LNG Industry - May 2021

May 2021

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ISSN 1747-1826

CONTENTS 03 Comment

MAY 2021

30 Coming out of the Ice Age

Margaret Greene (USA), William Dolan (USA), Justin Pan (USA), Al Maglio (USA), Tobias Eckardt (Germany), BASF, and Harold Boerrigter (Netherlands), Marco Smaling (Netherlands), and Imelda Rusli (UK), Shell, detail a dualpurpose adsorbent technology for combined heavy hydrocarbon and water removal from lean feed gas in LNG to prevent cold box freezing.

04 LNG news 08 A safari tour of LNG

Siva Prasad and Pranav Joshi, Rystad Energy, India, explore the current LNG production in Africa and how countries may consider new developments in the future to balance exports with domestic demand.

36 Making moves in the Med

Henri Beaussant and Arnaud Lamartine, SURFEO, France, discuss the small scale LNG markets in the Mediterranean area, looking at recent activity and future developments.

42 A Sub-Saharan first

Dieter Hilmes, TGE Marine, Germany, describes how the company supported the delivery of Gasfin’s FRU for the first LNG import terminal in Sub-Saharan Africa.

47 Venturing north

Saša Cook, Cryopeak LNG Solutions Corporation, Canada, discusses how to provide LNG to remote communities in Northern Canada.

51 Fortified for growth

08 14 Clean travels

Denise Kurtulus, Head of Marine Business, Rolls-Royce Power Systems, Germany, discusses how the introduction of a new gas engine technology can help combat emissions across a variety of vessels.

Andreas Glud, Hempel A/S, Denmark, outlines how the LNG carrier fleet can be optimised to trade flexibly, with a focus on hull biofouling.

53 Setting high standards

Chongmin Kim, Senior Surveyor and Researcher, Korean Register, South Korea, discusses the research, standards, and achievements that are at the forefront of the LNG industry.

56 15 facts on... Africa

20 LNG: the jack off all trades

Ann Nallo, BHE GT&S, USA, looks at how ow providing diverse fuel cross the US can help solutions for a variety of customers across expand business in a rapidly changing LNG sector.

25 Green is the new w black

Frans Launonen, Vahterus, Finland, highlights hlights the role of LNG in decarbonisation and how to maximise ptimal heat savings on skid building by selecting optimal exchangers.

ON THIS MONTH’S CO COVER BASF has developed Durasorb Cryo-HRU, BASF B Cry a new, n ew w, step-change technology that performs the dual purpose of removing heavy the th hea hydrocarbons, hyd h ydrocarbons, including BTX, and water to cryogenic specifications in a single unit, cr tthuss reducing the footprint of the LNG thu pretreatment train. Utilising this technology te feed gas provides flexibility for changing fe operations by composition and reliable operation reducing the concentration of com components going into the cold box that cause freezing and unplanned downtime. catalysts.basf.com/durasorb

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LYDIA WOELLWARTH EDITOR

COMMENT S

ince the recent publication of the World Bank’s report ‘The Role of LNG in the Transition Toward Low- and Zero-Carbon Shipping’, there has been much dispute in the industry regarding the report’s findings. LNG is constantly pitched as the greenest fossil fuel and has been acknowledged as an ideal transitional fuel for the industry’s journey to decarbonisation. However, read the 94-page report and it appears that LNG’s use as a bunker fuel should be avoided and it will be costlier to use LNG as a transition fuel in comparison with immediately introducing zero-carbon fuels.

I cannot say I am alone in my confusion regarding the report’s findings. Take Total, for example, which only this week realised France’s first ship-to-containership LNG bunkering and reiterated the positive momentum LNG as a marine fuel has gained in the global shipping industry, and how it lays the foundation for introducing bio-LNG at a stage in the future. Similarly, in a recent speech at the Singapore Maritime Technology Conference, Grahaeme Henderson – Shell’s Head of Shipping and Maritime – stated how the industry cannot sit idle until alternative fuels are available, because LNG is the choice today for minimising cumulative emissions from the shipping sector.

Not trying to sound like a broken record, but the benefits of LNG as a marine fuel are well recognised. LNG emits low quantities of sulfur oxides, nitrogen oxides, and particulate matter, and in fact using it can cut greenhouse gas emissions (GHG) by up to 23%. In comparison with the traditional oil-derived bunker fuels used in the shipping industry, LNG’s air quality improvements are “undeniable” reports the World Bank, yet still it considers the fuel to only play “a limited role

Managing Editor James Little james.little@palladianpublications.com

Editor

in the decarbonisation of the maritime transport sector.”

Alternative fuels such as hydrogen or ammonia are considered the ultimate goal in the future, as they are zero-carbon bunker fuels, and the concern is that all the infrastructure and technology developed for LNG as a transitional fuel cannot actually be utilised by the likes of hydrogen and ammonia – they are technically incompatible.

To approach it from this angle you can understand that it is risky to spend millions of dollars on infrastructure that, at some unknown point in the near or far future, will be redundant when zero-carbon bunker fuels are the sole fuel of the industry. However, the saying “you must learn to walk before you can run” seems valid here. Whilst the goal of a carbon neutral industry is the ultimate objective, it cannot just be a case of jumping from conventional heavy fuel oil straight to the likes of hydrogen – this simply is not feasible. SEA-LNG reinforces this logic, stating how to wait for unproven alternatives will only worsen the current GHG problems.

Just looking at news from the industry in the last week, there have been countless successful bunkering updates.

Titan LNG has developed a new LNG bunkering barge to supply English Channel regions with LNG; Puget LNG is to supply LNG marine fuel to GAC’s customers in the Pacific Northwest; Bureau Veritas has awarded classification to Norway’s first LNG bunkering vessel; to name a few samples from recent days.

To conclude with the remarks of Shell’s Grahaeme Henderson, in the shipping sector today, LNG is the lowest emission fuel available at scale – there is no fuel that can rival this ability.

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LNGNEWS Norway

Malaysia

PETRONAS strengthens Malaysia’s position as LNG ISO tank hub

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ETRONAS LNG Ltd has commenced the export of LNG to China in ISO tanks from its filling facility in Pengerang, Johor, Malaysia. The maiden shipment of LNG ISO tanks was safely delivered to Shanghai from Pasir Gudang Port of Johor on 23 April 2021, following a spot contract signed between PETRONAS and Tiger Gas (Hong Kong) Ltd, an affiliate of Tiger Clean Energy Limited (TCEL).

“This inaugural LNG ISO tank export from Peninsular Malaysia is an innovative solution that enables LNG to reach off-grid customers, not only domestically, but also internationally, extending the reach of our Virtual Pipeline System offering that we have started since late last year,” said PETRONAS Vice President of LNG Marketing and Trading, Shamsairi M Ibrahim.

In 2020, PETRONAS and TCEL signed a long-term Sales and Purchase Agreement for the supply of LNG to TCEL’s LNG ISO tank filling facility in Bintulu, Sarawak. As part of this agreement, PETRONAS’ LNG will be distributed to China using TCEL’s ISO tanks, with the first shipment sailed from Bintulu Port to the Port of Long Kou on 25 March 2021.

Commenting on the deal, Shamsairi said, “This is also a clear testament of PETRONAS’ commitment as a progressive energy solutions partner in reducing the carbon footprint of our customers’ existing and future operations.”

With the operation of PETRONAS’ ISO tank filling facility at Pengerang, Malaysia is now poised to strengthen its position as an LNG ISO tank export hub, with filling facilities in West and East Malaysia that provide customers with an alternative and reliable LNG solution.

Equinor announces revised Hammerfest LNG start-up date

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ased on extensive analyses and mapping of damages, Equinor has updated the schedule for repair and start-up of the LNG plant on Melkøya after the fire on 28 September 2020. Due to the comprehensive scope of work and COVID-19 restrictions, the revised estimated start-up date is set to 31 March 2022.

Even though the fire was limited to the air intake of one of the plant’s five big gas turbines, the fire and firefighting caused substantial damage to the plant. “We have worked systematically on getting an overview of the damages and scope of work to bring the plant’s technical condition back to the required standard. There is still some uncertainty related to the scope of work, however our best start-up estimate is 31 March 2022, based on current knowledge. Safety is our top priority, and we will not start the plant before it can be done safely,” said Grete B. Haaland, Equinor’s Senior Vice President for Onshore Plants.

Operational measures to handle the COVID-19 situation have affected the follow-up progress after the fire. The project has already introduced measures that allow fewer workers on site at the same time than previously expected, but there is still uncertainty surrounding how the COVID-19 development will impact the project progress.

More than 70 000 unique equipment components were potentially exposed to seawater during the firefighting. The components have been checked and a repair plan for securing the plant’s integrity has been prepared. The most time-consuming activity appears to be the replacement of electric cables connected to the power station where the fire occurred. Inspections show that more than 180bkm of cable must be replaced. New cables have been ordered and will arrive at Melkøya during the spring/ summer. Other equipment components are being procured for delivery in the summer/autumn of 2021.

Mozambique

Total declares force majeure on Mozambique LNG project

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onsidering the evolution of the security situation in the north of the Cabo Delgado province in Mozambique, Total confirms the withdrawal of all Mozambique LNG project personnel from the Afungi site. This situation leads Total, as operator of the Mozambique LNG project, to declare force majeure.

Total expresses its solidarity with the government and people of Mozambique and wishes that the actions carried out by the government of Mozambique and its regional and international

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May 2021

partners will enable the restoration of security and stability in Cabo Delgado province in a sustained manner.

Total E&P Mozambique Area 1 Limitada, a subsidiary of Total SE, operates Mozambique LNG with a 26.5% interest alongside ENH Rovuma Área Um, S.A. (15%), Mitsui E&P Mozambique Area1 Ltd (20%), ONGC Videsh Rovuma Ltd (10%), Beas Rovuma Energy Mozambique Ltd (10%), BPRL Ventures Mozambique B.V. (10%), and PTTEP Mozambique Area 1 Ltd (8.5%).

LNGNEWS Croatia

Høglund supplies system to LNG bunkering vessel

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ystems integration specialist Høglund Marine Solutions has supplied systems and support during the commissioning of what is now Norway’s first LNG bunkering unit, following successful gas and sea trials.

Once a conventional bunkering tanker known as Oslo Tank, the Bergen Tankers-owned vessel has been renamed Bergen LNG and will play a major role in setting the standard and establishing the infrastructure for Norway’s LNG shipping sector.

Høglund was responsible for the supply of the LNG gas handling system and the vessel’s Integrated Automation System (IAS), which includes an essential gas control and safety system. Høglund’s participation in the project involved the supply of an LNG cargo system incorporating a single Shell Type C tank with a capacity of 850 m3 and a bunkering rate of 500 m3/h. Other hardware and automation solutions that were provided by Høglund to ensure safe and efficient vessel operations include cargo pumps, bunker manifolds, custody transfer system, a shipto-ship transfer system, a cargo control and emergency shutdown (ESD) system, and ship-to-shore/ship-to-ship link systems to create the automation system.

As part of this ambitious project, Høglund worked closely with its partners HB Hunte Engineering – which provided a 3D detail design of the gas piping system – and LNG cargo tank manufacturer Gas & Heat Spa. Westcon Shipyards, which was contracted by Bergen Tankers, carried out the conversion of the vessel, including the installation of the LNG cargo system supplied by Høglund.

Closer to the completion of the project, Høglund’s team of highly skilled field service engineering professionals carried out a series of rigorous sea and gas trials of the installed equipment, collaborating with project partners Gasnor and classification society Bureau Veritas. The trials lasted for four consecutive days with minimal downtime.

After having been given the green light on both its mechanical and control equipment system, as well as its flowmeters, the vessel is now in operation.

Ingemar Presthus, Technical Manager at Bergen Tankers, added: “It is fantastic to count on a partner like Høglund Marine Solutions for a project as complex as the Bergen LNG conversion, which will pave the way for LNG shipping’s infrastructure in Norway.”

