LNG Industry November December 2013

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CONTENTSISSN 1747-1826

ON THIS MONTH’S COVER

NOV/DEC 2013 LNGINDUSTRY 1110 LNGINDUSTRY NOV/DEC 2013

G as production in Africa is currently estimated at 216 billion m3/y, 6% of total global supply. However, with a current gas per capital demand of 119 m3/y, Africa also has the lowest consumption rate of all continents; seven times less than the Middle East, and fourteen times

less than North America. Total domestic consumption is estimated at just 56% of supply, and with projections from BP expecting these ratios to be sustained over the next 20 years, exports will play a vital role in the future of the African gas industry. This is even more acute for West African producers where production to consumption ratios average 30 – 40%.

Fortunately, strong growth is expected in demand where a combination of a rapidly modernising Asia and carbon-cutting West are projected to increase global gas consumption by 46% over the next 20 years. Some 100 billion m3 of gas was exported by Africa in 2012, of which 45% was by pipeline

AfRicAN lNg:

Michelle Gomez, Douglas-Westwood, UK, examines the opportunities and pitfalls that African LNG presents.

born again?born again?

LNG_NovDec_2013_10-12.indd 10-11 04/12/2013 11:38

NOV/DEC 2013

10

13 A new playerArtur Pereira, Angola LNG Marketing Ltd, UK, provides an overview of the Angolan LNG project.

17 The future’s brightFord Garrard, NES Global Talent, UK, explains how Africa’s role in the LNG market is becoming increasingly significant.

20 Preparing Queensland for the LNG boomBhavna Patel, LogiCamms, Australia, reveals why a behavioural change is required to plan for effective training of all personnel.

26 Playing it safeDave Coppin, AVEVA, UK, explains how video game technology is transforming operator training in LNG plants.

33 Simulate to accumulatePlatt Beltz and Greg Hallauer, Yokogawa, USA, discuss how simulation can improve operator training in LNG operations.

38 Don’t miss the boatGraeme Henderson, WorleyParsons, explains how LNG producers can navigate the industry’s growing complexity through innovative data-based solutions.

45 “Are you ready?”Joost Smits, Systems Navigator, the Netherlands, examines whether terminals are ready for LNG bunkering.

51 Pioneering LNG as fuel in North AmericaPatrick Janssens and Roy Bleiberg, ABS, demonstrate how LNG projects in the US are setting the bar for vessel safety.

53 Turning adherence into opportunityColin Thurston, Thermo Fisher Scientific, UK, discusses how LIMS can enable LNG laboratory agility in the face of changing standards.

57 A moving targetDr Harri Kytömaa and Dr Trey Morrison, Exponent Inc., USA, explore US regulatory challenges faced by the LNG industry.

63 Capturing contaminantsVince Atma Row and Tony Hood, Johnson Matthey, UK, discuss desulfurisation and mercury removal from natural gases.

69 Small scale standardisationSharon Benard, USA, and Matthias Bruentrup, Germany, Linde Process Plants, look at standard small scale LNG plants.

73 Seal less, zero emission LNG pump solutionsDavid Loughman, Nikkiso Cryo Inc., USA, looks at how the small scale LNG industry can benefit from the unique properties of submerged motor pumps.

81 Reducing the ‘human factor’Mike Fynes, Smith Flow Control, UK, takes a common sense approach to valve safety.

84 Optimising safety offshoreVincent Lagarrigue and Richard Hepworth, Trelleborg, discuss the evolving nature of offshore LNG transfer in tandem configuration.

89 Work safe. Breathe easy.Allan Cameron, Sabre Safety, UK, analyses the challenges in dealing with irrespirable environments – from H2S to natural gas.

93 Integrated project valuationAlejandro Plano, Palantir Solutions, USA, shows why an integrated approach for managing risk, as well as understading the economics and the available commercial opportunities are important for truly understanding the value of a LNG project.

03 Comment05 LNG news10 African LNG: born again?


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I n this issue of LNG Industry, several articles address the workforce challenge currently facing our industry. While the battle is on to attract the limited number of skilled

professionals currently available, the sector is doing its utmost to deepen the talent pool through apprenticeship schemes and by retraining workers from other heavy industries. A large proportion of these new workers will belong to ‘Generation Y’ – roughly defined as those born between the late 1970s and mid-1990s.

The problem is, this new generation of technology-savvy workers do not respond particularly well to traditional training methods. According to an article from AVEVA starting on p. 26 of this issue, Gen Y is more easily “able to absorb industry-specific information […] if exploring unfamiliar information through an already familiar platform and learning techniques”. The company’s answer to this dilemma? Industrial gaming.

The theory goes that the ‘already familiar’ gaming genre can help the younger generation to assimilate the information required to perform safely and effectively within the LNG industry, as Gen Yers respond better to “visual and kinaesthetic learning” techniques. Furthermore, this method of training should be applicable to other generations, as we all excel at playing games long before we learn how to work.

Of course, it is one thing to effectively train (or retrain) your current workforce, and another thing entirely to attract new recruits to the industry. But perhaps the gaming sector can help here too. The US Army has seen significant success with its ‘America’s Army’ recruitment tool – a video game designed to let players experience what life is like in the army. And although the LNG industry may not have guns and bad guys, who’s to say

that a video game simulating the experience of running an LNG plant can’t be equally successful in helping to attract the next wave of engineering graduates to the industry?

Recruiters need to go where their audience spend the majority of their time. And if Gen Y isn’t playing on its games console, there is every chance that it is engaging with social media. According to a recent InSites Consulting research community project, the average Gen Yer is a member of 2.5 social networks, with Facebook, Twitter, Google+ and LinkedIn the most popular platforms. On top of this, 80% of those polled said that they log-on to social media every day.

Whilst these stats may fill some employers with dread – a separate survey from Hays plc indicates that 58% of Gen Y consider social media to be a distraction at work – others will see a golden opportunity to reach out directly to the engineers of tomorrow. Social media opens up a world of contacts, from all walks of life. If recruiters can connect with this enormous online contact book in an effective and engaging way, the rewards could be considerable.

But social media isn’t just for Gen Y. There are dozens of LNG-related interest groups on LinkedIn alone, offering industry veterans the opportunity to keep informed, expand their network of contacts, and share opinion with their peers.

We’re a social bunch here at LNG Industry. In addition to recently launching our brand new website: www.lngindustry.com – dedicated to the latest news, events and expert comment from across the global LNG industry – we are also heavily involved in Gen Y’s top four social networks. So, whether you’re a member of Gen Y, Gen X or a Baby Boomer, grab your smartphone and scan the QR codes below to join our social network.

Get the free mobile app athttp:/ /gettag.mobi




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LNGNEWS

NOV/DEC 2013 LNGINDUSTRY 5

Singapore

Keppel and Golar collaborate on FLNG conversion

Keppel Shipyard Ltd and its topside partners are currently negotiating conversion and liquefaction

contracts with Golar LNG on the conversion of an existing LNG carrier into a floating liquefaction and storage vessel (FLSV). The terms and conditions of the contracts, including the contract value and expected completion timeline, have yet to be finalised.

The negotiations on the contracts commenced following the conclusion of a front-end engineering and design (FEED) study conducted at the end of August by Keppel Shipyard to confirm the engineering and work scope. The study confirmed that the conversion will take approximately 30 months from financial commitment to complete.

Upon completion of the FEED study, Keppel Shipyard has announced that it will proceed to work with Golar LNG on the conversion and engineering of the first of three FLNG vessels. There will be an option to convert the other two FLNG vessels at a later date.

Canada

Aurora LNG files export application

B ritish Columbia’s first LNG proposal at Grassy Point near Prince Rupert has filed its export application with

Canada’s National Energy Board (NEB). Aurora LNG filed the application shortly after signing

a sole proponent agreement with the Province of British Columbia (BC). The sole proponent agreement provides Aurora LNG with the exclusive right to pursue long-term Crown land tenure in the Grassy Point area.

As part of the sole proponent agreement, Aurora LNG had to file for an export licence with the NEB. To date, the NEB has issued export licences to three LNG proponents in BC.

“With a vast supply of natural gas and a list [of] competitive advantages other jurisdictions can’t replicate, BC’s LNG plans continue to gain momentum,” said Rich Coleman, Canada’s Minister of Natural Gas Development. “We look forward to working with Aurora LNG as they advance their plans to be part of our energy future.”

Aurora LNG is a joint venture by Nexen Energy ULC, a wholly-owned subsidiary of CNOOC Ltd, INPEX Corp. and JGC Corp.

Australia

Shell floats hull of its Prelude FLNG facility

The 488 m-long hull of Shell’s Prelude floating LNG (FLNG) facility has been floated out of the dry dock at the

Samsung Heavy Industries (SHI) yard in Geoje, South Korea, where the facility is currently under construction.

On completion, Prelude FLNG will be the largest floating facility to date. Its purpose is to unlock new energy resources offshore and produce approximately 3.6 million tpy of LNG to meet increasing demand.

Matthias Bichsel, Shell Projects and Technology Director, said: “Making FLNG a reality is no simple feat. A project of

this complexity – both in size and ingenuity – harnesses the best of engineering, design, manufacturing and supply chain expertise from around the world. Getting to this stage of construction, given that we only cut the first steel a year ago, is down to the expert team we have ensuring that the project’s critical dimensions of safety, quality, cost and schedule are delivered.”

Prelude FLNG is the first deployment of Shell’s FLNG technology and will operate in a remote basin around 475 km north-east of Broome, Western Australia for around 25 years.

LNGNEWS

6 LNGINDUSTRY NOV/DEC 2013

NEWS HIGHLIGHTS

To read more about these stories go to:

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USA

Wärtsilä to design ConRo ships

Wärtsilä has been awarded a contract to supply the extended engineering scope for the initial, basic and

production designs for a series of two container roll-on/roll-off (ConRo) vessels to be built for US based owner, Crowley Maritime Corp. The vessels will be powered by LNG, and are to be built at the VT Halter Marine’s shipyard in Pascagoula, Mississippi. In November, Crowley announced that it has signed a contract with VT Halter Marine Inc. to build two of the world’s first LNG powered combination ConRo ships.

Wärtsilä Ship Design’s WSD CRV 2400 WB enables the capability to carry conventional 20 ft and 40 ft containers, as well as the special 45 ft and 53 ft wide body high cube container developed for the US market. The ConRo capacity is in excess of 350 private cars. The ConRo ships will operate between Jacksonville, Florida and San Juan, Puerto Rico on a weekly rotational basis.

The vessel design had to meet stringent environmental guidelines due to the recently established Emission Control Area (ECA) along the eastern seaboard of the US. Low emissions, reliability, and appropriate transit speed were, therefore, primary considerations.

“This vessel design raises the bar for merchant shipping, not only for US flagged ships, but globally. We are proud to be taking this bold step in bringing environmentally viable designs to the market, with Wärtsilä as a key partner,” said Rick Zubic, Vice President, Business Development, VT Halter Marine.

X RasGas celebrates safety milestone

X Companies awarded FLNG DOE export approval

X Japan to help BC gas development

Australia

QGC hiring 15 people per day

BG Group subsidiary QGC has announced that it is currently employing 14 500 people, with more than

15 people per day being hired as work on the Queensland Curtis LNG (QCLNG) project intensifies.

In the company’s latest six-monthly report to Queensland’s Coordinator-General on Australian industry participation, QGC said investment in construction, exploration and operations since January 2010 had passed AU$ 19.4 billion. This included all investment by BG Group in both QGC and the Queensland Curtis LNG Project.

QGC said approximately AU$ 16.3 billion – or 84% of the total AU$ 19.4 billion – had been invested with Australian firms since 1 January 2010. Queensland firms had received 68%, or AU$ 13.2 billion of the total. The report covers 1 April to 30 September 2013.

The number of training courses for staff and contractors had also increased to 36 100, with a focus on safety skills. QGC Managing Director, Derek Fisher, said: “Training people to work safely and efficiently is a priority as we ramp up construction ready for first LNG in 2014. Work to prepare our teams who will maintain and operate QCLNG is already underway.”

The report also showed 259 Aboriginal and Torres Strait Islanders were working with QGC and its major contractors, and 315 graduates, trainees, cadets and apprentices were employed.


Scan to visit the website

LNGNEWS


DIARY DATES

Canada

BASF and Pacific NorthWest LNG sign license agreement

BASF and Pacific NorthWest LNG have signed a license agreement on the use of BASF’s OASE® technology to

remove carbon dioxide and sulfur containing components from natural gas for all trains of the Pacific NorthWest LNG’s proposed LNG facility in British Columbia, Canada.

The proposed facility expects to begin shipping gas to customers by the end of 2018.

Andreas Northemann, Head of the Global Gas Treatment business in BASF’s Intermediates division, commented: “We are pleased to work together with Pacific NorthWest LNG to provide the optimum solution for their facility. This cooperation is another milestone in enhancing and building on our long-term presence in Canada.”

Front-end engineering and design (FEED) for the LNG facility is currently ongoing with three international engineering contractors. The FEED is expected to be complete and in time for a Final Investment Decision by the end of 2014.

19 - 22 January 2014International Petroleum Technology ConferenceDoha, Qatarwww.iptcnet.org/2014/doha

03 - 06 March 2014LNG Global Congress Asia Pacific 2014Singaporewww.lnggc-asia.com

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05 - 08 MayOffshore Technology ConferenceHouston, Texas, USAwww.otcnet.org/2014

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France

GAIL’s Tripathi, GTT and CNOOC scoop awards

Gail (India) Ltd Chairman and Managing Director, Shri B. C. Tripathi, has been awarded the

prestigious ‘LNG Executive of 2013’ award at CWC’s 14th World LNG Summit held in Paris, France, from 18 – 21 November 2013. Shri Tripathi was recognised for his outstanding contribution to the development of the global LNG industry and in recognition of his leadership skills that have steered GAIL forward.

Other winners on the night included Gaztransport & Technigaz (GTT), who received the ‘LNG Technological Innovation Award 2013’ for its work on the development of its membrane containment systems to reduce the daily boil-off in LNG carrier tanks.

The ‘LNG Award for Outstanding Contribution 2013’ was awarded to CNOOC Ltd, the largest offshore oil and gas producer in China. The company is rapidly evolving into a world-class international integrated group of energy-related companies.

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AfricAn LnG:



G as production in Africa is currently estimated at 216 billion m3/y, 6% of total global supply. However, with a current gas per capital demand of 119 m3/y, Africa also has the lowest consumption rate of all continents; seven times less than the Middle East, and fourteen times

less than North America. Total domestic consumption is estimated at just 56% of supply, and with projections from BP expecting these ratios to be sustained over the next 20 years, exports will play a vital role in the future of the African gas industry. This is even more acute for West African producers where production to consumption ratios average 30 – 40%.

Fortunately, strong growth is expected in demand where a combination of a rapidly modernising Asia and carbon-cutting West are projected to increase global gas consumption by 46% over the next 20 years. Some 100 billion m3 of gas was exported by Africa in 2012, of which 45% was by pipeline

born again?born again?


(typically in the north from Algeria and Libya) and 55% via LNG facilities. Piped gas predominantly supplies Europe where forecast gas demand growth is relatively stunted at a projected 18% over the next 20 years. More recently, European gas demand has been impacted by imports of coal from the US as American power generators switch to using low cost shale gas, releasing large amounts of unwanted coal into world markets.

However, 41% of current LNG exports went to Asia in 2012, where gas demand is expected to grow by a far greater 107% over the same period. It is clear from this that the flexibility of destination offered by LNG technology could well be a critical factor in the future of gas developments throughout Africa.

A brief overviewAfrica is known as the birthplace of commercial LNG: the world’s first export facility opened at Arzew, Algeria in 1964, a 1.1 million tpy facility built by Technip for Sonatrach. During the following decades numerous other facilities were brought onstream throughout Africa, such as the 2.9 million tpy Skikda development in 1971 (also Algeria), Marsa El Brega in Libya (also in 1971), and NLNG in Nigeria in 1989. Today, African capacity equals 73 million tpy, with additional facilities in Egypt (Damietta) and Bioko Island off Equatorial Guinea. However, with African LNG exports estimated at 54 million tpy in 2012, it appears that liquefaction terminals are being under-utilised, especially in relation to Algeria and Egypt’s export capabilities. Algeria has an export capacity of almost 30 million tpy, but its exports fall short by almost 15 million tpy, while Egypt’s export levels fall short by more than 7 million tpy. Whilst utilisation shortfalls in northern terminals can be partially explained by the 4% drop in gas demand registered in Europe between 2010 – 2012, this represents one of a number of challenges facing the African LNG industry.

However, substantial new investment is expected. Over the next five years Douglas-Westwood expects US$ 15.6 billion of expenditure on LNG facilities in Africa, an increase of 30% over the previous five years and 10% of the global total. Major projects contributing to this spend include the Bioko Island expansion expected onstream in 2017, Cameroon’s inaugral LNG development by GDF Suez and the highly anticipated Brass LNG facility in Nigeria, expected onstream in 2017.

Shifting focusBeyond 2017, LNG expenditure in Africa is expected to undergo a geographical refocus. Traditionally, North and West Africa have been at the frontiers of gas production in the region, contributing to more than 90% of regional output. However, recent discoveries in East Africa, specifically in Mozambique and Tanzania, are shifting the focus of the global exploration and production (E&P) industry. Discoveries in these two countries have been estimated to total more than 3 trillion m3 of natural gas reserves, 20% of Africa’s total current reserve base, potentially transforming these countries into major global gas hubs. Despite the relatively recent nature of these discoveries and the lack of local E&P infrastructure, a number of LNG developments are already being discussed. In Mozambique, Anadarko’s two-train Alfungi development with an export capacity of 10 million tpy, coupled with ENI’s Mamba 10 million tpy facility, are currently under evaluation and are expected onstream between 2018 – 2020. However,

before Mozambique can reap the monetary benefits of its abundant resources, more than US$ 40 billion of investment is required to develop the country’s natural gas infrastructure and, to date, it remains unclear as to which companies or countries will assist in building these terminals. In Tanzania, together with upstream operators Statoil and ExxonMobil, BG Group has proposed the country’s first 6.6 million tpy train development, with plans to see first exports post-2020.

ObstaclesHowever, there are a number of major obstacles that must first be overcome in order for these ambitious multi-million dollar plans to come to fruition. Firstly, local content and taxation policies, whilst aiming to distribute oil and gas wealth amongst the host nation’s citizens, in many instances are threatening the commercial viability of some of these Capex-intensive developments. In Mozambique, sales by foreign companies of domestic assets will be taxed at a fixed rate of 32% starting in 2014, whilst in Nigeria the introduction of the proposed Petroleum Industry Bill (PIB) in late 2013 or 2014 will boost the government’s share of oil and gas revenue to 73% (up on the current 61%). In particular, this latter proposal has drawn criticism from E&P companies who claim the new terms could see Nigerian output fall by 25% over the next five years. Early jitters over the impact of the PIB could explain recent actions by ConocoPhillips, who recently appeared to sell its 17% stake in the Nigerian Brass LNG development as part of a wider deal, only to subsequently retain it whilst divesting the rest of its holdings in the country to Oando Energy Resources for US$ 1.8 billion in late 2012.

Brass LNG has also been subject to numerous delays on Final Investment Decision (FID). Whilst no real reasons for the multiple deferrals have been offered, it is reminiscent of the commissioning delays that plagued Chevron’s Angola LNG development, with first gas deliveries in June 2013 after 18 months of delays due to local labour shortages, amongst other things.

In addition to taxation and local content, geopolitical instability has also shaken confidence in the world’s oldest LNG export market. Political upheaval and revolution in Egypt and Algeria have seen their LNG exports fall dramatically since 2010 when they accounted for a combined 25% of African exports, compared to just 12% today.

External commercial conditions are also threatening to impact this market. Rapidly increasing supply from the US and Australia will compete with African gas, particularly in the attractive consumer markets of North Asia. Combined export expenditure for North America and Australia will dwarf Africa with US$ 108 billion of anticipated investment – 75% of the global total over the next five years. The emergence of technology to extract once commercially unrecoverable shale reserves in North America has been a major concern for other regional exporters.

Today, new technology to crack deep sea methane hydrate reserves off Japan could, in the long-term, threaten the US gas export party, as Japan currently accounts for more than a third of total global imports.

ConclusionMany questions loom over the future of the African LNG industry, making cooperation and communications between sovereign governments, their customers, and the international oil and gas companies, more important now than ever.


A t US$ 10 billion, the Angola LNG project, built to create value from offshore gas resources, is one of

the largest ever single investments in the Angolan oil and gas industry.

Angola LNG’s vision is to be a reliable and competitive supplier, a strong community partner and a role model for development in Angola.

The project’s first cargo was produced, shipped and safely delivered earlier this year. Commenting on this, António Órfão, Chairman, Angola LNG Ltd said: “It was with great pride that we announced our first cargo. A result of lots of hard work from teams across the project, this event marked a major milestone in our history, added Angola to the list of LNG supply countries (the first since 2010) and helped move us closer towards achieving our vision.”

Project overviewThe project is the result of a partnership between Sonangol, Chevron, BP, ENI and Total to gather and process gas, and sell and deliver up to 5.2 million tpy of LNG to the global market.

Offering a dedicated fleet of seven LNG vessels and three loading jetties (LNG, liquids and compressed butane), the project’s mission is to minimise the flaring of gas, provide clean and reliable energy to customers, and maximise return on investment for shareholders. Angola LNG has built one of the world’s most modern LNG processing facilities, located 350 km north of Luanda in Soyo, at the mouth of the Congo River. This landmark project for Angola is unique compared to other global LNG projects, as the plant will initially be supplied with associated gas produced during oilfield operations. This will significantly contribute to the elimination of gas

flaring in the country, allowing for the development of offshore oil reserves in an environmentally sustainable manner.

Operations at Angola LNGAn extensive pipeline network of over 500 km delivers gas from offshore oilfields to the processing and liquefaction plant at Soyo. The Soyo plant is designed to process 1.1 billion ft3/d of natural gas with the capacity

A new player

Figure 1. Angola LNG unloading its first cargo from the SS Sonangol Sambizanga at Petrobras’ LNG receiving terminal in Guanabara Bay, Rio de Janeiro, Brazil.

Artur Pereira, Angola LNG Marketing Ltd, UK, provides an overview of the Angola LNG project.


to produce 5.2 million tpy of LNG – plus natural gas, propane, butane and condensate. The plant represents an important step in the efficient use of Angola’s natural resources, and boasts a workforce that is now equipped with expertise in every facet of LNG production, from plant construction and commissioning operations to logistics.

The production process is designed around a ‘two-train-in-one’ reliability concept that allows the plant to continue operating at a reduced rate even when a compressor is offline, resulting in high plant availability.

Plant infrastructure includes storage tanks for LNG, LPG and condensate, and an LNG loading jetty able to accommodate LNG vessels up to 210 m in length. The plant will also supply gas to the Angolan market to help meet local demand.

Seamless deliveryAngola LNG Marketing Ltd was created last year to conduct global LNG marketing and sales operations on behalf of the Angola LNG project. Based in London, UK, it is responsible for developing Angola LNG’s marketing strategy, negotiating sales agreements with buyers and managing a dedicated fleet of vessels that will ship LNG for delivery to customers around the world.

Angola LNG’s key priority is for safe and reliable production and delivery of cargoes to its customers. The company is entering the market at an exciting time – the world LNG market is expected to remain tight over the coming years, with very limited new LNG capacity coming on-stream.

Global LNG demand remains centred on Asia, with the majority of LNG imports and the greatest growth continuing to come from this region. Latin America and Europe are also key target import markets.

The company has already executed a number of master sale and purchase agreements and further agreements are being negotiated.

