whilst this speaks volumes for the way ships have been looked after over their lives, with appropriate long term maintenance programmes in continuous operation, much also depends on the quality of the original ship specifications. A high quality coatings system and diligent inspection are necessary to ensure the very best quality at the beginning of a project. Ships generally rust from the inside out, typically from the ballast tanks. If attention is not paid to ballast tank coatings at the outset, the reality is that half way through a long term charter, an operator could find himself facing a major repair exercise involving, for example, blasting and re-coating of ballast tanks, entailing weeks out of service. Such an operation could take several months and seriously affect the economics of a project. The key message is: get it right first time! If you have a long term contract, it’s a false economy not to put in good corrosion protection systems at the outset. The LNG fleet The demands made on LNG carriers are exacting. Transporting confined, potentially highly flammable cargo in tanks on tight schedules means that vessel safety and operating efficiency with planned maintenance are critical requirements. All of these issues will be high on the list of vessel operators’ priorities, particularly when selecting systems and equipment for a new ship. Choosing the correct high performance protection systems can help operators maximise returns on their substantial investments while ensuring long term vessel safety, efficiency and asset value. Fouling control A critical requirement for LNG carriers is to arrive at their destination on time. Loss of speed due to hull and/or propeller fouling can result in not only delayed arrival times but also increased engine wear, fuel consumption and emissions. Fouling control is thus a vital part of vessel operating efficiency, in which coatings can play a very important role. Foul release technology Foul release coatings do not rely on biocides to control fouling. The technology works by providing a very smooth, slippery, low friction surface onto which fouling organisms have difficulty attaching. Any that do attach, normally do so only weakly and can usually be easily removed either by the vessel moving through the water or by simple washing/wiping. The Intersleek foul release system, applied to over 30% of the global LNG carrier fleet, claims to resist fouling for up to 60 months and cut fuel consumption and emissions by up to 9%. 1 Exmar Ship Management, one of the world’s largest operators of LPG/LNG carrier vessels and the first company in the world to operate Energy Bridge Regasification Vessels (EBRV), has an interest in reducing fuel consumption and vessel emissions. It chose Intersleek 900, the revolutionary fluoropolymer foul release coating, for two LNG vessels. Intersleek 900 was selected to meet the environmental objectives of both Exmar and the vessel owner Excelerate Energy. In September 2008, Intersleek 900 was applied on the 76 500 dwt Excellence, the first EBRV vessel to be coated with the fluoropolymer foul Figure 1. Fouling control: four LNG newbuildings at Samsung, all coated with foul release technology. Figure 2. Fluoropolymer foul release technology on the underwater sides. LNG_Spring2012_64-71.indd 66 19/03/2012 10:03 The new ME-Gl generat|on of MAN B&W two-stroke dua| fue| 'gas |nject|on` eng|nes are charac- ter|sed by c|ean and effc|ent gas combust|on contro| w|th no gas s||p. The fue| fex|b|||ty and the |nherent re||ab|||ty of the two-stroke des|gn ensure good |ongterm operat|ona| economy. F|nd out more at www.mand|ese|turbo.com NAh 8&w N0lN0-0 £og|oes NAh 8&w N£lN£-0lN£-8 £og|oes NAh 8&w N£-6|lN£-0-6|lN£-8-6| £og|oes 0|eao, SaIe aod 8e||ab|e 0as aud fuel fexioilit] with NAh B&w NE-0l LNG_Spring2012_64-65.indd 67 14/03/2012 11:39 68 / LNGINDUSTRY / Spring2012 release technology. Its sister vessel, the 69 500 dwt LNG carrier Excalibur, also had Intersleek 900 applied at Lisnave shipyard in October 2008. The project involved the application of the Intersleek 900 system on the underwater vertical sides over Intersleek Linkcoat, which removed the need for full blasting, thus further reducing the overall environmental impact. Intersleek 900 was applied to the Sevilla Knutsen in June 2010. Built at Daewoo Shipbuilding and Marine Engineering (DSME) in South Korea, the 173 400 m 3 LNG carrier was the first of Norway’s Knutsen OAS Shipping’s vessels to be coated at newbuilding. September 2011 witnessed a milestone for International Paint and N-KOM, the Nakilat-Keppel Offshore & Marine Ltd, Erhama Bin Jaber Al Jalahma Shipyard, with the coating of three LNG vessels marking the application of 10 000 litres of Intersleek foul release technology at the new Qatar facility in less than four months since opening. The Al Marrouna and Al Areesh, 151 700 m 3 sister ships operated and managed by Teekay Marine Management and the 137 354 m 3 Doha, which is owned by a Japanese consortium led by Nippon Yusen Kaisha (NYK Line) and managed by NYK LNG Shipmanagement Ltd, were all repaired with the Intersleek 700 system within four weeks, completing the projects ahead of schedule, with the time savings afforded by the foul release system a key factor. The Al Marrouna and Al Areesh, coated with the Intersleek 700 scheme at newbuilding in October 2006 and January 2007 respectively, needed only one full coat at this latest docking. Significantly, the repair requirement is even less for vessels undergoing interim dockings. For example, no full coats were required for Doha, whose previous drydocking took place in June 2009. Biocidal antifoulings A cost-effective alternative to foul release coatings are biocidal antifoulings. The 151 885 m 3 LNG carrier, Tangguh Hiri, operated by Teekay Shipping, was coated with Intersmooth SPC self polishing copolymer antifouling at newbuilding in November 2008. Analysis of Figure 4. After 15 years in service, cleaning of the ballast tank area reveals the impressive true nature of the coatings beneath. Figure 3. Foul release coatings can significantly reduce time in drydock. LNG_Spring2012_64-65.indd 68 14/03/2012 11:39 weatherford.com Change the Process Shorten project schedules and reduce reworking losses by choosing a single-source provider for all of your process pipe needs. © 2 0 1 0 W e a t h e r f o r d . A ll r ig h t s r e s e r v e d . In c o r p o r a t e s p r o p r ie t a r y a n d p a t e n t e d W e a t h e r f o r d t e c h n o lo g y . Drilling Evaluation Completion Production Intervention PipeIine & SpeciaIty Services · Precomm|ss|on|ng · 6omm|ss|on|ng · Ha|ntenance - P|gg|rg - C|ear|rg - lrspecl|or - 3urvey|rg - Repa|rs - C|arps · 8hutdowns · 0ecomm|ss|on|ng Turn to Weatherford for all of your process pipe services and change your outcome: Bundled services save you money, while single-source efficiency shortens project duration and avoids costly reworking. Enjoy the convenience and advantages of having a single point of contact and accountability—along with a single contract and invoice. Weatherford offers complete solutions for projects of any size, anywhere in the world. A recent success in Yemen reduced the original duration projection by 14 days. For more information on this success or any of our services, email
[email protected]. To view our full line of Pipeline & Specialty Services offerings, visit us online at weatherford.com/pss. º Bo|ting º Va|ve testing º Chemica| c|eaning º F|ange management º Nitrogen services º Hydrostatic testing º Pneumatic testing º He|ium |eak detection Delivering Quality Under Pressure SM LNG_Spring2012_64-65.indd 69 14/03/2012 11:40 70 / LNGINDUSTRY / Spring2012 the vessel’s activity over the subsequent 30 months showed that for 65% of the time the vessel’s speed was between 0 - 1 knots, in average sea temperatures of 33 ˚C, in locations including the Yellow Sea, East China Sea and the Sea of Japan. Despite the severe fouling challenge presented by these conditions, the June 2011 in-dock inspection of the vessel revealed the vertical sides and flat bottom to be in excellent condition. Long term anticorrosive performance With an operational requirement for the highest levels of corrosion protection, many operators of recent LNG newbuildings have specified the light coloured, abrasion resistant, aluminium pure epoxy anticorrosive, Intershield 300 for just about every area of the vessel, including the structurally critical and difficult to maintain water ballast tanks. The recent 15 year inspections of the bulk carrier m.v. Eleranta and the crude oil tanker Samco Raven have suggested that Intershield 300 protects beyond compliance with the requirements of the IMO PSPC (International Maritime Organisation Performance Standard for Protective Coatings), in water ballast tanks and cargo oil tanks respectively. Built at Samsung in 1995 and operated by V. Ships UK Ltd, the 73 222 dwt Eleranta had Intershield 300 applied to her ballast tanks at newbuilding. At her June 2010 inspection, with minimal maintenance through her life to date, a Lloyd’s Register class surveyor rated as ‘good’ the condition of the double bottom tank coatings. The original application on board the Eleranta involved two coats of Intershield 300 of only 125 microns each, rather than the two 160 micron dft coats specified in the IMO regulations. Ice abrasion protection With 22% of the world’s unrecovered carbon reserves located in the Arctic, operational requirements of ice-going LNG carriers need to adapt to the challenge of this environment. The first point of contact between ice and a hull is the paint, and the correct ice class coating can provide a multifunctional barrier. Some coatings are especially designed for ships trading in temperatures down to -50 ˚C. Abrasion resistant, with low frictional resistance, they can help reduce vessel power consumption and fuel consumption. Operating image Topsides, superstructure and spherical tanks (on Moss type vessels) represent a considerable and highly visible surface area on LNG carriers. Whilst stained, faded or even damaged coatings do not normally impinge on the asset value of the vessel and are not on the