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May 2021

USA

NextDecade and Project Canary announce greenhouse gas measurement project

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extDecade Corp. and Project Canary have announced the formation of a joint pilot project for monitoring, reporting, and independent third-party measurement and certification of the greenhouse gas (GHG) intensity of LNG to be sold from NextDecade’s Rio Grande LNG export facility in the Port of Brownsville, Texas, US. Project Canary is focused on delivering independent, trusted, continuous emissions monitoring data and related technologies to assess environmental performance across the energy value chain. In its pilot project with NextDecade, the first in the global LNG industry, Project Canary will deploy its TrustWell™ certification process to confirm each element of the natural gas value chain – from the wellhead to the ship at Rio Grande LNG – has achieved low emissions targets and utilised the highest standards of environmental performance and social responsibility. This partnership will enable the development of a responsibly sourced natural gas supply chain from leading producers in the Permian Basin and Eagle Ford Shale, and independent, third-party certification of the GHG intensity of LNG.

THE LNG ROUNDUP X Avenir LNG completes bunkering between sister ships X Contract signed for GASPOOL and NetConnect merger X SeaspanLNG secures AiP for LNG bunker vessel Follow us on LinkedIn to read more about the articles

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LNGNEWS Croatia

North America

Krk terminal receives first MET Croatia LNG delivery

AMM licenses LNG transportation technology

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roatia has received another cargo of LNG at the Krk terminal in the northern Adriatic Sea, the first LNG delivery of MET Croatia. The 145 000 m3 LNG vessel Methane Nile Eagle, which loaded at the Zeebrugge port in Belgium, arrived on 26 April.

This latest delivery is Croatia’s fifth cargo imported to date, and is the first one originating from an EU port.

“Since the terminal started in January 2021, it has been a rather turbulent beginning of operations, with pricing anomalies and arbitrary situations on the global scale and changes to the delivery schedule locally at the terminal. However, since March the arrival of vessels to the terminal has stabilised,” said Mario Matkovic, CEO of MET Croatia Energy Trade.

Croatian gas supplier MET Croatia Energy Trade, part of Swiss-based energy company MET Group, booked an overall capacity of 2.67 billion m3 at the Krk LNG terminal for a period of seven years.

This is MET’s first delivery to Krk, itself. MET also supplied the commissioning cargo to the FSRU LNG Croatia in Sagunto, Spain, in November 2020.

According to Matkovic, an additional two LNG cargoes are due to be delivered by MET Croatia to the Krk terminal before the end of October 2021.

Croatia’s first LNG terminal has the capacity to send up to 2.6 billion m3/yr of natural gas into the national grid. The LNG terminal project cost €233 million, with the EU providing €101 million.

rgent Marine Management has licensed its patented technology for the transport by marine vessel of LNG in ISO containers.

The license is granted to an affiliate of New Fortress Energy for loading, transporting, and delivering LNG filled ISO containers in locations within the Caribbean and the territorial waters of the US, Mexico, and Canada.

Argent Marine’s patented technology involves the use of a proprietary manifold and control system on board a marine vessel that interconnects multiple ISO containers allowing the filling of all containers on-board in one operation, from a land-based or floating LNG source such as a liquefaction facility or LNG storage tank.

The manifold also provides control of boil-off in individual ISO containers while on-board the vessel, facilitating long distance delivery. Once loaded, individual ISO containers can be transported by vessel to multiple ports and then offloaded onto trucks for further land-based distribution of small scale LNG fuel.

The handling and transport system facilitates the distribution by vessel of small quantities of LNG to multiple consumption locations, minimising otherwise extensive handling costs and thereby improving overall transportation economics for small scale LNG distribution. For instance, the system will facilitate distribution of LNG from water-based US or other LNG facilities to the many small island-based power production facilities throughout the Caribbean, Mediterranean, or other archipelagos.

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May 2021

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Siva Prasad and Pranav Joshi, Rystad Energy, India, explore the current LNG production in Africa and how countries may consider new developments in the future to balance exports with domestic demand. he year 2021 is still reeling and recovering from the impact that COVID-19 created in the past 12 months. OPEC - OPEC+ production quotas are still in place and global oil demand has not yet returned to pre-COVID levels as many countries globally are still under lockdown. In early March 2021, Brent surged past US$70/bbl as a result of continued efforts from the cartel and partners, and also the recent attacks on Saudi Arabian facilities, and continued to hover around that mark during ensuing weeks. A predominantly oil producing continent with several economies relying heavily on their hydrocarbon revenues, the African oil and gas industry has been one of the worst hit during this market downturn. The impact has resulted in many projects going back to the drawing board and some even taken off the drawing board. However, African gas supplies, largely driven by currently producing fields, are expected to hover around the 250b-b275bbillion m3 mark for 2020 - 2025.

Having first discovered oil in the early 20th century, Africa has mainly been a crude oil producing continent. However, the tables have been turning recently, with natural gas accounting for more than 75% of the

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hydrocarbons discovered in Africa in the last 10 years. The gas production share also has improved from approximately 22% in the early 2000s to over 35% in 2020. Pre-COVID, Africa was poised to reach production levels of 300bbillion m3 by 2025 and 325 billion m3 by 2030. However, future developments took a hit, and the latest forecast puts 2025 levels at approximately 250bbillion m3 and 295 billion m3 by 2030.

Africa’s main natural gas producers Egypt, Algeria, and Nigeria were the top three natural gas producers in the continent for the year 2020, and their cumulative production represented more than 80% of the

Figure 1. Global natural gas production split by continent.

Figure 2. Africa gas production split by countries.

Figure 3. Top natural gas projects in the top three producing countries in Africa – Algeria, Egypt, and Nigeria.

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continent’s overall natural gas output. Algeria, the biggest gas producer in Africa, saw a marginal decline in gas production in 2020. While gas production dropped, domestic demand managed to continue growing as the country had lower pipeline and LNG exports. Italy and Spain, the major importers of Algerian pipeline gas, had reduced their Algerian pipeline imports as COVID-19 hit their domestic demand. Although Italy recovered by 2H20 and eventually imported 15% more volume compared to 2019, Spain saw a 20% y/y import drop. Algeria is still heavily reliant on mature legacy fields for gas production and has seen little sanctioning activity due to lack of any major recent discoveries.

The growing domestic consumption is expected to make it difficult for the country to sustain pipeline and LNG exports, which are quite important for foreign currency revenue. Rystad Energy estimates Algeria’s gas exports will be at 28bbillion m3 by 2025, 30% lower than 2020 levels of 40bbillion m3. The country is also finalising a new hydrocarbon law, through which it hopes to attract more IOCs. Sonatrach has already signed several Memorandum of Understandings (MoUs) with IOCs such as Eni, OMV, ExxonMobil, and more, to assess exploration opportunities.

Egypt, the second largest gas producer in Africa, is on its way to ramp up its gas production as major projects such as BP’s West Nile Delta and Eni’s Zohr project have started to add volumes.

Egypt’s gas production suffered last year as LNG exports dropped due to low global LNG prices and the domestic gas consumption was also reduced. The country faced a supply surplus due to this dual effect and had to cap its production. Zohr, which has the capacity to produce 91bmillionbm3/d , only produced an average of 59 million m3/d in 2020. While the domestic and LNG demand is expected to recover in 2021, Zohr is still expected to produce approximately 79 million m3/d. Rystad Energy estimates Egypt’s gas production to peak in 2023 and the country’s export potential is expected to be short lived. As a result, it is expected that the country will face a supply deficit in the second half of this decade. The country has been conducting several licensing rounds, both onshore and offshore, in the hope of discovering more volumes. Any commercial discoveries in offshore frontier regions would help reduce the gas deficit and possible future dependence on gas imports. A discovery similar to Zohr could help the country retain its net gas exporter status.

The two North African nations are followed by Nigeria, which is the third largest gas producer in Africa. The country currently has 22 million tpy (approximately 30 billion m3) LNG export capacity and 2020 exports were approximately 27.3bbillion m3.

The historical domestic demand also puts the 2020 domestic demand at approximately 27 billion m3. Rystad Energy estimates put 2020 Nigeria gas production including LPG volumes at 60bbillion m3. With the addition of 2019 approved NLNG Train 7 which is expected to start-up by the end of 2024, Nigeria’s export capacity is set to increase to approximately 40 billion m3. Nigeria is heavily relying on reducing flaring and monetising these volumes to support the increasing LNG export capacity. The country is also investing in improving its pipeline infrastructure to export gas from the hydrocarbon rich Niger Delta to domestic markets in Edo and other northern states. The recently commissioned Obiafu - Obrikom - Oben (OB3) pipeline along with the Escravos - Lagos Pipeline System (ELPS) represents phase one of the Trans-Nigerian Gas Pipeline (TNGP) project, which is being developed as part of Nigeria’s Gas Master Plan to utilise the country’s gas resources for power generation and domestic consumption. Many upcoming developments including Assa North - Ohaji South (ANOS), Ima, HA, HI-1, and more, along with

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many other currently undeveloped projects have the potential to add close to 140 billion m3 of gas production in the period 2021b- 2030. Accelerated development of these undeveloped projects will help Nigeria achieve the demand/supply balance that it requires to support both its domestic demand and LNG export capacity.

Libya and West African nations, Angola and Equatorial Guinea, come next in terms of the largest 2020 natural gas producers in Africa. Together, these countries add up to 26bbillionbm3 of gas supply with approximately 40% exported as LNG from the Soyo LNG Plant in Angola and Punta Europa LNG Plant in Equatorial Guinea. Further small volumes from Tunisia, Ghana, Cameroon, Congo, and Cote d’Ivoire put the overall cumulative continent-level 2020 gas supply at approximately 247bbillion m3.

Africa’s gas future In the future, Africa has the potential to further increase its gas production, mainly from projects located along the continent’s east coast. Some of the largest East African projects are in Mozambique and Tanzania, which have ample volume of discovered resources mostly being tapped for LNG exports.

Mozambique is set to ship its first LNG exports from its Coral floating LNG (FLNG) project in 2022. The 3.4 million tpy project was the first LNG project sanctioned in Mozambique in 2017.

In 2019, the 12.8 million tpy Mozambique LNG project in Area 1 was also sanctioned, where Total acquired Anadarko’s interest from Occidental Petroleum, after the latter acquired Anadarko. Rystad Energy estimates the project’s start-up to slip to 2025 from the originally planned 2024 in light of the growing insurgency in the country and also the slow progress in

Figure 4. 2020 - 2021 LNG exports from Africa.

construction activities due to COVID-19. Meanwhile ExxonMobil’s Rovuma LNG project in Area 4 has also faced many delays in getting sanctioned due to the partners’ goal to optimise project costs, and further delays now due to COVID-19. The project sanctioning was delayed to 2020 from the original expectations of 2019, and Rystad Energy’s latest estimate is for the project to be sanctioned in 2022. With all the three projects combined, Mozambique will be adding 31.5 million tpy of LNG. However, further expansion projects could also be planned in both Area 1 and Area 4 to tap additional gas resources.

Tanzania, on the other hand, has struggled to even finalise the fiscal terms after several negotiation talks with the IOCs failed to yield any agreement. Moreover, after Equinor recently wrote off US$982 million related to the Tanzania LNG project from its books, it indicates the project will not be sanctioned anytime soon. Equinor reported that the breakeven of this project was higher than that of other unsanctioned projects in its portfolio, which are planned for sanctioning in this decade. These issues suggest the Tanzania LNG project might only be sanctioned in the next decade. Rystad Energy estimates a 20bmillion tpy development to be one of the possible development scenarios to tap gas resources in Block 1, 2, and 4, however proactive discussions between the government and IOCs will be quite important to kick things off.

The maritime border between Senegal and Mauritania was on track to transition from an African exploration hotspot to an LNG export hub with annual capacity of up to 30bmillionbtpy in the pre-COVID era, and hence seemed like an impact area for future African gas supplies. However, a growing Islamic insurgency in neighbouring Mali started raising concerns about the security of the project and the project became a casualty of the pandemic in the following months. With an estimated recoverable gas reserve base of 1130 billion m3 at a conservative estimate, the Greater Tortue Ahmeyim (GTA), Bir Allah, and Yakaarb- Teranga projects were planned to be developed as 10bmillionbtpy LNG hubs each. However, the GTA FLNG is looking at possible delays and the 7.5 million tpy GTA LNG hub has been scaled down to 2.5bmillionbtpy according to the latest revised plan from the partners. These revisions also mean further delays to the other developments. Rystad Energy previously estimated 2025 and 2030 output levels from the region at 4.85 million tpy and 16.75 million tpy respectively before the pandemic hit. The upstream capital expenditure and production cuts along with strategy revisions from BP and Kosmos Energy are expected to result in 2025 and 2030 production to drop down to 2.85bmillionbtpy and 6 million tpy respectively.