A fleet of seven 160 000 m3 LNG vessels have been chartered on a long-term basis to transport Angola LNG cargoes to customers around the world. At full production, more than

Figure 2. The Angola LNG plant in Soyo, Angola.

Figure 3. Operations at the LNG plant in Soyo, Angola.

Figure 4. Angola LNG is supporting the conservation of the Palanca Negra Gigante – a critically endangered species native to Malange in Angola.

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70 LNG cargoes will be delivered globally from Angola every year.

Social responsibilityCentral to Angola LNG’s mission is to contribute to the social and economic development of Angola. The project has invested significant resources into the local community. In addition to promoting the use of local companies and providing training and local jobs during the construction and operation phases, Angola LNG has contributed greatly to the growth and development of Soyo.

Two key projects include the renovation and expansion of the Soyo municipal hospital to improve the health of the community, and refurbishment and expansion of the Bairro da Marinha School to develop a more highly educated population.

Transparency and community liaison are hallmarks of the project. Angola LNG has run hundreds of meetings and workshops in Luanda and Soyo to provide information about the project and to seek the views of the government, local people and other interested parties. The establishment of an information centre in Soyo has ensured that the community has the ability to remain informed during all stages of the project.

Additionally, Angola LNG is committed to conservation of biodiversity, and has set up a turtle management programme to protect Olive Ridley sea turtles that migrate to the northern beach of Kwanda Island each year.

The programme monitors and protects threatened nests and hatchlings to ensure the continued preservation of this species. The company is also involved in the protection of the Giant Sable Antelope (Palanca Negra Gigante), a critically endangered species and native to the province of Malanje in Angola.

Angola LNG’s peopleAngola LNG is committed to achieving operational excellence and industry leading performance standards whilst simultaneously promoting career opportunities for Angolans.

People are at the core of Angola LNG’s business, be they customers, employees, contractors, host communities, suppliers or shareholders. As a result, there is a culture of respect, support and encouragement throughout the organisation.

ConclusionAngola LNG has safely and reliably sold and delivered cargoes to reputable buyers in different regions around the world, and continues with its commissioning and testing of all facilities as part of its ramp-up to full production.

Strategically very important for Angola’s oil and gas industry, the project contributes to reducing gas flaring while maximising oil production, and will contribute to the economic development of the country.

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W ith the LNG industry continuing to grow its share in the global energy market, Africa is set to play an increasingly important role. Not only are existing LNG projects in the region going from strength to strength, but major new discoveries in East Africa promise to further boost

the market and create a host of job opportunities.According to the International Gas Union’s ‘World LNG Report 2013’,1 some 26 new LNG projects were

in the pipeline across the world at the end of 2012, with a number of new sources set to come on stream in the medium-term in regions including Africa.

Angola LNG is one of the most recent additions to the global LNG market and its first cargo was shipped in June. Angola LNG, whose shareholders are Sonangol, Chevron, Total, BP and ENI, is the first LNG project in Angola and one of the largest on the African continent.

Ford Garrard, NES Global Talent, UK, explains how Africa’s role in the LNG market is becoming increasingly significant.


The US$ 10 billion Angola LNG project will collect and transport natural gas from offshore Angola to an onshore liquefaction plant in Soyo, on the coast near the Congo River. The plant has the capacity to produce 5.2 million tpy of LNG, plus propane, butane and condensate, and at full production it is expected that over 70 cargoes will be shipped annually.

The Equatorial Guinea LNG (EG LNG) project is also progressing well. EG LNG, whose shareholders are Marathon Oil, Sonagas, Mitsui and Marubeni, delivered its first LNG cargo in 2007, and has plans to expand into a regional gas processing hub.

The success of both the Angola LNG and EG LNG projects is indicative of things to come in other countries across the African continent.

New frontierAll eyes are currently on East Africa as a new LNG frontier. Although oil and gas exploration has been ongoing in the region for a long time, until more recently there has been limited success due to doubts over the amount of recoverable resources, as well as the regional and civil unrest that deterred foreign companies and, to some extent, investment.

However, following sizeable discoveries in a number of countries including Mozambique and Tanzania, East Africa looks set to drive growth in the African natural gas sector and give a welcome boost to the global LNG market. According to the US Energy Information Administration (EIA) brief, ‘Emerging East Africa Energy’,2 Mozambique is expected to be the first country in the region to develop the capacity to export LNG, possibly followed by Tanzania.

Mozambique has large onshore and offshore basins. According to information quoted by the EIA, it has four proved gas fields – Pande, Buzi, Temane and Inhassoro – all located onshore in the Mozambique basin. At the start of this year, total proved natural gas reserves in Mozambique were 4.5 trillion ft3.

Since 2010, there have been a series of natural gas discoveries in Mozambique in the offshore Rovuma basin that are large enough to support LNG projects, according to the EIA. Anadarko has stated it expects to start selling LNG in the country in 2018, with production reaching full capacity by 2030 – 2032. So significant are the discoveries in Mozambique that, according to Ernst & Young’s report ‘Natural Gas in Africa –The Frontiers of the Golden Age’,3 the recent discoveries by Anadarko and ENI could hold as much potential value as 30 – 40 times the current GDP of the country.

Similarly, Tanzania, which had 230 million ft3 of proved natural gas reserves at the start of this year, also shows great potential. According to the EIA, while the Songo Songo gas field is currently the only fully producing gas field in the country, this could change in the near future if production at the Mnazi Bay Concession begins as expected.

The existing Songo Songo field is expected to grow, with operator Orca Exploration stating that production can be expanded following sizeable discoveries in the northern

part of the field. The west section of the field is also set to be explored.

According to the EIA, one of the wells in the Mnazi Bay Concession, which is located in the Rovuma basin and contains two gas fields, Mnazi Bay and Msimbati, is already producing gas at a rate of 1.7 – 2 ft3/d.2 Full gas production is expected to begin once the planned 331 mile Mnazi Bay to Dar es Salaam gas pipeline is constructed.

However, although recent discoveries have strengthened both Mozambique and Tanzania’s potential to become LNG exporters, a great deal needs to be done to improve infrastructure in both countries to make this a reality. Some analysts have also predicted that there may be an oversupply in LNG at some point in the future. The EIA states that success will depend on a number of factors including the shale gas boom in North America and China, the growth in liquefaction capacity in regions such as North America, Australia and the Middle East, regional demand, and the growth in the use of LNG in the transport sector.

Skills shortageAlthough the exact scale of East Africa’s success as an LNG exporter is yet to be seen, the increase in LNG activity in this region and across the whole of the African continent is significant, and is sure to give a welcome boost to the economy. However, it also comes at a time when the oil and gas industry is facing a global skills shortage.

With more than half of experienced engineers eligible to retire during the next five to ten years, and too few suitable skilled professionals coming through to replace them, the war for talent is intensifying, and it is difficult to find enough suitably experienced engineers to go around.

While there is no quick fix to addressing the skills shortage in Africa, the oil and gas industry is working hard to attract the people it needs at a global level. The sector is focused on creating more apprenticeships by working with educational establishments and institutions to educate the younger generation about the wide-ranging careers available working as an oil and gas engineer, and emphasising the importance of the STEM subjects (science, technology, engineering and mathematics), as well as recruiting from other manufacturing and heavy industries, utilising ex-service personnel leaving the military and tackling stringent immigration policies.

Operators are also working hard to ensure skills are passed down from senior employees to the next generation of engineers and that knowledge and skills are transferred across geographic and cultural boundaries. Skills and knowledge transfer programmes are a key tool in helping the industry ensure it has the appropriately trained people it needs to ‘keep the lights on’. Many major oil and gas producing regions, including Africa, have introduced local content requirements into their regulatory framework to create jobs for nationals, develop skills, and promote technology transfer. Companies also recognise the importance of reducing the high cost of maintaining an international workforce by recruiting local talent.

Skills transferHowever, while the African talent pool is deepening, there are certain skills that are simply not readily available in the local market, which is where expatriates can play an important part in transferring skills to the local workforce. Having said that, with African LNG projects competing with other high profile global LNG projects in attractive locations such as Western Australia, and only so many experienced engineers to go around, this in itself can be challenging.

Sophisticated employee retention strategies, including attractive benefits packages, are another consideration for the industry, but again, they come at a price. Thankfully, oil and gas can afford to make that investment in order to reap the rewards of being one of the most desirable industries in the world to work in.

In challenging locations, such as Africa, it is vital that people feel safe and secure. NES Global Talent attends the same training as its contractors to ensure that it fully understands the necessary safety and security requirements. The company even parkates in high risk territory training and replicating hostage taking situations. Its in-house security experts and security partners ensure that it is up to speed with the latest developments around the world, keeping any potential risks to a minimum and giving its candidates and their families the support they need when operating in challenging locations.

In order to make the most of Africa’s huge LNG potential, energy companies need to be able to boost the home-grown workforce by taking on the best people from around the world. If the industry can overcome the talent shortage, the future looks bright.

References1. ‘World LNG Report’, 2013 Edition,

International Gas Union, http://www.igu.org/gas-knowhow/publications/igu-publications/IGU_world_LNG_report_2013.pdf

2. ‘Emerging East Africa Energy’, Energy Information Administration, http://www.eia.gov/countries/analysisbriefs/East_Africa/eeae.pdf

3. ‘Natural Gas in Africa - The Frontiers of the Golden Age’, Ernst & Young, http://www.ey.com/Publication/vwLUAssets/Natural_gas_in_Africa_frontier_of_the_Golden_Age/$FILE/Natural_Gas%20in_Africa.pdf

Bibliography• Chevron’s Angola LNG press release,

http://www.chevron.com/chevron/pressreleases/article/06162013_chevronconfirmsfirstcargofromangolalng.news

• Angola LNG press release, http://www.angolalng.com/Project/FirstAngolaLNGCargoDelivered.htm

• EG LNG website, http://www.eglng.com/

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LNG BOOMFigure 1. Queensland’s LNG industry is expected to employ

over 30 000 people during construction.

Preparing

Queensland

for the


Australia is set to become the world’s leading producer of LNG in the next decade. Major capital projects in unconventional gas on the country’s east coast are contributing to this growth trajectory, accessing Queensland’s abundant reserves

of coal seam gas (or coal bed methane). In a world first, Queensland will produce LNG from coal seam gas (CSG), with three of five major LNG developments well into the construction phase and gearing up for first shipment from 2014.

The Competency Assurance and Training team at LogiCamms, an engineering and consulting services company in Australia and New Zealand, is currently working with a number of these large start-ups. In this article the company shares its solutions for workforce development in the LNG industry.

The QGC (wholly owned by BG Group) Queensland Curtis LNG (QCLNG) project is expected to be the first facility to produce gas. Situated on Curtis Island in Gladstone, the plant will have an initial capacity of 8.5 million tpy with the potential to increase production to 12 million tpy.

Santos is leading a joint venture of Petronas, Total and Kogas on the Gladstone LNG (GLNG) project. Also based on Curtis Island, this plant will have an initial capacity of 3.9 million tpy, with the potential to increase to 10 million tpy, and will receive gas from Santos’ gas fields in the Bowen and Surat basins.

Bhavna Patel, LogiCamms, Australia, reveals why a behavioural change is required to plan for effective training of all personnel.


The third project well into construction is the Australia Pacific LNG project (APLNG), a joint venture between Origin Energy, ConocoPhillips and Sinopec. With the largest potential production capacity at 18 million tpy, the first LNG cargo from this facility is scheduled for 2015.

A further two projects, the Arrow Energy LNG project and LNG Ltd’s Gladstone LNG Fisherman’s Landing project are still in the initial planning stages.

Together, these projects are expected to generate over US$ 45 billion in capital expenditure and produce over 28 million tpy of LNG. With all projects having the potential to increase production levels to over 60 million tpy, it is expected that the Queensland LNG boom will help lift Australia from the third largest exporter of LNG to the first.

Queensland’s skills shortageOne of the biggest challenges for Queensland’s LNG players is the recruitment and retention of skilled employees. Due to the infancy of the LNG industry within Australia and the volume of projects currently being undertaken around the nation and worldwide, Australia has found itself in the midst of a skills shortage.

Recent economic studies indicate that even a midsize LNG industry such as Queensland’s will employ over 30 000 people during construction and operation. As the state’s total population stands at 4.5 million and an established skilled labour market is lacking, this emerging industry is faced with a long term resourcing challenge.

State government agency, Energy Skills Queensland, produced a 2013 ‘Skills and Workforce Development Report’, which confirms an immediate expected increase in operations and maintenance roles for CSG and LNG. Critical job roles identified for downstream operation included various trade roles, engineers, high level operators and project managers. The report also identifies 17 critical upstream roles. The fact that these roles are considered critical for both upstream and downstream indicates the focus required for workforce development.

People at the core of operational readinessWith any new project, large or small, operational readiness is key to achieving return and should focus on people, plant and procedures; establishing systems and lifecycle plans that enable the equipment to continue to meet its designed operating performance within a known budget. LogiCamms’ Asset Performance team has witnessed projects that too often look to make cost savings during the construction phase, and do not fully consider the multiple decades that the facility will need to be operational. This results in millions of dollars being wasted and, in some cases, the return on the project never achieved.

Operations often focus on ensuring that the right equipment is purchased with the appropriate specifications and installed to the best standards. Whilst all of this is important, the training and development of the people who will be expected to keep the operation and its equipment performing to its best is crucial. With a complete understanding of how a project is to operate, effective recruitment practices can be employed with structured training plans and training that is tailored to the specific operation to support success for the life of the project.

Appropriately chosen and trained personnel underpin the success of the assets through their lifecycle, from operational readiness to asset integrity and operational excellence.

Identifying the skills gap Whether working with a largely unskilled workforce, as in Queensland, or recruiting experienced staff, understanding of the operational direction and goals will enable effective planning of workforce requirements.

Task needs analysis processAn analysis of the tasks required of personnel and roles will set the foundations for recruitment and training. An analysis should clearly identify the knowledge, skills and behaviours that are required to carry out tasks safely, efficiently and to operational standards.

Recruitment strategy and training burdenPreviously, individuals with non-industry experience have faced a great challenge finding an entry point to the LNG industry in Australia. So far, recruitment in Queensland’s LNG industry has indicated that companies are accepting staff from both industry and non-industry backgrounds to fill key roles. Previous experience may be loosely related, such as plant refineries, or completely unrelated, such as butchery.

With such varied skills, the burden on training will be high. As such, a carefully executed training strategy is paramount to make the activity as effective and efficient as possible.

Training strategyIn developing a training strategy, managers will be required to make decisions on how they wish to execute, for example, putting all staff through mandatory training to establish a baseline of knowledge and skills. Beyond this, the initial training considerations on how the skills will be applied need to be made. With plants still under construction and not yet operational there is clearly no place to practice.

Training strategies will need to take into consideration the specifications and manufacturer guidelines of the plant’s equipment, as well as industry standards. For Queensland operations, this will be the Australian Quality and Training Framework (AQTF). LNG operations can leverage these baseline standards to develop something tailored to their operations.

The actual training for these new projects is likely to be theoretical during the construction phase, with comprehensive on-the-job training tools to ensure that personnel are supported both post-commissioning and for the life of the project. This is already being seen in the Queensland projects.

The training strategy put together for these types of operations ought to look even beyond the lifecycle of the project. With so much invested in training personnel, they are now an asset to the company.

Developing a local workforceOver the mining boom years, Australia saw a massive increase in the number of people ‘flying in and flying out’ of remote mining operations, and subsequently of salaries in the sector. This was partly as a result of companies recruiting skilled and experienced labourers over training local

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personnel. With individuals ‘job hopping’ from one operation to the next for higher salaries (and being in a position to demand them), there came to be the expectation of high salaries in the sector by both the Australian and international labour market when seeking employment with Australian operations.

Companies with large/predominant ‘fly-in, fly-out’ workforces have faced criticism, but the argument is that the skills do not exist locally. In response, state governments and local councils often encourage companies to invest in the training and development of the local workforce for the sustainability of the local community and economy.

Problems arise when the numbers of potential staff in the regional areas, where many of these projects are based, are much lower than the number of available positions. It is a challenge to encourage suitable staff to move to these remote locations to take up long-term residence and employment.

LNG operations in Gladstone can benefit from the fact that it is a coastal town, with lots of infrastructure development in planning and implementation phases. It has the potential to comfortably attract individuals/families for relocation for long-term employment and residence.

BenefitsThere are a number of benefits that can be secured by employing locally, including the following:

� Cost savings: � Not having to set up large camp facilities. � Fewer flights and allowance payments.

� Retention: � Increased retention of staff with people wanting to live in the area and work close to home for better work/life balance.

� International portfolio/presence: � With Gladstone set to be the largest international LNG port in Australia, it will see an influx of internationals through export. There is the potential to attract internationals to Gladstone by offering training and development, in turn developing educational capabilities, and attracting other professions to the region.

� Reputation: � Recruiting locally is great for building public relations within local communities.

Looking to the futureIt has been observed in many existing operations around the world that training is still not enough of a proactive and planned occurrence – it is often reactive to a problem arising rather than a proactive phenomenon.

In the US, there are currently 17 proposal submissions for the export of natural gas, with the first shipments of gas (to be exported as LNG) scheduled for 2015. In a wholesale redisposition, the US will shift from a predominantly importing, to an exporting hub. This will require a massive development of skills in LNG processing.

A behavioural change is required to plan for effective training of all personnel in a planned and structured manner to deliver high performance operations in a sustainable way. These training trends will need to change fast for the US to develop the skill sets for operational readiness, if the proposals are approved.

With gas booming all over the world, and government and local requirements applying more pressure and regulations around the development of local workforces, companies now have to demonstrate how they plan to work within these requirements to set up operations in the area. Many local governments are wisely insisting that there is a maximum possible usage of nationals in any new operations, to ensure the country’s future capability and overall economic development.

The current development in Queensland makes an ideal test case. The international players currently setting up operations can apply the learning from developing locals with varied levels of skill to these new environments. In this instance, adaptation will certainly be easier than creation.

Bibliography1. ‘CSG-LNG Projects in Queensland’, Queensland government,

June 2012, http://www.industry.qld.gov.au/lng/projects-queensland.html

2. ‘Skills and Workforce Development Report 2013’, Energy Skills Queensland, August 2013, http://www.energyskillsqld.com.au/

3. ‘Queensland LNG industry employs 30,000 people’, Australian Mining, June 2013, http://www.miningaustralia.com.au/news/queensland-lng-industry-employs-30-000-people

4. ‘US to begin exporting “fracked” gas’, BBC News, July 2013, http://www.bbc.co.uk/news/science-environment-23317370

Figure 2. Gladstone has the benefit of being a coastal town, offering a more attractive lifestyle for long-term employment and residence.

Figure 3. LogiCamms is training a number of local electricians in high voltage for the QCLNG project.

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Dave Coppin, AVEVA, UK, explains how video game technology is transforming operator training in LNG plants.

Playing it

safePlaying it

safe


LNG has a unique set of safety challenges: although LNG is not flammable as long as it remains liquefied, since it is odourless and colourless, and atmosphere concentrations

of 5% are sufficient to be explosive, any leaks are potentially lethal and hugely expensive. As a result – though LNG tankers have sailed over 100 million miles without accident – this maturing industry must continue to ensure that all personnel understand proper operational procedures.

The nature of LNG agreements is an additional pressure on the need to mitigate against the risk of unplanned downtime. Whereas conventional oil and gas players follow an open market supply and demand model, the LNG industry to date has focused on developing long-term supply agreements with the downstream market. Therefore, any downtime in LNG production has a direct and real-time impact on contractual obligations.


The economic ramifications of downtime are also amplified by a market that already has high total ownership costs. In its report ‘The World LNG Market Forecast 2013 – 2017’, Douglas-Westwood predicted strong growth for the next five years and identified an upwards trend in capital expenditure totalling US$ 228 billion by 2017.1 In consequence, the need to maintain operational best practices and foster employee excellence without the associated potential risks will only become more pressing. Other industries have long caught on to a solution that has yet to be fully leveraged by the LNG industry: virtual reality simulation.

Gaming comes of ageVirtual reality (VR) technology that was developed in the entertainment world can now be used for LNG applications. Thanks to advances in gaming technology, and with detailed 3D modelling at its core, it has become practical, affordable, and quick to create a fully navigable, ‘hyper-real’ equivalent of a facility or ship, whether already operational or yet to be constructed.

Gaming, with its commercial potential, has come a long way since the 2D platform games of the 1980s; the fact that the release of a new title made £1 billion in three days is testament to the sector’s vast expansion, which has entered a period of democratisation and diversification with exciting ramifications for industry.

The change is partly due to the fact that the sophisticated graphics and complex physics engines that lend the games their realism can now run on entry-level hardware and multiple platforms. Meanwhile, increased internet speeds and bandwidth have also seen massive multi-player online games (MMOG) explode in numbers, with every player’s actions updating in real-time worldwide and with audio links to further enhance the

live-action gameplay. The market conditions are right for a new genre to emerge: industrial gaming.

This might sound interesting, but what are the business justifications for the creation of an industrial ‘virtual world’ for the LNG market? Why would an owner/operator want to invest in industrial gaming? At the lowest level, the objectives of gaming for entertainment and those of industrial gaming are relatively similar: practice makes perfect.

Dr Michael Platt, a specialist in human behaviour at Lockheed Martin, has said that people should not be trained until they get it right, they must be trained until they do not get it wrong. Similarly, gamers are only allowed to progress when they no longer make errors, trying repeatedly until they get it right.

Central to the application of industrial gaming for the LNG sector is a desire to create and maintain skills and understanding in all site personnel through familiarisation and repeated practice. Human error is widely recognised as the number one cause of safety incidents, and the enhanced skills gained through repeated practice could not only aid productivity, but could also serve to eradicate human error from operations.

This is all the more important for a sector undergoing radical change. Whilst Europe – whose gas prices are still tethered to oil prices – has increased its consumption of coal, the US is focusing on gas. Mexico, meanwhile, is investing in a number of gas pipeline projects to bring US gas across the border to feed its burgeoning manufacturing sector. With gas looking increasingly attractive, new-builds and retrofits are now LNG-enabled. But are personnel ready for the challenge?

A new approach to trainingThe ability, not just to understand information, but also to retain it, is critical to ensuring safety in high-risk environments, and a ‘trial-and-error’ approach to learning significantly improves retention. It utilises self-educating techniques where individuals evaluate the feedback resulting from actions to improve performance.

However, in the LNG industry, allowing trainees to ‘learn by doing’ in a live environment might be costly, disruptive to production and potentially hazardous to the individual or the facility, and the consequences of a mistake can be catastrophic.

Never has the need for improved training in all aspects of LNG operations been more important. Currently, there is a lack of experienced engineers, and with more complex and automated assets, this introduces new risks into safe and effective operations. This is where virtual reality comes in. Using industrial 3D gaming technology to supplement physical on-the-job training can both greatly increase operator effectiveness at zero risk and optimise the cost of training.

In a report entitled ‘Why Simulation Games Work’, authors Hoftstede, de Caluwe and Peters note that in many cases industrial gaming can help make the information more relevant and easier to understand, which is critical for HSE and high-risk activity training where full comprehension and retention of safety information are paramount.2

Similarly, in a study conducted by New South Wales Mines Rescue Service, it was identified that traditional classroom training (including demonstrations and video presentations) led, at best, to a 50% retention performance.3 Simulator-based training, where trainees performed actions themselves, lifted that retention level to 75%.

But this perspective is not new; the LNG industry is playing catch-up. The development of flight simulators has contributed enormously to improving air safety by enabling crew to learn and practise their skills in perfect safety.

Figure 2. In addition to mimicking the exact layout of a facility, industrial gaming environments can even reflect different environmental conditions (daytime, night-time, fog/smoke etc.) for maximum realism.