critical inspection list for surveyors or port authorities, in this condition they are not the best advertisement for a professional company or well managed ship. There is no doubt that the basis for a good ‘topsides’ system is the anticorrosive but the choice of finish coat, however, should also be carefully considered. Low solar absorption coatings Absorption of the sun’s infrared rays can lead to heat build up inside the vessel and can affect the thermal control of cargo and reliquefaction plants, crew and passenger comfort in accommodation areas and increase in energy costs. Principles of LSA coatings are that they reflect more sunlight and absorb less heat, keeping these exposed areas cooler and at a more constant temperature. These coatings incorporate specialist pigments into a standard polyurethane finish formulation with laboratory recorded temperature reductions of up to 8 ˚C. Global support With a strong growth phase underway for specialised LNG tonnage, the importance of preserving asset value, controlling through life operating costs and maximising return on investment through a well planned and implemented coatings strategy cannot be overstated. Notes 1. “Energy and GHG Emissions Savings Analysis of Fluoropolymer Foul Release Hull Coating”, Professor James J. Corbett, Energy and Environmental Research Associates L.L.C. (EERA), February 2011. Figure 5. Operating image is important. LNG_Spring2012_64-71.indd 70 16/03/2012 16:11 LNG_Spring2012_64-65.indd 71 14/03/2012 11:40 Thierry Vermeersch, AVEVA, UK, examines current capabilities and trends in the integration of engineering, design and information management technologies between the plant and marine industries. LNG_Spring2012_72-76.indd 72 14/03/2012 11:51 I n the energy sector, increasingly complex projects are being driven by the move to more challenging oil and gas resources, and enabled by increasingly powerful engineering and design technologies. But even the most powerful individual CAE or CAD tools are insufficient by themselves for the new generations of oil and gas projects. The key to success lies in integrating technologies to enable effective collaboration between different engineering, design and business disciplines across geographically distributed project teams. A clear illustration of this need is the development of FLNG projects to harvest deepwater gas resources. If the original oil FPSOs weren’t challenging enough, tomorrow’s massive FLNG vessels will be more so. They must combine the disciplines and resources of shipbuilding with those of process plant, deepwater well engineering and cryogenic storage. Meanwhile, onshore LNG projects are inexorably becoming ever more massive in scale. Evidently, technology must provide a seamless and scalable working environment to support these challenges. The oil and gas industry has come a long way in offshore engineering. Inevitably, the first FPSOs were a learning exercise as plant and marine engineers tried to get to grips with each other’s unfamiliar disciplines. Early projects were beset with problems leading to delays and cost overruns, due in part to the functional barriers created by mutually incompatible engineering and design software. While such barriers are not unique to offshore, this sector arguably suffers most because shipbuilding and plant engineering have traditionally been independent industries, each with their own working methods, standards and specialised design tools. There was little need for technology integration between them. But a number of factors have changed this situation rapidly. First, new technologies and the need to move into ever deeper water have forced the demand. Second, the collapse in demand for ships has driven more shipyards to diversify into offshore, an obvious adjacent market for their skills and facilities. Third, trends in the plant industries have increased awareness of the need for wider data interoperability and there has been much progress in the adoption of neutral standards, for example. Lastly, technology vendors have anticipated the demand by integrating plant and marine applications. Plant and marine integration To an extent, of course, ship design includes an element of plant design as every ship has at least a fuel system. But the most complex vessels such as cruise ships or warships can almost be described as plants in boxes – albeit very sophisticated boxes. In practice it was never very likely that a plant contractor would adopt a LNG_Spring2012_72-76.indd 73 14/03/2012 11:51 74 / LNGINDUSTRY / Spring2012 marine solution, even where it provided suitable functions, and plant design systems have generally been unable to integrate with the ship designers’ systems. So collaborative, FPSO-type projects had to work around the design interface issues. This has now changed. AVEVA was among the first to recognise the emerging demand and acquired a leading marine design solution. Since then, not only has it greatly extended the integration between hull and outfitting design, it has also integrated many of the corresponding functions of its plant and outfitting applications so that both can share a common database. Marine outfitting designers also benefitted from certain functions that were more advanced in the plant applications. As a result, collaborations between ship and plant builders have become much easier and even the most complex vessel can be engineered and designed in a common environment. An obvious problem area in plant/ship design integration is negotiating the physical interfaces between plant systems, vessel outfitting systems and the hull structure. Much of this involves detailed design negotiation between discipline specialists, so it is essential that each should be able to see the other’s design, while retaining control over their own. Perhaps the most extreme example of this would be the integration of a mooring turret into a hull structure, where almost every project discipline would be closely involved. If the turret and hull are designed in incompatible systems, clash detection and elimination become difficult and time consuming. 3D design integration 3D might be the common technology for engineering design, but it actually comprises two distinctly different technologies. The systems used by hull designers (and also equipment manufacturers) use modelling technologies based on surfaces, while those used in outfitting and the plant industries use geometric solids. Clearly, one cannot expect designers to collaborate efficiently if their software cannot communicate, but neither should one expect either discipline to abandon its particular, optimal, design system. Worse, individual equipment vendors’ systems use mutually incompatible proprietary data formats. Various approaches to 3D model exchange have been tried over the years, but did not result in a sufficiently effective or widely supported standard. However, growing demand and recent initiatives by industry forums have encouraged vendors to collaborate on neutral standards, with notable success. Now the STEP data exchange protocols are proving effective and are attracting wide industry support. In AVEVA’s case, STEP AP203 has been implemented in a bi-directional interface which supports the leading 3D MCAD systems. This enables equipment vendors to export 3D models, in a selective and controlled manner, via the neutral STEP format, for import into outfitting design. The process is quick and robust, and ensures that the 3D outfitting designer can work with accurate and sufficiently detailed equipment models. While such model exchanges will generally occur between an equipment supplier and a designer, it also enables the optimum choice of technologies within the same organisation. A typical example might be a company in which one division designs and builds, say, compressors, while a sister division builds these into complete packaged solutions. The two require different 3D design software, but now the system builders need no longer be constrained by having to use the same system as the equipment designers. Engineering and design integration Historically, individual disciplines have been supported by specialist software applications, invariably each with its own data format even when performing the same functions. While this led to high productivity within disciplines it also created barriers between them. These barriers have now become a hindrance and removing them offers considerable productivity gains across projects. A good example is schematic design, for purposes such as P&IDs or electrical and instrumentation (E&I) systems. Even now, some commonly used 2D drafting systems only create what are essentially ‘dumb’ drawings; that is, they consist of lines and symbols but do not contain the definitions or associativity of the objects represented. This lack of intelligence prevents the source design from supplying data to support associated functions such as 3D layout design, so these functions remain independent. Inevitably, this leads to errors, inconsistencies, duplications and rework. This has been overcome in the most advanced solutions by enabling a systems engineer to create, say, a P&ID as an interconnected set of defined objects. While the deliverable may still be a 2D schematic drawing, this is now just one particular view of a dataset which defines the system. By storing this data in the common project database, it becomes Figure 2. The management of engineering data across multiple disciplines. Figure 1. Example of a compressor originally created in an MCAD system included in a 3D design model. (Courtesy of Howden). LNG_Spring2012_72-76.indd 74 14/03/2012 11:51 is a leading publisher covering all areas of the global energy industry, in print and online. Special offer: Register online for subscription to LNG Industry magazine. Subscription includes delivery of quarterly hard copy magazine and access to digital issue online. Palladian Publications www.energyglobal.com/magazines SCAN NOW TO REGISTER LNG_Spring2012_72-76.indd 75 16/03/2012 10:11 76 / LNGINDUSTRY / Spring2012 accessible across the project and can be used by other disciplines on a read-only basis. This integration of engineering