Domestic demand putting pressure on LNG exports

Figure 5. Domestic demand in the top three producing countries.

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The two largest gas demand centres in North Africa are Algeria and Egypt, and both countries are expected to see an increase in demand in the coming years. Algeria’s domestic gas demand is estimated to have reached 44 billion m3 last year and is expected to reach close to 50 billion m3 by 2025, but more volumes need to be discovered to meet growing domestic consumption and sustain exports. Algeria’s increasing demand is putting pressure on the country’s capability to sustain LNG and pipeline exports in the medium-term. The country has signed several MoUs with various IOCs such as ExxonMobil, OMV, etc., to explore under the new Hydrocarbon Law, which is expected to be finalised by 1Q21.

Egyptian gas demand witnessed strong growth between 2015 and 2019 fuelled by the increase in domestic production, mainly

from the Zhor field. However, demand took a hit in 2020 due to the economic effects of COVID-19; consumption is estimated to have dropped 2% last year to 60 billion m3. Rystad Energy is expecting the country’s demand to recover and reach close to 70bbillion m3 in 2025, and most of this growth is expected to be driven by the power sector. But after 2025, demand growth could slow down as production is expected to start declining. As a result of the decline in production, Egypt’s LNG export from domestic resources could stop again in 2024 as the country could experience a supply deficit. Egypt has actively been conducting offshore licensing rounds in hope to discover more gas volumes.

Alternatively, supplies from Israel which are forecasted to continue growing, could help meet growing demand and could even help free some volumes to feed into the liquefaction plants.

The Nigerian domestic gas sector is classified mainly into the following three sectors as contained in the Nigerian Gas Master Plan (NGMP): Power (independent power plants); commercial (industries such as cement plants utilising gas as fuel); and gas-based industry (industries like fertilizer plants utilising gas as feedstock).

Approximately 83% of energy used to generate power in Nigeria is currently derived from gas. Presently, 25 gas-fired plants with a combined installed capacity of approximately 11b500 MW exist in the country. The total gas requirement to run all the plants at full capacity is approximately 85bmillionbm3/d. Between 2018 and 2037, it is expected that 55badditional thermal plants will come on stream as per the Nigeria Transmission Masterplan. These plants will generate an additional combined power of 19 000 MW and will require gas volumes of approximately 141 million m3/d (or 51bbillionbm3/yr) to generate the power equivalent. Clearly, Nigeria’s gas power generation has large potential but actual gas

consumption from this sector could be curtailed by available supplies. The average total domestic consumption over the years 2014 - 2019 was approximately 24 billion m3. Based on the trend, 2020 domestic demand is estimated to have reached approximately 25bbillionbm3 and the tally expected to surpass 40bbillion m3 by the end of the decade. The country is banking on infrastructure development, reduction of flaring and increased gas monetisation, and development of currently pre-Final Investment Decision gas projects in Nigeria to meet this demand along with fulfilling its LNG export aspirations.

Conclusion Rystad Energy analysis suggests that Africa has a great natural gas reserve potential, but project delays are going to be the main hindrance to raising gas production levels in the future to beyond current estimates. The post-pandemic upstream revisions from operators have resulted in many projects going back to the drawing board and some of them undergoing major revisions.

While gas supply has been hit hard by these delays, any growth is expected from cutting down these delays, reducing flaring, and carrying out further exploration. The demand is mainly expected to be met by improving the existing infrastructure and investing in developing new infrastructure. While the current supply/demand forecast suggests tight balance, the upside in major producing countries like Nigeria and exploration success in North Africa can easily outrun the demand and also cater to intra-African exports.

Note Data for all figures has been sourced from Rystad Energy GasMarketCube.

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14

Figure 1. The Dutch Reederei Doeksen has selected the new mtu gas engines to operate their vessels in an environmentally friendly way on the Wadden Sea, which has been designated as a special area of conservation.

Denise Kurtulus, Head of Marine Business, Rolls-Royce Power Systems, Germany, discusses how the introduction of a new gas engine technology can help combat emissions across a variety of vessels.

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olls-Royce first unveiled its mtu gas engines for marine propulsion in September 2016 at the SMM shipping exhibition in Hamburg, Germany. The new propulsion system for tugs, ferries, pushboats, and special ships is the first high-speed pure gas engine that can directly drive a fixed pitch propeller, giving it dynamic acceleration capability. It undercuts the nitrogen oxide limits of the current IMO III emissions directive even

without exhaust gas aftertreatment. It emits no sulfur oxides and particulate mass is below the detection level.

The first pre-series engines of the 16-cylinder version were already delivered to the Strategic Marine shipyard in Vietnam at the end of 2017 for two catamarans owened by Dutch shipping company Doeksen. In the summer of 2020, the first of Doeksen’s two LNG-powered passenger ferries, the Willem Barentsz, entered service, followed by sister

15

ship Willem de Vlamingh in early 2021. The shipping company of the Konstanz municipal utility in southern Germany received the first gas engines of the eight-cylinder version at the end of 2019 for a new Lake Constance ferry, which will enter service at the end of 2021. Rolls-Royce has also delivered the first gas engines for a harbour tug with hybrid propulsion, while Flensburg University of Applied Sciences is using the benefits of this engine for an energy transition research project looking at the capabilities of wind turbines for grid support.

No exhaust gas aftertreatment needed The new mtu gas engine is based on the proven mtu diesel engine of the 4000 M63 series for workboats. The engines are offered in an eight-cylinder version with an output of 746bkW and as a 16-cylinder version with an output of 1492 kW. Fuel consumption, emissions, safety, and acceleration were the focus of development from the outset. The new mtu gas engines were equipped with multipoint gas injection, dynamic engine control, and advanced turbocharging. The multipoint gas injection system ensures

Figure 2. The new mtu gas engines are offered in an eight-cylinder version with an output of 746 kW, and as a 16-cylinder version with an output of 1492 kW.

dynamic acceleration and reduced emissions. The combustion concept enables compliance with IMO III emission standards without additional exhaust gas aftertreatment. The controlled combustion also ensures efficient fuel use. A single-stage turbocharging system with two exhaust gas turbochargers operating in parallel is used. The high-efficiency turbochargers are the third generation of the ZR series, and the turbocharging system also incorporates a controllable compressor bypass and intake throttling concept. The engine thus has sufficient power reserves throughout the entire speed range for difficult driving manoeuvres. As a result of the doublewalled design of the gas system, the engine room can be designed to be diesel-like. The mtu gas engine is compliant with the official international IGF code (gas-safe engine room) of the IMO.

A sustainable propulsion system “Even though the COVID-19 pandemic is currently in focus worldwide, we must not forget the environment. In the maritime industry, we need sustainable solutions that reduce pollutant emissions. I am pleased that we can now already add the second LNG ferry to our fleet,” said Dirk Spoor, CEO of Reederei Doeksen, on the occasion of the commissioning of the Willem de Vlamingh in January 2021 in Harlingen, the Netherlands. During the first voyages in 2020, there were several other advantages of the gas engines that stood out, including how the engines are particularly quiet and do not produce vibrations, unpleasant odour, or black smoke.

Similar to its sister ship, the new 70 m long, LNGpowered ferry is made entirely of aluminium. This material makes the vessel lighter and consume less fuel than conventional ferries. The 16-cylinder mtu 4000 series gas engines produce 1492bkW each, giving the ferry a top speed of 14 knots. The existing fleet can make good use of the reinforcement – every year, approximately 800 000 people need transportation back and forth from Harlingen on the Dutch mainland to the islands of Vlieland and Terschelling on the North Sea in the Wadden Sea nature reserve, approximately 30 km away.

Changing over to biogas

Figure 3. In the summer of 2020, the first of Reedereij Doeksen’s two passenger ferries, the Willem Barentsz, entered service with the new 16-cylinder mtu gas engines on board, followed by sister ship Willem de Vlamingh (pictured) in early 2021.

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May 2021

The Doeksen shipping company is aiming to switch to biogas in the near-future. Initially, its vessels will be operated with LNG, which the shipping company sees as a transitional fuel. In the future – as soon as the necessary infrastructure is in place – the company would like to switch to more sustainable bio-LNG or liquefied biogas (LBG).

A residual heat recovery system already ensures that thermal energy from both the engine cooling system and the exhaust gases is used. Two Orcan units also supply all the electrical power needs of the bow thruster system and meet some of the normal electrical needs on-board.

“We are proud that Reederei Doeksen has selected our new gas engines to operate their vessels in an environmentally friendly way on the Wadden Sea, which has been designated as a special area of conservation,” said Denise Kurtulus, Head of Marine Business at Rolls-Royce Power Systems. “Together with our partner, we are thus doing everything we can to advance the maritime energy revolution.”

LNG Sampling at low pressures (> 0.7 barg)

LNG sampling can be considered as a mature technology as its basic principles have initially been described in the ISO8943 back in 1991.

Yet, it is currently still a very active phenomenon with many GHYHORSPHQWV LQ LWV ȴHOG RI SUDFWLFH 7KH PDLQ FKDOOHQJH LV obtaining a representative sample for custody transfer based on the critical characteristics of LNG. One of the most important and subsequently the most challenging characteristic of LNG, is that at atmospheric pressure, a typical LNG mixture has a boiling point of -162°C. This makes representative sampling at lower pressures (0-1 barg) challenging due to less available subcooling and thus the high chance of pre-vaporisation and fractionation of LNG during sampling.

Low pressures are usually present during ship-to-ship or ship-to-land custody transfers. Generally, this is due to the low pressure transfer manifolds and the on-ship high capacity, low pressure pumps. The LNG booster pumps on LNG carriers are cryogenic centrifugal pumps fully submerged in LNG DQG RSHUDWHG DW ȴ[HG VSHHG ΖQ WKLV FDVH ȵRZ DQG SUHVVXUH FDQ RQO\ be increased by means of manual throttling on the pump discharge side.

7KLV VR FDOOHG WKURWWOLQJ LQYROYHV PDQXDO UHJXODWLRQ RI ȵRZ DQG WKXV pressure, at the side of the receiving party.

Besides the required extra manual labour for throttling and longer transfer (batch) time, increasing pump capacity (above nominal) to increase pressure can subsequently raise the LNG temperature due WR KHDW WUDQVIHU RI WKH SXPSV $OVR WKURWWOLQJ ZLOO OHDG WR D ȵXFWXDWLQJ ȵRZ DQG SUHVVXUH ZKLFK LQ WXUQ KDV FRQVHTXHQFHV IRU /1* VDPSOLQJ 0RUHRYHU ȵXFWXDWLRQ LQ /1* WHPSHUDWXUHV SUHVVXUHV DQG ȵRZV FDQ

To cope with all of the aforementioned issues and with other (on land) low pressure LNG transfer applications, a new concept of an integrated probe-vaporiser combination has been recently introduced by 360°KAS: The CryoSamp. The CryoSamp is in compliance with WKH Ζ62 DQG WKH *ΖΖ*1/ VWDQGDUGV DQG LV DQ DOO LQ RQH PRGXOH LQFOXGLQJ ȴOWHUHG WDNH R΍ SUREH YDSRULVHU LVRODWLRQ YDOYHV DQG temperature monitoring.

A unique characteristic of this concept, is that the probe UHDOLVHV D FRQWLQXRXV ȵRZ RI /1* WR %RLO RI *DV %2*

in which the LNG sample is maintained at an adequate temperature without any fractionation and pre-vaporisation.

Furthermore, another advantage of this design is that potential gas bubbles will be extracted from the LNG supply which in turn will not be a part of the LNG sample.