Figure 1. Virtual reality – people need operational experience to be able to work to the very high standards of safety required.

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Like flight simulators, virtual reality will only be useful if it accurately mirrors the real life conditions of the asset in which the employee is going to be operating. AVEVA’s Activity Visualisation Platform™ (AVEVA AVP™) simulations are created directly from the asset’s 3D digital information hub, which allows employees to run through routine inspections to complex maintenance decisions in an immersive 3D environment. It is a new way to test and consolidate learning before the employee is introduced into a much higher risk environment.

Within a virtual reality environment, trainees can be provided with full on-screen details to follow when introduced to the training programme, and the advice can then be steadily reduced to hints and finally to ‘no-help’ test modes to ensure complete comprehension of a process. The ability to make mistakes and repeat a course programme with no safety or cost consequences ensures that the different learning and retention speeds of each employee can be accommodated easily through self-paced learning.

While advanced visual simulation technology enhances data assimilation, AVEVA AVP™ supports this process with in-app web-browser access. The functionality of the web browser is twofold: firstly, the in-app web browser allows access to reference data so that when trainees require an extra piece of information they do not need to leave the application in order to access it. For example, they could view PDF data sheets from an OEM’s website. The second key advantage lies in the possibilities posed by a constantly updating live stream of data. Real-time SCADA information, shown in the game, could allow the gamer to respond to the status of the physical

plant itself. The presence of the web browser adds another potential layer of engagement for users of the software, and another way of enhancing safety through operator familiarity.

Increased safety, increased complianceMany of the recent investigations into incidents in the LNG industry have highlighted a level of commonality as to probable causes. These include:

� Limited awareness of operating procedures.

� Improper identification of safety hazards and hazardous processes.

� Inadequate inspection.

� Inadequately trained workers.

The first step towards a safer workforce is ensuring that, before entering the facility, all site personnel are fully familiar with the environment in which they are working. Many new recruits (even engineering graduates) will not have an understanding of full scale operations and may not even be able to identify some of the hazardous operational areas of an LNG facility. To compound the problem, the facilities themselves are often remote, difficult to reach, infrequently accessed, and sometimes even unmanned.

In such circumstances, there may be no supervisor or safety professional present to review the site for hazards and instruct remote workers or new site visitors in avoidance. Using an immersive environment built from the 3D model of the asset, workers can prepare fully for a site visit by reviewing layout, hazardous locations, emergency egress routes, assembly areas, and the locations of the nearest safety stations such as eye-washes, showers and emergency call buttons.

Adding procedural training to the immersive environment also enables operators to educate new employees, remote workers, and all those on site, in site-specific emergency procedures, ensuring they respond appropriately in the event of an incident and do not unintentionally compound risk by failing to follow the defined process.

Findings published by the Politecnico di Milano Department of Materials and Chemical Engineering reveal that process sequences including start-ups/shut-downs, hot work, and lock-out/tag-out, as well as abnormal conditions (e.g. confined space entry), alarms, failures, and accidents are not easily replicable in a real LNG facility.4 The ability to create an immersive virtual environment with comprehensive step-by-step instructions and opportunities to repeatedly test comprehension and retention provides a far better option for ensuring safety.

It is true that improving the speed-to-proficiency in key areas such as safety, reliability and risk management prior to entering the field has productivity benefits for operators, but immersive training is not just for new employees; it is also important to ensure that bad working practices do not slip into regular activities. For example, one of the problems that caused the Texas City Refinery explosion was that operators relied on knowledge of past start-up experiences (passed down by the more skilled veteran operators) and developed informal work practices. The ability to train or evaluate operators at any time, in any location and as often as necessary, allows immersive simulation training to be a vital tool in refresher training for existing employees.

Figure 3. By enabling repeated practice of complex or high-risk activities, industrial gaming could serve to eradicate human error, the number one cause of operational safety incidents.

Figure 4. The usability and affordability of the technology means that specific application of visualisation technology to the LNG industry is limited only by the imagination of O&M and training departments.

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The forthcoming ISO 55000 regulations will ensure that safety training is a central Recognised And Generally Accepted Good Engineering Practice (RAGAGEP) pillar of operational readiness and Process Safety Management (PSM), whilst the US Occupational Safety and Health Administration (OSHA), in its regulation OSHA 1910.119(g)(1), indicates that topics covered by training should, as a minimum, include the following:

� Lock-out/tag-out.

� Hot work.

� Line and equipment opening.

� Confined space entry.

� Emergency response.

� Operating procedures.

Application to LNGThe increasing presence of intelligent 3D models in LNG engineering means that the process for creating specific virtual reality environments using industrial gaming such as AVEVA’s AVP™ can be straightforward and cost-effective. The usability and affordability of the technology means that specific application of the technology to the LNG industry is limited only by the imagination of O&M and training departments.

Outlined below are some of the simplest use cases: � Facility familiarisation – the orientation of personnel

new to a facility, including preparation for emergency procedures and evacuation response. Similarly, preparation for a change to the working environment is an intrinsic element of effective Management of Change (MoC).

� High-risk or complex activity training and rehearsal – where the risks of process failure carry significant consequences for individuals and for the facility’s operation, including: lock-out/tag-out, isolation of safety systems, pressure testing or work with dangerous materials, start-up/shut-down checks, hot work, line and equipment opening, confined space entry, fire simulation training, and other emergency responses.

� Refresher training for collaborative activities – enhancing or maintaining the safety and productivity of cross-functional teams required to collaborate, ensuring that bad practices do not appear and are not replicated.

� HSE compliance requirements – the advanced planning and rehearsal of toolbox meetings, HAZOP assessments prior to completion of construction, rehearsal of inspection line walk-downs, and testing understanding of equipment-level relationships.

In addition, there are a multitude of further applications to improve teamwork and increase productivity, including:

� Construction, operations and maintenance planning – testing the feasibility of planned works from construction through into O&M, simulating the processes involved in order to test new working methods and to conduct clash detection or hazard spotting.

� Remote problem solving – allowing remote teams to review and address construction or O&M challenges and

repeating model scenarios in a virtual environment to predetermine the optimum solution prior to arrival on site.

� Sign-off for certification and operational readiness – access need not be limited to internal teams. Commissioning and completions companies can now allow the certification authorities to undertake virtual plant walk-throughs. This will enable the certifying body to view punch-lists and compare against the design intent well before going to site, and will speed up the certification process.

� Complex ‘storytelling’ – create a sequence of individually driven, interactive, animated environments to demonstrate progress of a particular maintenance activity, or activities associated with field operations. Storytelling provides improved stakeholder comprehension, communication, speed and proficiency for completing planned and unplanned daily activities.

The application of advanced technology to enhance the safety of all field operations personnel is expected to increase significantly over the coming years. Clearly, there are many opportunities to make full use of existing asset information – including documentation, maintenance histories, 3D models and intelligent P&IDs – in the creation of sophisticated virtual reality environments and scenarios. But this is not merely a long-term vision: the use case exists today.

The forthcoming ISO 55000 standard outlines six different asset management subject groups, and details the requisite processes and capabilities required in each subject group. The application of immersive environment training supports processes and capabilities across all of the categories.

With renewed emphasis on the importance of safety, the LNG industry will be searching for ways in which operational best practices can be enhanced – especially as the ‘baby boomers’ retire, leaving younger engineers to hold the fort. Gen Y, the most technologically focused generation to date, will be able to absorb industry-specific information more easily if exploring unfamiliar information through an already familiar platform and learning techniques. Traditional learning by rote has all but disappeared from the modern day education system, meaning that for Gen Y, if new information is to be assimilated, a more effective approach is through visual and kinaesthetic learning, such as that offered via simulation environments.

References1. ‘The World LNG Market Forecast 2013 - 2017’,

Douglas-Westwood.

2. Hofstede, G., de Caluwe, J., and Peters, V., ‘Why Simulation Games Work – In Search of the Active Substance: A Synthesis’, Simulation Gaming, Vol. 41, No. 6, 2010.

3. Dowsett, B., Coal Services Pty Limited, New South Wales Mines Rescue Service: ‘Application of Virtual Reality Training for the Mining Industry – Training for Tomorrow’, Mechanical Engineering Seminar, 5 August 2009.

4. Findings published by the Politecnico di Milano source: Manca, D., Totaro, R., and Nazir, S. et al., ‘Virtual and Augmented Reality as Viable Tools to Train Industrial Operators’, Dipartimento di Chimica, Materiali e Ingegeria Chimica, Politecnico di Milano, 22nd European Symposium on Computer Aided Process Engineering – ESCAPE22, June 2012.


W ith the increased focus to implement LNG liquefaction facilities globally, and an increasing number of new projects coming online in the next

five years, a new generation of first time operations teams will be responsible for the management of multi-million dollar facilities. Each of these facilities, regardless of their location, will face the same problem of having adequately trained operators. From initial start-up to full training capacity, new operations teams will be required to bring up various sizes and types of plants safely. To make this process successful, many will be using operator training simulation (OTS) systems in preparation for start-up and will use these throughout the lifecycle of the facility to sustain optimal control and uptime of the LNG or terminal assets.

People learn more by seeing how something works rather than just reading about it. If interaction is added to a visual interface, improved results occur in almost every training

scenario. As such, process plant operator training through simulation is practiced throughout the industry.

Operator training is vital for a number of reasons. First and foremost is safety: training helps to reduce incidents and accidents. Training also improves process control, resulting in higher throughput and consistent quality with less downtime. Well trained operators can also have an impact on reducing maintenance by operating equipment closer to its original design specification.

As most of the projects are implemented on the coastline or offshore, compliance with regulations may also require some form of operator training in many instances. In general, the higher the potential environmental and safety impact, the more oversight involved from regulatory agencies.

In addition to direct operational costs, operator errors and subsequent incidences can result in fines, restricted operations or loss of capacity. These occurrences can be minimised or

Platt Beltz and Greg Hallauer, Yokogawa, USA,

discuss how simulation can improve operator

training in LNG operations.


eliminated with the right training plan and equipment, of which offline process simulation represents a key component. Moreover, if an accident does occur, training programmes and related records can be a mitigating factor to show that the plant took precautions and performed due diligence.

Why simulate?For the reasons outlined above, it is apparent that all process plants need to train their operators, and most companies use some combination of three basic training methods. The first is training by working alongside more experienced personnel. The second method is the study of written materials, and the third is training through simulation.

To understand the value of operator training through simulation, it is necessary to think about the operators’ responsibilities during the first few days of start-up. There are a multitude of activities taking place for the first time with a live process. Operators report to the control room where they are promptly overwhelmed by a crowd of engineering support and contractors; even with a veteran operator providing guidance it would still be a challenging task. One should also consider the time it takes for an operator to understand what is really happening in the facility, and how this learning experience could be accelerated to meet current requirements. Simulation is one way, and it is a lower-cost option in today’s environment.

When process simulators were first introduced in the early days of the Distributed Control System (DCS), a great deal of software engineering was required just to get the simulator’s screens to emulate the ones the operators were using. Much more time was required to simulate the process itself, as well as a very high level of process knowledge.

Simulator programming previously had to be done with sophisticated computers, so it took a combination of cooperative personnel with special skill sets to program and maintain the simulator. With the exception of nucleur power plants and refineries, where simulation capability was absolutely critical to prevent incidents, very few industries could afford the cost.

Fast forward to the present, to the ubiquitous and inexpensive PC. The PC’s introduction into the process control industry made simulation an affordable option, as costs decreased and options multiplied. The PC hardware itself is inexpensive, and graphical programming methods created for the Windows operating system now allow simulator programming and configuration by plant personnel instead of by IT experts.

Introduction to simulationWith the advent of the PC, simulation is now affordable, and available in three basic types. First is the basic process simulator that is generally part of the engineering configuration software supplied with the control system, particularly with a higher-end process plant DCS.

This basic process simulator enables software loop tiebacks in which the output of a loop is taken back into the input through software in a virtual environment. This creates basic loop responses that give operators a fundamental feel for loop control, screen navigation and basic responses. Simulating more sophisticated loops is not feasible with this type of software.

The next level of simulation uses two PCs, one running the control software program, and the second supplying process simulation responses, with the two PCs typically communicating via Ethernet. This type of simulation can also be done in ‘the cloud’, allowing operators to be trained wherever a PC is available.

At this point, sophisticated and realistic process dynamics can become an integral part of the simulation. Sizing of vessels, stroking times of a valve and dynamics of the process can be entered and adjusted. Because the properties of the process unit in the simulator PC can be changed, it is now possible to integrate process noise and make the simulation more realistic.

This type of simulation is not meant to replicate exact plant processes, but it can be modified on a tag-by-tag basis to yield required response levels, and this level of simulation can be expanded to cover the entire operation if necessary.

Perched at the top of the process simulation hierarchy is the high fidelity simulator. This type of simulation can precisely replicate the process dynamics for every piece of equipment in the plant. If operator training simulation must precisely mimic the actions of a process train or terminal, this is the route to take. Several types of industries require this level of simulation, and many others could benefit.

The terms low fidelity, medium fidelity and high fidelity, are often used to define the three levels of simulation. These terms Figure 1. Process flow diagram screen example.

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loosely describe how close the simulated plant’s process and equipment responses are to the actual plant. In reality, there are a lot of grey areas where the functionalities of one level can cross over into another.

OTS implementationBefore simulation can be incorporated into operator training, the training programme itself should be examined. Operator training should revolve around certification and benchmarking. Certification verifies that specific skill sets have been met, and benchmarking creates the best practices.

Capability and knowledge assessments must take place to ensure that each operator is at the correct level. The process simulator can help to create scenarios that depict actual train operation problems. Common and unique events can be recreated and used to record the operator’s response.

Responses of the best operators can be used to establish the best practices, and should be used for comparison by less experienced personnel. Once the best practices are established, the training system can be used to measure improvement.

To build for success, training scenarios should be created in which instruction is self-paced and easily understandable. Exercises should be broken into smaller digestible pieces that build on each other. Normal operating procedures for process start-up, shut-down, loading or unloading, are good starting points for training.

A process simulator can be set up to quickly move to different process operating conditions. One operator could practice training start-up and operation, but the next one must work on ship loading. These simulations can be executed by taking snapshots of the process running in specific conditions. One can then simply implement the process snapshot to fit the required training.

Simulators can also be sped up or slowed down. For a process with a large amount of dead time, the simulator can be sped up to compensate for the delay. For training of inexperienced operators, actual process conditions can be slowed to build confidence, and then gradually sped up as experience is gained.

Taking training a step further, observation of operator actions can be used to better the actual process control programmes and the Human Machine Interface screen designs. This can further enhance operator actions, reducing the possibility of incidences and improving general plant operation.

Giving simulation easy accessThe simulator can be made more accessible and user friendly, helping to break the old-school conception of an OTS. This is where using ‘the cloud’ comes into play.

An OTS can be run in a global server, which gives employees access from any PC. Procedures pop up on the operation window to guide the user through the start-up, shut-down or train change, in a safe manner. Every user has a unique login and password; passwords can be as strong as one wants to ensure OTS security.

Training is now self-paced and accessible 24/7; it can be stopped and started at any point. The user can return to where they left off in the OTS, so there is no unnecessary repeating of training units.

An instructor can be added later to trigger process events, or one can have pre-defined events automatically triggered. Student response tracking data is reported back to the learning management system without any additional personnel required.

Simulation challengesEvery expenditure has an associated cost/benefit ratio, and operator training simulation is no different. LNG facility management personnel must decide how closely the simulator needs to mimic the exact operation of the process as this is the primary cost driver. The closer the simulation to the actual response of the gas treatment, acid gas removal and in-tank pressure control, the higher the cost, but the greater the potential benefit.

Once the right level of operator training simulation is selected and implemented, a common point of failure is a lack of ownership or assigned responsibility.

Table 1. Benefits of simulation for operator training

Improves operator response time to process upsets and incidents

Improves quality of operator response and subsequent actions

Can reduce troubleshooting time

Analysis of operator training can lead to improved HMI design

Fastest practical operator training method, particularly for inexperienced personnel

Least expensive operator training method

Often leads to process improvements, including increased uptime, more throughput and higher quality

Better trained personnel allows operations with less required operating staff

Can often be used to meet regulatory requirements

As part of a comprehensive training programme, it can be a mitigating factor if an incident does occur

Placing it in ‘the cloud’ gives 24/7 access, making it self-paced and freeing up valuable individuals

Cloud based OTS can also miminise (or eliminate) software/hardware maintenance headches

Figure 2. Operator control room.

Every process undergoes constant changes, as do most simulation software packages, and someone has to own and implement these changes.

If the operator training simulation does not have a champion, it will fall out of use, and the last thing any plant wants is an investment gathering dust. Horror stories abound about plants spending large amounts of money on a process simulator that becomes redundant. That is not a failure of operator training simulation, but rather a failure of plant training and operating procedures.

An important investmentThe military and the airline industries have been using simulators for decades. They understand the value of experiencing situations in a virtual environment before being plunged into reality. The goal is to get the trainee as close to the real world as possible. This is accomplished by training individuals so that if and when they experience a worst case scenario in real life, they have already implemented the solution via simulation. This gears trainees for success.

Experienced operators are retiring or just do not exist for the new liquefaction plants being implemented, and new personnel have to be brought up to speed quickly. Fewer experienced operators mean fewer opportunities to spread industry and process knowledge than in the past. This can lead to unscheduled shutdowns, costing millions of dollars. Shutdowns can also bring fines, plus unwanted government and media attention.

To improve this situation, a solution is an on-going operator training simulation program that challenges operators, both new

and experienced. The results will speak for themselves as a process simulator allows competencies to be established in months, not years. A smoother running process translates into a more profitable plant, yielding a quick payback on the simulation system investment.

No plant can risk training operators on actual equipment, but a good plant simulator will have the look and feel of the actual process, enabling the training of new and experienced operators without jeopardising actual operations. The closer to the look and feel of the actual process, the more prepared operators will be when monitoring, controlling and performing that process.

Often overlooked are the morale dividends created by investing in employee training. The time and expense involved with training on a process simulator is not lost on the plant employees as they know it is an investment in their future, as well as the future of the facility where they work.

Table 2. Challenges of simulation for operator training

The simulator must be programmed to closely mimic actual plant operations

Simulator programming must be kept up-to-date as the process changes

Simulation software must be integrated with existing plant automation systems

A regular training programme must be implemented and followed, preferably with some type of certification

Time and money must be allocated for on-going operator training


Graeme Henderson, WorleyParsons, explains how LNG producers can navigate the industry’s growing complexity through innovative data-based solutions.


The LNG industry is growing in size and complexity at a time when the broader business trend is towards ‘big’ data. For example, in environmental management, monitoring requirements are shifting from

selected sampling to large quantities of continuous real-time data.However, some things do not change, such as the imperative to meet

contracted production schedules and to ‘not miss any boats’.This article focuses on data-based solutions including the following:

� Asset data management.

� Dynamic simulation.

� Portfolio management.

� Benchmarking and continuous improvement.


Although individually each of these data-based solutions has much to offer, it is in the context of a more holistic approach to optimising ongoing LNG operations that they deliver their full potential (Figure 1). The most effective outcome is achieved using this consolidated information highway approach in an integrated team.

These solutions align with new industry thinking, with a focus on net present value (NPV) and profitable sustainability across a network of assets aiming to achieve maximised profit over the lifecycle of all operating assets while fulfilling stakeholder obligations.

Growth, complexity and data-based solutionsThe LNG industry is entering a period of rapid expansion in global production capacity, which is expected to increase by more than 60% by 2020, based on known, planned

LNG trains. This expansion includes the development of between 20 – 30 new LNG export projects requiring ongoing operations and maintenance support, and brownfields capital services.

Such strong growth in production capacity implies a raft of strategic considerations by all players, including a rapid increase in demand for experienced personnel for both the operator and the associated maintenance and brownfields contractors.

Ensuring safe and reliable operations for all LNG facilities with various process and production interdependencies requires new ways to monitor, control, maintain and troubleshoot. LNG plants are characterised by very low temperatures of the liquefaction process, presenting many challenges in terms of materials selection, insulation and mechanical interactions. Some of the equipment and facilities associated with the low temperature side of operations are unique to the LNG business, such as loading arms, heat exchangers, expansion bellows, and LNG storage tanks. The other major characteristic of LNG plants is the significant amount of rotating equipment employed via gas compressors and power turbines. Approximately 10% of available feed gas is used to power the gas compression process, equal to approximately 45 MW of rotating equipment compression capacity per 1 million tpy of production. The ability to maintain the integrity and reliability of this equipment is critical to the ongoing operation of the plant.

The production of LNG is a volume driven business. It is underpinned by long-term sales contracts that require reliable and predictable operational performance. The goal is to deliver all contracted cargoes, taking full advantage of spot cargo opportunities.

Some of the answers to the LNG industry’s challenges are to be found in data-based solutions. Effective data-based solutions start with the operator’s business drivers and accurate data for these drivers. In skilled hands, sophisticated computer-based tools can convert this data into information that supports decision-making to optimise the performance

of operations in terms of safety, cost, reliability, social and environmental impact, and production.

Asset data managementWith so many new operations coming on stream, operational readiness and successful project handover are key industry challenges. Handovers can account for as much as 5% of total installed cost – that represents US$ 1 billion on a US$ 20 billion project. Therefore, before start-up, it is advisable to develop an effective asset data management system.

Unfortunately, on some new LNG projects, less than half of the required data is being handed over to the operations team at start-up. Adding to this complexity, the data can be poorly structured and difficult

Figure 1. Information highway for current and future assets and upgrades in the LNG industry.

Figure 2. Simulation output for optimising LNG storage.

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to search, with little or no interconnectivity between a myriad of databases. One of the major causes of this data dilemma is the evolution of information management towards data optimisation while many operators and contractors remain in a document-centric world.

Dynamic simulationEach LNG operation is a complex supply chain. Often in remote areas with limited access, they are vulnerable to bottlenecks, disruptions and uncertainty. The challenge for LNG producers is to optimise production and sustain capital programmes within strict financial and commercial constraints. With complex processes it is not immediately clear which lever to pull to achieve the desired outcome.

Discrete event dynamic simulation (DEDS) is a ‘big’ data-based solution that can be used to measure the actions, effects and responses within a complex system. It can identify the most important variables from the many that have some impact on the outcome and can, therefore, be used for many different tasks, including to:

� Quantify operational risk.

� Undertake ‘what-if’ analysis.

� Assess the efficiency of equipment.

� Optimise inventory and production.

� Assess shipping patterns.

� Identify priority brownfield projects.

� Optimise maintenance schedules and resource allocation.

� Assess debottlenecking options.This approach can replicate the entire process from

wellhead to final destination within a virtual real-time computer model that not only incorporates very large amounts of engineering data, but also considers external forces (e.g. weather), and financial variables and criteria

(e.g. maximising NPV). A well-defined model based on accurate data simulates as real a situation as is possible, without the risk of mistakes leading to downtime or disruptions to production.

Although the underlying mathematics does not change much over time, the technological advances of recent years have been in computational power and speed – the ability to continuously process a vast quantity of data rather than drawing implications from relatively small samples. These advances are contributing to the evolution of the information management industry towards ‘big’ data-based applications.

Capacity optimisationFor a number of LNG customers, WorleyParsons has developed complete models for both new and existing operations that include production, storage and shipping. These complex models incorporate a wide range of variables:

� Environmental – weather, tides and berth operability.

� Engineering – process data and flow rates.

� Operational – scheduled maintenance and utilisation targets.

� Logistical – fleet availability and shipping schedule.

� Economic – market demand and prices.

� Financial – NPV.