and design data is an important enabler of efficient working. As soon as the initial P&ID has been created, materials management can begin procuring long-lead items, negotiating advantageous prices and reserving suppliers’ production schedules. Meanwhile, piping designers can translate the system into a 3D layout, creating a detailed and accurate Bill of Materials (BoM) as they do so. The P&ID, the BoM and the 3D layout are each different views of the same underlying data. Both layout design and BoMs can be updated in a controlled manner as the engineering design evolves; one does not have to wait until system engineering has reached an advanced state of maturity. Interestingly, one feature provided in the AVEVA solution is the ability for a systems engineer to create, say, a hydraulic system schematic over the background of a ship’s hull arrangement drawing. This not only provides a useful visual context for the design, it actually associates each individual pump, valve, pipe and so on with its location in the vessel, making the outfitting designer’s work easier and facilitating a number of important downstream tasks. Information integration So engineering and design integration is removing a substantial constraint on complex projects. But schematics and 3D models are just the visible tip of a very large information iceberg, which seems to grow exponentially with every new generation of project. To make things worse, large scale projects must inevitably be collaborations between a network of partners, subcontractors and suppliers spread around the world. Each of these will have their own preferences for software tools for both technical and business functions, and will create information in a wide variety of formats. Some of this information incompatibility can be dealt with as outlined above, using applicable neutral standards such as STEP or ISO15926, but far more must be used as-is. This creates a vulnerability if all this disparate information cannot be centrally managed, cross referenced, validated and shared across the team. Now we move into the realm of information management: an application of technology which offers possibly the greatest single increase in business performance. Information management systems are advancing rapidly and being increasingly deployed across the engineering industries. And just as with engineering and design systems, we are seeing integration within and across the plant and marine sectors. Systems that have evolved to serve one particular industry are being integrated and extended to become much more widely applicable; many of the issues they address are common to both plant and marine, for example. The interesting challenge, for which some genuinely exciting developments have been made, lies in integrating many different types and sources of information. This is more than just document management, because a single document may contain many different items of information, which may each relate to other items in other sources. AVEVA’s approach to this has been to create technologies which are ‘data-agnostic’. That is, they can handle data of widely different types and sources without needing the programs used to create the data. Recognising also that information is a valuable asset to be controlled, these technologies are non-invasive; they read but do not interfere with source data. On these technologies is built an information management system comprising a central data hub for all project or asset information, supported by a number of interfaces (‘gateways’) for different types of data, and presenting information to the user through a browser-type application. The key features of this particular solution are that the incoming information is automatically validated and cross-referenced with related information so that all tag related data is aggregated. Automatically applied hotspots then enable the user to navigate through the integrated digital asset in an intuitive manner, perhaps compiling custom views to extract particular reports. Different vendors have different approaches to the problem, but two common user requirements are, first, that any information management system be web enabled so that it can be deployed flexibly and worldwide without requiring costly infrastructure, and second, that it should be vendor-neutral to allow the widest freedom of choice of authoring applications. Such systems are now available and it is notable that they are being widely adopted by leading companies in the oil and gas industry. Lastly, it is worth noting that these technologies are not restricted to project execution; they are equally, arguably even more, applicable to asset management. Here, they enable the effective management and exploitation of all the information embodied in a physical plant or vessel, the so-called ‘digital plant.’ Users of these systems have gained considerable benefits in areas such as project handover, operations and maintenance, shift handover, regulatory compliance and auditing, and so on. In conclusion The last decade has seen a rapid advance in technology integration that now provides a sound basis for designing, building and operating the next generation of energy projects. Unnecessary barriers to collaboration are continuing to be swept away and new technologies are putting information at the heart of business strategies. All these will enable engineers to create increasingly ambitious projects and make LNG an increasingly important source of the world’s energy. Figure 3. The latest information management technologies put every type of information, even 3D models, at a user’s fingertips. LNG_Spring2012_72-76.indd 76 14/03/2012 11:51 Spring2012 / LNGINDUSTRY / 77 Mun-Seong Kim, Endress+Hauser, Japan, describes the intricacies of LNG storage solutions. Figure 1. Typical instrumentation on a modern LNG storage tank. T he recent earthquake and tsunami in Japan followed by the Fukushima nuclear disaster have resulted in dramatic changes to the Japanese government’s energy plan. In considering energy sources to replace nuclear power generation, LNG has risen to the top of the list. There are many reasons for this, namely the fact that Japan is already one of the world’s largest consumers of LNG coupled with the environmental advantages inherent in LNG utilisation. By expanding the existing infrastructure and securing additional sources of LNG, the immediate energy demands can be met. At the same time, the long term goal is to develop new technology for renewable energy sources and eliminate the dependence on outside resources. LNG_Spring2012_77-80.indd 77 14/03/2012 11:54 78 / LNGINDUSTRY / Spring2012 LNG storage Safe and efficient storage of LNG is a key factor that must be addressed to allow the effective use of LNG. LNG results in a 600:1 compression of the storage space required. In a country where space is at a premium, this is very important. However, lowering the gas temperature to -160 ˚C also results in many technological challenges in handling cold temperatures. Among the many things that must be considered are safety, efficiency, security and environmental issues. Storage tanks are often located in densely populated areas, thus, measures must be taken to ensure that all factors have been properly addressed. Proper instrumentation Proper instrumentation for LNG storage tanks is a key factor in providing the necessary information to operators for intelligent and timely decisions during plant operation. These tanks are quite large (typically approximately 60 m in diameter and 55 m high and capable of storing 120 000 m 3 of liquid). The tanks are filled rapidly from ships and then the liquid is regasified and fed into distribution pipelines for electric power generation and direct use by commercial and residential users. All of this requires proper instrumentation to measure liquid level, temperature, density, pressure and flow. The information must be collected and presented in a user-friendly way to enable operators to manage the LNG plants in a safe and efficient manner. Unique factors of cryogenic liquid storage The storage of LNG at cryogenic temperatures presents some unique challenges that must be handled properly to ensure that the plant is operated safely and efficiently. One of these issues is the potential danger of a ‘rollover.’ Rollover is a term to describe the event of two layers of different densities rapidly mixing with the side effect of large amounts of gas being released. Most such events are relatively harmless, but under the right tank conditions, the excessive amounts of gas can result in product being lost to the atmosphere through relief valves and, in a worst case scenario, the increase in pressure can result in excessive pressurisation of the storage tank with possible structural damage. Offloading/mixing operation The conditions in an LNG storage tank that could lead to such an event is the formation of a light layer on top of a heavy layer. There are several ways this can come about but the most common one occurs in offloading from an LNG tanker of lighter LNG into a storage tank that contains heavier LNG. If this happens, there is no natural reason for the layers to mix. The difference in density to inhibit mixing depends on many factors, but published literature indicates a difference of 1 kg/m 3 is sufficient. The heat leak through the insulation of the storage tank causes energy to build up in the lower layer and decreases the density. At the same time, the lighter elements of the LNG in the upper layer tend to boil off first, causing the upper layer to become heavier. At some point, the layers converge to similar density values resulting in the phenomenon called ‘rollover.’ The layers do not really roll over, but the name has become established throughout the industry. Detailed studies of rollover have been made by the major gas companies (such as Tokyo Gas, Kogas, and Gaz de France) but the results of those studies are proprietary and have not been released to the public. Rollover prevention To prevent such a condition, operators normally try to make sure that the layer never forms in the first place. When loading a tank, the normal procedure is to top-fill heavy LNG and bottom-fill light LNG. If this is always done, then the heavy LNG will sink and cause complete mixing so that no layer can result. While some older LNG storage tanks may not Figure 2. FPSO. LNG_Spring2012_77-80.indd 78 14/03/2012 11:54 1-561-881-8500