Also, accurate and complete vaporisation of the sample is HQVXUHG E\ D WZR VWHS SURFHVV $V WKH KRW VHFWLRQ LV KDOI ȴOOHG ZLWK ZDWHU WKH ȴUVW VWHS LQYROYHV YDSRULVDWLRQ RSWLPLVDWLRQ through water vapor that condensates on the coil for a maximum heat exchange. The second step is vaporisation of LNG in the liquid section in which LNG is vaporised by heated water (under vacuum) at a temperature of 50°C. r.$6 VHUYHV WKH /1* 9DOXH &KDLQ VLQFH ZLWK VROXWLRQV WR WDNH YHULȴDEO\ DFFXUDWH DQG UHSUHVHQWDWLYH /1* VDPSOHV IURP D FU\RJHQLF ȵRZ SURYLGLQJ WKH IROORZLQJ 6DPSOH 7DNH 2΍ $VVHPEO\ 3UREH 9DSRULVHU 6\VWHPV Ζ QWHUPLWWHQW &3 )3 DQG &RQWLQXRXV :DWHUOHVV 0HPEUDQH RU &RQWLQXRXV :DWHU 6HDO 'RPH /1* 6DPSOLQJ 6\VWHPV ΖQWHOOLJHQW 4XDOLW\ 5HSRUWLQJ 0RGXOH L450

:LWK WKH DGGLWLRQ RI WKH &U\R6DPS WR LWV SRUWIROLR r.$6 LV DEOH WR further contribute to the challenge of obtaining the best possible LNG sample for custody transfer and add a high performance innovative probe-vaporiser design to the (low-pressure) LNG sampling market.

lead to a reduction in the amount of available subcooling (enthalpy), a chance of pre-vaporisation, fractionation, a non-representative sample and thus a high potential risk of LNG heating values deviation.

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The new Lake Constance ferry Another ferry with the new mtu gas engines powered by LNG will enter service in Constance, southern Germany, at the end of 2021. Stadtwerke Konstanz operates a Lake Constance ferry fleet there with a total of six ships that

shuttle back and forth between the two shores every day around the clock. The company received the first gas engines of the eight-cylinder version with an output of 746bkW for the first gas-powered fleet member at the end of 2019. The 82.5 m vessel, with a capacity of 62 vehicles and 700 passengers, is currently under construction.

The world’s first hybrid LNG tugboat

Figure 4. The 16-cylinder mtu 4000 series gas engines give the Doeksen ferries a top speed of 14 knots. They are the first high-speed pure gas engines that can directly drive a fixed pitch propeller, giving it dynamic acceleration capability. They undercut the nitrogen oxide limits of the current IMO III emissions directive even without exhaust gas aftertreatment. They also emit no sulfur oxides and particulate mass is below the detection level.

Rolls-Royce supplied two 16V 4000 M55RN mtu gas engines to Sembcorp Marine Integrated Yard for the construction of the world’s first LNG hybrid propulsion tug.

The harbour tug will be operated in Singapore by Jurong Marine Services, a wholly owned subsidiary of Sembcorp Marine. The new LNG hybrid tug is the first of 12 tugs Sembcorp Marine plans to design and build to replace existing diesel-powered tugs in the years leading up to 2025.

This is the world’s first LNG hybrid tug powered by mtu gas engines. The LNG hybrid tug was designed by LMG Marin (Norway), part of the Sembcorp Marine Group, for the delivery of 65 t ABS-class bollard pull, and is expected to be completed later in 2021. The tug’s main propulsion system consists of two 16-cylinder mtu series 4000 gas engines that will deliver a combined total output of 2984bkW at 1600 rpm. The LNG hybrid propulsion system will be able to flexibly respond to different operating modes and switch between low-emission LNG engines and zero-emission battery power.

Multipurpose vessels The German Directorate-General for Waterways and Shipping is relying entirely on gas engines from RollsRoyce to equip its three new multipurpose vessels: the ships will be powered by special gas-protected mediumspeed Rolls-Royce Bergen B36:45 engines.

The four engines for the gas-electric propulsion system each have an output of 3161 kW and are specially equipped for use in explosive and hazardous environments. One mtu 16V 4000 M55RN gas engine per ship powers a fifth genset. In a dual function, this provides electricity in port when there is no shore connection. But it also supplies propulsion energy when the ships are operating in the low-load range. In the future, the three 95 m long special ships will be called out on the North Sea and Baltic Sea to deal with accidents at sea, fires, or when ships are unable to manoeuvre. The first of the new special ships is scheduled to enter service in 2023, the second a year later, and the third in 2025.

A programme with the future in mind

Figure 5. A single-stage turbocharging system with two exhaust gas turbochargers operating in parallel is used for the new mtu gas engines. The high efficiency turbochargers are the third generation of the ZR series, and the turbocharging system also incorporates a controllable compressor bypass and intake throttling concept.

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May 2021

The new gas engine is part of Rolls-Royce’s Green and High-Tech programme. In this way, the company is investing specifically in environmentally friendly future solutions for lower emissions and reduced consumption of energy and raw materials. Rolls-Royce’s Green and High-Tech programme focuses on efficiency enhancement, alternative fuels, electrification, digitalisation, and integrated system solutions, with the aim of offering complete powertrain and energy generation systems.

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Figure 1. The small scale LNG facility, JAX LNG, sits along the St. John’s River in Jacksonville, Florida, US, and is the only facility of its kind on the US East Coast to offer both marine and trucking capabilities.

Ann Nallo, BHE GT&S, USA, looks at how providing diverse fuel solutions for a variety of customers across the US can help expand business in a rapidly changing LNG sector.

20

ith the implementation of new International Maritime Organization (IMO) regulations in 2020 and the increasing need for a reliable and clean domestic energy supply, BHE GT&S — a Berkshire Hathaway Energy company — sees a growing trend for LNG infrastructure investments. Through the Cove Point LNG import and export facility 60 miles southeast of Washington, D.C., US, and its subsidiary Pivotal LNG, BHE GT&S has been making its name in the LNG industry for more than 15 years.

Businesses across the US today are focused on decarbonisation and BHE GT&S is actively supporting those efforts in a number of sectors, including transportation, space travel, and heavy industry. LNG, in particular, is a much cleaner fuel than the diesel or fuel oil that maritime shipping, longhaul trucking, and manufacturing have traditionally relied upon.

At the same time, LNG is helping to alleviate constraints in regions where natural gas supply or infrastructure is inadequate to furnish energy needs during peak days.

Pivotal LNG owns and operates the Trussville LNG facility in Alabama, US, and the Towanda LNG facility in Pennsylvania, US, and holds a 50% ownership of the JAX LNG facility in

Jacksonville, Florida, US (the other 50% belonging to partner NorthStar Midstream). Together, the facilities currently have the capacity to produce 230b000bgal./d of LNG and to store approximately 7bmillion gal. of LNG. “BHE GT&S is committed to doing our part to help transform the energy industry and make supply chains more sustainable,” said Roger Williams, VP of Commercial LNG and Gas Development at BHE GT&S. “We think our investments in LNG will go a long way to provide cleaner and lower cost solutions to our customers, such as marine shipping, that have historically had very limited fuel alternatives.”

Jacksonville, Florida – the cradle of US LNG marine bunkering Pivotal LNG has access to several LNG supply sources in the southeast, including both Trussville and JAX LNG, that provide a well-integrated supply platform for customers using LNG for trucking fuel, pipeline outages, and a range of industrial applications. This network, and the use of Pivotal’s large storage tanks, ensures customers receive the LNG that they depend on for critical operations when and where they need it,

21

even if one of the facilities temporarily halts production due to a scheduled or unscheduled outage.

JAX LNG overlooks the St. John’s River in Jacksonville, Florida, just a short distance from the Atlantic Ocean, and is the only facility of its kind on the East Coast to offer both marine and truck loading capabilities on-site. The JAX LNG facility is in a particularly ideal location to deliver LNG to maritime customers due to its proximity to JAXPORT, one of the largest cargo ports on the East Coast, and Port Canaveral, one of the largest cruise ports in the US. Within its 37-acre footprint, the state-of-the-art small scale facility connects to a firm gas supply and currently contains a liquefier, a storage tank, truck loading bay, on-site power generation, and marine loading dock.

Due to the new IMO 2020 regulations requiring a reduction in emissions from ships in international waters, ship owners are now altering their fuel sources, installing scrubbers, or constructing new LNG-fuelled ships to meet these standards. BHE GT&S sees this as an opportunity to provide its expertise and capital to further develop the required infrastructure and ensure reliable LNG supply to its customers.

JAX LNG is the LNG supplier to the world’s first LNG dual-fuel container vessels — Isla Bella and Perla del Caribe — which are operated by TOTE Maritime and provide weekly shipping services to Puerto Rico. TOTE Maritime’s Clean

Jacksonville, the first LNG bunker barge built in the US, receives LNG at the JAX LNG dock and then delivers it to the TOTE ships, which are berthed at nearby JAXPORT. International maritime customers that utilise JAXPORT are increasingly looking for LNG supply. In February, JAX LNG and TOTE Maritime collaborated to provide LNG to the Siem Confucius, part of the newest generation of car carriers that was put into service in late 2020. The 7500bcar capacity Siem Confucius and its sister ship, Siem Aristotle, are Liberianregistered and regularly call on JAXPORT to unload factorynew Volkswagen Group of America cars and SUVs. Eric Green, JAXPORT CEO, recently said, “Some of the world’s most eco-friendly ships call at JAXPORT thanks to the innovation and vision of our customers and port partners. Jacksonville is a global leader in the use of LNG and we are proud to help support the continued growth of LNG in the maritime industry and beyond.”

Another customer, Crowley, loads LNG onto ISO containers at JAX LNG and transports them by ship to Puerto Rico for use by its customers. In Puerto Rico, many companies have turned to LNG-fuelled electric generators to ensure they have access to around-the-clock power during periods of intermittent electric supply.

To prepare for growing LNG demand, JAX LNG is tripling its LNG production capacity to 360 000 gal./d and doubling its storage capacity to 4 million gal. – a project planned for completion in early 2022. Along with the facility expansion, NorthStar’s subsidiary, Polaris, is constructing a 5400 m3 LNG barge to better serve the marine industry, using LNG sourced from JAX LNG. The barge is set to be in service by late 2021.

In addition, the JAX LNG facility sits next to a railway and has the capacity for further infrastructure development to serve that market when the time is right.

Supplying the aerospace industry

Figure 2. Owned by TOTE Maritime, the Clean Jacksonville is the first LNG bunker barge built in the US. It receives LNG from the JAX LNG facility to fuel two dual-container cargo ships that service Puerto Rico.

Situated within a two-hour drive from the NASA Marshall Space Flight Center in Huntsville, Alabama, US, the Trussville LNG facility is helping support aerospace endeavours. For a number of years, Trussville has been providing LNG to the Flight Center towards the testing of materials and equipment.

The use of LNG in the aerospace industry — and specifically near ‘Rocket City’ (Huntsville) — is expected to grow substantially over the next several years as the commercial aerospace industry advances LNG-powered rocket engine technology.

Last year, Pivotal LNG was awarded a NASA agency-wide supply of LNG to multiple centres to support additional testing and launches from the Kennedy Space Center in Florida. The recent indefinite delivery requirements contract will be supported by all of Pivotal’s facilities.

“It is exciting to see NASA and a number of private companies looking to LNG as a rocket fuel,” said Tim Delay, Vice President of Pivotal LNG. “LNG is already having a positive effect on industries and on our environment. We expect that will continue for the foreseeable future.”

Expanding into the northeastern US Figure 3. Pivotal LNG’s Trussville, Alabama, US, facility provides LNG for trucking, industrial, and aerospace companies.

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Located in the heart of the Marcellus shale gas production region, the Towanda LNG facility entered service in January 2021 and offers on-site truck loading capabilities and customised LNG solutions, such as temporary tanks with vaporisers that companies can rent or buy to help meet their

energy needs. The facility is well situated to meet the needs of customers in the northeastern US who are increasingly experiencing a lack of access to natural gas, especially during periods of low temperatures.

“LNG is a low-cost and easily transportable fuel that does not compromise on reliability and is not as susceptible to price volatility as other fuels,” said Lyle Henry, Director of Gas Partnership Business Development at BHE GT&S. “In the northeast especially, where you see cold winters, there is still a strong reliance on fuel oil, propane, and coal for many homes and businesses. LNG is a great option because it has a lower carbon footprint and can help solve pipeline constraints using infrastructure that is already there.”

Additionally, the facility is opening doors to new markets for LNG in the northeast US. Just ahead of official in-service, LNG from the facility refuelled a marine vessel at the Port of Hamilton by Lake Ontario, Canada. It was the first ever LNG fuelling of a vessel on the Great Lakes, a major milestone in the evolution of the regional shipping industry.

Building out a broad business For BHE GT&S, the key to success for a growing LNG business is providing diverse solutions for commercial and industrial customers of all sizes. With LNG operations in Pennsylvania, Maryland, Alabama, and Florida, the company has already built up a strong presence across most of the eastern US and plans to continue supporting broad decarbonisation, with Cove Point and JAX LNG being well-positioned to serve as anchor points in a coastal marine strategy.