With these LNG industry customers, the simulations led the company to prioritise issues and eliminate any factors that, despite expectations, did not have a significant impact on the outcome. For example, one study found dredging and night navigation was not necessary to achieve the desired objective, saving the company millions of dollars in costs. In another case, it was discovered that as little as a 1% difference in berth operability translated to a change in annual revenue of hundreds of millions of dollars.

Figure 3. Output from portfolio optimisation analysis in LNG operations.

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LNG storage simulationTo determine the optimal additional LNG storage capacity at a major port, WorleyParsons created a ‘virtual’ copy of the port, supply fleet of LNG tankers and supply chain to assess the impact of key variables, including:

� Ship traffic engineering distributions.

� Weather.

� Operational uncertainties and delays.

This model quantified the risks to the supply of LNG product to the end market and identified the optimal additional storage capacity and composition to ensure balance between inbound and outbound LNG tankers, and to maintain constant throughput (Figure 2).

These examples demonstrate how dynamic simulation can be used to achieve greater certainty over the outcomes of decisions by reducing all types of risk. Among other benefits, this allows for a less conservative approach to fleet and equipment sizing; one that reduces capital and operating expenditure to maximise NPV. The specifications can be fine-tuned to avoid ‘over-engineering’.

Portfolio managementTypically, an LNG company has a portfolio of sustaining projects under consideration – growth, capital, maintenance, safety and environmental – at each of its sites. The challenge is to prioritise the order in which to implement them to achieve the highest value. With the right data and specialist tools and

skills, projects can be prioritised so that each contributes to the overall achievement of the business objectives.

For example, WorleyParsons DELTΔ™ portfolio optimisation tool analyses a portfolio of projects across a range of interrelated drivers such as safety, NPV, power use, and greenhouse gas emissions, while placing constraints on variables such as available construction man-hours to determine the optimum project sequence.

A recent application of effective portfolio management using the DELTΔ™ tool in the LNG industry identified a high-cost project (Project 1 in Figure 3) that, if implemented, would undermine the accumulated value of contributing projects. This demonstrates that pursuing the ‘wrong’ projects can be equally as detrimental as not pursuing the ‘right’ projects.

Benchmarking and continuous improvementIn the context of effective management of a portfolio of sustaining capital projects, accurate data plays a crucial role in providing clarity, consistency and control. Data for the key measures of safety, cost, schedule, efficiency, quality and productivity provide insights into performance against contract benchmarks (Figure 1).

When compared to wider industry benchmarks, key performance indicators can identify gaps between best practice and current operating practice. A continuous cycle of planning, implementing, measuring and reviewing, and improving performance, puts data to work.

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More and more ports are forcing the shipping industry to change its marine fuel options using stringent

regulations, such as emission control. One of the new fuelling options for the shipping industry is LNG, but LNG bunkering stations are hard to find at the moment due to the ‘chicken and egg standoff’. For those not familiar with this standoff, the shipping industry is reluctant to invest in LNG fuelled vessels due to the lack of bunkering stations, while potential bunkering companies are withholding investments in infrastructure due to the lack of LNG fuelled

“Are you ready?”

Joost Smits, Systems Navigator,

the Netherlands, examines whether terminals are ready

for LNG bunkering.


vessels. The EU, however, is trying to establish a breakthrough in the current standoff by subsidising and promoting LNG bunker stations and it seems that it has succeeded, since the LNG bunkering market in Europe is developing rapidly. There are many options for LNG bunkering stations, one of which is to convert existing regasification terminals to a combination terminal offering both regasification and bunkering services.

Case study: SN LNGSN LNG is a fictive regasification terminal consisting of one berth and three storage tanks, each having a capacity of 180 000 m3 of LNG. Pump capacity of the terminal is 12 500 m3 of LNG per hour and the terminal currently has an annual scheduled send-out rate of 24 000 m3 of LNG per day.

SN LNG is considering investing in bunkering equipment to allow bunkering operations, but is unsure of what impact the bunkering operations will have on current terminal processes. The commercial department of SN LNG needs input from the project team regarding the maximum contracted send-out they can promise to terminal clients, while the port where SN LNG is located is interested in learning how many vessels SN LNG can accommodate for bunkering operations without disrupting unloading operations. Unloading operations are considered disrupted by terminal management if more than 10 unloading vessels per year have to wait before or during berthing.

Port management is willing to co-invest in bunkering equipment at the existing jetty of SN LNG, but only if the

terminal bunkering service level is at least 70%. The service level is defined as the number of vessels that can bunker at the terminal, divided by the number of bunkering attempts. Vessels requesting bunkering at the terminal are declined if the berth is already occupied.

To study the feasibility of changing the regasification terminal into a regas-bunkering terminal, port and terminal management are building a business case based on the following question: ‘What is the average number of bunkering vessels SN LNG can accommodate vs. the terminal send-out while the number of waiting unloading vessels is not exceeding 10 and the bunkering service level is at least 70%?’

Based on market research performed by port management, 170 vessels interested in bunkering can be expected in the port. Therefore, port management is also interested in an additional case answering the following research question: ‘Is SN LNG able to accommodate this amount of vessels within the limits set by port and terminal management? If not, what would be the implications if 170 vessels would bunker at SN LNG?’

SN LNG has 53 unloading vessel arrivals a year, of which 10% consist of Q-Flex vessels and 90% of large conventional LNG vessels. These arrivals are scheduled for an entire year, but the type of vessels that are arriving are unknown (they do have 90/10 distribution). The exact type of vessels that are loading at the terminal is unclear, but they can vary from large container vessels to bunker barges. SN LNG is not considering back-loading operations at the terminal, during which LNG is loaded in empty LNG vessels. Terminal management, rather, operates the terminal as a gas station for LNG fuelled vessels. Due to existing contracts, SN LNG will prioritise unloading vessels over loading vessels.

Used technology and key performance indicatorsTo investigate the impact of bunkering operations on the current terminal infrastructure, a combination of simulation modelling and scenario navigator interface software is used. The interface software is capable of easy scenario creation and comparison. To analyse the problem, over 70 scenarios are created and analysed using the following key performance indicators (KPIs):

� Total waiting time.

� Total annual terminal send-out.

� Storage levels, including tanktops and tank depletions.

� Vessels handled at berth.

� Average number of vessels declined at berth.

� Terminal bunkering service level.

� Number of unloading vessels that have to wait.

Model inputSN LNG has the terminal characteristics listed in Table 1.The model simulates terminal operations for the duration of 1 year, using 25 replications. Scenario results are the average of the model outcomes of these 25 replications. Applying this approach produces statistically significant results allowing scenario comparison (Table 2).

Table 3. Fleet mix unloading vessel arivals

Vessel name Unloading capacity (m3)

Unloading rate (m3/hr)

% in fleet

Q-Flex 217 000 12 500 10

Large vessel 165 000 12 500 90

Table 1. SN LNG terminal characteristics

Total tank capacity 540 000 m3

Terminal send out Scenario dependent

Terminal safety stock 17 500 m3

Number of vessels loading LNG Scenario dependent

Number of vessels unloading LNG 53

Pre-berth time 4 hrs

Post-berth time 4 hrs

Berths 1

Priority at berth Unloading vessels

Table 2. Used simulation settings

Timeframe 1 year

Replications 25

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SN LNG has only two types of vessels arriving for unloading operations: Q-Flex and large conventional vessels. A comparison of these can be seen in Table 3.

Model assumptionsSince a high level (coarse granularity) model is used for the case study as described in this article, terminal processes are simplified using the following assumptions.

Assumptions � No berthing restrictions per vessel type.

� No loading or unloading rate restrictions at the terminal: vessel sets loading or unloading rate.

� No departure restrictions.

� No weather influences.

� No failures and maintenance of equipment.

� Pre-pump, post-pump and navigation times are included in ‘pre-berthing time’ and ‘post-berthing time’.

� No ramp up or down.

� Tank capacity is updated hourly.

� Vessel can load or unload if current tank capacity is sufficient. This is checked every hour. Pumping rates are not taken into account.

� If no loading stock is available, the loading vessel will wait at the buoy.

� It is possible that a loading vessel can go to berth (stock > safety stock), but still has to wait since its loading capacity is larger than the stock level. This is measured as occupancy including waiting time at berth.

� Advanced scheduling is not included in the demonstration model, vessels are scheduled independent from each other and based on randomness, arrival timeframes and percentages.

� Arrival schedules are created at the beginning of the year.

� If the bunker capacity of a vessel trying to load at the terminal is not available in the tanks the vessel is declined.

� Vessels attempting to bunker are declined if the berth is already occupied.

� Terminal send-out is temporarily stopped if tank levels reach the safety stock level.

� Only one vessel at the time can be accommodated at the berth.

Scenario descriptionSimulation modelling allows the use of variability in the analysed system and is therefore the preferred modelling technique. For more information about variability, see the ‘Explained: variability’ sidebar. To show the impact

Table 4. Fleet mix bunkering vessel arrivals

Vessel name Loading capacity (m3) Loading rate (m3/hr) % in fleet

Large container vessel 7000 1200 5

RoPax ferry 1500 1200 30

Tanker 1000 1200 25

RoRo ferry 1500 1200 10

Offshore services vessel 300 1200 20

Bunker barge 10 000 1200 10

Explained: variabilityThe key issue in predicting future system performance is variability. One of the major advantages of using simulation modelling is the ability to include variability in the analysis of the system, such as the terminal environment. The importance of variability can be shown in a simple test that includes two scenarios. Scenario 1 has a constant arrival pattern and a constant process time and scenario 2 has a variable arrival pattern and a constant process time.

Scenario 1 has no waiting time and no vessels in queue, since every vessel that arrives can berth due to the constant arrival pattern and process time. When analysing these scenarios over a period of 1 year and running 10 replications, it can be seen that the number of arriving vessels that are waiting in queue before berthing is increasing over time in scenario 2. The same pattern is seen when analysing the average waiting time per vessel. Long waiting times lead to large demurrage costs and a lower level of service.

Figure 1. This graph shows the number of entities in queue when adding variability to a single server system.

Figure 2. This graph shows the average waiting time of entities in queue when adding variability to a single server system.


of variability on terminal operations, scenarios 1 and 2 are included in the analysis. Various scenarios are designed to study the effect of bunkering at the existing berth on SN LNG’s operations working towards an optimised number of bunkering vessel arrivals.

Scenario 1: unloading vessels in a perfect worldWhen unloading vessels in a perfect world, there is no delay in arrivals and the equipment never fails or needs maintenance. Since vessels arrive at the exact second they are scheduled, no tanktops occur and waiting times do not exist. Scenario 1 has no vessel arrivals for loading operations.

Scenario 2: vessels arrive in a 12 hour time periodUnfortunately, a perfect world does not exist, so vessels arrive in a 12 hour time period around their scheduled arrival time. This works as following: if a vessel is scheduled to arrive at 16:00 hours, it has an equal chance to arrive at any time between 10:00 and 22:00 hours. Even when scheduling an average of one vessel a week, this arrival variability leads to occasional waiting time for vessels. Simulation results show that in 3 out of 25 years vessels can encounter waiting times.

Scenario 3: unloading in a perfect world – random loadingSN LNG chooses a ‘gas station approach’. Bunkering vessels can try to load LNG whenever they need; therefore the vessels will arrive randomly over the year. Scenario 3 analyses the combination of such random arrivals and exact arrival times of unloading vessels. Unloading vessels have priority over loading vessels and loading vessels are declined at berth if there is not enough LNG in the tank to service a bunkering vessel or if the berth is occupied at the moment of arrival.

Scenario 4: unloading in a 12 hour time period – random loadingThe final scenario describes terminal operations as can be expected in reality, including variability in the arrival of vessels that are unloading. While scenarios 1 – 3 show the impact of variability on terminal operations, this scenario is used to analyse both the business case and the additional case as defined by terminal and port management.

ConclusionsA scenario is considered feasible if the terminal can facilitate both 53 unloading vessels and as many loading vessels if the maximum limitations are met:

� No more than 10 unloading vessels can wait.

� Terminal bunkering service level is at least 70%.

Table 5. Overview of main scenario results

Scenario Scheduled send-out rate1 (m3/d)

Realised send-out rate2 (m3/d)

Vessels waiting to unload3

Vessels loading4 Service level bunkering5 (%)

1 24 000 24 000 0 - -

2 24 000 23 916 2 - -

3 24 000 23 573 10 158 70.0

4a 24 000 23 636 10 151 70.2

4b 23 500 23 350 10 151 70.3

4c 23 000 Not feasible Not feasible Not feasible Not feasible

4d 24 500 23 856 7 144 70.0

4e 25 000 23 933 6 137 70.3

4f 24 000 23 572 10 170 67.8

4g 23 500 23 316 10 171 68.2

4h 24 500 23 656 9 172 66.1

4i 25 000 23 719 8 170 65.5

1 The maximum send-out rate per day. If possible, the terminal will use this value as send-out. The value is constant.

2 Due to tank depletions, the terminal cannot always use the maximum send-out rate. Therefore, the realised send-out will be lower than the maximum send-out. 3 Vessels that had to wait before berthing due to unavailability of the berth or that have to wait at berth due to tanktop events. The number shown is the average of all replications.

4 The number of vesels that can bunker at the terminal. The number shown is the average of all replications.

5 The number of vessels that can bunker at the terminal divided by the number of bunkering attempts. The number shown is the average of all replications.


Scenarios 4a – 4e (Table 5) are used to answer: ‘What is the average number of bunkering vessels SN LNG can accommodate vs. the terminal send-out, while the number of waiting unloading vessels is not exceeding 10 and the bunkering service level is at least 70%?’ While scenarios 4f to 4i answer: ‘Is SN LNG able to accommodate this amount of vessels within the limits set by port and terminal management? If not, what would be the implications if 170 vessels would bunker at SN LNG?’

Summary of the scenario resultsTable 5 shows an overview of the main key performance indicators per scenario. Only the ‘best fit’ scenario is shown in Table 5.

If terminals were operated in a perfect world, simple scheduling tools would be sufficient to schedule vessel arrivals. Vessels would arrive at the exact second they are scheduled and waiting times would never occur. Unfortunately, arriving vessels can be early or delayed due to a number of factors; a whole new world is opened up that consists of waiting times, tanktops and tank depletions.

Variability impacts scheduled operationsAdding variability to the arrival schedule (meaning that vessels have an equal chance to arrive in a 12 hour time period around their scheduled arrival time) leads to tanktop events that can be significant in 3 out of 25 years. It should be noted that vessel arrivals are scheduled independently, increasing the chance of potential bottleneck events, such as tanktops or tank depletions. This is shown in scenario 2. Bottleneck events are causing a very minor dip in the realised send-out rate compared to the scheduled send-out

rate. When comparing scenarios 3 and 4a it is clear that variability leads to a reduced number of vessels that are able to bunker at SN LNG.

Business case results: average number of bunkering vessels vs. terminal send-outTerminal management was expecting that a reduced send-out would result in an increased number of vessels able to bunker at the terminal. However, this is not the case. Analysis of scenarios 4a – 4c shows that reducing the scheduled send-out eventually leads to infeasible results: either the number of vessels waiting to unload is larger than 10 due to tanktop events or the service level for bunkering is below the target of 70%. Increasing the send-out has a positive effect on the number of vessels waiting to unload, since the chance of a tanktop event is reduced. However, the number of vessels able to bunker at the terminal is reduced compared to

current scheduled send-out.The answer to the business case research question is

that an average of 151 vessels are able to bunker at SN LNG for both a scheduled send-out rate of 24 000 and 23 500 m3/d. The realised send-out in scenario 4b (scheduled send-out of 23 500 m3/d) is closer to the scheduled send-out compared to scenario 4a. Therefore, it is advised to decrease the scheduled send-out to 23 500 m3/d when implementing bunkering operations at the terminal. It should be noted that this option should only be chosen if the revenue of bunkering operations is at least equal to the lost income of a reduced send-out rate.

Figure 3 shows the storage capacities of the replications resulting in the least amount of waiting time for unloading vessels in scenario 4b. The graph clearly shows tanktop events in the ‘blue replication’ responible for the increased waiting time.

Additional case: implications to SN LNG of 170 bunkering vesselsSN LNG is not able to accommodate 170 bunkering vessels within the limitations defined in the business case. However, if the service level of bunkering is reduced, 170 vessels can be easily accommodated. Most bunkering vessels can be accommodated in scenario 4h (increased scheduled send-out rate of 24 500 m3/d), while the best service level is achieved in scenario 4g (decreased scheduled send-out rate of 23 500 m3/d). Combining the results of the business case and the additional case, it is in the interest of both terminal and port management to aim for a decreased scheduled send-out of 23 500 m3/d if SN LNG is implementing bunkering operations.

Figure 3. Storage capacity comparison scenario 4b.


N ew regulations require vessels operating within the North American Emission Control Area (ECA) of 200 nautical miles of the US, Canada, Puerto Rico,

and the Virgin Islands to meet a 1% sulfur content limit in fuels. While the current limits pose a challenge, the drop of this limit to 0.1% in 2015 will change the operating landscape even more, requiring ship owners and operators to identify and employ cleaner fuel options.

There are several viable options at present for meeting this requirement, such as burning ECA-compliant blends of marine distillates, using ultra-low sulfur fuels, and using exhaust gas scrubber systems to remove pollutants from the emission stream. These solutions, while effective to some degree, may be relatively costly. When seeking to identify long-term solutions, especially for new construction, there is a more effective option owners and operators should consider.

Class perspective Vessel owners, operators and designers are showing increased interest in maturing the application of natural gas to fuel ships. A number of companies are looking to LNG as a more sustainable and economical fuel source

for the marine and offshore industries to comply with North American ECA standards, which are stricter than global standards.

Working closely with industry and regulatory bodies such as the US Coast Guard (USCG), class societies are committed to verifying that LNG ship designs are based on sound engineering practices, from the initial planning stage to the final delivery of the vessels.

Toward that end, the ABS ‘Guide for Propulsion and Auxiliary Systems for Gas Fueled Ships, 2011’ was released to provide technical standards for the arrangement, construction, installation, and operation of machinery

Pioneering LNG as fuel in

Patrick Janssens and Roy Bleiberg, ABS, demonstrate how LNG projects in the US are setting the bar for vessel safety.

North America

Image courtesy of Harvey Gulf International Marine LLC.


components and systems for gas fuelled vessels. Providing a basis for gas fuelled ship designs, the guide incorporates more than 50 years of experience with LNG handling and storage on board ships, many with dual fuel diesel propulsion plants. Industry standards considered in this guide include International Maritime Organisation (IMO) Resolution MSC.285 (86) Interim Guidelines on Safety for Natural Gas-Fuelled Engine Installations in Ships, the International Gas Carrier Code and the IMO International Code of Safety for Gas-Fuelled Ships.

When determining the appropriate requirements for gas fuelled ships and LNG fuel propulsion systems, the USCG has primarily relied on IMO Resolution MSC.285 (86) to provide a baseline for developing its design criteria. Furthermore, the USCG has drafted a policy for vessels and waterfront facilities conducting LNG marine fuel transfer (bunkering) operations, which was scheduled for publication in late Q3 2013.

The first wave of LNG developments, involving new-build and conversion gas fuelled ship designs under way in the US, must meet the appropriate regulatory requirements to receive safety notations certifying that the vessels are in full compliance with all applicable ABS rules, guides, and statutory guidelines and regulations.

First US applicationHarvey Gulf International Marine, based in New Orleans, has taken the first step to introducing LNG propulsion technology

to the US Gulf of Mexico (GOM) as part of the company’s ‘Going Green’ initiative that includes the goal of having a fleet of gas fuelled supply vessels for offshore support. Although this technology is not novel – having been developed by Wärtsilä and implemented 10 years ago on the first platform supply vessel (PSV) to run on natural gas for Statoil in the North Sea – Harvey Gulf’s LNG powered offshore supply vessels (OSVs) will be the first built in a US shipyard under USCG requirements and classed by ABS.

The new-build programme includes six dual fuel (LNG and diesel) DP-2 PSVs powered by Wärtsilä’s integrated propulsion system with dual fuel machinery. Data gathered and analysed by Harvey Gulf indicate this new generation of OSVs will be the cleanest burning vessels operating in the GOM.

In addition to ABS requirements, the LNG OSV design was developed in accordance with the IMO requirements for gas fuelled ships and the USCG policy on gas fuelled ships. These vessels will receive ABS Enviro+ and GP (Green Passport) notations, outlining additional steps to take in designing, constructing, operating, and recycling vessels in an environmentally responsible way. Harvey Gulf anticipates the use of LNG will save as much as US$ 2.5 million per ship in operating costs.

ABS and USCG have worked closely together to promote safety and consistency to the application of the new requirements for gas fuelled vessels.

Technical challengesWhile ongoing research and development of LNG technology and the developments being undertaken in the US support the technical feasibility of using LNG as fuel, several near-term challenges tied to regulatory requirements and support infrastructure must be overcome for its wide-scale adoption.

As class, industry, and the USCG are shaping concept and design specifications for LNG fuelled vessels under the US flag, applying the insight garnered from combined experience in areas such as vessel operation and bunkering logistics is critical. While the concepts for supporting complex vessels build on existing technology and practices, the lessons learned from working in tandem to resolve these issues and in identifying technical solutions are directly impacting new policies, procedures, and design acceptance criteria for gas fuelled ships.

Lessons learned, to list a few, include recommendations to address hazardous areas, best practices for LNG tank venting arrangements, and clarification of required surveys after construction.

Continued collaborative efforts will provide a better understanding of appropriate operational requirements and restrictions, design loads, applicable class society rules, industry standards, and flag state statutory requirements.

Charting the courseEarly adopters of LNG as fuel stand to gain on three significant fronts: they will be well prepared to meet strict exhaust emissions requirements, will have the added benefit of achieving improved environmental stewardship, and will benefit from reducing fuel costs over the vessel’s operational life.

Green initiatives aimed at building dual fuel fleets and using LNG propulsion technology are providing the framework and best practices for gas fuelled ship design and are the foundation for longer-term solutions for meeting increasingly stringent emissions standards in North America.

Figure 1. A new generation of LNG fuelled OSVs, classed by ABS, will use dual fuel engines for optimal fuel and cost savings (image courtesy of Harvey Gulf International Marine LLC).

Global Gas SolutionsOrganising resources to focus on specific disciplines is one of the first steps in meeting technology challenges. The recently formed Global Gas Solutions Team was created at ABS to align internal resources with external needs. The new team brings together industry-focused professionals, whose objective is to work alongside owners, shipyards, and equipment manufacturers to promote LNG and other gas-related projects as a way to meet more demanding exhaust gas emissions requirements.

A dedicated group within the Global Gas Solutions Team will oversee programmes in North America, focusing on advancing LNG as a marine fuel and developing export capabilities to move growing North American gas supplies into the global marketplace.

Combining extensive LNG and LPG experience with a track record of working with the USCG, Federal Energy Regulatory Commission, and Maritime Administration, ABS will help stakeholders in the global gas industry navigate the sector’s unique challenges.


When laboratory professionals discuss the vision of the true

paperless laboratory – a lab that contains zero paper, where processes are automated and data is virtually mistake-free – simplified compliance is usually one of the first advantages mentioned. In LNG sampling labs, however, automating compliance is much easier said than done. In addition to regulations enforced by local, national and international agencies, LNG customers require suppliers to comply with standards that are usually stricter than the law. And if manufacturers cannot meet these stringent requirements, they risk being displaced by companies that will.

Compliance would be one thing if standards for testing such as those recommended by ISO and ASTM were a static set of guidelines, but standards are in constant flux as methods and technologies evolve.

TURNING ADHERENCEINTO OPPORTUNITY

Colin Thurston, Thermo Fisher Scientific, UK, discusses how LIMS can enable LNG laboratory agility in the face of changing standards.


Running a paperless LNG laboratory that complies with moving targets and completes audits efficiently would be an impossible task without major automation capabilities.