[email protected] www.scientificinstruments.com LNG MEASUREMENT AT ITS FINEST 6290 Tank Gauging System The Mode| 6290 Tank Gaug|ng System provides automatic continuous level gauging, temperature monitoring, and density measuring of liquid media. º System may oe |nsta||ed w|t|o0t st||||ng we|| º 2 w||e data t|ansm|ss|on º /ow cost of |nsta||at|on º F0|| system |ed0ndancy Discover the best in Tank Gauging Systems. Ca|| today or v|s|t www.sc|ent|ñc|nstruments.com. www.energyglobal.com/sectors READ about the latest developments in the shale gas sector on Energy Global LNG_Spring2012_77-80.indd 79 16/03/2012 16:13 80 / LNGINDUSTRY / Spring2012 have both top-fill and bottom-fill capability, all newer tanks have that capability. Of course, this also requires that the exact density of the LNG both in the tank and on the ship is known. Minimised BOG A second phenomenon that works against this normal procedure is the natural evolution of ‘boil-off gas’ (BOG) during filling operations. When top-filling a tank with heavier (and colder) LNG, the liquid tends to ‘flash’ when the colder LNG hits the warmer LNG. When this happens, this BOG must be dealt with in some way. Depending on the particular design and facilities of the LNG plant it might be compressed into liquid and returned to the storage tank or possibly fed into the gas supply line from the plant. As a last resort, it can be flared off but, of course, that is a loss of product. No matter what choice is taken to deal with this, all solutions cost money, thus the plant will try to make choices to minimise the production of BOG. LNG tank instrumentation In order to deal with these and other matters effectively, it is imperative that the LNG storage tanks such as liquefaction storage tanks as well floating storage (LNG FPSO) be fitted with proper instrumentation. Figure 1 shows the typical instrumentation on a modern LNG storage tank. This instrumentation normally consists of two level gauges (either servo or radar), two in-tank temperature arrays, a high-level alarm gauge, an LTD gauge for obtaining temperature/density tank profiles, and an array of temperature sensors outside of the storage tank. The temperature sensors on the outside of the tank are initially used to monitor the cooling-down process and subsequently also as on-going leak detection sensors. All of these instruments are normally combined to an integrated system to present the operator with a complete picture of tank conditions. With that information, intelligent and timely decisions can be made to operate the tank safely and with maximum efficiency. LTD density meter In some ways, the LTD instrument stands out as somewhat unique among these instruments. A single probe is traversed over the entire depth of the LNG in the tank. The probe contains both a temperature sensor and density sensor. The temperature and density is recorded at different levels and the data is shown in a graph. In this way, any layering can be easily detected. The LTD unit is often used to measure the density of the LNG in the tank before loading operations commence and is then used again to scan the tank once the operation is complete. This verifies that the proper loading decision was made and if not, layering is immediately detected so that the most cost-effective decision can be made to eliminate the layer. LNG management system Since it is not always possible to completely eliminate all layers, it is sometimes very useful to know if an existing layer is potentially dangerous. A small layer that will only result in a manageable amount of BOG can actually be advantageous if it can be assured that the evolution of gas can be handled safely. Because many factors enter into an accurate prediction, it requires very specialised software to perform such an analysis. Such software is available and has been proven to be very effective. The safe and effective handling of even one potential hazard in an LNG storage tank can actually pay for the cost of the software. Future trends in LNG At the time of writing, there is a worldwide surge in the production and usage of LNG. Due to commercial factors, there is much more mixing of sources of supply than before. In the past, receiving terminals tended to receive LNG from a limited number of sources. The composition of the gas was usually known and an effective plan was formulated to handle any differences. However, in recent years there has been a very large growth in what is known as ‘spot trading.’ This term is used to describe buying a shipload of LNG on a random basis, thus the composition can vary widely. Japan is one of the nations that has used this practice increasingly in recent days. This means in practical terms that provision must be made to deal with much wider composition (density) ranges. This trend is expected to continue in the future. Again, proper instrumentation is one of the most important factors in dealing with this change. Summary In summary, LNG is destined to be a major factor in the energy mix in the foreseeable future. Availability, flexibility, environmental compatibility, and cost-effectiveness all work together to meet the immediate demands. Even though Japan has led the way in the past in the use of LNG, other nations are not far behind in making effective use of this energy resource to meet their ever growing demands. Figure 3. Large capacity of LNG storage tank (over 180 m³ capacity). Figure 4. Small scale LNG production tank. LNG_Spring2012_77-80.indd 80 14/03/2012 11:54 Spring2012 / LNGINDUSTRY / 81 N atural gas is a mixture of hydrocarbons, mostly C1 through C6+, inerts (N 2 , He, H 2 , Ar, O 2 ), acid gases (CO 2 and H 2 S), organic sulfur species (RSH, RSR, RSSR) and other impurities. The mixture composition depends upon the location of fields and the age of the wells. By and large, the H 2 S content in natural gas ranges from 0.1% - 5% vol., whilst the CO 2 ranges from 0.67% vol. to more than 15% vol. The natural gas is called sour if the concentration of H 2 S is greater than 2% vol. The content of H 2 S in natural gas is generally not allowed to exceed 4 ppm vol. The CO 2 concentration is typically required to lie in the range of 1% – 3% vol. For LNG applications, the latter has to be less than 100 ppm vol. in order to avoid freezing problems in the cold end of the plant. Thus, sour gases have to be treated in order to remove these acidic species before being sold or sent to the LNG plant. Figures 1 and 2 portray a general architecture of a field gas development. As can be seen, the sour gas from the slug catchers is mixed with the gas from the oil treatment section and routed toward the gas treatment block. The first initial function of the gas treatment plant is the acid gas removal, which splits the feed into two streams: a sweetened natural gas to be further treated in the downstream units (dehydration, LPG recovery, etc.) to meet selling or LNG Lorenzo Micucci, Siirtec Nigi, Italy, takes a holistic approach to sour gas treatment. Sweet from sour LNG_Spring2012_81-84.indd 81 14/03/2012 14:06 82 / LNGINDUSTRY / Spring2012 specifications and an acid gas stream to be disposed of with sulfur recovery units. The concentration of H 2 S in the acid gas stream from the acid gas removal box is in the range of 10% – 22% vol. For an LNG plant, where deep CO 2 removal is required, the H 2 S concentration can even be as low as 0.5 - 0.7% vol. These concentrations are too low for the acid gas stream to be accepted by a typical Claus unit because the flame inside its thermal reactor becomes erratic and the whole operation becomes troublesome. In these cases, the acid gas has to be further treated in an enrichment box in order to raise the H 2 S concentration well above 40% vol. (the minimum concentration to assure the flame stability) before entering the Claus unit. As acid gases are mixtures of H 2 S and CO 2 , the enrichment operation requires a selective separation of H 2 S from CO 2 . Typically, this selective separation is achieved by means of a regenerative absorption process on aqueous solutions of alkanolamines. There are several options that can be used to meet the enrichment target. These include the use of tailored absorption media (formulated, activated, or sterically hindered amines) or the implementation of a particular process line-up, based on the use of generic amine. Tertiary amines do not form carbamate with CO 2 , thus they are the most selective absorbing solvent for the H 2 S. This makes MDEA the solvent of choice. In addition, its selectivity can be further enlarged (selecting the absorber trays residence time) by exploiting the slower mass transfer rate of CO 2 in the liquid film relative to the H 2 S. The above properties have been used for the following case study project to effectively enrich the diluted acid gas from a sweetening unit without making use of a special solvent or a particular process line-up (both of which are expensive). It is noteworthy that treating sour gas from a gas field is not all about the selection of solvents and designing the absorber to maximise the CO 2 slip at the top of the tower. The enrichment ratio attainable with the above method is around five, thus the H 2 S concentration in the Claus feed may still fall outside the performance envelope of the Claus unit depending upon the actual natural gas composition. Thus, to cover the full range of operational cases, the configuration of the Claus thermal reactor needs to be addressed so that the whole sour gas treatment plant is fully responsive to all composition variations in a cost-effective manner. Furthermore, the sulfur recovery unit exports energy across its boundary and has material flows that can be synergistically used in other process functional boxes. Thus, the holistic approach to the design of a sour gas treatment plant results in the most cost-effective project. The following case study