Figure 4. Pivotal LNG’s Towanda, Pennsylvania, US, facility provides LNG for northeast utilities in a constrained market.

“I’ve been in the energy industry for nearly 20 years and have never seen more rapid change than I do today,” said Williams. “We’re working hard to do what’s best for the environment and listening to customers to make sure they have the energy that supports their needs. From global trade of LNG that supports international markets to our small scale solutions for domestic customers, I’m confident LNG will continue to grow in our core markets of marine, trucking, aerospace, and constrained gas utilities. It all comes back to the fact that LNG is a cleaner, lower-carbon fuel choice and, thanks to its low-cost and abundant supply, it shows great promise for the future.”

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Frans Launonen, Vahterus, Finland, highlights the role of LNG in decarbonisation and how to maximise savings on skid building by selecting optimal heat exchangers.

T

he aim of this article is to highlight the benefits of the optimal heat exchanger selection for LNG and boil-off gas (BOG) fuel gas systems. First, however, it is helpful to take a look at the current situation with new-build vessels and why LNG is needed in decarbonisation.

2020 will be remembered as the year of COVID-19, but it was also the worst year of the new millennium with regard to vessel contracting. At present, the world fleet is close to 100b000 vessels. New-build projects, especially those related to LNG, are concentrated in Asian shipyards. The only exception is the LNG-fuelled cruise industry, which has remained in Europe. But despite the low number of new vessels, the total amount should increase by 2050. Just how much depends on who is forecasting. Increases take place due to a growing population, a rise in gross domestic product rates, and rise in global exchange. A growing fleet of vessels using traditional fossil fuels such as heavy fuel oil (HFO) or marine gas oil (MGO), combined with zero improvements in

efficiency, would be the worst-case scenario from the perspective of greenhouse gases (GHG). Thus, the International Maritime Organization (IMO) is trying to ensure a cleaner future through various proactive measures. IMO has clear targets for cutting emissions and increasing efficiency. Its biggest ambitions are to reduce carbon intensity by at least 40% by 2030, and CO2 emissions by 70% by 2050, as well as GHG emissions by at least 50% (in comparison to 2008). No fuel available today can meet the 2050 targets alone.

The road to year 2020 The increasing fleet will mean that per vessel, the emission reductions will need to be even stricter to meet the 2050 target. This requires energy improvement supported by the Energy Efficiency Design Index for new-builds and existing vessels, smarter operation during voyages, as well as the gradual decarbonisation of the fuel chain. Most of the vessels ordered today will still be sailing in 30 years’

25

Figure 1. Proper lifting points and lifting plans are always essential. Assembly and disassembly is made convenient and safe for maintenance personnel due to the compact size and low weight of the PSHE units.

Figure 2. In the latest cryogenic testing at the Vahterus laboratory, the company utilised liquefied nitrogen with an inlet temperature of -180˚C induced in cycles by an automatic control valve to the plate and shell heat exchanger.

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May 2021

time, which means there is only one generation of vessels between tomorrow and the year 2050. It is therefore crucial that responsibility for the future is taken now. The fuel technology selections made today must stand up to the test of time.

One of the most promising and future-proofed approaches is to utilise LNG. The development of the LNG-fuelled vessels segment started around 2000. Between 2010 and 2020, the number of vessels has been growing rapidly each year. The current LNG-fuelled fleet (less than 200 vessels) is utilising close to 1 million t of LNG. That number will rise with both new-builds and existing LNGconverted vessels going into operation. Based on the information gathered by DNV and Clarksons Research, in two years’ time there will be close to 200 vessels on order.

During the year 2022, the total fleet – including operating, LNG-ready, and vessels on order – will peak at over 500.

Bunkering LNG infrastructure is globally available, which is supporting the growth. The current trend is that even larger LNG terminals are adapting to small scale LNG demands by preparing bunkering capabilities for smaller vessels on their jetties or through bunkering vessels.

There are several reasons why the number of LNGfuelled vessels will increase during the next decade. Firstly, switching to LNG lowers CO2 emissions by close to 20% compared to MGO. Secondly, LNG’s energy density is half that of MGO, a key factor since most of the vessels are sailing longer distances. Utilisation of renewable power and batteries onboard is currently limited by space and capacity on longer voyages and, in comparison to LNG, other alternative future fuels have higher volumetric needs for providing the same amount of energy. LNG can also be considered as a transition fuel to a cleaner future because it can be replaced by carbon-neutral fuels such as biogas. One step further is Power-to-X technology – for example, the forming of green hydrogen through electrolysis using renewable power. Mixing this hydrogen with CO2 from carbon capture in synthesis will generate green methane for liquefaction. The result is similar to the LNG currently available, but better since it has a higher methane number and is a non-fossil fuel. The technology for decarbonisation does exist, it just needs to be scaled up in a feasible manner.

LNG is clearly a significant element in the decarbonisation of shipping. As DNV has pointed out in its ‘Maritime Forecast to 2050’, LNG is already one of the best, if not the top contender among alternative fuels when considering fuel availability, infrastructure, energy costs, safety, and technical maturity. The potential of alternative future fuels such as ammonia and hydrogen should not be underestimated, but they are still taking baby steps and lack formal regulation, while the LNG-fuelled vessel market is backed by rules related to safety and technology. Methanol is coming closer to being a stronger option in the short-term, but it currently has very limited global availability for bunkering, combined with a high price.

Impact of heat exchangers on system design Due to the nature of shipbuilding, most shipyards rely on long-term partnerships and suppliers for auxiliary and process systems on vessels. LNG and BOG fuel gas skids are no exception. The direction in the market is towards higher

reliability, maintaining the safety record, and operational flexibility. It all boils down to cost. Fuel gas system prices have been dropping significantly during recent years as a result of consistent work between suppliers, yards, and shipowners. CAPEX has always been a major issue regarding investments, and remains so. Nowadays, OPEX and owner benefits are also becoming more important in technology selection. Many shipowners are starting to understand from their experience in the field that the bottom line is the sum of both costs. The greatest individual impact on the cost of the fuel system is the storage tank.

Space is always at a premium in shipbuilding. LNG needs twice as much storage space in the vessel than fuel oils.

Ammonia requires an additional doubling of storage space compared to LNG, and hydrogen even more. Added to this is the challenge that fuel auxiliary systems require onboard space. Most of the LNG fuel systems featuring pressurised tanks run with simple and robust pressure build-up (PBU) technology, which means that no mechanically driven cryogenic equipment is needed to force the gas to consumers. This is a major benefit in terms of OPEX and CAPEX. LNG heat exchangers are much more feasible than LNG pumps and do not require frequent maintenance. The system also requires an LNG vaporiser and/or superheater.

BOG heat exchangers are also required in those cases where the tank pressure accumulation or consumer side cannot keep the holding time within the 15-day minimum level required by the IGF code.

If heat exchangers are based on ageing shell and tube or coil technology, this will heavily affect LNG and BOG skid

sizes and limit the freedom of mechanical and process designers. Why is this the case? The reason is that due to their size, shell and tube and coil technology will in many cases dictate the width or height of the whole skid assembly.

Luckily, other alternatives do exist, so that actions can be undertaken in a more compact way while saving natural resources at the same time. One way is to utilise Vahterus plate and shell heat exchangers (PSHE), which are on average close to five times smaller and much lighter than shell and tube heat exchangers.

Plate and shell technology enables various benefits related to the CAPEX of skid building. As a rule of thumb, normally with plate and shell technology, vaporising and superheating of the LNG can be completed within a single unit, which eliminates the need to have separate gas heaters in the system. This leads to a simplified process, and the system takes up less space. In addition, nozzle sizes and locations can be chosen more freely with a PSHE. This is a major benefit that other technologies do not have. It might sound a small thing, but having a nozzle pointing in the desired direction from the heat exchanger on the LNG and BOG skid can save a significant amount of piping metres and bends on the skid. There is substantial space-saving impact on the size of the whole skid. This can be converted directly into money. A smaller skid is a sales advantage and can be considered better in terms of maintenance, since maintenance distances can be designed more flexibly in compact heat exchangers. Plate and shell heat exchangers do not require any additional support, and can be stacked to optimise the skid design even further.

Some of its new customers, for example, require a thermal shock demonstration to be part of the project, which Vahterus is happy to provide.

In the latest cryogenic testing at Vahterus laboratory, the company utilised liquefied nitrogen with an inlet temperature of -180˚C induced in cycles by an automatic control valve to the plate and shell heat exchanger. Over several months, more than 90 t of liquefied nitrogen was consumed, generating a total of over 60 000 full thermal cycles, with no leakages or structural damages detected on a subsequent helium vacuum test. The amount is equivalent to more than two to four times as many cycles than an average vessel would see during its lifetime.

The second important testing during the last year was to find the real operational freezing limits with different flows, temperatures, and mixtures for plate heat exchangers by having glycol-water on one side, and cryogenic fluid on the other side of the plate. Understanding the freezing limits is crucial when designing LNG cold recovery systems where low approach temperatures are important for achieving high total efficiency. Besides laboratory testing, evidence from the field demonstrates that even standard PSHEs, which have not been optimised for high cyclic loads, withstand at least twice as long as shell and tube. This was demonstrated on similar sister vessels with high-frequency thermal cycling. In many cryogenic projects, failing shell and tube heat exchangers have been replaced by PSHEs with positive results.

Figure 3. LNG expert Frans Launonen photographed at the Vahterus test lab during a series of cryogenic tests.

Benefits for inspections and enhanced reliability Having nozzles on the heat exchanger instead of welded connections provides further flexibility for maintenance. Skid maintenance and inspection issues become visible to the owner during dry docking, when the heat exchangers can be lifted up easily from the LNG fuel gas skid (or from the tank connection space) without any modifications to the cofferdam.

With bigger heat exchangers such as coils or shell and tubes, more volumetric space is needed for the tank connection space and/or a bigger opening to get them out of the tank connection space.

When it comes to operational aspects during the ship’s lifetime, it is a known fact that all vessels with mechanically driven equipment have certain vibrational design challenges that must be accounted for, especially if the equipment is located on the lower decks close to engines. Both plate and shell and shell and tube technologies are ideal in this respect due to their rigid shell design. Operational profiles and varying loads on the consumer side of the LNG fuel gas system can induce thermal cycles for separate PBU and vaporiser units. One of the more demanding scenarios, causing multiple thermal cycles per day, is operation on a short route combined with a poorly adapted control system.

Due to a heavy focus on R&D during recent years, Vahterus has developed several solutions to improve the mechanical design and optimal fluid routing within the heat exchanger so that it is able to withstand significantly more thermal cycles. In addition, with its partners the company has undertaken extensive testing around freezing and thermal cycling to demonstrate the robustness of the technology.

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Greener alternatives coming into use Advantages related to more flexible and compact solutions are well understood by the leading LNG fuel gas and BOG system builders. Some are still providing skids with traditional heat exchangers such as shell and tube, for two main reasons: they themselves produce shell and tube exchangers, and they do not know about plate and shell technology. Therefore, raising awareness about the newer and more sustainable products is still required among LNG industry solution providers and end users. More than a third of the globally existing LNG-fuelled fleet is equipped with Vahterus LNG plate and shell heat exchangers. This is as a result of close collaboration with Vahterus’ partners, most of whom have seen the benefits of this technology from the start, while others have required pilot projects and time before coming to the same conclusion.

LNG as a marine fuel can secure the IMO 2030 target, but the targets for 2050 cannot be achieved with fossil-based LNG. The latest development and research on LNG as a marine fuel has been touching on the utilisation of ammonia for LNG systems in the future. Early this year, leading membrane technology design company GTT announced that it has received an Approval in Principle for its Mark III membrane tanks to be used for the containment of ammonia without any major design changes. Ammonia as a natural refrigerant is much-utilised in the refrigeration business, which is one of the main users of plate and shell technology. A possible transition from LNG to green ammonia further bolsters the role of LNG in the decarbonisation path. This gives confidence to vessel owners that LNG fuel gas systems will have added value and flexibility to provide not only both for bio and synthetic natural gas but also for ammonia. Plate and shell heat exchangers are the optimal choice for LNG and BOG system builders when looking for future-proofed solutions in a sustainable and cost-effective manner.