A laboratory information management system (LIMS) not only enables a LNG laboratory to collect, store and analyse data more accurately and efficiently in a paperless environment, it also ensures compliance in an environment of constant change. This article will explore how a LIMS enables integration with enterprise systems and automation of processes to transform compliance with industry standards from a burdensome source of worry to a business differentiator.

Compliance in the paperless labTwenty years ago, when nothing in the lab was automated and the idea of a paperless lab would have seemed farfetched, compliance revolved around frequent referrals to hard copy manuals kept in the lab. Standard organisations issued new testing definitions through subscription, and each time a standard was created or revised, the lab would update an operating procedure and retire the old one. Lab technicians unfamiliar with updated procedures were obligated to refer to the newest manual to ensure that their day-to-day activities would not violate the new standard. Control of the correct versions of operating procedures required a manual control system

to ensure that everyone was using the right version at the right time. Under this system, unintended violations were difficult, if not impossible, to spot, and audits were slow and inefficient.

Today’s successful LNG enterprise relies heavily on the integration and automation capabilities of a LIMS to enable compliance in an environment when standards are more accessible, but also updated more frequently. Instead of having to familiarise personnel with perpetually outdated hard copy manuals, labs now have LIMS that automatically link directly to the revised standards and update records accordingly. Some advanced LIMS, such as Thermo Scientific SampleManager 11, can even store standards as attached documents on relevant workflows. That way, if a user wants to double check for compliance midway through a procedure, he or she need not track down the correct section in an enormous paper document. Rather, a simple point and click will open up the relevant parts of the standard for the technician to review.

With automation, however, even point and click navigation is often unnecessary. New standards are not just downloaded automatically, the LIMS also adjusts laboratory management workflows to conform to new requirements. This includes necessary user training requirements, equipment calibration, instrument timelines and more. If, for instance, an ASTM standard is revised to require instrument inspection for accuracy on a monthly basis instead of bimonthly, the LIMS will automatically revise inspection scheduling and issue reminders to lab managers so that the company does not miss a beat.

So which standards are most onerous for LNG companies? This article considers two of the most important standards organisations: ASTM and ISO.

Managing to ASTM standardsASTM International, formerly the American Society for Testing and Materials, is an internationally recognised organisation that issues standards “to improve product quality, enhance safety, facilitate market access and trade, and build consumer confidence”. ASTM creates standards on everything from 3D imaging, nuclear technology and quality control, to, most relevantly, laboratory testing. LNG customers worldwide require suppliers to comply with ASTM standards, which, if followed correctly, will ensure that tests to assess product composition and quality are performed correctly and are comparable wherever they have been carried out across a global industry.

Unlike some other standards, which are revised on a schedule basis, ASTM’s recommendations are changed whenever necessary. Standard D1945, for example, which pertains to analysis of natural gas by gas chromatography, was updated in 1991, 1996, 2001 and 2003. Revisions can range from recommendations for new instruments, such as detectors or autosamplers, to sampling frequencies and other changes that are equally important for compliance. An old-fashioned paper-based system would require a huge expenditure of resources to monitor such irregular updates. Not only would a laboratory have to check regularly for revisions, it would also have a limited amount of time to prepare itself to modify a test. The automation provided by a LIMS gives lab managers the lead time to think more strategically about implementing these

Figure 2. SampleManager integration.

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changes, some of which can have a dramatic impact on existing workflows. New and updated workflows can now be prepared ahead of time, and then activated when the whole laboratory goes live with the new version of the standard, ensuring complete consistency across the organisation.

Industry-generated revisions are another area where LIMS add value to ASTM compliance. ASTM International accepts external requests to review existing methods, so if a lab employee notices that a tool, technology or technique is not currently in compliance with a standard that actually produces superior results, he or she can initiate a review by ASTM. If ASTM agrees, this could lead to an industry-wide change.

With a LIMS, staff need not work overtime just to ensure ASTM compliance. Instead, the LIMS gives lab personnel at every level the capacity and ability to analyse data quickly, efficiently and reliably, with the confidence that workflows are compliant with the most current ASTM requirements, and it enables users to initiate changes to those requirements if necessary.

ISO 17025 and the LIMSThe International Organization for Standardization (ISO) is similar in some respects to ASTM, but its standards are intended to give personnel a framework for managing other standards. In a lab setting, ASTM gives laboratories recommended parameters, while ISO – especially the lab standard ISO 17025 – helps lab managers implement changes to meet those parameters.

ISO 17025 is widely adopted in laboratories across a variety of industries, but in oil and gas manufacturing, compliance is an absolute necessity to conduct business. As with ASTM standards, customers demand that their LNG suppliers adhere to ISO 17025 so that they can accept shipments quickly and efficiently, without the costly delays of additionally testing every single container upon receipt.

ISO standards are altered on a more regular schedule than ASTM recommendations – they are revised every four to five years – but LIMS functionality is still critical

to ensuring constant compliance, and proving that compliance in the case of an audit. In fact, advanced LIMS, such as Thermo Scientific SampleManager 11, are preconfigured for compliance; no additional programming or bolt-on modules are required. For an onsite or third-party laboratory in the LNG industry, built-in functionality saves time, money and months of aggravation that can be associated with custom software development.

For example, sections 4 and 5 of ISO 17025 resemble a list of best

practices for any lab at first glance, but what is spelled out in each section is more complex than many realise. It is nearly impossible to manage so many interdependencies and so much relational data without assistance from software. While some companies have developed home-grown paper systems that seem intuitive, ultimately they cannot scale, often contain burdensome processes and can be slow to track down data, especially during an audit. Auditors often want to follow the data trail from a test result, to an analyser’s calibration history, to the qualification of the lab technician, to the approval of the result – all of which can be shown immediately in the LIMS application, but it is not so simple when dealing with paper.

An integrated data management system, such as Thermo Scientific LIMS, is designed to manage this complexity, easing compliance within LNG laboratories, and, most importantly, exposing previously unrecognised opportunities for performance improvement.

ConclusionWhen it comes to regulations and standards, LNG companies can be sure of one thing: the rules will not become less strict anytime soon. However, standards are constantly evolving to include the latest methods for preserving safety, quality and the environment. At the same time, compliance is in higher demand than ever: in a customer-controlled industry, LNG producers have no choice but to maintain strict compliance, or risk losing market share.

But that does not mean standards such as ASTM and ISO should be a burden to the LNG industry. When examined closely, the standards offer keys to efficiency, safety, data accuracy and other business benefits, as long as the laboratory is outfitted with a LIMS that can properly manage the demands of compliance. The automation and integration provided by a LIMS turns adherence with ASTM and ISO standards into an opportunity to identify methods, tools and workflows that ultimately drive a better bottom line.

Figure 3. Multi sample login.


W ith the recent growth in production of shale gas in North America, continental gas prices have dropped considerably. In the US, this

has had a positive impact on the economics of chemicals production where natural gas is used as feedstock, and has also made natural gas an attractive fuel for power generation. Low North American gas prices have also attracted international buyers for the resource. For example, increased demand for natural gas in Japan due to the Fukushima nuclear power plant accident, Germany’s desire to wean itself from nuclear power, and Europe’s drive to become independent of Russian natural gas have all influenced demand. This foreign demand for North American gas has spurred the development of a new US infrastructure for exporting gas in the form of LNG. The process of developing the North American liquefaction and export capacity has been met with multiple hurdles. There are strong lobbies to keep the resource on the continent to help grow the local industrial base as the US works its way out of the recent economic recession. From an administrative perspective, the US regulatory environment has not historically been

structured to address large scale liquefaction and export of LNG. The US Department of Energy (DOE) must first issue authorisation before any business can export US natural gas to non-free trade agreement (non-FTA) countries. The anti-export lobby has been vocal in the US media, and is keen to prevent authorisations. To date, only four

facilities have received DOE export authorisation: Sabine Pass Liquefaction (Cheniere), Freeport LNG, Dominion Cove Point LNG, and Lake Charles Exports. The US Federal Energy Regulatory Commission (FERC) has identified almost 30 individual projects in North America that are trying to capitalise on LNG exports.

All applicants for a permit to develop an onshore liquefaction

facility must satisfy the regulatory requirements of the US Pipeline and Hazardous Materials Safety Administration (PHMSA) in the Department of Transportation (DOT). These requirements are enforced by the FERC. The permitting process has become a significant business hurdle for proposed projects. For projects that are at the exploratory stage, the DOT/FERC permitting process is now often considered in the context of fatal flaw analyses to assess

MOVINGDr Harri Kytömaa and Dr Trey Morrison, Exponent Inc., USA, explore US regulatory challenges faced by the LNG industry.

TARGET

A


project feasibility. In light of the fact that LNG liquefaction technology is well established, with an impeccable operating and safety record, it is perhaps surprising that meeting the US regulatory requirements continues to be a considerably time-consuming hurdle. The reasons for this derive firstly from the fact that both PHMSA and FERC have changed the criteria on multiple occasions regarding what accident scenarios must be considered; secondly from the prescriptive nature of the regulations; and finally from the fact that the regulators constrain the industry with respect to the tools that can be used for safety analyses – to the point of excluding commercial tools that have been validated, peer reviewed and widely used. This article elaborates upon these issues, and explores ways of overcoming them.

BackgroundThe US regulations covering import and export LNG facilities are written in the Code of Federal Regulations Title 49 Part 193 ‘Liquefied Natural Gas Facilities: Federal Safety Standards’ (49CFR193), which incorporates the National Fire Protection Association (NFPA) standard 59A ‘Standard for the Production, Storage, and Handling of Liquefied Natural Gas (LNG)’ 2001 edition to address technical details. 49CFR193 and NFPA 59A prescribe that potential fire hazards remain onsite (i.e. within the facility boundaries) in the event of a loss of containment. NFPA 59A (2001) prescribes a series of 10 minute duration design spills (also called single accidental leakage sources), which must be analysed. These spills are defined for LNG and not flammable refrigerant liquids, and are all large diameter pipeline failure cases. The hazard is manifested by the ignitable cloud and the radiant heat from pool fires, and the public cannot be exposed to these hazards. However, the regulations do not address the hazards posed to onsite personnel. The ignitable cloud and radiant heat flux that are deemed dangerous to the public are both required to remain within the property boundaries. The areas within the facility boundaries impacted by the design spills are termed as ‘exclusion zones’ where potential fire hazards exist. To meet these requirements, FERC specifies that only passive mitigation strategies can be applied and does not allow for active leak detection or fire protection systems to be utilised in meeting the criteria.

A moving target: regular changes in the rulesOver the past decade, FERC has clarified its interpretation of the federal requirements by means of formal letters, less formal precedent-setting memoranda, as well as data requests to specific projects requiring certain analyses to be performed. It is clear that the regulations were developed with only small peak-shaving and regasification import terminals in mind. As a consequence, FERC has issued interpretations that continue to evolve over time, with the continual introduction of new criteria. The most significant changes were implemented during

the past few years, including the approval methodology for vapour dispersion software tools1 – a new method of identifying single accidental leakage sources – and the introduction of vapour cloud explosion calculations for flammable refrigerants. Other details of the changes are addressed elsewhere.2

Vapour cloud explosion hazardsLiquefaction plants contain flammable refrigerants in significant volumes. Two well-established refrigeration processes are the ConocoPhillips Optimized Cascade® Process3 and the Air Products and Chemicals Inc. propane/pre-cooled mixed refrigerant process.4 In most refrigeration processes, the mixed refrigerants are proprietary mixtures of flammable gases that may include methane, ethane, ethylene, propane, and iso-pentane.

Some of these refrigerants are more energetic than natural gas when burned. That is particularly the case with ethylene, which can undergo vapour cloud detonation. As NFPA 59A does not address this risk, FERC now references 40 CFR 68 ‘Chemical Accident Prevention Provisions’ to require applicants to analyse vapour cloud explosions associated with worst-case flammable gas releases, to identify the 1 psi over-pressure boundary, and to analyse the associated offsite consequences of 1 psi and greater overpressures.

The latest single accidental leakage requirementsIn 2010 and 2011, single accidental leakage scenarios had to be chosen based on pipe or component size, and later, pipe length. These initially prescriptive criteria were superseded in May 2012 by the requirement that single accidental leakage source hole sizes be selected for analysis if the likelihood of failure is greater than 3 x 10-5 failures per year.5 Recently, FERC has deferred to PHMSA on definition of leakage scenarios. A detailed discussion of the criterion’s development and application is provided elsewhere.6,7 FERC staff provided a table of yearly failure rates for piping and other equipment. All single accidental leakage sources that need to be considered are now selected based upon the length of the piping system and the resulting failure rate for a given hole size. This latest change was a paradigm shift from a strict prescriptive approach to one that is based

Figure 1. Use of computational fluid dynamics (CFD) for analysing vapour dispersion.

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on a failure rate criterion, even though the consequences remain prescriptive because the exclusion zones must remain within the boundaries of the facility. This paradigm shift constitutes a step closer towards international criteria, which are commonly based on quantitative risk analysis (QRA), e.g. in the European Standard EN-1473.

Limitations of the prescriptive DOT regulationsPrescriptive regulations tend to be application-specific, and inherently lack flexibility in being able to easily accommodate changes in processes or technologies that had not been originally anticipated. This limitation is certainly at play with the current DOT regulations for LNG terminals, as is demonstrated by the continual regulatory reinterpretation of requirements as new issues arise. Prescriptive regulations also tend to erect barriers that have the effect of discouraging the introduction of new solutions or technologies, as these often fail to meet the requirements as a simple consequence of not being anticipated, and therefore not being prescribed as an option.

An example of an alternative technology is the use of vacuum-insulated pipe-in-pipe for conveying LNG.8 The use of a pipe with an outer pipe that is rated for cryogenic service will provide full containment in the event of the failure of the inner pipe. In the event that either the inner pipe or the outer pipe fails, a leak would be detected by a

loss of vacuum. This arrangement is attractive for situations where a single walled pipe is located close to a property boundary that would cause an unacceptable consequence when applying the FERC-prescribed pipe failure scenario. With pipe-in-pipe technology, not only would a release be contained, but the probability of both pipes failing is much lower than that of a single pipe failing, and would, in most instances, fall below the 3 x 10-5 threshold, thereby eliminating this scenario as one that requires further analysis. While this concept has routinely been used in industrial gas applications, it has not been used in the US because the regulators do not consider it acceptable for LNG.

A regulatory environment that employs QRA is expected to be more receptive to such mitigation methods. Vacuum insulated pipe was utilised for the LNG transfer line at the Skangass LNG receiving terminal in Lysekil in Sweden. The QRA methodology, which is often used for LNG projects outside of the US, primarily focuses on the overall probabilistic risk of the loss of life and property. The QRA methodology is generally more flexible and can be accepting of hazards impacting neighbouring populations as long as the overall risk is acceptable. Similarly, the QRA framework often accommodates new technologies or configurations that may not be conceivable under prescriptive rules, as long as the overall risk to life and property remains below acceptable bounds. In the instances where the overall risk associated with a specific pipe segment is too high, solutions such as pipe-in-pipe can therefore be very effective.

Why are state-of-the-art CFD tools not used?In the early days of the LNG industry in the US, namely in the 1970s and the 1980s, a considerable effort was undertaken by both the industry and governments to characterise the risks associated with LNG spills. This involved both large scale tests (e.g. the Falcon and the Burro test series in the Nevada and California deserts), as well as the development of mathematical models to analyse vapour dispersion. As LNG is spilled onto the

ground, it evaporates creating a cold cloud that is heavier than air. As it disperses, this cloud slumps under its own weight and is carried by the wind. At that time, computational fluid dynamics (CFD) was in its infancy, and robust commercial packages did not exist. The research efforts resulted in tools to compute the size and shape of dispersing dense clouds using an integral approach, such as HEGADIS, DEGADIS and SLAB. These simplified models are good for flat ground with no obstacles such as vapour barriers, buildings or tanks. They are easy and quick to use, and became the tools of choice for vapour dispersion, in particular DEGADIS in the US.

With the revival of the LNG industry in the early 2000s, DEGADIS continued to be used for spills into sumps and

Figure 2. Pipe-in-pipe technology.

Figure 3. Cheniere’s Sabine Pass LNG terminal.

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impoundment areas. But the need soon arose to take into consideration spills into trenches and obstacles such as vapour fences and tanks. The simple integral models that were only able to address approximately circular evaporating pools on flat ground were not up to the task. In the meantime, CFD tools had matured and were, by then, widely used in industry and government laboratories, as well as academia. A large body of literature had developed that included the peer reviewed, scientific validation of commercially available tools that included FLUENT, CFX, Star-CCM and many others. The relevant physics of dense cloud dispersion9 were all well established and incorporated into many commercial CFD software packages by the early 2000s. One of the important developments that helped bring CFD into wide use was the introduction of unstructured meshing that allows fine mesh discretisation where it is needed, such as near walls and in areas of high velocity gradients. Combined with the continually increasing processor speeds, these CFD software packages are routinely run on laptops today. But these capabilities, and the wide body of validation that was already in the public domain, did not satisfy the US regulators.

Instead, after much study, DOT proposed a formal process for the approval of analytical tools for vapour dispersion at LNG facilities. The Model Evaluation Protocol (MEP) was published in April 2007 and requires prospective dispersion models to be compared to a database of spill tests on ground and water, and associated vapour dispersion measurements that were conducted over the past decades.10 It is relevant to note that the National Association of State Fire Marshals (NASFM) concluded that the MEP was unnecessarily long and complex.11

Four years after the publication of the MEP, a single CFD software product was approved by DOT (PHMSA) in 2011, namely FLACS Version 9.1. No other CFD product is currently approved. The FLACS CFD software is commercially available, and can model vapour dispersion scenarios and vapour cloud explosions in 3D.12 This CFD model discretises the domain using a rectangular grid, which is much less computationally efficient than state-of-the-art CFD codes.

Other CFD vendors have not jumped at this opportunity for two reasons. The first relates to the size of the market from the perspective of the developer of CFD codes, or to how many licenses they can sell. The other relates to the size of the undertaking to obtain DOT approval through the MEP process. In comparison with the number of CFD licenses that software companies may sell on an annual basis, the total number of LNG projects in North America is very small. For that reason, the high cost of undertaking the MEP process, which can be in the hundreds of thousands of US dollars, renders it an unattractive business proposition.

The consequence is that many tools that are better suited for this vapour dispersion application are not available to the US LNG industry. Instead, the industry is constrained to using a single, less computationally efficient CFD tool that is used by fewer service providers.

ConclusionWhy are these issues of scenario definition, hazard criteria, and model selection important? Should not the issue of vapour dispersion be easily addressed for all projects? Vapour dispersion, while one of a large number of elements that requires consideration for prospective US LNG liquefaction facilities, has become one of the more difficult to satisfy. In fact, this step has become such a challenge for projects that are at the exploratory stage that the DOT/FERC permitting step is now often considered in the context of fatal flaw analyses, even before FEED studies. A larger, strategic shift in regulatory requirements to meet international quantitative risk criteria could provide more flexibility and innovation within the field of LNG facility safety in the US, while balancing the broader business case for expansion. Likewise, streamlined acceptance criteria for CFD software packages with a stronger reliance on the peer reviewed literature could facilitate the safety analyses.

References1. ‘Evaluating Vapor Dispersion Models for Safety

Analysis of LNG Facilities Research Project’, Fire Protection Research Foundation, April 2007.

2. Ibarreta, A.F.; Hart, R.J.; Morrison, D.R.; and Kytömaa, H.K., ‘A View of the evolving LNG regulations and associated exclusion zones from an industry perspective’, American Institute of Chemical Engineers 2013 Spring National Meeting, 13th Topical Conference on Gas Utilization, San Antonio, Texas, USA, 28 April - 2 May 2013.

3. lnglicensing.conocophillips.com/EN/Documents/ConocoPhillipsLNG_Brochure.pdf

4. This liquefaction process is often called C3MR in reference to propane pre-cooling and the use of a mixed refrigerant.

5. ‘Meeting Summary, Corpus Christi Project, Docket No. PF12-3-000, LNG Engineering Conference Call, May 7, 2012’, FERC Document Accession No. 20120507-4014.

6. Kohout A., ‘Regulatory Framework and Guidance for Siting Liquefied Natural Gas Facilities – A Lifecycle Approach’, Proceedings of Mary Kay O’Connor Process Safety Center, 15th International Symposium, College Station, Texas, USA, 23 - 25 October 2012.

7. McInerny, E.H.; Hart, R.J.; Morrison, D.R.; and Kytömaa, H.K., ‘New Quantitative Risk Criteria for U.S. LNG Facilities’, American Institute of Chemical Engineers, 2013 Spring Meeting, 9th Global Congress on Process Safety, San Antonio, Texas, USA, 28 April - 1 May 2013.

8. Admiraal, E., ‘A Long Time Coming’, LNG Industry, September/October 2013, pp. 62 - 65.

9. These include gravity, turbulent mixing, convective heat transfer, the need to accommodate multiple species (e.g. air and gas vapour), and the ability to impose atmospheric wind conditions.

10. ‘Evaluating Vapor Dispersion Models for Safety Analysis of LNG Facilities Research Project’, Fire Protection Research Foundation, April 2007.

11. Review of the LNG Vapor Dispersion Model Evaluation Protocol Report of the Technical Panel Prepared for The National Association of State Fire Marshals, Prepared by AcuTech Consulting Group, 28 January 2009.

12. http://www.gexcon.com/flacs-software


M ercury (Hg) and hydrogen sulfide (H2S) are recognised as serious contaminants of hydrocarbon streams that must be removed to

avoid corrosion of equipment and poisoning of catalysts, and to comply with environmental regulations.

Johnson Matthey has developed a range of fixed bed absorbents for both H2S and mercury removal. This article demonstrates the benefits that can be achieved from the PURASPECJM

TM fixed bed technology.

Sulfur removalDuring the early stages of gas processing projects it can be difficult to get a detailed composition of the gas stream and its associated impurities. This uncertainty has sometimes led to acid gas removal units being over designed to take into account the fluctuations in H2S concentration. Introducing a more flexible approach to sulfur removal could have saved the extra CAPEX in those cases.

To meet stringent product specifications with varying feedstock, a single sweetening unit may not be the most

cost-effective option and it would be worth considering a two-step process, such as a bulk sulfur removal step followed by a polishing step. A phased investment approach would also reduce capital expenditure, as capital is only spent when required. By realistic assessment of the project development and the inclusion of appropriate civil work and tie-ins, investment can be delayed, cash flow improved, and, in some instances, unnecessary capital expenditure avoided. Operators can also benefit by taking advantage of ongoing process and product improvements.

A conventional acid gas removal plant uses a solvent to trap the acid gases at ambient or a lower temperature and the solvent is regenerated in a reboiler. The absorption is carried out at pressure in a packed column and regeneration is carried out at close to atmospheric pressure in a stripping column. Figure 1 shows a typical acid gas removal flowsheet.

Johnson Matthey has developed a range of high capacity absorbents that use the high rate of reaction of H2S with activated metal oxides for its complete removal:

H2S + metal oxide = metal sulfide + H2O

CAPTURING CONTAMINANTS

Vince Atma Row and Tony Hood, Johnson Matthey, UK, discuss desulfurisation and mercury removal from natural gases.


Gas sweetening with combined amine and fixed bed absorberA combined activated-MDEA, TEG dehydration and fixed bed polishing system was installed in Europe to remove H2S down to <3.3 ppmv, while simultaneously controlling sales gas CO2 content to <4% (Figure 2). The plant was designed to process any of four different feed gases or a mixture. Inlet concentrations of H2S varied from 2 – 50 ppmv, while the CO2 level in the feed gas ranged from 4.5 – 10.5%. The aMDEA absorber was only designed to handle the fraction of full production gas flow, which, when combined with the gas bypassing the absorber, yields the required sales gas CO2 content. This gas must be polished to bring it within H2S specification. The absorber is also provided with multiple injection points so that, at low production rates, all the gas can be processed through the absorber to remove H2S, whilst not exceeding the required removal of CO2.