illustrates how this approach has been implemented. Case study The launch of a big onshore project for the exploitation of condensate wells located both in the Mediterranean Sea and at onshore sites, gave rise to the challenging task of selecting the most cost-effective technology for the sulfur removal and recovery unit. The management of the wells and the relevant gas/condensate clusters could produce a broad variation of quantity and quality of acid gases to be treated by the plants that were targeted to produce 540 tpd of sulfur with a recovery efficiency of 99.8%. The H 2 S concentrations in the natural gas from wells were estimated to range from 0.7% to 2.8% vol. The sales gas specification required the customary 4 ppm vol. of H 2 S and 2% vol. maximum of CO 2 . Under these conditions and upon the request of the customer not to be tied to a particular solvent supplier, the generic MDEA at high pressure (> 2 MPa) was selected for the sulfur removal process. The enrichment section was conceived to be totally independent from the sulfur removal section in order to avoid upsets on the sulfur recovery block impairing the gas treating line. In fact, the goal of the gas field project was the production of natural gas for selling offshore; therefore, high reliability and availability of the plant were requested. The availability assessment performed during the feasibility study showed that the arrangement described above was the best for maximising overall plant availability. In order to have one single solvent management with common storage, loading and unloading facilities, both the enrichment section and the high pressure sulfur removal processes were based on MDEA aqueous solution at 50% w. The operating pressure of the absorption and regeneration ends of the enrichment section was set at 20 kPa g and 70 kPa g respectively. For the tail gas treatment, Siirtec Nigi’s HCR™ was chosen, the off-gas from the tail gas treatment unit, containing 150 – 200 ppm vol. of H 2 S, was routed directly towards the thermal incinerator as shown in Figure 2. Because 95% of the fed sulfur was recovered and collected in the sulfur pit, the quantity of H 2 S absorbed Figure 1. Example of gas field architecture. Figure 2. Example of gas treatment process architecture. LNG_Spring2012_81-84.indd 82 14/03/2012 14:06 Founded in 1962, Temati began by manufacturing, promoting and selling Foster® products in the Benelux. Nowadays Temati is Europe’s sole licensed manufacturer and supplier of Foster® and Childers® products, with now five office- and warehouse- locations in different countries and an international distributors- network. Today we sell an extensive range of specialized materials to customers throughout Europe, as well as overseas. As we continue to expand our services, you can continue to rely on us for a wide range of products and the best solutions. Temati B.V. Tel: (+31) (0)251 229 172 Fax: (+31) (0)251 212 380 E-mail:
[email protected] www.temati.com Industrial processes come with a multitude of challenges, which require reliable and innovative products. At Temati, we have decades of experience and expertise. We are your ideal partner when seeking solutions that make a real difference. Unique solutions for industrial processes Americas: +1.281.971.5600 EMEA: +44.1708.620.248 APAC: +65.6322.8228 Email:
[email protected] www.intertek.com/petroleum/testing/lng-services LNG Services Testing Inspection Calibration Global Expertise Confidence through expertise LNG_Spring2012_81-84.indd 83 14/03/2012 14:06 84 / LNGINDUSTRY / Spring2012 into the MDEA was small. Thus, a semi-lean solution exited the tail gas treatment unit (HCR). It was convenient to strip off the H 2 S, loading this semi-lean amine stream and kick it back to the Claus unit. For this reason, two options have been investigated. Firstly, the installation of a dedicated amine regenerator in the HCR area, or secondly, the integration of the amine end of the HCR with the enrichment section. Because the semi-lean flow rate coming from the HCR was only 10% of overall amine circulating in the enrichment box, the second option was chosen, with the aim of reducing the investment cost. Thus, the semi-lean amine stream was sent to the enrichment absorber tower on an intermediate try in order to maximise the service factor of this stream. The rich amine from the bottom of the enrichment absorber tower was sent to a common regeneration tower from where the lean MDEA was split, after cooling in two streams: approximately 90% of the overall flow rate was routed towards the enrichment absorber tower and the rest to the HCR absorber tower. Figure 3 portrays the integrated process scheme. It is noteworthy that the design was aimed at achieving an enrichment ratio (the H 2 S concentration ratio between the enriched acid gas and the feed of the enrichment section) of approximately five. Accordingly, the trays of the absorber and the regenerator towers were designed on the base of the mass transfer rate criteria. Under this condition, the concentration of the H 2 S in the acid gas leaving the regeneration tower ranged from 21% to 45% vol., depending upon the operating case. This latter concentration could be handled by a Claus thermal reactor operated according to the conventional straight through configuration (all the acid was passed through the main furnace burner along with the combustion air). The lower limit could not be managed without using fuel gas for supporting the combustion because, as mentioned earlier, the flame produced by a very lean acid gas would be erratic and the plant operation would become difficult, if not impossible. The fuel supporting mode, however, bears the drawback of further dilution of the process gas with flue gases (inert relative to Claus process). The increased level of inert limits the overall plant throughput. Thus the fuel support mode operation was limited only to operational cases of very lean acid gases (H 2 S concentration less than 27% vol.) processing. For acid gases having a concentration between 27% and 45% vol., the stability of the flames was achieved by bypassing part of the acid gas so that only a portion of the feed was introduced into the main burner along with the whole air flow rate. The other part is injected downstream into the second zone of the Claus thermal reactor through a distribution ring constructed out of refractory material, located in between the burner tile and the tube sheet of the waste heat boiler (double chamber configuration). In this way, the temperature of the first zone of the reactor and thus, flame stability, could be kept stable by adjusting the bypass flow rate of the H 2 S concentration in the feed. In conclusion, the Claus thermal reactor operation modes for the case study were: H 2 S concentration in the feed > 45% (straight through mode). 27% < H 2 S concentration in the feed < 45% (double chamber). H 2 S concentration in the feed < 27% (fuel support mode). The incinerator of the SRU was designed to handle the off-gas from the absorber tower of both the sweetening unit and the HCR unit containing 300 ppm vol. and 150 – 200 ppm vol. of H 2 S, respectively. The sweep air coming from the sulfur pit was routed towards the incinerator as well. The effluent discharged to the atmosphere had less than 7 ppm vol. of H 2 S. Eventually, the steam demand of gas field facilities was a further area in which the integration of a sulfur recovery unit offered major benefits. In the case study, because the overall capacity of the plant was high (570 tpd), the recovery of heat developed by the Claus unit was geared to produce saturated steam at 45 barg. Part of this steam was used to supply energy to the Claus process and the rest delivered to the high pressure steam network (at 40 barg) of the gas field facility after having been superheated to 450 ˚C in a dedicated superheater coil located in the incinerator. Part of the enthalpy of the effluent gas from the incinerator was also recovered to produce superheated steam at 45 barg and 450 ˚C. The incinerator was therefore fitted with a waste heat boiler and two superheater coils. The first coils superheated the steam coming from the Claus unit and the second the steam generated by the incinerator waste heat boiler. Both sets of superheated steam were mixed and delivered to the steam network of the gas field facilities. Conclusion In conclusion, selecting the best processing strategies for sour gas field development is not a trivial task. It requires a careful selection of solvents for the acid gas removal and acid gas enrichment and a holistic approach to integrate, cost-effectively, the boxes of the sour gas treatment plant. In particular, the Claus arrangement and the related operating modes have to be addressed in connection with the operation of the other units of the plant. Furthermore, the tail gas treatment process has to be selected in the light of the potential integration with other units for the best economic operation of the gas complex. Figure 3. Siirtec Nigi’s integrated HCR - PFD. LNG_Spring2012_81-84.indd 84 14/03/2012 14:06 Spring2012 / LNGINDUSTRY / 85 F or many years LNG has been primarily used for electric power generation and domestic heating. However, today natural gas is gaining momentum as a transportation fuel replacing diesel in marine and trucking applications and bus fleets. The emergence of natural gas as a transportation fuel began primarily through the use of compressed natural gas (CNG) in major cities as a means to ease pollution caused by the heavy concentration of vehicular traffic. In many cases the acceptance of natural gas as an alternative transportation fuel was not automatic, but required government incentives or regulations in order to effect the change. But the growth is now being spurred on by fundamental economic considerations rooted in the growing gap between crude oil and natural gas prices. The favourable long term prospects Scaling it down James Solomon, Jr., Air Products, USA, explains how small to mid-sized plants are likely to play a key role in servicing demand. Figure 1. Baseload LNG plant (courtesy of Segas LNG). LNG_Spring2012_85-88.indd 85 16/03/2012 