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Margaret Greene (USA), William Dolan (USA), Justin Pan (USA), Al Maglio (USA), Tobias Eckardt (Germany), BASF, and Harold Boerrigter (Netherlands), Marco Smaling (Netherlands), and Imelda Rusli (UK), Shell, detail a dual-purpose adsorbent technology for combined heavy hydrocarbon and water removal from lean feed gas in LNG to prevent cold box freezing.

L

ean feed gas to LNG plants is becoming increasingly prevalent as several recent LNG projects are based on pipeline gas which contains predominantly methane with low natural gas liquid (C2-C5) and lower heavy hydrocarbons (C5+) content than typical conventional natural gas.1 However, the leaner compositions, especially dew pointed pipeline gas, can manifest a small but significant ‘heavy tail’ of heavy hydrocarbons and BTX which can be challenging to define and remove.

Removal of heavy hydrocarbons (C8+ HHCs) and aromatic (BTX) components from natural gas prior to liquefaction is critical for continuous LNG production. Even trace concentrations of certain HHCs and aromatics can cause precipitation of solids (freezing) and fouling of main liquefaction heat exchangers. For example, even

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existing LNG plants supplied by relatively lean feeds or experiencing feed gas composition fluctuations often face challenges with currently installed technology to deal with trace heavies in lean feed gas.

A lean feed gas presents many challenges to the conventional heavy hydrocarbon removal methods such as a scrub column and natural gas liquids extraction unit. The natural gas liquid extraction unit is a capital-intensive unit

Figure 1. Typical line-up for conventional LNG plant.

with a high equipment count, and it requires considerable utility demands during operation. With low yields a natural gas liquids extraction unit becomes uneconomical. The integrated scrub column may become unsuitable due to the low levels of C2-C5 components, as there is insufficient liquid traffic within the scrub column to stably operate the unit at available condensing temperatures.

In this article, a line-up study is presented comparing dual-purpose temperature swing adsorption (TSA) technology (Durasorb Cryo-HRU) to conventional processes for the removal of C8+ HHCs from lean feed gas. The analysis will highlight the benefits of the adsorption technology under specified feed gas and operating conditions. The case will be made that dual-purpose TSA technology presents significant benefits, including for dehydration retrofit applications, with regards to reduced complexity, improved CAPEX, ease and flexibility of operation, and reliability. The novelties of the technology are discussed with results from extensive testing, illustrating that the combined HHC and water removal in one system is robust. The specifications for the feed to the main cryogenic heat exchanger (MCHE) of the liquefaction unit – as referred to in this article – are summarised in Tableb1.2

Conventional line-up Figure 2. Heavy hydrocarbon (HHC) removal with a scrub column inside cold box.

Figure 3. Natural gas liquids turboexpander.

Table 1. Recommended specifications for feed to MCHE Component

Specification (ppmv)

H2O

0.1

C5+

< 500 (LNG rundown)

nC8

< 0.5 (#)

Benzene/BTX (*)

1-3

nC9

≤ 0.3 (below the detectable limit)

nC10

≤ 0.3 (below the detectable limit)

< 0.1 molecular% (LNG product)

(*) Total of BTX components are lumped to benzene, as this is most critical for the adsorption process. (#) Solubility of nC8 at -162°C, 60 bara in liquid CH4 is experimentally measured to be <0.5 ppmv.

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The analysis presented considers the various technologies for the pretreatment of lean natural gas for LNG production.

Lean gas, also known as dry gas, is defined as natural gas containing less than 5% liquefiable hydrocarbons.3 The typical line-up for a conventional LNG plant with a non-lean feed gas is shown in Figureb1. After the inlet facility, the gas passes through the mercury removal unit (MRU) to remove the mercury, followed by an acid gas removal unit (AGRU) to remove the CO2 (to <50 ppmv) and H2S (to <3.5bppmv), and a dehydration unit (DeHy) to remove the water (to <0.1bppmv). An alternative option is to position the MRU downstream of the DeHy. The C5+ specification of <500bppmv of the gas is reached in a scrub column or in the natural gas liquids section. In these steps the heavier hydrocarbons and the aromatics are removed to well below 1bppmv.

In a line-up with a scrub column, treated gas from the pretreatment unit is sent to the scrub column to remove HHCs using reflux generated in the liquefaction process (Figure 2). The liquid reflux consists of natural gas liquids (C2-C5) that wash down C6+ components to achieve removal of C6+ and BTX to meet specification. For lean feed gas the amount of liquid reflux is insufficient for stable operation of the column and to achieve the required specifications. A variation would be to supply external washing liquid, but in an LNG plant no suitable stream is available (i.e. the LNG is too light, and the condensate is already HHC saturated) and import of a scrubbing liquid would make the option unattractive.

A natural gas liquid extraction plant can be placed upstream of the liquefaction unit to remove natural gas liquids and HHCs (Figureb3). A natural gas liquid unit can operate at any pressure, handle wide feed variation, and remove C6+ and BTX to liquefaction specifications with low methane loss. However, this line-up is generally unattractive for lean gas as the condensate yield is too low to economically justify the CAPEX and OPEX.

Lean gas line-up options The methods for HHC removal from lean natural gas considered in this article include the following conventional methods: addition of a TSA hydrocarbon removal unit (HRU) upstream of the DeHy unit and simple cold flash inside the liquefaction cold box. Pros and cons of both methods are described next and are compared to the newly developed BASF Durasorb Cryo-HRU technology.

An option recently made available by BASF is the addition of a HRU upstream of the DeHy unit, as depicted in Figureb4.

This option offers several advantages; the Durasorb HRU targets C8+ removal to below 0.5bppmv, considering a solubility of nC8 is <0.5bppmv in liquid methane (at -162˚C and 60 bara). The HRU also removes the bulk water, leaving a significantly lighter duty for the downstream DeHy unit that only must remove the last 50bppmv of water. The removal of bulk water by the HRU allows for the DeHy unit to be smaller and achieve a longer bed life, in some cases up to 12 years between material change out.4 The bulk C5-C7 removal to meet the C5+ specification is achieved with a flash. Although the DeHy unit can be as much as 40% smaller, the addition of the HRU adds a regeneration system and doubles the piping and valves required for the overall system. This downside can be overlooked if the increased flexibility and reliability is considered and valued.

Incorporation of a cold flash inside the cold box is another method to remove HHCs (Figureb5). This is the simplest vapour-liquid separation scheme. Treated gas from the pretreatment unit is cooled by a refrigerant and expanded in the liquefaction cold box. The HHCs drop out in the liquid phase in the cold flash separator and are removed, and the lean gas is further processed. The two major drawbacks of this approach are the significant losses of methane and lighter hydrocarbons to the HHC stream, as well as the expansion of >20bbar required to achieve very deep cooling that is necessary to remove highly soluble HHCs to meet the specifications for benzene and nC8+. This process requires recompression to avoid LNG production losses. The expansion and recompression are inefficient from both a pressure management and equipment management standpoint.

Furthermore, stabilisation of the HHC stream is required to meet the condensate Reid vapour pressure (RVP) specification, adding additional CAPEX.

Dual-purpose adsorption technology The newly developed Durasorb Cryo-HRU technology from BASF is designed to be a simple and effective solution for the removal of trace HHCs from lean feed gas. Durasorb Cryo-HRU technology combines the HRU and DeHy unit functionalities into one system by utilising a multi-material approach to achieve both HHC and water removal to the required cryogenic specifications.

The configuration is similar to Figure 4, having the HRU upstream of the DeHy unit, but in the case of dual-purpose TSA, the DeHy unit is removed and replaced with the Cryo-HRU (Figureb6).

The dual-purpose adsorption unit is downstream of the AGRU, which provides the sweet gas feed to the adsorption unit. Durasorb Cryo-HRU technology is a temperature swing adsorption process, where each vessel goes through an adsorption cycle, followed by an elevated temperature regeneration cycle, followed by a cooling cycle, before going

Figure 4. Addition of a TSA HRU upstream of the dehydration unit.

Figure 5. Simple cold flash inside liquefaction cold box.

back into adsorption. The vessels operate in parallel but staggered cycles. In units where there are multiple vessels in adsorption at any given time, the outlet gas stream is combined as the product gas going to the downstream cryogenic unit.

The regeneration gas is a fraction of the treated product gas. The design uses a series heat and cool regeneration system. Therefore, regeneration gas first passes through a heated bed in a co-current (downward) direction to cool down the adsorber prior to taking it in adsorption. While doing so, the gas is pre-heated and is then sent to a regeneration gas heater to heat it up to the required regeneration temperature. Heating is performed in a counter-current (upward) direction. As the hot

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gas passes up through the bed it desorbs the adsorbate, takes it into the vapour phase, and carries it out of the bed. The spent regeneration gas is then cooled to condense desorbed moisture and hydrocarbons, which are collected in a three-phase regeneration gas separator. The effluent regeneration gas is then routed through a regen recycle compressor to increase its pressure, and is mixed with the sweet gas stream upstream of the sweet gas chiller. The vapour is sent back to the adsorbing tower(s). After flowing down the adsorbing bed(s), the conditioned gas is routed to the cryogenic stage.

The majority of the adsorbent bed consists of specially Figure 6. Line-up of the dual-purpose adsorption technology for combined HHC and water removal. developed aluminosilicate gel materials that perform bulk water removal and removal of C8+ and aromatic hydrocarbons to the cryogenic specification (Figureb7). The bottom of the bed consists of a molecular sieve material specially developed for robustness. An optional top layer can be added as a guard against carry-over from the upstream AGRU amine system. The simultaneous removal of HHCs and water in a single unit makes this approach both economical and effective, providing greater reliability and flexibility for changing feed gas conditions.

The novel aspect to the development of the dual-purpose TSA technology was the need to combine the short-cycle HRU process with the long-cycle molecular sieve dehydration process. The characteristics of the different systems are presented in Tableb2.

For LNG plants fed with lean gas, alternative line-ups with less capital-intensive methods for HHC removal that are tailored for the conditioning of lean feed gases must be considered. The TSA HRU technology offers many benefits compared to more conventional arrangements for HHC removal, and BASF’s TSA HRU technologies are well proven. The Figure 7. Typical adsorbent bed configuration of BASF step-change technological advance of combining the HRU and Durasorb technology in a dual-purpose concept. the DeHy unit into a single, dual-purpose adsorption unit that simultaneously removes HHCs and water to cryogenic specifications, enhances the Table 2. Summary of the key performance of the standard MSU, HRU, and CAPEX efficiencies for new projects and Durasorb dual-purpose unit provides a cost-effective retrofit option Dual-purpose to existing plants.

Parameter Molecular sieve HRU adsorption unit

Dehydration

Dew pointing

Deep nC8+ and H2O removal

Configuration (towers in adsorption + regen)

2+1 / 3+1

X+2

X*+2 / X*+1

Water removal (Residual) <0.1 ppmv

Approximately 30 - 50 ppmv

<0.1 ppmv

C8+ removal

N/A

<0.5ppmv

<0.5 ppmv

5 - 7%

10 - 15%

7 - 15%

1. SIMONETTI, T., NARAYANAN, M., BLADANET, C., Technip; CHEN, F., OTT, C., Air Products and Chemicals, Inc., “Innovations in Small to Mid-Scale LNG Plants,” 26th World Gas Conference, June 2015.

200 - 500

2. SMITH, T., DOONG, S., UOP Honeywell, “Selective C5+ Removal for Lean Feed Gas,” LNG Industry, February 2016.

Regen gas flow (% Fresh feed) Cycle time (min.)

960/1440 (higher with 60 - 500 variable cycle time <2000

Lifetime cycles (4 years)

Approximately 1500 (longer lifetime with variable cycling)

>4000

>4000

Adsorbent type

Molecular sieve

Silica gel

Silica gel + Molecular sieve

Regeneration

Temperature ramp-up

Fast heating

Fast heating

Note: *X can be 1, 2, 3 beds

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To learn how BASF developed the technology and proved its capabilities, read the remainder of the article by visiting www.lngindustry.com

Functionality

May 2021

References

3. SCHMIDT, W., CHEN, F., OTT, C., Air Products and Chemicals, Inc., “Advances in Removing Heavy Hydrocarbons from LNG Liquefaction Feed Gas,” Gastech, September 2018.

4. HEYWOOD, M., UHE, M., Spirit Energy Ltd; ECKARDT, T., GREENE, M., RACHER, R., WYATT, R., BASF, “North Morecambe Onshore Gas Terminal Adapts to Changing Feedstock,” Oil and Gas Journal, October 2020.