Integration of membranes and fixed bed polishingThe PURASPECJM fixed bed technology for H2S removal can also be integrated with a membrane unit to offer significant flexibility in plant operations. A gas processing facility in Australia processing raw gas contains 5 – 6% CO2 and 8 – 10 ppmv H2S that necessitates some treatment before transmission down a dedicated pipeline to

an industrial customer. The first purification stage is a carbon bed to remove polycyclic aromatics (PCAs) to prevent fouling of downstream membrane materials. This is followed by the membrane separator, which produces a permeate stream rich in CO2, which is burned while reducing the CO2 in the product stream to less than the 4% specification. The membrane unit also reduces the H2S to 5 – 6 ppmv but further removal is needed to achieve the product specification of <3.2 ppmv. This is provided by a fixed bed unit, which has been in service since 1993. H2S is completely removed from gas passing through the absorbent beds and the bypass valve is adjusted to ensure that export gas always meets specification while absorbent consumption is minimised. Typically 35 – 40% of the gas stream is treated. Operation has been reliable and trouble free, demonstrating the suitability of these technologies to remote locations, including offshore, where there are limitations on space, weight and labour availability (Figure 3).

Mercury distribution on gas plantsAlmost all hydrocarbons contain mercury. In the case of natural gas and natural gas liquids (NGL) it is likely to be present as elemental mercury. In the case of crude oil it may also be present as organo-metallic and ionic mercury. The concentration of mercury in natural gas varies widely from 450 – 5000 µg/Nm3 in some fields in North Germany, to less

than 0.01 µg/Nm3 in some parts of the US and Africa.

Although the levels of mercury recorded are low, the tonnages of hydrocarbons handled are enormous, so downstream processing equipment is exposed to a substantial amount of mercury. Thus a typical 10 000 tes/d LNG plant would use 600 million ft3/d of natural gas and if this contained 100 µg/m3 of mercury, the plant would receive 582 kg of mercury per year.

The main concerns associated with mercury are:

� Corrosion of process equipment.

� Exposure of workers to high levels of mercury during maintenance operations.

Figure 1. Typical acid gas removal flow sheet – amine wash system with drier.

Figure 2. Gas sweetening with combined amine and fixed bed absorber.

Figure 3. Integration of membranes and fixed bed polishing.


� Difficulty in disposal of mercury contaminated equipment.

� Emissions to the environment.

� Potential liabilities resulting from mercury contaminated product streams.

Two major types of mercury corrosion can be observed. These are amalgam corrosion and liquid metal embrittlement (LME). Amalgam induced corrosion is shown by any metal capable of forming an amalgam with mercury. Most metals owe protection from corrosion to the presence of an oxide layer. If this protective layer is damaged in the presence of liquid mercury, then the metal can show its full reactivity and attack by air or water is rapid.

LME involves the diffusion of mercury into the grain boundaries and results in cracks developing along the grain boundary. This type of attack does not involve air or water and, once initiated, progresses rapidly, often with the result of a catastrophic failure.

Little data has been published on the distribution of mercury on gas processing plants and its monitoring has tended to be only from specific feed and product streams. Over the last few years a number of surveys have been carried out by Johnson Matthey on gas processing plants located in the UK, North Africa, the Far East and South America. Measurements were made using the Sir Gallahad II mercury analyser.

The nature of the plants and the difficulty of carrying out the measurements meant that it was not possible to carry out a mass balance on the distribution of mercury through the various process streams. Instead, a number of readings were obtained showing the steady state concentrations of mercury at the various process stages. Not all of the plants had all of

these processing stages, and only two of the seven plants quoted had mercury removal beds.

Figure 4 clearly shows that mercury is distributed right through the plant and is adsorbed on all the metal surfaces, which makes maintenance and decommissioning of redundant equipments highly hazardous.

A mass balance was also carried out on a gas processing plant in the Far East. The gas flowrate was 50 million ft3/d and the mercury balance was carried out across the main processing units. The results are shown in Table 1.

Mercury removal processesThe traditional method for the removal of mercury relies on its reaction with elemental sulfur. The sulfur is deposited on a support, typically carbon, and

the resulting captive mass is used in a fixed bed reactor. The reaction is rapid and high levels of mercury can be absorbed onto the bed. There are numerous units in service on gas processing plants around the world, although there are some major drawbacks from using activated carbon.

Sulfur impregnated carbon can only be used on dry gas. Activated carbon has a very high surface area and a small pore size (average pore size <20 angstrom). This makes it an effective adsorbent, but prone to capillary condensation. This restricts the access of mercury to the sulfur and increases the length of the reaction zone. It has been shown that as little as a 3% loading of water on carbon increases the mass transfer zone by 12% and allows slippage of 0.02 µg/m3 of mercury. Sulfur can be lost by sublimation and by dissolution in hydrocarbon liquids. This not only reduces the capacity for mercury, but also leads to fouling of downstream equipment. The need to avoid condensation and migration of sulfur poses problems for operators of LNG and nitrogen rejection unit (NRU) plants. If carbon is used then it must be located downstream of the molecular sieve dryers and it can only be dried with cold gas. Disposal of spent absorbent containing mercury is primarily through landfill. Since the carbon bed is situated downstream of the mol sieves, the front end of the gas processing plant is saturated with mercury if it is present in the gas.

Mercury can also be removed by amalgamation with a precious metal such as silver or gold. This provides effective removal with the potential for regeneration by heating. Doping the molecular sieves used in gas dryers with silver has used this approach. At first sight this is an elegant process, but the mercury is not stored. All metal amalgams release mercury as the temperature is raised, so mercury is released into the regeneration gas and enters the condensed water. This system is also not applicable in the presence of high levels of H2S.

Johnson Matthey’s PURASPECJM material relies on the high reactivity of mercury with the metal sulfides of certain variable valency metal sulfides:

Hg + MxSy = MxSa + HgS

The reactive metal is incorporated in an inorganic support and the absorbent is supplied with reactive sulfide present, or this is formed ‘in situ’ by reaction with H2S in the hydrocarbon to be treated.

Figure 4. Mercury distribution on gas processing plants.

Table 1. Distribution of mercury on a 50 million ft3/d gas plant

Process stream Mercury (kg/year)

Raw gas 220

Acid gas removal vent 22

Dryer vent 3

Condensate 45

Sales gas 150

www.jmprotech.com

Johnson Matthey offers a comprehensive range of high-performance absorbents for the removal of sulphur and mercury from hydrocarbon streams.

By carefully co-ordinating the choice of absorbent for the duty, we enable our customers to maximize production and optimize performance. This is why many of our customer relationships span several decades, and why they continue to work with us for all of their purifi cation needs.

Our range of PURASPECJM fi xed bed technology provides:

∆ Impurity removal to a very low level

∆ Effective low temperature operation

∆ Simple and fl exible operation

∆ Easy retrofi tting

∆ No hydrocarbon losses

∆ An environmentally friendly solution

∆ Plant optimization assistance

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The PURASPECJM technology offers a number of advantages over carbon, including the following:

� The spent mercury absorbent can be recycled through metal smelters.

� The materials can be used on wet and dry gases.

� The reactive species and the support have meso-porous structures with little affinity for hydrocarbons. There is little risk of capillary condensation even when used with gases at very high pressures (120+ bar).

� There is no risk of sulfur migration by sublimation or dissolution.

� The absorbents can be used to process liquid hydrocarbons.

Location of the mercury removal unit The location of the mercury removal unit is thus critical in ensuring that most of the mercury coming into the plant is removed as far upstream as possible. The PURASPECJM material has been designed to operate in a gas that is at its hydrocarbon/water dew point and can thus be installed directly upstream of the acid gas removal unit. This prevents mercury contamination of the amine wash and drying stages. During start-ups the mercury guard does not require an extra drying step, as any moisture liberated from the bed will be absorbed by the dryers downstream, hence reducing start-up time for the gas processing or LNG plant. Figure 5 shows the location of the PURASPECJM mercury and sulfur removal units.

Recycling of spent sulfur and mercury absorbentsSome traditional reprocessing routes for spent catalysts such as landfills are now generally considered to be environmentally unsound. Using these facilities may therefore not be in the long-term interests of the operator, even though they may be cheaper in the short-term. There is also an ever-increasing volume of environmental legislation that can make catalyst reprocessing a time consuming and daunting activity.

Johnson Matthey has a full reprocessing package which includes:

� Complete commitment to recycling.

� No use of landfill or food chain related reprocessing routes.

� Use of facilities that are properly licensed and environmentally audited.

� Provision of a certificate of consumption.

All movements to the reprocessing plant are carried out under international legislation including Trans-Frontier Shipments of Hazardous Waste. The material is imported into a plant that removes absorbed mercury before transfer of the absorbent itself to a final outlet that extracts the metals and recycles them into the industry.

Therefore, all metals, including mercury and sulfur, are

purified and returned into the chemical industry. All processes involved have been audited and trialled by the company before offering its customers environmentally friendly recycling of their spent mercury guard absorbents.

ConclusionDevelopment of new high activity mercury and sulfur removal absorbents allows greater flexibility in the design of gas processing plants. It is now possible to locate the mercury removal unit upstream of the main gas processing plant and thus avoid mercury emissions and contamination of any co-produced NGLs. The PURASPECJM sulfur polishing unit can be used in conjunction with a bulk sulfur removal technology, not only to give added flexibility, but also to deliver a more cost-effective sulfur removal step.

The high activity of the PURASPECJM absorbent allows for smaller beds, which, coupled with novel reactor designs, allows for savings in compression costs. The PURASPECJM absorbents can be fully reprocessed and thus offer an environmentally acceptable route for disposal.

Bibliography• Coyle, D.; de la Vega, F. F.; and Durr, C., ‘Natural Gas

Specification Challenges in the LNG Industry’, LNG15, Barcelona, Spain, 24 - 26 April 2007.

• Carnell, P., J.H.; Joslin, K.W.; and Woodham, P., ‘Fixed-Bed Processes Provide Flexibility for COS and H2S Removal’ 74th Annual GPA conference, San Antonio, Texas, USA, 13 - 15 March 1995.

• Carnell, P.; McKenna, R.; and Row, V., ‘A Re-think of the Mercury Removal problem for LNG Plants’, LNG15, Barcelona, Spain, 24 - 26 April 2007.

• Kane, A.; Gardiner, J.; Abraham, N.; and Judd. R., ‘Assessment of the options for Gas Blending and Ballasting’, February 2005.

• Openshaw, P.; Abott, J.; and Woodward, C., ‘Process Design and phased investment’, Johnson Matthey, 2002.

• Carnell, P., J.H., and Openshaw, P. J., ‘Mercury Distribution on Gas Processing Plants’, GPA Spring Mtg., Dublin, Ireland, May 2004.

• Openshaw, P., J. H. and Woodward, C., ‘New Developments in Mercury Removal’, AIChE Spring National Meeting, Houston, Texas, USA, 22 - 26 April 2001.

• Carnell, P., J., H.; Openshaw, P., J., and Rhodes, E. F., ‘Fixed-bed Technology Purifies Rich Gas with H2S, Hg’, Oil & Gas Journal, May 1999.

Figure 5. PURASPECJM beds on the optimised gas procesing flow sheet.

D riven by growing domestic natural gas reserves, favourable gas prices, and stricter emission regulations in North America, LNG is beginning to replace traditional oil-based fuels in marine or heavy vehicle engines,

power generation, and process industries. This emerging ‘Merchant LNG’ market calls for decentralised small to mid scale LNG plants and is now growing beyond a niche market.

Linde’s Air Separation Units (ASUs) have been in use for more than a century and, over time, have been optimised and standardised. To take advantage of LNG’s current position as a clean fuel on the verge of a breakthrough in the North American market, Linde has applied this standardisation idea to small scale LNG.

StarLNGTM provides a small to mid scale LNG plant suitable for a wide set of capacity and process variations. A generic LNG plant design for a 200 tpd (net liquefaction capacity) base case is surrounded by many alternatives, with pre-engineered documents including a 3D CAD-model for a fully modularised plant. A ‘process toolbox’ approach was designed to cover about 90% of real-life boundary conditions, with the following major benefits:

� Safety levels matching world scale LNG plants.

� Fast-track EPC time schedule.

� Reduction of Capex.

SMALL SCALESharon Benard, USA, and Matthias Bruentrup, Germany, Linde Process Plants, look at standard small scale LNG plants.

Figure 1. Small scale LNG plant liquefying natural gas coming from a natural gas liquids recovery plant located in Kwinana, Australia.

STANDARDISATION


� Highly efficient processes that are easy to operate.

� Modularised units for pre-treatment, processing and main pipe racks.

� Configuration flexibility with many options.

The StarLNGTM standardised plant concept covers a capacity range from 0.03 – 0.5 million tpy and uses a robust and easy-to-operate single mixed refrigeration process based on proven technology.

Industrial standardisation is a necessary response to clients requiring shorter delivery times for a previously custom-designed product. Unlike ASUs, there is considerable variation in the feed compositions and conditions for a LNG plant. To cover the anticipated range while still avoiding overdesign (and high cost) based on a combination of worst-case conditions, the process was considered as a series of modules – a ‘toolbox’ approach (see ‘Toolbox approach’ sidebar).

Combining these modules as needed in the liquefaction cold box makes it possible to design a StarLNGTM plant for most pipeline gas compositions worldwide. The plant configuration comprises all systems typically needed for a small scale LNG business including LNG storage and off-loading, utilities, and infrastructure.

Plant’s coreThe core of an LNG plant is its refrigeration system. LIMUM is Linde’s high efficiency single mixed refrigerant process. This closed cycle refrigeration system provides cryogenic

temperatures via two-staged compression followed by Joule-Thomson expansion and liquid evaporation of the mixed refrigerant. Energy efficiency is similar to competing two-staged mixed refrigerant processes, approximately 5 – 10% higher than single-staged processes (such as PRICO) and 20 – 30% higher than nitrogen expander plants. For the given capacity range, a mixed refrigerant compressor is simpler and more robust than large compander machines or split compressors and expanders respectively. The LIMUM process also has a low equipment count.

TransportationA road transportable, generic module concept was developed for StarLNGTM to serve markets with high on-site construction costs. The concept’s 3D-CAD model targets minimum hook-up work and moderate crane lifting capacities on site while facilitating road transport, including escorts or special permits if necessary. Process modules are typically manufactured in-house, and so can be split into smaller units for transportation if needed.

SafetyAs LNG is a flammable hydrocarbon with a very high energy density, plant safety is Linde’s number one priority under all circumstances. Significant effort has thus been put into safety of design and safety reviews of the process and the plant layout, all of which is reflected in standard documents such as:

� Detailed hazard and operability (HAZOP) study.

� Detailed hazard analysis (HAZAN) study.

� Hazardous area plan.

� Fire fighting plot plan.

� Fire and gas detection plot plan.

� Quantitative risk assessment (QRA) report.

Understanding all safety requirements and constraints on this basis at the outset of a new LNG project helps to satisfy these guidelines by attentive plant design, rather than by adding expensive protection systems during later project stages. During execution of a previous LNG plant, it was found that otherwise cost-neutral modifications of the plant layout would have resulted in savings for passive fire protection. Unfortunately, this opportunity was only considered at an execution stage where such layout modifications were no longer feasible.

Risks from new LNG plants to surrounding populations are a concern in any LNG project development. This is generally a more serious issue for small scale LNG plants, as they are typically located close to their LNG end users in more populated areas than world scale LNG plants or terminals. Just following the design guidelines provided by LNG standards such as 49 CFR 193 or NFPA 59A does not tackle such concerns, as they only define technical minimum requirements and do not provide quantification of the risks to the surrounding population. QRA for StarLNGTM plants has proven a valuable basis for activities such as comparing the risks of different LNG plant design alternatives, assessing the adequacy of separation distances, benchmarking the risks of an LNG facility against the risk profiles accepted in other industries, etc.

Toolbox approach (exemplary for the liquefaction unit, see Figure 2)With an ‘ideal’ feed composition (a close match to the LNG product), a straight-through liquefaction can be applied as the only processing step. This is the simplest option and so was chosen as the base case (liquefaction unit).

If a feed gas contains heavier hydrocarbons (HHCs), such as hexane, freezing will occur during liquefaction if the concentration has not been lowered sufficiently. This is handled by adding a knock-out drum to the base case, operated at a controlled temperature below the dew point of HHCs (HHC separator).

It may be undesirable to have heavy hydrocarbons, such as ethane or propane, accumulating at higher concentrations in the LNG product, e.g. if it is to be used as vehicle fuel. Those components can be removed via the addition of a stripping column to the base case liquefaction process.

High nitrogen concentration in the feed gas may require removal to avoid increased process energy consumption, reduced LNG product heating value, or to address storage safety concerns (stratification and roll-over in the tank). A nitrogen rejection column can then be added to the base case liquefaction process (N2-removal unit).

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StorageSensitivity calculations, based on direct EPC execution experience, were performed to gauge the risk to external population associated with different storage alternatives for different sites:

� Flat bottom tank, single containment.

� Flat bottom tank, full containment.

� Sphere with secondary impoundment.

� Bullets with secondary impoundment.

� Bullets with full-integrity design (not requiring secondary impoundment whilst providing even higher safety).

Storage capacity for 3 – 10 days of plant production is common for small scale LNG plants. Considering the high cost of LNG storage volume, it is important to understand the economics of each alternative to retain the best fit for a specific project. Yet, there is no general response as to what storage solution is best for what LNG storage

volume. The answer is usually driven by the project specifics for on-site construction cost as well as shipping cost. Typical ranges for relative economics of various tank types are shown in Figure 3.

The use of pressurised storage (typically 30 – 40 psig) results in lower liquefaction power demand (up to 20%) and therefore offers significant Capex and Opex savings. Yet, pressurised storage is only recommended when the downstream distribution chain, all the way to the end user, is designed for this elevated pressure. Unlike the world scale LNG distribution chain, this is usually practical for new,

small scale LNG distribution schemes.

Case studyFor an LNG project in Western Australia, a client’s requirement for 4000 m³ (~1 million gal.) of LNG storage volume, combined with the economic advantage of low liquefaction power consumption, led to the selection of a spherical storage tank as the optimum solution. In view of high on-site construction costs, a feasibility and economic study of off-site prefabrication of the entire tank was conducted. Although pre-fabrication of the vessel in Europe, and marine and road transport to the site was confirmed as practical, the cost was found to be unfavourable since the increase in shipping costs exceeded the savings in fabrication cost. Therefore, on-site

construction was chosen, which resulted in one of the world’s first spherical storage tanks for large LNG volumes.

StarLNGTM can provide further value to any small scale LNG scheme project from the pipeline to the end consumer, with equipment supply including:

� LNG regasification units.

� LNG import terminals.

� Integrated LNG/NGL solutions.

� LNG/CNG fuel stations and dispensers.

� LNG road tankers.

ConclusionOverall, the standard plant concept, such as StarLNGTM, combines the benefits of custom designed plants including feedgas, product flexibility, high process efficiency and excellent operability with the benefits of short delivery time, competitive capital cost and minimum technical risk.

Figure 2. Toolbox approach, exemplary for liquefaction unit.

Figure 3. Economic LNG tank design vs. capacity.


The development of hydraulic fracturing technology and its success in the last five years in unlocking the abundant shale gas resources in North America and worldwide has been described as the single biggest energy development since 1859, when oil was

first discovered in the US. The availability of low cost natural gas, together with new global regulations on emissions, has created innovation and development across the complete LNG supply chain, and given stimulus to the creation of new market sectors. The development of small scale LNG, including the LNG distribution market sectors for onshore, offshore, lake and inland waterways is visible. Development of these new market sectors has been based on the industrial gas distribution market practices and technologies. A notable difference currently exists between the industrial gas sector and the mid/large scale LNG sector in the respective use of seal vs. seal less type pumps. As this article will demonstrate, this starting situation is not unexpected,

David Loughman, Nikkiso Cryo Inc., USA, looks at how the small scale LNG industry can benefit from the unique

properties of submerged motor pumps.


and follows the early trends in other LNG markets prior to switching to seal less only solutions. Submerged motor pumps (SMPs) are used for LNG applications including bunkering/loading, product transfer, vaporiser feed and road/train/barge tankers for cargo off-loading duties. They are also used for pumping both the associated fractionated natural gas liquids (NGLs), such as propane, butane, ethane, etc., and the downstream chemicals and petrochemicals (liquids such as ethylene, propylene and ammonia). SMPs are available in pot mounted, removable and fixed styles, thus providing the maximum flexibility with regard to installation and operation either inside or outside of storage tanks.

The first applications SMPs were introduced to the world LNG market as far back as the early 1960s, when LNG transport by ocean finally became a reality. The SMP was first developed and later employed by J.C. Carter Co. at the Lake Charles LNG plant

in the US before being applied to the LNG carrier Beauvais, built in France. After the initial shock of contemplating the presence of electric cabling and motors in a tank full of hydrocarbon liquid, the SMP solution eventually received global approval by the main classification societies of the day, based on the logic of the proposal and backed by hard facts. The SMPs were finally chosen as the LNG pump standard,

replacing the original external motor deep-well cargo pump arrangements (Figure 1) despite intervening efforts by major pump brands to enter the LNG market using seal type pumps.1 This standardisation continues today where all large and medium scale LNG projects, onshore and offshore, are equipped with SMP designs. Identical patterns can be seen in the development and standardisation of the submerged generator liquid and liquid/gas expander (SGEs) machines currently being applied.2 The range of equipment supplied has grown with the demands of the market and equipment performance envelope now covers a wide range, as shown in Figure 2. There have been over 10 000 units operating worldwide since the 1960s, with pumps in excess of 2.1 MW in size. In fact, full factory acceptance testing of SMPs at Nikkiso Cryo Inc.’s test facility in Nevada, USA, can be carried out currently using LNG, LPG, or liquid nitrogen up to 3000 m3/h, total differential head (TDH) 5000 m and 3.5 MW with continuous run times of over four hours a standard.

Case study 1 – operating near boiling point3 Common cryogenic fluids such as argon, nitrogen and oxygen are stored near their atmospheric pressure and pumped near their normal boiling points. These are the most common cryogenic fluids used in the industrial gas industry, which is currently the driver of the small scale LNG business. The fluids are delivered by over-the-road trucks. Each truck uses a single stage centrifugal pump driven by a hydraulic or electric motor to move these liquids from the truck to the storage tanks. One fleet operator with 25 trucks began an aggressive programme to reduce failures and improve equipment reliability. An analysis of the operation’s seal life and repair costs is shown in Table 1. Not only were the maintenance costs excessive, there were also financial losses when deliveries could not be made.

Conclusion � The most significant maintenance cost factor is related

to the mechanical seal life.

� The most common cause of pump failure is the failure of mechanical seals.

� Total life cycle costs are many multiples times the initial pump cost.

� Seal failure may be reduced and optimised but can never be eliminated.

� Costs do not include lost production and fire and safety risks including increased liability.

Table 1. Analysis of seal life and repair costs for the example cryogenic fluid delivery fleet operation

Cryogenic fluid sealed

Tankers in service

Average seal life in weeks

Failures per year

Cost per year Achieved savings with minimum seal life of 6 years

Argon 5 6 45 US$ 67 500 US$ 405 000

Nitrogen 10 14 35 US$ 52 500 US$ 315 000

Oxygen 10 25 20 US$ 30 000 US$ 180 000

Cost of maintenance per year US$ 150 000 0

Total savings over 6 years US$ 900 000

Figure 1. SMP fixed type vs. external motor pump.