09:53 86 / LNGINDUSTRY / Spring2012 for an abundant natural gas supply indicate that this gap will remain for an extended period of time, stimulating further investment in LNG vehicles and fuelling facilities. Advances driven by market demand Advances in LNG technology have always been driven by changing market requirements, which have continually presented the LNG industry with new sets of challenges. Up until recently, most LNG plants possessed very similar attributes - all were land based export plants, most were designed to employ the largest equipment that was proven at the time, and all but one were in tropical locations. However, these factors no longer hold true for some recently established projects and many developing ones. Most known large gas fields are already in production. Many new gas finds are smaller, offshore, more remote or in Arctic locations. In addition, some newer LNG plants will be designed to produce LNG for domestic, rather than export, markets. As a result, the challenges of establishing new projects have multiplied and the market is demanding new solutions. Designing a plant configuration to meet the smaller scale requirements of the emerging transportation fuel market is yet another challenge. But the dedicated contributors to the industry have demonstrated time and again an ability to meet a wide variety of challenges posed by an ever changing market. Although the trend in recent years has been towards larger LNG plants in order to capture economies of scale, it is often overlooked that approximately half of the operating LNG plants today have capacities of 0.5 - 2.5 million tpy. Although these plants were historically built as baseload plants, today plants in this size range are termed ‘mid-sized’. In addition, for a number of years there was a very active market for LNG plants only one tenth the size of today’s mid-sized plants. Most of these plants, in the 100 - 300 tpd range were built as peak shaving plants, primarily in the USA. In its typical application, a peak shaving plant would consist of a relatively small liquefaction plant and large field erected LNG storage tank located adjacent to a natural gas pipeline. During summer months, when natural gas demand is low, gas would be withdrawn from the pipeline and liquefied for storage. During cold weather months, when pipeline demand is higher, the stored LNG would be vaporised and injected into the pipeline to meet peak winter demand. Thus, the peak shaving plant would operate only a few months per year in order to fill the available storage, and then be idled when the storage capacity became full and during times of re-vaporisation. As the transportation fuel market struggles to become established, very small demonstration plants (sometimes termed ‘micro’ plants) may be a prerequisite to spur local demand. However, as the market develops, plants will need to be sized to economically meet the growing demand, and this is where mid-size and traditional peak shaver size plants will be required. So, while the market drivers for small and mid-size LNG plants may be new, there is significant experience within the LNG industry in supplying technology and equipment for these size ranges. Renewed interest in small and mid-sized plants In very simple terms, the production of LNG requires heat exchange between natural gas and a refrigerant cold enough to effect liquefaction. There are many choices of refrigerants, but they fall into two general categories: mixed refrigerants or pure component refrigerants. The majority of large LNG trains in operation today use either a pre-cooled mixed refrigerant or pure component cascade liquefaction process. The propane pre-cooled mixed refrigerant technology is the most prevalent liquefaction process in use today, followed by the cascade process technology. Partly due to the growing transportation fuel market, there is a renewed interest in small and medium-sized plants as a way to monetise lower volume gas reserves at reduced cost. Because smaller plants cannot achieve the same economies of scale as larger plants, many developers focus on reducing capital. Additionally, project developers are focusing on execution strategies that facilitate shorter project schedules, accelerating time to onstream and thus, quicker monetary returns. However, in order to be economically viable in the long term, a small or medium-sized LNG plant must minimise downtime, maintenance, and lost production just like a large plant. For small and mid-size requirements, either pure component nitrogen refrigeration or single mixed refrigerant (SMR) systems may be an ideal fit. Figure 2. LNG peak shaving plant. Figure 3. Nitrogen recycle refrigeration process. LNG_Spring2012_85-88.indd 86 16/03/2012 09:53 17th International Conference & Exhibition on Liquefied Natural Gas (LNG 17) The Biggest Global Gas Event in 2013 1 6 - 1 9 APRI L 2 0 1 3 # HOUSTON, T EXAS # USA HAVE YOU SUBMITTED AN ABSTRACT YET? CALL FOR PAPERS ENDS 6 APRIL 2012 www.LNG17.org LNG 17 is coming to Beijing # Meet the team at CIPPE Booth A1058, Hall W2, 19-21 March 2012, New China International Exhibition Centre, Beijing INTERNATIONAL ORGANIZERS: HOST ASSOCIATION: PRINCIPAL SPONSOR: LNG_Spring2012_85-88.indd 87 16/03/2012 09:53 88 / LNGINDUSTRY / Spring2012 Nitrogen recycle LNG liquefier In the hope of reducing capital, nitrogen (N 2 ) expander cycles are often considered for smaller plants due to their simplicity. A simple nitrogen recycle system is shown in Figure 3. The nitrogen recycle system is easy to operate and has superior turndown efficiency, and the nitrogen used as a refrigerant is non-flammable and environmentally benign. The use of nitrogen also eliminates the need to store hydrocarbon refrigerants, as required by mixed refrigerant systems. For this reason, nitrogen cycles are also being considered for floating plant applications. In addition, the nitrogen recycle liquefier can be highly modularised to minimise field construction cost. Attractive as these attributes are, most N 2 expander LNG trains operating today are less than 0.1 million tpy and are used in peak shaving or interruptible service. Although simple, these cycles suffer from relatively low process efficiency since the natural gas must be cooled, condensed and sub-cooled all against a single-phase vapour refrigerant, limiting their practical size. Nevertheless, a simple N 2 refrigeration system may be acceptable for small requirements, or where low capital is the main driving force, and efficiency is not heavily weighted in the project evaluation. However, in order to supply LNG to niche markets such as transportation fuel, the market demand may require a higher capacity plant that will need to be designed to operate continuously. For these applications, operating and maintenance costs will tend to be weighted more heavily in the evaluation, making a higher efficiency system relatively more attractive. To make up for inefficiencies and the limited size of proven equipment, multiple levels of expansion and parallel equipment may be added as shown in Figure 4. Adding pre-cooling to the nitrogen system can also increase its efficiency, but these enhancements also increase the number of pieces of equipment resulting in a more complicated plant. Mixed refrigerant process For larger capacity requirements, the SMR LNG process can provide proven performance and reliability. SMR processes are more efficient than simple N 2 expander cycles, require fewer rotating equipment items and are well proven in this size range. The refrigerant consists of a mixture of hydrocarbons and nitrogen optimised to match the natural gas cooling curve as closely as possible. SMR cycles are still significantly less efficient than pre-cooled mixed refrigerant cycles, which tends to limit the practical size of a single train before parallel equipment is required. However, when considering efficiency, operating simplicity and capital in an overall project evaluation, the market has proven that SMR systems are well suited to mid-size applications. Rising to the challenge There is no single technical solution to meet every plant requirement of a given size range. Figure 6 provides some general guidelines, but the ideal solution for any particular situation will depend on a variety of issues specific to a given opportunity. Plant scale is only one aspect to be considered. Energy costs, capital constraints and operating philosophy are only a few of the other factors that should be taken into account in the evaluation process. Throughout the history of the LNG industry, technical advancements have always been driven by market requirements. This will continue to be the case in the future as the next generation of LNG plants is built to meet the growing demand for LNG transportation fuel. Figure 5. Single mixed-refrigerant liquefier. Figure 4. Improved efficiency nitrogen recycle liquefier. Figure 6. Liquefaction technology vs. plant scale. LNG_Spring2012_85-88.indd 88 16/03/2012 09:53 Spring2012 / LNGINDUSTRY / 89 G as turbines play a fundamental role in LNG production, with many LNG plants using gas turbines to drive compressors used to cool and liquefy gas for transportation. As such, keeping gas turbines running effectively is key to maximising plant productivity and reducing expensive, unscheduled downtime. One challenge to maintaining effective gas turbine performance is controlling the formation of varnish, a catch all term for deposits found in gas turbine operation either in the form of sludge or varnish. Varnish can have a significant detrimental impact on gas turbine operation but by selecting the right oils, together with improved maintenance strategies, companies can help minimise its build-up and extend gas turbine life. Compared to 20 years ago, there is now much greater awareness of varnish issues. Based on limited experience, some companies may hold the incorrect view that newer technology turbine oils have caused increasing amounts of gas turbine hydraulic varnish. However, direct field experience, combined with test rig comparisons, confirms that advancements in some turbine oil formulations have improved turbine oil life with less