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Henri Beaussant and Arnaud Lamartine, SURFEO, France, discuss the small scale LNG markets in the Mediterranean area, looking at recent activity and future developments.

I

nterest in the use of small scale LNG has strongly developed in recent years as demand for natural gas continues to increase – albeit at a slower pace over the past few months (+3% in 2020 over 2019) due to the COVID-19 pandemic and a mild 2020 winter.

Large array of equipment and markets Small scale LNG indeed covers a wide range of uses, markets, and technologies. Regarding infrastructure, small scale LNG includes all or part of a wide range of equipment from an LNG source – liquefaction facility or stationary/mobile LNG primary storage – to the end user(s), including loading/unloading, land or sea transportation, satellite storage, regasification, and final connection.

While several definitions – and categories – may co-exist, it is usually considered that small scale refers to liquefaction and regasification facilities below 1 million tpy, and storage and tankers up to 30 000 m3 – i.e. approximately one-fifth of the capacity of conventional LNG terminals.

As far as markets are concerned, small scale LNG gathers a collection of niche demand segments that cover both stationary energy end users (power generation, industry, and residential) and mobile fuel consumers (marine and surface transport). It proves particularly suitable for meeting off-grid demand (stranded customers), and to further develop markets that, in the beginning, may prove too small for conventional suppliers (emerging markets).

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Most small scale LNG operations are currently directed towards the following three markets: z Small and mid size capacity power plants and standalone industry. z Bunkering for maritime and river transport (vessels and self-propelled barges). z Heavy-duty surface transportation currently focused on trucking, with some potential in railways.

Figure 1. A typical mid size, small scale LNG terminal. Image courtesy of Manga LNG, Tornio, Finland.

CNG may be a downstream market of LNG, suitable for small end users (personal cars and light-duty trucks, small scale industry/commercial buildings), based on the vaporisation of LNG. In 2019, with an estimated 30 million t delivered worldwide – mostly in Europe, the US, and China – small scale LNG operations accounted for 8.5% of the global 351bmillion t LNG trade.

While small scale LNG is still a nascent industry, it is projected to expand rapidly. Engie and other operators and analysts forecast that demand of the key markets outlined above will reach 95bmillion t by 2030 (+12% each year), with demand split between power (26%), bunkering (32%), and road transport (42%).

In Europe, small scale LNG has been developing first within and around Scandinavia and the Baltic Sea, and the North West Europe (NWE) area. Two factors have largely contributed to the development of small scale LNG in this area: environmental factors and geographical conditions.

Environmental factors

Figure 2. Global demand for small scale LNG by segment (2030 forecast). Image courtesy of Engie Strategy & Research.

The development was triggered by EU environmental regulations, in particular the creation, from 1 January 2015, of the maritime SOx Emissions Control Area (SECA), according to which EU member states have to ensure that ships in the Baltic, the North Sea, and the English Channel use fuels with a sulfur content of no more than 0.10%. Norway – although not an EU member – is already a world leader in the use of LNG for bunkering, feeding ferries, patrol vessels, tugboats, tankers, and platforms for supplying vessels.

Geographical conditions Population and economic activities in Norway, Sweden, and Finland are distributed across vast expanses of territory, sometimes difficult to access (Norway). While low population densities (14 to 23 inhabitants/km2) make a comprehensive gas grid uneconomic, long coastlines allow for efficient and relatively easy maritime supply of coastal communities.

Mediterranean and Near Atlantic islands: the next frontier?

Figure 3. Shipping routes and flows across Greece’s Aegean Sea (Crete, Cyclades, and South Aegean islands).

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May 2021

Although its geographical background is very different from that of Northern Europe, the Mediterranean and Near Atlantic (MED-NA) area does present strong favourable conditions to become the next cradle of small scale LNG development in Europe. In particular when it comes to supplying the numerous islands and archipelagos that dot the area.

Island regions are particularly suitable for the development of small scale LNG solutions: gas demand is often relatively small and most islands could not be

economically supplied through an expensive pipeline grid or a conventional, large size regasification terminal. Small scale LNG could help switch away from liquid products and bring significant savings and improved environmental conditions. This is why small scale LNG has been developing in several archipelagos worldwide (e.g. the Caribbean), or is being seriously considered in Asian island countries such as Indonesia and the Philippines.

Geography In Europe, the MED-NA area offers a perfect terrain to develop integrated small scale LNG systems. Nearly 14 million people live on these island systems, with high population densities on some of them: over 250binhabitants/km2 in Mallorca, Malta, and the Canary Islands. These islands either constitute independent nations (Cyprus, Malta) or are part of mainland countries (Portugal, Spain, France, Italy, Croatia, Greece).

They are spread across the whole region, from the Eastern Basin (Crete, Ionian, Cyclades, Dodecanese, North Aegean archipelagos) to the Adriatic (Croatia’s coastal islands), and the Western Basin (Balearics, Corsica, Sardinia, Sicily), as well as the Near Atlantic (Canary Islands, Madeira, and farther west to the Azores).

Markets and applications Within the overall small scale LNG potential market, island regions are all the more attractive as their natural borders favour the implementation of integrated systems.

Concentrated projects allow for a better optimisation of

the infrastructure, economies of scale (to some extent), participation of local operators, as well as reducing market risks. Some market segments sound particularly suitable: z LNG-to-power constitutes the most attractive segment.

Almost any single island, regardless of its population and economic activity, relies on at least one power production unit. There are only a few interconnections, whether between islands or with the mainland. While renewable sources develop at a fairly fast pace in the islands – including geothermal in the Azores – oil-fired thermal plants, with 13 GW of installed capacity across the area, still constitute the bulk of the production. z LNG-to-power barge is a new concept (the first LNG-to-power barges are being implemented in Asia) of an integrated fuel storage and power production facility mounted on a single floating unit. The concept is particularly suitable for those areas where power capacity extension or renewal is not feasible due to environmental regulations and/or lack of suitable land. z Except in the larger islands, e.g. Sicily, industry has not been greatly developed in the MED-NA area. Seawater desalination is an attractive prospect in those islands where rainfall is insufficient to supply both the population and economic activities, in particular during the peak tourist season. z Bunkering: LNG is increasingly becoming the fuel of choice for marine transport, driven by environmental considerations following the EU and IMO rulings on sulfur and nitrogen emissions. In December 2019, all

on the island’s west coast, the Oristano terminal, currently in the commissioning phase, is the first coastal LNG services facility and bunkering station in the Mediterranean. The LNG will be sourced in a terminal nearby equipped with a reloading facility – tentatively Barcelona, Fos, or OLT Toscana – and shipped to the 10 600 m3 land storage via a small size (7500 m3) dedicated LNG tanker. It will then be transported to customers across the island through road tankers (with a capacity of 180b000 tpy LNG) and, later on, regasified and transported through a (to be built) 380 km pipeline grid.

Figure 4. Gibraltar LNG terminal and new power station.

the Mediterranean states gathered under the Barcelona Convention endorsed the principle of a SECA zone covering the entire Mediterranean from Gibraltar to Suez. The wide differences in resources, techniques, and controls of the countries of the area need to be overcome to allow the designation of this new SECA by the IMO, which is expected to be reached by the end of the decade. z Automotive fuel requires a critical mass – in terms of both the size of LNG-fuelled fleets and yearly distances travelled – to justify the implementation of a network of filling stations and dedicated storage, and LNG road tankers to feed them. As for industry, only larger or denser islands constitute a real potential market to develop automotive LNG, whether in LNG or CNG form.

Pure small scale LNG schemes in operation Conversely to Northern Europe, the Mediterranean area is well endowed with numerous large size LNG terminals where LNG can be sourced. 16 facilities in seven countries are in operation and more are under construction or being considered in Italy, Greece, Cyprus, and the Canary Islands. While 10 terminals, mostly in the Western Basin, have already adapted their services to small scale LNG operations, others (e.g. Revithoussa in Greece) are actively developing small scale LNG-dedicated infrastructure.

Small scale LNG services installed in large regasification terminals generally focus on bunkering and loading road tankers to supply satellite stations further down the road (truck loading). In addition to these basic services, operators are also developing grassroots, integrated small scale LNG supply schemes. In 2014, Gaslink of Portugal established the first LNG scheme in the MED-NA area between the Sines LNG terminal and Madeira, delivering ISO LNG containers to fuel the island’s Vitoria power plant. In 2019, the Gibraltar receiving and storage station was put on stream in the harbour to supply a newly built 80 MW gas-fired power plant.

In Italy, two small scale LNG terminals will come on stream this year, followed by a further two in the next two years. Sardinia, the second-largest Italian island, opted for a small scale LNG solution following the failure of the Algeriab- Sardinia - Toscana GALSI pipeline project. Located

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May 2021

Economics and industry structure The capital investments for small scale LNG terminals are significant, but not on the same level as other elements of the LNG chain. The CAPEX of the Oristano terminal amounts to €43 million, while the larger Manga terminal in Tornio, Finland (including receiving facilities, 50b000bm3 storage, bunkering, and truck loading equipment) was estimated at €110 million at the time activity began.

This compares with the cost of a full-size land terminal (typically between US$0.8 - US$1 billion) or FSRU facility (approximately US$0.3 billion for a new-build ship).

Most small scale receiving terminal projects have much more in common with downstream distribution businesses than with the larger scale LNG terminals. This is one of the main reasons – in addition to lower CAPEX needs – why the small scale LNG industry attracts new players with new project structure and commercial models. Those newcomers are often local operators or future LNG consumers and are not necessarily connected to the oil and gas industry. The Madeira project was promoted and is operated by Gaslink, a subsidiary of the local Sousa Group, a maritime port, logistics, energy, and tourism operator, considered one of the largest Portuguese shipowners. Manga LNG is a joint venture between local operators, including two large steel producers, an LNG and biogas downstream operator, and an emission-free power producer. All four owners are also the clients of the terminal.

However, larger oil and gas operators are progressively showing interest in small scale LNG, with a view to widen their LNG strategy and diversify their LNG market in the hope of either finding new demand sources for overflowing inventories (in the case of sellers) or taking advantage of lower priced LNG (in the case of buyers) – while greening their activities. The Gibraltar terminal was promoted and is operated by Gasnor, a Norwegian 100% subsidiary of Shell, under a long-term agreement with the government of the Territory.

Conclusion Small scale LNG has the advantages of lower initial investment costs and shorter implementation time compared with conventional LNG. Also, increasing environmental awareness is driving the use of lower carbon energy in many regions of Europe. Small scale LNG thus offers a more suitable alternative for supplying natural gas to remote and less populated areas. This has helped develop small scale LNG as a lower carbon energy in the Nordics/Baltic Sea area and NWE, and it is ready to achieve the same in and around the Mediterranean.

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Dieter Hilmes, TGE Marine, Germany, describes how the company supported the delivery of Gasfin’s FRU for the first LNG import terminal in Sub-Saharan Africa. n November 2017, Gasfin Development, Helios, and Lyndhurst partnered to establish Tema LNG Terminal Company Co. (TLTC) – a project company to develop, construct, and operate Sub-Saharan Africa’s first LNG import terminal. TLTC will employ an innovative combination of a purpose-built FRU twinned with an existing LNG carrier converted into an FSU, to receive, store, and regasify the LNG. This system provides Ghana with all the functionality of an FSRU-based terminal with added flexibility of operations, yet at a significantly reduced cost. Operations are due to

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commence within 2021, at which time gas will be imported into the terminal and piped out to customers in Ghana.

As a founding partner of TLTC, Gasfin has led the design of the entire project and the fabrication of the floating infrastructure, helping deliver a new 2bmillion tpy+ LNG import plant at a competitive price in a challenging marine and logistical environment.

TGE Marine Gas Engineering GmbH has been working on FSRU

designs since the turn of the millennium. After executing several extensive FSRU FEED studies for dedicated small and mid scale supply solutions, TGE Marine supported Gasfin in the development of the Ghana FRU concept. The long-established players in the cryogenic gas market had already started their collaboration for this flexible regasification barge in 2015. With this article, TGE Marine intends to introduce the readers to the detailed solutions of this innovative FRU concept, the flexibility of regas barges, and solutions beyond this specific project.

Barge design TGE Marine’s naval architects and marine engineers were already involved in an early stage of this project. In a first step, they prepared a conceptual design package which enabled Gasfin to enter into a shipyard tendering process.