Case study 2 – mechanical seal reliabilityIt is well known that bearing malfunction often precedes mechanical seal failure in centrifugal process pumps. Statistical information to that effect has recently been published in the technical paper ‘Mechanical Seal Reliability – What Realistically can be Achieved’, which facilitates assessing the benefits of sound remedial action.4 The data of interest were presented at the Mechanical Sealing Technology Seminar, IMechE, London. The presentation reviewed 11 000 mechanical seal failures from 148 different reliability contract and alliance plant sites over a two-year period. The findings are shown in Figure 3. Various studies estimate the world market for mechanical seals at US$ 3.2 billion/year.

ConclusionSeal failure cause costs are distributed as follows:

� Bearings: US$ 416 million/year.

� Alignment/installation: US$ 192 million/year.

� Process/operations: US$ 1560 million/year.

� Seal/seal system: US$ 832 million/year.

Case study 3 – sensitivity of seals to pump operationIn 1996, a major US chemical company conducted an exhausitve study whereby it surveyed the maintenance records of over 6600 chemical process pumps in its various plants and found (Figure 4):

� The most significant maintenance cost factor related to conventional chemical process pumps is mechanical seal life.

� The most common cause of chemical process pump failure is failure of mechanical seals.

� Running chemical process pumps outside of the preferred operating range (80 – 110% of BEP) has a major impact on mechanical seal life and in some cases can reduce mean time between failures by a factor of ten.

� Eliminating mechanical seals from a pump in chemical process duty has the potential to reduce maintenance cost by 65 – 90%.

Figure 2. Typical performance range covered by SMP.

Figure 3. Seal failure case distribution. Estimated world market for mechanical seals is US$ 3.2 billion/year.

Figure 4. Sensitivity of seals to pump operation.


Key features and benefits of SMP5

SMP typesThe SMP is a versatile design in that the same basic pump configuration, with all of its features and benefits, can be adapted in a variety of ways to meet various process, transport, transfer and storage applications in various static or dynamic installations. These installation types include suction pot mounted, removable and fixed.

The SMP consists of a single shaft design where the motor and pump hydraulic components (inducer, impellers) are mounted on a common shaft supported by product cooled ball bearings. The total pump assembly is mounted inside a suction pressure vessel and fully submerged in the pumped liquid. Once the entire SMP is cooled down initially and with no sealing or lubrication systems required, the design is on continuous standby and ready for quick start-up at any time. Figure 5 shows a typical SMP layout, in this case mounted inside a suction pot.

The SMP’s basic design excludes the key elements associated with the majority of pump failures today in all types of facilities worldwide. The SMP helps eliminate the majority of problems and costs associated with pumping LNG.

No shaft seals Whether the seals are contacting or non-contacting types, they will eventually either wear out, fail in operation, or, in some cases, fail while on standby, thereby contaminating the surrounding area, introducing fire and explosion hazards, as well as stopping production and deliveries of LNG. The best solution is to completely eliminate the requirement for

seals. Seals by their very nature allow the process liquid to become contaminated by the sealing medium upon failure and contaminate the surrounding areas of the pump with pumped product.

No thrust bearings and associated bearing lube systems Thrust bearings are designed for limited lifespan operation. This lifespan is further influenced by the need for regular maintenance and monitoring by plant personnel, as well as the cost associated with the consumption of lubricants. In the case of cryogenic installations, lubricants must be prevented from freezing or icing, adding to complication and costs. In the case of the SMP, all thrust is balanced using the balance piston arrangement, whereby the pumped liquid is used to float the rotating assembly, thus allowing the pump bearings to operate unloaded throughout the operating lifespan of the pump. This zero-load operating condition provides theoretically infinite lifespan of the SMP bearings. The thrust balance system is very robust and will operate in even the most extreme ciscumstances,such as on board Excelerate’s FSRU operations during Hurricane Katrina.6

SMPs operated continuously within their preferred operating capacity range can achieve in excess of 25 000 hours under field operating conditions.

No shaft couplings and critical alignment issue problemsThe SMP is designed to be fully self-aligning during assembly and repeatable during rebuilds by even the most inexperienced technicians with no need for critical base plate shimming and coupling set up. Cold leakage pathways, from internal cold liquid to external warm ambient moisture laden zone, result in heat-loss problems, which leads to cold spots and icing problems. Thermal distortion can cause eccentricities in the rotating assembly, resulting in binding during cool down or high vibration during operation.

No motor failures7 The conditions which normally lead to the deterioration and early failure of motors are not present in SMPs. Therefore it is not unusual to find original motors in SMPs that have been operating for up to 40 years in the field, as the motors are fully submerged in the pumped liquid and continuously wet with the process liquid passing through the rotor air gap to ensure homogeneous cooling. The pumped liquid provides an almost infinite heat-sink, ensuring sufficient cooling, resulting in a very low operating temperature rise (1 – 3 °C). Operating in such cryogenic temperatures also means that the motor sizing is smaller than equivalent external motors due to the superior electrical properties associated with materials at low temperatures. Since the motors are fully submerged in the pumped liquid, they are not exposed to the conditions that lead to deterioration and failure of the insulation system. Motors suffer short lifespans when operated in areas such as the deck of ships, shore based terminals, refineries, petrochemical and gas plants. These facilities operate in unavoidably severe environments, such as being exposed to marine, saline, brine, wet, condensation, corrosive/erosive environments, ambient temperature Figure 5. Suction vessel mounted.

It’s � nally arrived...




fluctuations, chemical attack, UV degradation, and physical damage due to impact from surrounding equipment and structures. As higher temperatures shorten motor life, it is estimated that for every 10 °C rise in operating temperature, the insulation life is reduced by half. The SMP is much quieter than an external motor design as the fluid acts as a buffer, greatly decreasing the overall noise level transmitted to the outside of the vessel.

Special canned motorIn the case of pumped liquids that are conductive, erosive or corrosive, there are solutions available where canned motors are incorporated in the SMP replacing the wet motor.

Disadvantages of seal type, deepwell or external motor pumpsSome disadvantages of using an external motor pump for LNG or other liquefied gas applications include the following:

� External motor pumps use a complicated seal arrangement, which is difficult to maintain and can fail in operation or on standby if not monitored and maintained on a daily basis.

� In addition to the seal, it is necessary to include a seal oil, gas and/or vapour chamber to control the pressure across the seal. When leakage of the seal into the LNG occurs, these frozen droplets can enter into the pump and damage the pump internals as well as the seal itself and even contaminate the process.

� It is not possible to vent the seal chamber area/barrier pot on initial start-up for proper seal operation and extended life. Any seal pot pressure loss will cause unrecoverable premature seal failure.

� A coupling is used between the motor section and the pump section, which requires careful installation and alignment. If any eccentricity occurs, the seals will fail rapidly.

� Because of the seal chamber area and larger motor, a two-piece shaft system must be used. Maintenance is more difficult and costly, due to the larger footprint and weight of the components.

� The external motor must have an explosion proof housing, and can be quite large in comparison to a submerged motor of the same power. This size will increase loads on the support structure, requiring a more expensive support design.

� The external motor may also use oil filled bearings and require a lube oil system with pumps to supply oil in and out of the bearings, which must be kept warm to avoid freeing and build up of ice. This adds complexity to the system. In addition, the power required for the lube oil system should be considered when calculating the overall efficiency of the pump/motor.

� Other disadvantages are listed in the bullet points of ‘Case study 3 - sensitivity of seals to pump operation’ (p. 75).

Zero emissions solution With the move toward tighter emissions control standards, especially in and around loading terminals and marine ports, there is a heightened awareness and fresh focus on the benefits of zero emissions pumping solutions. The SMP provides such a solution, which results in a simple and cost-effective means to ensure compliance with current and any future onshore or offshore regulatory emission standards around the world. Such regulations are hard to predict, but failure to comply can result in limitations to the operation of the vessel or the facility. The seal less pumps provide a ‘green solution’ to LNG pumping.

Safety and hazardsSMPs are inherently safe. No explosion proof motor is required since the inside of the suction pot or storage tank is classified as a non-hazardous area in accordance with NFPA 59A, due to the positively pressurised conditions associated with cold boiling liquids inside the tank, which precludes any possible ingress of oxygen. The exclusion of oxygen eliminates a key element of the ‘fire triangle’, and the compliance with certain specific operational measures results in a safe, non-hazardous operating environment. In addition, the SMP is completely contained within the pressure vessel or storage tank, which is non-accessible to plant personnel except after gas freeing and warming up the equipment, so that in the event of failure, the chances of surrounding collateral damage to personnel or equipment is greatly reduced.

High speed designs and variable speed control8

Companies such as Nikkiso Cryo Inc. have a history of variable speed operation and high speed pumping designs, which have been operating successfully for many years in the field. Experience with the Sundyne/Sundstrand high speed

Table 2. Typical life cycle cost breakdown example for a vertical lineshaft pumpCic Initial capital – two pumps @ US$ 75 000 each US$ 150 000

Cin Installation 0.75 x Cic US$ 112 500

Ce Electrical 51 kW x US$ 0.08/kWh x 8760 hrs *15 years US$ 536 000

Ce Water flush 3 GPM x US$ 0.02/gal * 60 min/hr * 8760 hrs/year x 15 years US$ 473 000

Co Operating cost (US$ 2000 operator allocation x 15 years) US$ 30 000

Cm Maintenance – two pumps @ US$ 75 000/year x 15 years US$ 2 250 000

Cs 10 000 bpd/@ US$ 3/bbl margin + 750 tbd coke @ US$ 50/t = US$ 67 000/day margin. Estimated 0.5 days/year lost production due to pump related slowdown or outages x 15 years

US$ 500 000

Cenv Environmental cost – estimated @ 5% of pump cost/year = US$ 3750 x 15 years US$ 112 000

Cd 2 x US$ 150 000 capital cost US$ 300 000

Total life cycle costs US$ 4 463 500


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pump designs, together with experience in aerospace rocket engine booster pump technology with speeds up to 92 000 rpm, creates an environment where the strengths and weaknesses of high speed design are understood and appreciated. Benefits of high speed pump design include:

� Smaller footprint with compact size and light weight, resulting in lower installation costs.

� High efficiency with proven high reliability under field operation conditions, resulting in a lower Opex.

� Reduced maintenance cost due to compact size and horizontal assembly features.

� Lower material cost of construction due to the smaller size, resulting in lower Capex price.

� Reduced total life cycle costs due to reduced Capex and Opex cost advantages.

� Superior process control and lower operating energy costs due to variable frequency drive (VFD) operation.

Evaluating life cycle cost9

It is important to evaluate all of the features and benefits offered by the seal less pumps vs. other types of pumps. Pump life cycle cost pertains to the total cost associated with installation, operation, maintenance and decommissioning activities during the course of a pump’s installed life, often 15 – 20 years and sometimes more. Most people who deal with pumps and pumping systems recognise that the initial capital outlay for a pumping system is small in comparison to the life cycle cost associated with the installed equipment. The problem is that many do not have life cycle costs quantified in such a way that they can be used effectively to make cost saving decisions. Below is a suggested formula, and Table 2 shows an example of a life cycle cost evaluation that demonstrates the importance of evaluating the true costs of less expensive initial capital pumps:

Total life cycle cost = initial capital cost + installation and commissioning costs + energy costs (electricity, steam, water, nitrogen) + operator costs (normal system supervision) + maintenance costs + downtime and lost production costs + environmental costs (related to leakage, emissions or decontamination) + final decontamination and disposal costs.

Selecting an LNG pumpIndividuals with reliable engineering backgrounds and an acute awareness of how and why pumps fail are best equipped to conduct the initial pump selection and specification process. The possible impact of a number of issues, including the ones mentioned in this article, should be considered, and are summarised below:

� One must keep in mind the potential value of selecting pumps that cost more initially, but last much longer between repairs. The mean time between failures (MTBF) of a better SMP may be many years longer than that of its external motor pump counterpart.

� Consider that the published average cost of pump failures does not include lost opportunity costs for production, delivery and plant operations, where these costs can quickly dwarf the initial cost of the equipment.

� Where spending time and effort for pre-purchase reviews of pump proposals, it makes economic sense to concentrate on the typical problems encountered with

centrifugal pumps. One should attempt to eliminate these problems before the pump ever reaches the field.

� Owners/operators should insist that total life cycle cost evaluations are included with any equipment recommendation or evaluation. Table 2 shows the intial capital cost of US$ 150 000 vs. total life cycle costs of US$ 4 463 500 – a 30 times cost ratio.

� There are several critically important pump applications where buying on price alone is almost certain to cause costly failures. These include the following:

� Applications with insufficient net positive suction head (NPSH) or low NPSH margin ratios.

� High specific-speed pumps. � Feed, transfer and product pumps without which the plant will not run.

� Vertical turbine deep-well pumps. � Seal vs. seal less pumps.

ConclusionThe submerged electric motor pump has been around now for over 50 years and has proven itself as an excellent solution for pumping LNG, NGLs, ethylene and other liquid hydrocarbons. Small scale LNG owners and operators can achieve significant operating reliability improvements and reduced total life time costs by specifying SMPs for their facilities.

References 1. Ffooks, R., ‘Natural Gas By Sea – the Development of a

New Technology’, Witherby & Co. Ltd, London, 1979.

2. Van den Handel, R., J.A.N., and Kimmel, H.E.,‘A New Generation of Liquid Expanders in Operation at Oman LNG’, Proceedings of the Gastech 2000, Houston, Texas, USA, November 2000.

3. Netzel, J., ‘What Do Seal Failures Really Cost?’, Article based on a presentation delivered at MARTS2008, April 2008.

4. Flood, S., ‘Mechanical Seal Reliability – What Realistically can be Achieved’, IMechE Mechanical Sealing Technology Seminar, London, UK, April 2007.

5. Loughman, D., ‘Unique Requirements Regarding The Installation, Operation and Maintenance Of Cryogenic Submerged Motor Pumps’, BPMA Pump Users Forum – Managing Lifetime Costs, May 1994.

6. Nikkiso Cryo Inc’s SMPs and thrust balance pistons can work under extreme conditions, as demonstrated in a video currently available here: http://www.lngindustry.com/videos/. NCI carried out qualification testing for Excelerate’s FSRU, which ensured NCI SMPs were able to maintain full send out capacity during Hurricane Katrina while stationed in the Gulf.

7. Loughman, D., and Cullen, D., ‘Submerged Electric Motor Pumps for Marine Liquefied Gas Carriers’, World Pumps Magazine, September 1996.

8. Wahl, F. A., ‘LNG Pumps For Floating Units’, Proceedings LNG17, Poster Session, Houston, Texas, USA, 2013.

9. Russell, D. P., ‘Evaluating Life Cycle Cost – Life Cycle Cost Calculator’, Lawrence Pumps Inc., available at www.lawrencepumps.com

Bibliography• ‘Technically Recoverable Shale Oil and Shale Gas

Resources: An Assessment of 137 Shale Formations in 41 Countries Outside the United States’, US Energy Administration Information, June 2013.

• Bloch, Heinz, P., and Budris, A., ‘Pump User’s Handbook: Life Extension’, Fairmont: Lilburn, 2006.


REDUCING THE‘HUMAN FACTOR’

Mike Fynes, Smith Flow Control, UK, takes a common

sense approach to valve safety.

Working on location in the oil and gas industry is a stressful environment. Workers operating valves are exposed to constant noise and

activity and undertake dangerous, repetitive tasks that often require intensive labour. Contractual staffing arrangements combined with hazardous working conditions can result in physical injury and an increased risk of accidents and loss of product. A significant 70% of accidents in the oil and gas industry are attributed to the ‘human factor’.

Human Factors Engineering (HFE) is the design of work processes and systems to ensure the safe and efficient functioning of human beings, by taking into account human capabilities, limitations and requirements.

System safetyIn the oil and gas industry, valve systems must be designed for safety, rather than placing sole responsibility

on the operator. Distractions, misunderstandings, shift changeovers or simple blunders can all lead the

operator to make catastrophic errors. Simply relying on operator adherence is not enough in such a

dangerous, fast paced environment. Safety must be applied to the process itself. The focus then

becomes accident prevention, not accident management.


For example, common permit‑to‑work systems provide a way of controlling potentially dangerous tasks. They outline necessary steps, such as maintenance procedures, that require isolating particular machinery. Padlocks or chains provide a lock‑off capability but they do not confirm the status of the equipment to which they are fixed. Removing a key from a padlock ensures neither that the equipment is locked nor its ‘open/closed’ or ‘on/off’ status. While a padlock and chain may be suitable and sufficiently robust in low risk applications, they have virtually no mechanical integrity and are a minimal solution offering, at best, a visual restriction against unauthorised operation. Permit‑to‑work procedures require clarity, accurate identification of hazards, thorough checking, and adherence by operators. This process places responsibility on the employee without system support.

In contrast, using mechanical interlocks removes the ‘human factor’ by ensuring dangerous processes happen only in a designated sequence.

Interlocks are relatively simple, specialised mechanical locks designed as integral‑fit attachments to the host

equipment. These interlocks are attached to the host equipment (any valve, closures, equipment needing human intervention) and compose of a simple lock and key design. Workers transfer specific keys from lock to lock (equipment to equipment) in a particular sequence. The next step in the process can only take place once the previous step has been completed. The sequence must be followed in the exact order to completion.

Mechanical interlocks are ideally suited to integrate with permit‑to‑work procedures. Indeed, the Cullen Report on the Public Inquiry into the Piper Alpha Disaster (1990) strongly recommended the use of locking systems integrated with permit‑to‑work procedures, especially where routine procedures cannot be accomplished in the timescale of a single work shift. They ensure safety, rather than place responsibility on the operator.

For example, mechanical interlocks are a suitable safety system in the operation of pig traps. Pigging operations are inherently dangerous and written safety procedures are not enough to ensure operator safety. Opening a pig trap closure while there is pressure in the barrel can shoot the pig out of the launcher at high speeds. Attempting to pass a pig through a partially open outlet valve, or prematurely opening the pig trap in the presence of high levels of toxic H2S can have fatal consequences. Using a sequence of interlocks on the pig trap vessel ensures that an operator can only unlock and open the vessel door to retrieve the pig after the vent has been opened. This ensures that the system is depressurised and protects the operator from exposure to dangerous H2S or from the pig shooting out of the vessel.

Malaysian LNG installationMechanical interlocks make sense from a productivity standpoint too. Interlocks can ensure the safe transfer of product. For example, Smith Flow Control’s (SFC) valve interlocking system was installed on a Malaysian LNG installation at Bintulu in Sarawak, East Malaysia, to prevent accidental product spillage while tankers were loading. By integrating a safety system into the process,

it eliminated the risk of human error or negligence when loading the tanker, which could lead to a vessel leaving the transfer area whilst still connected to the onshore facilities via a loading arm. This would result in damage to equipment, product spillage and a potential fire hazard to plant and personnel.

The LNG installation at Bintulu is one of the largest LNG facilities in the world. The loading site features hydraulically actuated loading arms, which are manoeuvred into place from a control station. Once connected, the supply valve is opened up, allowing product transfer to the tanker.

Two interlock units were integrated into the system; one in the control station and a small valve lock was fitted to the hydraulic supply line on the LNG supply valve. Only a single key is used between the two units.

Figure 1. A portable valve actuator.

Figure 2. An example of a mechanical interlock on a vessel closure, such as one used in pig traps. The door is locked but when the key on the right is inserted, the locking arm is released, allowing the door to open.


When the single interlock key is in place in the control station switch panel lock, the hydraulic loading arm can be manoeuvred into place. Once the arm is connected to the ship, the key is released from the lock and used to unlock and open the valve in the supply valve actuator. The supply valve can now be opened in the usual way, allowing safe and efficient product transfer. While the transfer takes place, the key remains trapped in the valve lock, preventing operation of the loading arm. Once transfer is complete, the supply valve is closed, enabling release of the key, which is then returned to the control station, reinstating controls of the loading arm and allowing it to be retracted. Using Smith Flow Control’s interlocks, the system can only operate in this defined sequence.

Well‑designed key interlock systems are always operator‑friendly – they require no additional work effort from the operator than normal procedures would require – and, most importantly, should never permit more than one key to be free (available) at any one time.

Valve operationPrinciples of HFE can be applied to the physical operation of valves onsite. An increase in the diversity of the workforce age, gender and physical strength requires consideration. Operating valves can expose operators to risk of musculoskeletal injury through repetitive twisting and stretching. Valves can vary in size and can require over a hundred turns using excessive, sustained force by several operators at once. Using a portable valve operating system can reduce the stress on workers and improve productivity.

Smith Flow Control supplied a number of portable, pneumatic valve actuators called EasiDrive to energy and chemical company Sasol in South Africa to ease operation and improve efficiencies. Prior to EasiDrive, manual operation of valves at Sasol created safety concerns. Worker fatigue meant that not all the valves were opened or closed fully, resulting in potential safety hazards. Emergency shut‑off valves were not operated as efficiently as expected, again causing safety issues. Operators needed to carry out more frequent maintenance and servicing on the valves to ensure that operation effort was kept as low as possible, which, in turn, reduced productivity. The new valve actuators at Sasol eliminated these concerns.

Valve operating systems can offer reduced operation time and fewer health problems for personnel. They improve emergency response through fast operation and status feedback of critical valves. In addition, they are ideal where severe weather conditions can make operations more challenging.

Occasionally, valves may be located in dangerous or inaccessible areas and require permanent access. However, unavoidable constraints on accessibility mean that operators have difficulty ensuring valves in critical service

are properly open or closed. Remote valve operating systems are the common sense approach to these valves, ensuring that operators are kept at a safe distance while valves are actuated efficiently. Remote valve operators, such as FlexiDrive, can pass through walls and floors and operate valves via a drive cable at distances up to 30 m. It allows workers to stay in safe, designated areas while critical valves are operated remotely.

ConclusionMany routine procedures are potentially dangerous if executed incorrectly or in unsafe conditions, with the scope for injury and/or damage significantly increased when high temperature, high pressure or toxic/flammable product is present. By taking simple steps to integrate safety into valve operating systems, workers are protected and work processes flow in a designated, safe way. Interlocks are versatile building blocks that can be configured to meet almost any simple or complex procedure. And drive systems are cost‑effective ways to operate difficult to open and/or hard to reach valves, protecting personnel while increasing efficiency.

Figure 3. This is an example of an LNG facility, discussed in the case study example (Malaysian LNG installation).


OPTIMISING SAFETY OFFSHORE

Vincent Lagarrigue and Richard Hepworth, Trelleborg, discuss the evolving nature of offshore LNG transfer in tandem configuration.


Moving LNG production offshore has presented the oil and gas industry with a unique and complex set of challenges. It is essential that floating LNG (FLNG) facilities maintain the utmost levels of safety and give increased flexibility to LNG production, while withstanding the effects of wind,

waves and currents in the open seas. Whilst many of these requirements have been met, the market is moving towards taking FLNG further

offshore. This means that existing components used on current sites that are relatively mild are not as effective. It is also important to remember that even the first FLNG plants are still relatively new, so there are still lessons to be learned.

Figure 1. Tandem LNG transfer (image courtesy

of Saipem).


In practice, some major operators are now finding that there is a need to evolve certain components, and innovative new products are being developed to keep pace with this rapidly evolving industry.

Ship-to-ship LNG transferConventional transfer systems, which have been adapted to enable LNG ship-to-ship transfers in open water through side-by-side configuration, might not always be sufficient, and could result in the shutdown of the liquefaction plant in the event of adverse weather conditions.

With downtime at such a premium in the LNG arena, more flexible solutions are being considered. Hosed-based systems are coming to the forefront as viable alternatives, with the potential benefit of being more price-competitive.