varnish generation. For example, ExxonMobil Lubricants & Petroleum Specialties Akram Reda, ExxonMobil Lubricants and Specialties, EAME, explains the benefits of choosing the right lubrication oil for gas turbines. LNG_Spring2012_89-92.indd 89 14/03/2012 14:18 90 / LNGINDUSTRY / Spring2012 has demonstrated that newer turbine oils have performed with improved reliability in the same service as older, now retired turbine oil formulations. Understanding where varnish comes from One of the problems facing LNG operators is understanding why some turbines are more susceptible to varnish than others. The answer lies in varnish formation theory, which looks at the different ways varnish can occur. There are three main mechanisms of varnish formation: thermal degradation of oil, which can take place at temperatures above 300 ˚C, oxidation, (a reaction that acts to decompose the oil) and contamination of the oil, through either internal or external sources. While treating the symptoms of varnish through mitigation technologies may extend service life, the important factors for reliable operation are starting with a clean system and using a turbine oil designed to prevent varnish from forming. A well balanced formulation that utilises high performance base stocks and advanced technology additives is the first line of defence against the formation of sludge and varnish. What to look for in turbine oil? By selecting an oil with highly refined base oils and a proper balance of advanced technology additives, operators are less likely to see their oil compromised during long term service. In general, higher group base stocks blended with advanced technology additives offer the strongest defence against varnish. In finding a well balanced gas turbine lubricant, maintenance personnel should consider analysing a lubricant’s deposit control, oxidation stability, air release and foam control, filterability, rust and corrosion, and wear protection in their selection of an appropriate lubricant that will mitigate and manage varnish formation. Deposit control As mentioned earlier, varnish can be generated by thermal degradation, oxidation and contamination. Some oils generate more deposits than others, but advanced turbine oils are formulated to limit the generation of sludge and varnish, while keeping deposits in suspension. Oxidation stability Turbine bearing temperatures approaching 250 ˚C, in combination with equipment metals, contaminants and entrained air all contribute to oxidation, which precedes varnish formation. Operators should look for higher level turbine oil base stocks and advanced antioxidants which can provide protection against oxidation when properly formulated. Air release and foam control Entrained air in an oil with inferior air release performance may be compressed in turbine bearings or high pressure hydraulics and cause adiabatic compression (aka micro dieseling). Adiabatic compression could cause localised elevated oil temperatures that may promote the formation of varnish. In addition, inferior air release can result in less than precise control in system hydraulics. Similarly, excessive surface level foaming can accelerate oxidation and can lead to operational issues, such as the inability to measure lubricant levels correctly, or lead to reservoir overflow from vents. Oils formulated to have rapid air release and minimal foam formation will provide superior protection against the formation of varnish. Filterability The filterability characteristic of a fluid can be defined as its ability to pass through a filter with minimal pressure drop. An oil with poor filterability will foul filters faster that an oil with good filterability. This often translates into more frequent filter changes. Anti-rust and corrosion protection Rust and corrosion can also contribute to oxidation and the formation of contaminant-based varnish. Oils formulated to minimise rust and corrosion will reduce the likelihood of varnish formation. Wear protection Wear on high pressure hydraulics, the gears of the accessory gearbox, generator reduction gear or turning gear, can directly impact operation of gas turbine performance. Wear material from these components can indirectly be a source of varnish formation since the wear metals will act as an oxidation catalyst. A balanced formulation Varnish formation and management are greatly impacted by the oil’s formulation. It is anticipated that a gas turbine utilising a lubricant formulated with highly refined base oils Figure 2. The spider chart above graphically demonstrates the concept of a balanced formulation. Figure 1. Photos above show varnish formation on three market available oils and an ExxonMobil Research and Engineering developmental oil from test rig inspections. LNG_Spring2012_89-92.indd 90 14/03/2012 14:18 and a proper balance of advanced technology additives will be less likely to be compromised during long term service. In general, higher group base stocks blended with advanced technology additives offer the best first line of defence against varnish. One of the main challenges is formulating an oil that achieves key performance goals without sacrificing other oil attributes. The leading attribute of a low varnish/sludge oil is deposit control. However, achieving this may lead to some performance characteristics being less than optimal, like demulsibility. Less than optimal demulsibility is considered an acceptable trade-off for a substantial improvement in improved deposit control since gas turbines operate with bearing and reservoir operating temperatures that will volatise minor water ingression. Rig testing turbine oils To help further its understanding of varnish and oil performance, ExxonMobil Research and Engineering has designed and constructed turbine oil developmental test rigs, called Valve Varnish Rig Test (VVRT), that simulate real world service. These test rigs are used to develop next generation turbine oils and to evaluate oils in use today. Testing oils in a rig offers evaluations closer to real world conditions than the typical glassware testing traditionally used in the industry. Monitoring and predicting varnish Once the appropriate lubricant is selected, it is imperative that its performance is monitored through a proactive oil analysis programme. Sampling and testing should be done at least quarterly, and it is usually beneficial to perform it more frequently as the oil condition degrades. By trending the results of these tests, maintenance personnel can gain valuable insights into the condition of the oil, the equipment and the remaining service life of both. Today’s available historical oil analysis testing methods cannot accurately predict varnish, although the industry has been working to develop methods to better predict varnish in gas turbine hydraulic systems with a combination of Ultra Centrifuge (UC), Membrane Patch Colorimetry (MPC) and Linear Sweep Voltammetry (RULER) tests. While these tests can be helpful, care should be taken regarding action plans based on test performance. Action plans from these tests should be application and oil specific. ‘Application specific’ action plans consider that gas turbines with combined hydraulic and bearing reservoirs are more varnish sensitive than a steam turbine with separate hydraulics. ‘Oil specific’ action plans refer to the formulation chemistry of the turbine oil. Making the right choice Understanding how varnish is made and its impact should provide plant personnel with tools to enhance equipment reliability and allow them to focus on operation. The key to trouble free operation is selecting a high quality turbine oil that has been validated in field-like conditions. Setting the stage with a well formulated oil in a properly flushed turbine and utilising the proper prediction tools will offer years of reliable operation. But selecting the right oil is not a simple choice, and LNG operators should work with expert lubricant manufacturers and oil analysis providers who have the application expertise needed to help vanquish varnish. Figure 3. The chart above shows relative comparisons of eight turbine oils based on hours to valve stick, in ExxonMobil Research and Engineering’s valve varnish rig test. LNG_Spring2012_89-92.indd 91 14/03/2012 14:18 24-27 April 2012 Marriott Riverwalk | San Antonio | Texas Distinguished Speakers Include: The Premier Global LNG Gathering in the Americas Championing a New Era for Gas & LNG in the Americas Call Tyler Forbes on +44 20 7978 0061 or email
[email protected] www.cwclng.com/americas CHENIERE SPONSORS: SUPPORTED BY: Senator the Hon. Kevin C. Ramnarine Minister of Energy & Energy Afairs Trinidad & Tobago Davis Thames President Cheniere Marketing Rob Bryngelson CEO Excelerate Energy Clay Harris President & CEO GDF Suez LNG North America LLC Rudolf Araneda CEO GasAtacama LNG_Spring2012_89-92.indd 92 14/03/2012 14:18 93 25 th World Gas Conference 2012 LNG Industry presents a small selection of companies that will be exhibiting at the 25 th World Gas Conference, Kuala Lumpur, 4 - 8 June 2012. Air Products A ir Products is the world leader in natural gas liquefaction technology. Our experience extends from peak shaving plants producing less than 0.1 million tpy of LNG to the largest baseload plants in the world using the new AP-X ® LNG process. Our MCR ® main cryogenic heat exchangers and natural gas liquefaction processes have become the world’s standard for baseload LNG because of their reliability, high efficiency and operational flexibility. With over 40 years of LNG experience, Air Products has built more than 80 main cryogenic heat exchangers for customers in 13 countries worldwide. Air Products and Chemicals, Inc., a global company with annual sales of US$ 10 billion, has a leading market position in industrial gases and selected chemicals. The company is recognised for its innovative culture, operational excellence and commitment to safety and the environment. Corporate headquarters are located in eastern Pennsylvania, USA. Air Products operates in 40 countries and has more than 18 000 employees around the globe. Please visit us at WGC2012 at stand number 9310. Exhibitor Preview LNG_Spring2012_93-96.indd 93 14/03/2012 16:02 2012 94 World Gas Conference Preview Arc Energy Resources A rc Energy Resources is one of the UK’s leading specialists in weld overlay cladding and fabrication for the oil and gas industry. The company’s expertise provides protection against corrosion and wear for a variety of process and pipeline equipment for use in any hostile environment. The company recently made a major investment in two new Rotating Head welding machines costing £500 000. This has increased productivity and extended the size and scope of work it can handle, which now includes complicated component geometries for the full or partial cladding and fabrication of a huge range of component sizes weighing up to 15 t. The company’s in-house designed cladding workstations feature state-of-the-art control systems developed to suit its customer’s specialised engineering requirements, and can clad bores up to 4 m in diameter and areas of restricted access within bores as small as 20 mm in diameter. Arc Energy also offers in-house test weld, heat treatment, PMI and NDT facilities. Industry certifications include ISO 9001:2008 quality management, ISO 3834-2 fusion welding of metallic materials, and the internationally renowned ASME U and R Stamps, as well as ISO 14001:2004 environment management, Investors in People and OHSAS 18001:2007 Health & Safety management system. Have We Entered the Golden Age for Gas? Find out more at Gastech 2012 LNG_Spring2012_93-96.indd 94 14/03/2012 16:02 95 2012 World Gas Conference Preview Gas Technology Institute (GTI) G as Technology Institute (GTI) is the leading research, development, and training organisation serving the natural gas industry and energy markets. For more than 70 years, GTI has been meeting the nation’s energy and environmental challenges by developing technology-based solutions for consumers, industry and government. Specific LNG technology areas include storage, safety, combustion and interchangeability topics. Our experience in technology development combined with our educational expertise enables GTI to deliver high quality training programmes and materials that meet changing industry needs. GTI has been a leader in LNG training and education since the industry’s inception and holds open-enrollment and private client courses in all aspects of the LNG industry. Topic areas include an overview of the LNG industry, terminal design and operations, as well as detailed training for plant operating personnel. The modular courses can be customised to address specific client issues and our programmes accommodate the needs of employees with varying experience levels. GTI held the first LNG Conference in Chicago in 1968 and remains one of three official sponsors. The company has published the proceedings from LNG1 to LNG16, and its publications are essential sources of information for anyone involved in the LNG business. The Global Gas Industry is Coming to London The Gastech London conference begins with an exclusive opening address from Sir Frank Chapman, Chief Executive of BG Group, before opening out with a fascinating panel debate examining: “Have We Entered the Golden Age for Gas?” Confirmed Moderator and Speakers to date: • (Moderator) Martin Houston, Chief Operating Ofcer & Executive Director – BG Group • Helge Lund, President & Chief Executive Ofcer – Statoil • Shigeru Muraki, Representative Director, Executive Vice President & Chief Executive of Energy Solution Division – Tokyo Gas Co Ltd • Hamad Rashid Al-Mohannadi, Managing Director – RasGas Company Limited & Vice-Chairman – Qatar Petroleum • Bill Dudley, President & Chief Operating Ofcer – Bechtel Corporation • Abdelhamid Zerguine, Chief Executive Ofcer – Sonatrach For more information about becoming a delegate contact us at
[email protected] Book before June 30 and take advantage of our Spring Rate Save £250* on your delegate place www.gastech.co.uk/LNG-Industry * o f f u l l d e l e g a t e r a t e UK | ExCeL London | 8-11 October 2012 A world leader in natural gas Hosted by LNG_Spring2012_93-96.indd 95 14/03/2012 16:02 2012 96 World Gas Conference Preview KEMA Gas Consulting & Services K EMA Gas Consulting & Services is an independent, leading authority and strategic partner on gas and energy market developments. At the forefront of developments that will shape the gas market of the future, GCS proactively adds value to the business of its customers by offering premium consulting, applied research and operational services. KEMA possesses broad experience throughout the total energy chain, supplemented by in-depth knowledge of the gas and LNG industry. Hence, we are fully capable of integrating the LNG solution into the wider energy strategy. LNG is one of the solutions, but this development is not without risk. We strive for maximal value creation and risk reduction with a special focus on integral solutions. Over the years we have performed several projects and assignments varying from market and strategic analysis and conceptual design to safety and impact assessments, and feasibility and performance studies. KEMA provides impartial advice that is directly tailored to the best interests of the individual client. KEMA can advise stakeholders throughout the various stages of developing and operating LNG infrastructure as an independent party with an integrated view on energy. Visit us at the World Gas Conference, booth 2320. A D V E R T I S E R S I N D E X LNG Industry is audited by the Audit Bureau of Circulations (ABC). An audit certificate is available on request from our sales department. www.energyglobal.com ABC 44 AIR PRODUCTS IFC BURCKHARDT COMPRESSION 15 CB&I OFC & 61 CHART ENERGY AND CHEMICALS INC. 43 CONOCOPHILLIPS 33 CONSOLIDATED CONTRACTORS 63 EBARA INTERNATIONAL CORPORATION 71 ENERGY GLOBAL 24 & 62 & 79 FMC TECHNOLOGIES 09 GASTECH 2012 94 & 95 GDF SUEZ OBC GE OIL & GAS 21 GTT 51 ILTA 32ND ANNUAL INTERNATIONAL OPERATING CONFERENCE & TRADE SHOW 34 INTERNATIONAL REGISTRIES 57 INTERTEK 83 KOBELCO IBC LNG AMERICAS SUMMIT 92 LNG 17 87 LYDALL 23 MAN DIESEL 67 MARKEY MACHINERY 91 PITTSBURGH CORNING 07 RAS LAFFAN INDUSTRIAL CITY 02 RIDDERINKHOF 49 SAFEHOUSE 39 SAMSON 29 SCIENTIFIC INSTRUMENTS 79 SIEMENS 04 STRABAG INTERNATIONAL GMBH 27 SUBSCRIPTIONS 75 TEMATI BV 83 TGE MARINE 36 UOP 55 VOITH 13 WEATHERFORD 69 GDF SUEZ G DF SUEZ develops its businesses (electricity, natural gas, energy and environmental services) around a model based on responsible growth to take up today’s major challenges: meeting energy needs, ensuring the security of supply, fighting against climate change and maximising the use of resources. The group provides highly efficient and innovative solutions to individuals, cities and businesses by relying on diversified gas supply sources, flexible and low-emission power generation as well as unique expertise in four key sectors: LNG, energy efficiency services, independent power production and environmental services. GDF SUEZ employs 218 900 people worldwide and achieved revenues of f 90.7 billion in 2011. The group is listed on the Paris, Brussels and Luxembourg stock exchanges and is represented in the main international indices: CAC 40, BEL 20, DJ Stoxx 50, DJ Euro Stoxx 50, Euronext 100, FTSE Eurotop 100, MSCI Europe, ASPI Eurozone and ECPI Ethical Index EMU. Key group figures 218 900 employees in close to 70 countries. Including 61 250 in electricity and gas. 77 200 in energy services. 80 450 in environmental services. f 90.7 billion in 2011 revenues. e 11 billion in investments per year over 2011 - 2013. 1100 researchers and experts at nine R&D centres. 100 000 new hires between 2011 and 2015: 50% in France and 10 000 in Belgium. First company in the ‘utilities’ sector worldwide (Forbes Global 2000). Most valuable brand in the ‘utilities’ sector worldwide (Brand Finance Global 500). LNG_Spring2012_93-96.indd 96 19/03/2012 10:34 Kobelco LNG BOG Compressors TOUGH IN EXTREME COLD Tokyo +81-3-5739-6771 Munich +49-89-242-18424 www.kobelco.co.jp/compressor Kobelco EDTI Compressors, Inc. Houston, Texas +1-713-655-0015
[email protected] www.kobelcoedti.com Kobelco reciprocating compressors deliver robust performance in LNG boil-off gas and booster service. The API-618-compliant, horizontal design delivers the industry’s broadest range of capabilities: I inlet temperatures down to -162°C (-260°F ) I discharge pressures up to 220 bar (3,200 psi) I power as high as12,000 kW (16,000 hp). Rugged design features – like die-forged steel connecting rods, steel-backed aluminum bearings and long-life valves – provide exceptionally high reliability and dependable long-term value. You’ll enjoy low maintenance too, with extended continuous operating intervals and design features that make routine service simpler, faster and more economical to perform. For LNG solutions, turn to Kobelco – a leader in gas compression technology since 1915. Kobelco LNG BOG Compressors – high performance at low temperatures. Broadest Capabilities in the World LNG_Spring2012_IBC.indd 1 14/03/2012 15:22 Our mission is a source of pride each and every day: responding to today’s needs while shaping the world of tomorrow. Throughout the world, the men and women at GDF SUEZ focus their businesses on responsible growth to take up today’s major energy and environmental challenges: responding to energy needs, fighting against climate change, ensuring the security of supply and maximizing the use of resources. For 50 years, the Group is a leader of liquefied natural gas (LNG). GDF SUEZ has developed successfully relationships with its partners on long term basis and all along the LNG chain. Today, GDF SUEZ is the 1st LNG importer in the Atlantic Basin, and the 3rd worldwide. The Group has a unique, flexible and diversified LNG portfolio. At the cutting edge of innovation, with the regasification vessels and the development of a floating liquefaction project, LNG contributes to our customers safety of supply in order to satisfy daily their energy needs. Thus, LNG represents almost 30% of the GDF SUEZ long term natural gas supplies portfolio. gdfsuez.com © G I L L E S C R A M P E S . A G E N C E M A R C P R A Q U I N . LNG_Spring2012_OBC.indd 1 14/03/2012 15:23