The cryogenic flexible hose is a technology that has seen a rapid increase in innovation and development to keep up with these requirements, and help address the

stringent demands of the offshore oil and gas industry.

However, there is a certain level of dissatisfaction with hoses that are currently used in the market, and in the absence of mature tandem offloading solutions using floating hoses, leading manufacturers have initiated the development of their own systems.

Technical detailsOne such system is the Cryoline LNG hose, which is suitable for use in floating submarine configuration. This new floating cryogenic hose is made up of several key components, including an inner cryogenic hose, an outer protective hose, an

efficient insulation layer, and an integrated leak monitoring system.

The inner cryogenic hose has been derived from the latest developments in composite hose technology and is best known for its high flexibility and proven suitability for LNG ship-to-ship transfer in side-by-side configuration. Composite LNG hoses usually consist of multiple unbonded, polymeric film and woven fabric layers, trapped between two stainless steel wire helices, which give the hose its convoluted shape, one being internal and one external.

The film layers provide a fluid-tight barrier to the conveyed product, while the woven fabric layers provide the mechanical strength of the hose. The number and arrangement of multiple polymeric film and woven fabric layers is specific to the hose size and application.

The polymeric film and fabric materials are compatible with the conveyed product and the extreme operating temperatures. Composite LNG hoses have already proven their suitability for such an application, as this technology has been validated through many full scale static and dynamic tests, and many offshore ship-to-ship LNG transfers.

The outer protective hose is based on flexible rubber bonded hose technology – best known for its high resistance to fatigue and ability to comply with harsh environmental conditions. By protecting the inner cryogenic hose from external loads or aggressions, the hose also prolongs service life.

The annular space between the inner and outer hoses is insulated, enabling a reduction in boil off gas (BOG) creation during offloading operations, and, as such, increasing the efficiency of the offloading process. Thanks to the insulation, handling operations are also easier as no ice is formed on top of the hose even when it is full of LNG.

Figure 3. Ship-to-ship FLNG will have between 8 – 10 sets of mooring hooks.

Figure 2. Pneumatic fenders with chain tyre nets have been the traditional choice for ship-to-ship mooring.


The hose also features an integrated leak monitoring system based on optical fiber technology to detect gas leaks in the annular space between the inner and outer hoses. This innovative system increases the safety of the transfer as it enables the operator to make decisions on instigating emergency procedures by monitoring data on the offloading conditions.

In addition, the hose features an innovative compact and specific connection system, which uses end-fittings rather than the traditional ‘sections’ in typical LNG floating hoses. This ensures load transfer, protects against leaks and minimises heat loss within offloading lines.

Trelleborg has worked closely with Saipem in the development of this innovative floating hose offloading system by evolving proven technologies and building upon existing industry practices and procedures. Safety, robustness, simplicity of operations, and installation have driven the design of each component.

Qualification of the system has been progressing well and is now into its final stage; an 18 in. cryogenic flexible hose has already been certified by DNV and ABS. Additionally, the company is focused on enhancing the properties of the 20 in. Cryoline LNG floating hose through a full scale testing programme. This development, which combines the expertise of technology providers, suppliers and contractors, as well as the support of a major operator and classification society, will provide the LNG industry with a reliable and robust solution for LNG tandem loading operations.

Developing docking and mooringBefore transfer can take place, there are elements of the docking and mooring package that must be considered and evolved for FLNG. Off-the-shelf packages are not an option in the FLNG arena, where integrated solutions and customised maintenance packages should be developed in order to maximise operational efficiencies and minimise whole life project costs.

Similar to onshore mooring, ship-to-ship FLNG will have between 8 – 10 sets of mooring hooks with a safe working load capacity of 100 – 150 t configured as double and triple hooks. A compact footprint for the mooring equipment is necessary as deck space is at a premium.

Under-deck reinforcement requirements must be simplified as much as possible and high salt-spray ingress protection is also essential for mechanisms such as load cells, capstan motors and electrical control boxes.

A typical side-by-side FLNG integrated mooring package will consist of the following elements:

� Quick release hooks and capstans.

� Mooring line load monitoring system.

� Remote hook release.

� Docking aid system using GPS.

� Metocean and environmental monitoring.

� Ship/shore link emergency shutdown (SSL ESD) communications system.

� Pneumatic or foam filled fenders and deployment and monitoring system.

� Central control, monitoring and reporting arrangements.

� Distributed control system (DCS) interface.

Although the core modules of each mooring package may be similar from project to project, it is vital that the terminal operator has an understanding of the individual requirements of a specific offshore environment so that the overall system is optimised for that application.

Additionally, to avoid the cost associated with downtime in the LNG arena, all elements of the mooring package must be available and functioning 100% of the time.

This 100% availability requirement does not simply apply to the mechanical elements of the mooring package, such as fenders and hooks; an FLNG mooring system must be truly integrated. All monitoring systems should be interfaced to a single point (usually an operations control room) to ensure module availability and redundancy are optimised.

Harnessing the right hardwareThe maintenance of fenders, as well as deployment and recovery systems, should also be reassessed for FLNG applications. Traditional fixed fenders are not an option. Pneumatic fenders with chain tyre nets have been the traditional choice for ship-to-ship mooring, but the downside of pneumatic fenders is that they do not offer flotation redundancy: if punctured, they will fill with water and can run the risk of overloading the fender deployment system when lifted.

Foam fenders can provide an attractive alternative. They can be manufactured without tyre nets, and provide lower frictional resistance since the fender skin can be manufactured from a low polyurethane material, rather than rubber.

Foam fenders also offer similar reaction and energy performance to pneumatic fenders, and can be engineered to offer low hull pressure. Virtually unsinkable, they provide a practicable alternative to pneumatic fenders, better suited to FLNG operations.

Pneumatic or foam, the fenders will need to be retrieved when no LNG carrier berths alongside the FLNG unit. Contrary to a small margin of opinion, fenders should not be left in the water once the LNG carrier has departed.

Fenders left deployed will take the full force of the waves. This will become more of a problem as FLNG terminals move further offshore and experience more extreme conditions.

It is essential then that operators have the deployment and retrieval systems necessary to bring fenders back on deck for storage when they are not in use. Given that deck space is at a premium, this scenario necessitates good forward planning at the earliest stages of LNG carrier to FLNG unit conversion.

Offshore berthing considerationsOne primary difference between offshore and onshore (or near shore) operations arises right at the outset, when the LNG carrier approaches the FLNG unit. In extreme offshore

conditions, operators need to take a different approach to the standards commonly deployed in onshore FSRU transfers. For example, in the case of offshore applications – and of particular importance as conditions become more extreme – fixed lasers are no longer an appropriate solution in measuring and recording berthing speed and the angle of approach. Alternative solutions are required to allow the flexibility needed for open sea berthing and allow for pitch and roll.

The use of real time kinetic (RTK) GPS will allow the operator more reliable management of the LNG carrier’s speed of approach, angle and distance, whilst providing a similar level of accuracy to traditional fixed lasers.

Additional environmental monitoring, and the use of predictive software in a GPS docking tool, will further assist the pilot during this critical stage, and optimise the operational window.

ConclusionFLNG is now technically and economically proven in enabling previously unviable gas fields to be exploited, and while the industry looks to move further offshore, there are lessons to be learnt and best practices to be taken from onshore and near shore applications.

However, an understanding of the complexities and individual requirements of more extreme offshore environments is key to successful systems development in FLNG docking, mooring and transfer, whether side-by-side

or tandem configuration. As these projects evolve, manufacturers and end-users must collaborate to develop innovative, best practice solutions to be suited to specific FLNG requirements.

The latest development in cryogenic LNG floating hoses will become a key component in offloading systems for future offshore FLNG projects, allowing these projects to be considered for harsher conditions, without excessive downtime due to offloading system availability, and with significantly reduced risk.

The importance of continuous uptime and, above all, safety, does not begin and end during transfer; before and beyond, the performance and maintenance of mooring systems will need to be carefully considered, enabling potential problems to be identified and resolved at the outset.

As FLNG projects move further offshore and both risk and reward become higher, a more holistic approach to systems development and integration will become necessary. Increasingly, manufacturers will need to offer a more comprehensive and evolved portfolio to demonstrate expertise in this more extreme offshore arena. They will need to couple this with tailored, innovative solutions, that can be adapted and developed on a project-by-project basis. The basic toolkit will remain the same, but the elements must evolve, and each component – and its interrelation with other components – must be considered on the merits of each environment.

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Equipment, training and teamwork are the cornerstones of ensuring the safety of staff in all irrespirable environments. This article examines how these

cornerstones can help to counteract high-order gas hazards.

Hydrogen sulfideA natural by-product of organic decay, hydrogen sulfide (H2S) is unlocked as a result of drilling and well-servicing operations. Oil and gas fields, tankers and production facilities all have the potential to contain significant amounts of H2S – a hugely challenging gas to deal with. It is a killer gas that acts as a broad spectrum poison when inhaled by mammals (meaning that it can affect many different systems in the body – from the respiratory, pulmonary and circulatory, to the digestive system). It has claimed the lives of numerous workers around the world in incidents that might have been prevented had the properties of H2S been more substantially understood.

The gas occurs naturally in geological formations and certain geological periods are more likely to contain it than others, such as the Triassic, Permian and Carboniferous.

Allan Cameron, Sabre Safety, UK, analyses the challenges in dealing with irrespirable environments – from H2S to natural gas.


All petroleum industry jobsites are potential H2S locations. The effects of this neuro toxin gas can range from mild discomfort to death. It is so toxic that it quickly overwhelms the nervous system. At higher concentrations, the effects are immediate and can be catastrophic.

H2S is colourless and therefore invisible. Although it has a distinct odour of ‘rotten eggs’, it attacks and quickly impairs a victim’s sense of smell, even in low concentrations. Quite simply, it could be fatal for a person to rely on their nose as a detection device.

As H2S is heavier than air, it tends to settle in low-lying areas such as pits, cellars or tanks. It is a potentially explosive as well as a poisonous gas. Mixed with the right proportion of air or oxygen, H2S can ignite. The ignition range is 4.3 and 46% of atmosphere and it can auto-ignite at temperatures around 260 ˚C. Its highly corrosive qualities, and the fact that it is soluble and can therefore be present in any container or vessel used to carry or hold fluids, makes it a formidable adversary.

In terms of toxicity, 5 ppm is the long-term exposure limit. A dose of 500 – 700 ppm will cause loss of consciousness and death within 30 minutes to 1 hour. A dose of 1000 ppm (the equivalent of one tenth of 1%) will cause immediate unconsciousness and death within a few minutes – even if the casualty is removed to fresh air. There is no margin for error when working with this highly dangerous gas. This demands that company’s not only meet, but exceed safety requirements, with multiple backups available to ensure that there is no danger to breathing systems under any circumstances.

Natural gas environmentsNatural gas presents some similar challenges. In LNG work, there is always a risk of leakage and explosion at every stage of the production process and in storage and distribution. Unlike highly toxic H2S, natural gas is an asphyxiant and an anaesthetic as well as a narcotic, and it is these properties that pose the real breathing hazard. If methane in the atmosphere reaches its upper explosive limit (UEL) – 15% of the total volume of atmosphere – then oxygen levels drop to 15%; at this point a person would start to be affected by the oxygen depletion in the atmosphere. Once methane is out of its explosive range and rising in concentration, it starts to become an asphyxiant instead of an explosive gas.

On LNG plants, tasks such as hot work may need to be carried out inside storage tanks as part of planned maintenance or emergency repairs. As these areas are classed as confined spaces, the tanks are ventilated for an adequate time to allow any gases to vent naturally before an entry is made. However, there are occasions when it is impossible to completely rid the tank of all gases. One method is to purge the tank with nitrogen to mitigate the risk of fire and explosion from gases, fumes and vapours still present inside the tank. The use of nitrogen purging causes an inert atmosphere; therefore, if entry is needed into the confined space whilst the nitrogen is still present, breathing apparatus will be used as a control measure to safeguard the entrants.

Confined space – a broad term that covers many hazardsConfined space work is not what people necessarily think: there are many scenarios that are designated as confined spaces due to the constraints involved in working within them. Often workers are attached to a scaffold in such situations. They could be working on cracking towers at refineries or working on a flare boom offshore as part of shutdown and maintenance.

Changing out the burners on a flare stack in an oil and gas installation is another prime example of confined space work. Once the burners are taken off, there is the possibility of a gas release and the proximity to any potential release and the nature of the situation renders it a confined space. Rope-access workers have to be fully trained in the use of breathing apparatus and provided with an air feed from a system that is run by the company’s onsite team.

This is exactly what happened at a refinery in the Northeast of Scotland where Sabre Safety was called on to supply breathing apparatus and expertise as part of a three-night job, to replace burners on four flares, checking the welds, and working on ladders at the top of the flare stack. Breathing air is supplied to low-pressure distribution manifolds at the top of the flare stack. Nitrogen is used to displace oxygen in the surrounding area and ensure that there is no possibility of ignition during such work.

Breathing expertise in LNG environmentsSabre Safety has also advised LNG facilities, such as one in central Scotland, regarding breathing apparatus systems, to enable onsite personnel to inspect and/or repair systems in the event of an equipment failure and subsequent release of LNG. In this instance, there were two main areas to be dealt with: a main process area and LNG storage tanks.

In the production area, the company proposed a trailer mounted hurricane unit suitable for extended operations in any irrespirable atmosphere, be it toxic or oxygen deficient. This

Figure 1. Worker entering platform leg storage cell.

Figure 2. Decommissioning poses new challenges.

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system is ideally suited for work in oil and gas exploration and production, major refinery and plant shutdown, tank cleaning and refurbishment, and utilities such as water, gas and sewage. It is a lightweight airmobile system that is also designed for use by emergency services and civil defence organisations and is ideal for many other applications, including disaster relief throughout the world. The supplied breathing air system is based on a fully transportable trailer mounted unit, which means that it is mobile and efficient.

In this case, the standard set up available from the company was capable of supplying up to 50 man hours of air to individual airline supplied breathing apparatus. A 150 m high-pressure line to the remote distribution panel allowed the main area of the site to be covered by one unit.

In the LNG storage tank areas, the proposed solution was to install independent Sabre Cyclone 2 Breathing Air Cascade units on each tank with remote reducing station and retractor reels for reduced pressure (RP) air delivery. A cascade airline system consists of a high pressure stored air reserve, with a capacity of 50 man hours of air. The high pressure (4500 psi/300 bar) air supply is fed via high pressure lines to a remote distribution panel. The high pressure air is then reduced at the control panel to 7 bar and the reduced air is then fed into the distribution manifold for delivery to four breathing air hose connection points. The distribution manifold can be split; this allows for immediate repairs to be made to one half of the system without having to shut the entire system down.

Furthermore, the cascade system has the capacity for the introduction of additional high pressure air supply from a secondary source should this be required. From the distribution

manifold, the RP air is fed via the personnel line to individual Sabre Flite mini breathing apparatus sets, weighing less than 4 kg. A specialised Y piece connector allows changeover between airline supplies, and protection is enahnced by a positive pressure facemask, a demand valve and a lightweight carbon composite cylinder supplying up to 15 minutes of air for escape.

In the plan, a 10 m retractor reel mounted high up on the walkway allowed inspection of high level valves and other equipment whilst working under air, and a 50 m hose reel allowed personnel to plug-in at the bottom of the spiral stair. This meant that from this point, personnel could work under air whilst climbing the stairway, and at any point on the main walkway at the 36.5 m level.

ConclusionIn all gas work, ongoing investment in respiratory protection and training is essential. Sabre is constantly developing its systems and training based on experience across diverse breathing and gas environments. Maintenance tasks in particular involve a high risk of exposure to gas-rich environments that really test the quality of planning, training and equipment. Work in tough locations such as the North Sea and the Atlantic off the coast of Nova Scotia call for the highest standards of breathing expertise. The complexity of today’s oil and gas industry means that companies such as Sabre are no longer just suppliers of equipment, but are developers of solutions in a wide range of workplaces – including LNG facilities. Teamwork, from the planning stage onwards, not only produces the safest, but also the most cost-effective ways of getting things done.

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How often do exploration and production (E&P) organisations or vertically integrated oil and gas companies hoping to find oil actually discover large dry

gas reservoirs when they are exploring? This does not happen very frequently, but it does occur often enough to intrigue management teams when exploring in frontier or unexplored basins. Two common questions arise when this happens: firstly, ‘what are we going to do with all this gas?’; and secondly, ‘how do we capture value out of this discovery?’ There are several ways to realise such value, and one of them is by taking an integrated LNG project valuation approach. Similarly, known prolific gas basins will not escape the same question until the learning curve on monetising LNG E&P projects has been built, or

if already built, how different or sub-optimal it is compared to that of other E&P companies. This article will outline such an approach step-by-step.

Unlocking valueAfter the excitement of finding a vast gas reservoir, the dilemma lies in understanding its potential value, and how to align it with company targets. This may sound like business as usual, as this is about a very large reservoir containing dry gas – nothing new to E&P companies/divisions. However, monetising E&P LNG opportunities is a relatively new challenge for many E&P players and investors in E&P LNG projects, and hence could become a competitive advantage.

Alejandro Plano, Palantir Solutions, USA, shows why an integrated approach for managing risk, as well as understanding the economics and the available commercial opportunities are important for truly understanding the value of a LNG project.

INTEGRATED PROJECT VALUATION


The first step is breaking the LNG value chain into its main components – upstream, LNG plant (or midstream) and LNG shipping – by clearly defining the boundaries between them. Regasification is left aside as it is, in most cases, a buyer’s burden.

The next step would require a decision analysis (DA) workshop where key subject matter experts and decision makers will be invited to participate in sharing their teams’ targets and expectations, and identifying risks. This input creates the foundation that the DA expert leading the workshop will use to help identify base scenarios, exit points and worst case scenarios that will define the LNG project decision tree. Subsequently, this tree will determine the skeleton of the integrated economics evaluation – hierarchies, economic models and iterations, including testing how robust the LNG project is. Furthermore, mitigation plans will be added to the project decision tree and translated into scenarios to be tested in the economic valuation.

Following the DA session, understanding whether the components of the E&P LNG project above the upstream (midstream and LNG shipping) fall under the fiscal regime will help capture incremental value and/or manage risk. This will be explored in the next section.

Fiscal regimeDo the fiscal regime terms include the LNG plant? If not, a separate tax structure may apply, such as a particular tax scheme for large projects or simply corporate tax. In addition, having a clear understanding of the business drivers (economic and financial metrics) for all partners, including the National Oil Company (NOC), will help identify the tax structure that benefits the consortium and the government the most.

Similarly, ownership in the LNG plant (trains and common facilities) will be separate from that in the upstream, providing flexibility as it could be divested without selling a working interest in the upstream. For this reason, some companies find it important to guarantee an acceptable return to the LNG plant, and associate this decision to real option analysis as a means to reduce risk.

On the financing side, lenders will scrutinise the risk associated to the LNG plant separately from that of the upstream

based on the credit rate of partners and buyers, which, in turn, raises several questions.

Financing termsHow different are these financing terms from those of the upstream? What model aligns better with the company’s risk profile? A buy/sell (merchant) model where the LNG plant purchases feedstock from the upstream and sells LNG? Or a toll fee (tolling) model where a processing fee is charged to the upstream? Which one will be preferred by the government from a tax perspective?

In the tolling model, the liquefaction fee flows back to the upstream as a cost and therefore is included in the cost recovery mechanism. That said, how is the government going to consider this toll fee? As an operating cost?

In contrast, transfer price regulations may be in place and used to determine fair notional margins for the LNG plant and the upstream that are, in turn, used to calculate tax liabilities, as seen in Australia.

If the LNG plant is considered to be governed by the E&P contract, as more trains are added, an incremental back-allocation of costs will help ensure the value (e.g. net present value) of each LNG train is properly estimated, not only for making an investment decision, but also for estimating a fair divestment price.

Another step that brings valuable insight involves analysing the LNG shipping operation.

Shipping costsHow do LNG shipping costs impact returns? Some would consider LNG shipping as a midstream operation, others as downstream. Regardless, LNG shipping costs have an impact on returns in the upstream as they are a key component for establishing LNG prices. Understanding ownership vs. charter (leasing) models will help upstream and LNG plant owners estimate costs buyers incur, and, as a result, negotiate fair LNG FOB and DES prices. Boil-off assumptions, voyage and loading/unloading times, as well as port fees (including Panama/Suez Canals) and charter daily rates could be discussed

Figure 1. Palantir’s integrated LNG project valuation model.

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and agreed upon to establish a baseline for negotiating prices. However, there is a limit to sharing an economic model as there will be proprietary pricing or cost models that will never be shared.

RoyaltiesWhere will the royalties determined in the PSC be paid? At the well head? Field boundaries? Or on FOB LNG prices? How is the government going to determine these prices?

Using the same shipping economic model will not only bring consistency and enhance trust among the consortium of International Oil Companies (IOCs), the NOC, and the government, but will also link LNG volumes (either FOB or DES) to upstream revenues.

One of the key characteristics of an LNG integrated project valuation relies on its iterative nature. Gas production profiles and volumes are initially determined and fed to the LNG plant to subsequently determine FOB and DES LNG volumes in the shipping model. Nevertheless, FOB price will be known in the latter model, feeding back such price to the upstream (or LNG plant in a buy/sell model) in order to calculate revenues, royalties and profit sharing (see Figure 1 for more details).

Once these steps have been completed, the integrated LNG project valuation is ready to be shared with all partners, including the NOC and government entities (if applicable).

An ideal means to do so is via workshops to align interpretations of the NOC and the consortium of IOC’s on fiscal terms such as royalties, cost recovery, profit sharing, depreciation and taxation. More of these workshops will take place as the integrated economic analysis progresses and adjustments/expansions to the decision tree are made.

Managing risk through consistencySharing assumptions and economic models with all teams in the LNG project will create enough overlap to reduce the risk of having different teams, e.g. marketing, running its own separate pricing model, or the LNG shipping team overseeing its own economic shipping model. The goal is not to replace any existing model with this integrated valuation; rather, it is to bring consistency from the decision tree to the upstream and LNG plant economic valuation, pricing negotiations and LNG shipping.

ConclusionIn a world where cleaner energy is a trend, and where some LNG producer countries face challenges to meet local gas demand, LNG positions itself as an alternative that is increasingly preferred by governments and buyers, rendering the LNG market a growing one.

However, this does not come without market risks. More competition is expected in the LNG market as unconventional developments have, or will, turn some LNG importers into LNG exporters in the coming years, and as Australia and East Africa fully develop their LNG exporting potential.

The true value of E&P LNG projects could be unlocked and associated risks may be better mitigated if framed and analysed as an integrated LNG value. Understanding how value is created in each component of the LNG valuation chain, and learning how to monetise this value, will enable IOCs and any investor in E&P LNG projects to better negotiate LNG prices, contract terms, farm-ins, farm-outs, unitisation terms, and shipping fees while building investor confidence, which, in turn, should reflect in higher share prices.

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■ discharge pressures up to 220 bar (3,200 psi)

■ 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 continuousoperating intervals and design features that make routine service simpler, faster and moreeconomical 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.

BroadestCapabilities in the World

www.kobelcocompressors.com

WHETHER YOU’RE EXPLORING, DRILLING, PRODUCING, PROCESSING, TRANSPORTING, STORING, OR USING – CHOOSE AN LNG PARTNER THAT

KNOWS WHAT THEY’RE DOING

We’ve got products, solutions and services for all phases of the lifecycle of the oil &gas process. They’re each designed to increase your efficiency and profitability, while ensuring environmental compliance. As the market leader in multi-fuel applications and engineering, our track record is in a class of its own. Read more about what we have to offer your business at www.wartsila.com

WÄRTSILÄ: YOUR SHORTER ROUTE