The regas capacity, the storage volume, and a final set-up of detailed solutions was adapted in several reviews and

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agreed by all involved parties. One lesson taken away from these reviews was that the size of the regas capacity and the process equipment would determine the barge size.

Now, in case storage is foreseen on the barge, this will be installed in the hull below the process equipment. With the process equipment being the determining factor for the main dimensions of the barge, the storage volume can be optimised for these dimensions and a reduced storage volume will lead only to minor cost optimisation, as also addressed next. In the end, TGE Marine delivered the whole basic design engineering of the innovative regasification barge.

Storage Storage volume on the barge can either be designed as buffer tanks only or sized to increase the overall terminal capacity to full-size parcels of modern LNG carriers. Usually, older LNG carriers are employed as FSUs, which have a lower storage volume (125 000 - 150 000 m3) compared to today’s standard 170 000 m3 size class vessel. This gap can be covered by the storage volume of the FRU. Also, in the Tema project the original idea was to equip the barge with just two 2000bm3 LNG buffer tanks. But as Gasfin identified suitable FSU candidates for this project, one suitable choice was an old inefficient steam LNG carrier in the size of

Figure 1. Animation of arrangement in the port of Tema – FRU → FSU → LNG carrier (from left to right).

127b500bm3. However, it quickly became clear that the total storage volume was not sufficient for this project. In order to increase the loading capacity of the FRU, the parties evaluated the installation of two cylindrical storage tanks each of 10b000bm3, which were later further increased from a total of 20 000 m3 storage volume to 28b000bm3 storage volume. Despite the increased volume, the original working name FRU (floating storage unit) is still being used instead of the more common name FSRU (floating storage and regasification unit).

The two 14b000bm3 IMO Type C tanks with a design pressure of 5.4 barg are the largest cylindrical tanks which have ever been built (Figure 2). Each tank is equipped with two submerged motor pumps which can be removed via a retraction system without gas freeing of the tanks. One of the main benefits of Type C tanks is that these can be fabricated separately outside the hull with an installation time of a mere few days. Besides improvement, this provides schedule and reduction of executional risk to the overall project, and also extends options in the site and location of barge fabrication.

Regasification trains One of the main ideas in the earlier designs for so-called small to mid scale FSRUs was the integration of small to mid scale supply chains for the supply of remote areas or logistical integration of customers without access to pipeline gas. Compared to these pure mid scale FSRUs, the Ghana FRU has disproportionately high regasification capacity (close to a full scale terminal capacity) compared to its storage volume. As each regas train has a capacity of 67 tph of natural gas (80bmillionbft3/d), the peak send-out of the five regasification trains amounts to 335 tph (400 millionbft3/d).

Through an integrated skid design, all items such as vaporisers, super heaters, high pressure pumps, and the vent stack are easily accessible (Figure 3). The natural gas send-out pressure amounts to 65bbarg. An open loop waterglycol circuit using seawater as a heat source will warm up the LNG in the vaporisers with an integration of the engine cooling water as an additional heating source. In order to also guarantee reliable operations at extreme low sea water temperatures, the partners decided to install additional trim heaters which were directly heated by sea water.

Boil-off gas handling

Figure 2. One of two tanks in the dimensions of 16.1 m dia. × 74.5 m length ready for insulation works.

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With the set of the terminal in FSU-FRU combination, the following sources of boil-off gas (BOG) need to be considered for the BOG handling system: BOG of the FRU’s Type C tanks, BOG from the FSU’s tanks, and BOG generated during loading operations from the shuttle carriers.

In the overall design of the terminal, an important factor is the question of insulation quality and of the FSU. As mentioned earlier, usually older LNG carriers are applied with higher BOG rates than today’s new-build vessels. The BOG of the FSU and the FRU will be partly consumed by the installed dual-fuel engines, which provides electricity for the FRU and FSU (cold ironing of FSU). A secondary option for BOG handling will be realised by applying a recondenser technology. In this process, the BOG will be compressed, via the installed BOG compressors, into the liquid low-pressure stream from the LNG feed pumps inside the tanks. With this innovative method of BOG handling, the complete amount of

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gas can be handled and there is no need for further equipment such as a gas combustion unit.

Redundancy is an important factor in BOG handling considerations, and here the applied Type C tanks have a significant advantage of being capable to buffer some of the heat ingress by pressure built up in case BOG handling should not be available. In the conversion of the carrier to

Figure 3. The FRU is equipped with five regasification trains which are mounted on skids.

Figure 4. Top view of the weather deck. In the top left are the regasification trains, and the water-glycol system is located on the top right.

an FSU, whether the original installed BOG handling such as boilers of dump condensers remain available in warm lay-up mode or will be put to cold lay-up also needs to be considered.

Flexibility Right from the start of the project it was very important to all parties involved to make the design as flexible as possible. Thus the design allows the unloading of LNG to bunker vessels and, in addition, a truck loading possibility is essentially provided. The concept can handle strong variations in sea water temperatures and with a high rate of redundancy, so overall a reliable operation under all conditions is ensured.

Generally, it can be said that small scale FSRUs are tailor-made for the dedicated applications. There are no one-fits-all expedient solutions as they are most probably not suitable for the specific project demands. Small scale FSRUs are highly flexible and can be equipped with all needed features, such as the LNG unloading features mentioned earlier. Furthermore, it is possible to operate an FSRU with sufficient storage volume at low regasification capacity requirements without additional storage from an FSU. In case of existing or emerging small scale supply chains, the LNG can be provided directly from a shuttle carrier to the FSRU. This regasification concept seems to be the best solution for LNG-to-power projects. The technology is ready for using bio-LNG or synthetic LNG, which can contribute to the decarbonisation of engine related emissions.

TGE Marine has focused on FRUs with a storage volume up to 50 000 m3 and a regasification capacity maximum of 100 tph (120 million ft3/d) per regasification train. The regasification trains can be heated with an open loop circuit by using sea water, or in case of sensible sea water areas, in a closed loop with ambient air vaporisers. All types of mooring systems are generally possible, such as pile mooring, spread mooring, or jetty moored applications.

Supervision In 2018, Gasfin executed the shipyard contract with the Chinese yard Jiangnan Shipyard (Group) Co. Ltd for the construction of the FRU. As TGE Marine has 40 years of business track record with Jiangnan, this selection was most welcome. Due to the intensive work during this long collaboration time, TGE’s Shanghai office is closely connected with the yard staff. The TGE supervision team was involved in the tank building process and in all types of detailed decisions around the gas handling system.

Commissioning

Figure 5. Section through the FRU shows the compact design.

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The pre-commissioning phase has already started at the shipyard in the presence of TGE’s commissioning engineers.

It is expected that the commissioning of the whole plant in Ghana will take place within 1H21. The company’s engineers will support from the side in order to ensure a smooth operation from the beginning.

TGE Marine is very proud to be part with this project. As small to mid scale solutions with tailor-made designs offer high flexibility to the operators, TGE is convinced that the number of LNG import terminals will increase significantly within the next few years.

Saša Cook, Cryopeak LNG Solutions Corporation, Canada, discusses how to provide LNG to remote communities in Northern Canada.

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n early February 2021, Cryopeak started LNG production at its regional LNG production facility located in Fort Nelson, North East British Columbia (BC), Canada. The LNG plant has a capacity of 27b000bgal./d and will be used to provide LNG to off-grid communities and industries for power generation and heating.

The vision for Cryopeak was to locate a modular and scalable LNG production facility as close as possible to the customers’ point of use. Transportation costs are often the largest cost component in the LNG value chain, so securing a site on the Alaska Highway as close as possible to the company’s customers was a key determining factor in the site selection.

Initially the LNG industry in BC has been focused on large LNG production facilities and Cryopeak wanted to change this way of

Figure 1. Ice road on the Dempster Highway.

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thinking and design and build smaller, more modular production facilities which can lower capital costs, and enable efficient installation in remote areas.

Another factor in the design was to minimise operator intervention and maximise remote monitoring. Under the code this is permitted and the intent will be for Cryopeak to monitor the facility remotely and only attend the facility for truck loading operations and in the event of any alarms or abnormal situations.

Shifting energy markets North East BC has abundant natural gas reserves and low gas pricing, so the production of LNG makes economic sense as the fuel is highly competitive against incumbent fuels such as diesel and propane.

Figure 2. Cryopeak 20 000 gal. Super B LNG tanker.

LNG is the cleanest burning fossil fuel and is viable for remote customers which have extreme weather conditions and challenging logistics routes. Domestic demand for LNG is increasing with the fuel now being used in mining operations as well as communities.

While renewable energy sources such as wind and solar are being used in remote locations, LNG plays a role to support renewable fuels, provide efficient direct heating, and enable communities and industry to have less reliance on diesel as an energy source.

LNG facility Cryopeak’s LNG production facility was designed to be a scalable facility to meet growing regional energy demand in North Western Canada. The plant has an initial production capacity of 27b000bgal./d, which can be scaled up to 100b000bgal. production capacity as demand comes online. The liquefaction plant is based on a single mixed refrigerant system which ensures LNG is produced efficiently, and the facility has 100 000bgal. of on-site storage capacity. The facility has access to high pressure, sweet natural gas from the adjacent transmission pipeline.

One feature of the facility is the use of grid power to drive the facility and the refrigerant compressor. This achieves two key objectives; simplifying the equipment count at site and supporting minimal on-site monitoring, as well as using grid power to lower the net greenhouse gas emissions from the facility.

The company was able to secure the site in March 2020 and then commence operations in less than one year later. The project strategy was to construct as much of the modular facilities offsite and then complete the site works in parallel with the construction of the production modules and modular storage tanks and skids. This approach worked well – even with the pandemic affecting some equipment deliveries.

LNG transportation

Figure 3. Cryopeak’s LNG production facility, March 2021.

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Cryopeak has safely and reliably delivered LNG, and its fleet of trucks has covered over 4 millionbkm since the company’s founding in 2012. In 2019, Cryopeak designed and permitted the first LNG B-train in North America which provided a significant payload advantage over the tridem and tandem trailers. The company currently operates four B-train trailer units in its fleet.

Cryopeak routinely delivers LNG to the Arctic community of Inuvik, and the community is a significant user of natural gas to support its energy needs in Northern Canada. The route of LNG is challenging and it is more than a

1300-mile one way trip from Fort Nelson to the community.

The route passes through BC, the Yukon, and Northwest Territories, and there are over 400 miles of the Dempster Highway, which is a gravel road, and leads the company’s gas through the vast northern Canadian wilderness to the Arctic Circle (Figureb1). The road includes two ice crossings which Cryopeak’s 140b000 lb Super B-trains transit during the winter frozen months.

A further feature of the LNG production plant has been to develop a loading system which can load either single or combination trailers through a proprietary loading process.

This reduces time and the system will automatically load and weigh out trailers at the facility.

The LNG production facility is located close to Cryopeak’s logistics hub, approximately 12 km north along the Alaska Highway. The hub allows for regular in-house preventative, regular, and unplanned maintenance for trucks and trailers, as well as storage for LNG trailers. Technical staff are also able to support the LNG facility for regular maintenance activities and attend as required. There is a remote monitoring station at the logistics hub to ensure the plant can be effectively monitored. The transportation of LNG is a critical activity in the value chain and generally the amount of energy storage for facilities is smaller with LNG as compared to traditional liquid fuels.

Prior to constructing its first LNG plant, Cryopeak established a reputation for reliability and safety, delivering LNG as well as on-site power equipment and storage solutions for off-grid communities and projects in BC, the Yukon, and Northwest Territories.

The company has supplied LNG and on-site equipment including cryogenic storage and regasification for the Coeur

Silvertip mine since 2016.

Partners It is always critical to have trusted partners for a new project such as this. Cryopeak has been welcomed by the local community of Fort Nelson in many ways. It was important to use many local businesses and contractors in the construction of the LNG facility.

In 2019, Cryopeak signed a mutual benefits agreement with the Fort Nelson First Nations to lay a strong foundation for a partnership between the company and local community members. The agreement includes a plan for training and job opportunities for First Nations members. Cryopeak received support from local First Nations businesses during the construction phase of the project.

The Fort Nelson community is home to resilient and capable community members. The workforce is experienced in oil and gas activities, which made it easy to find local workers capable and willing to complete the construction of the LNG facility and also engage with the new potential opportunities the facility will produce.

Future plans Cryopeak intends to continue its strategic growth in Northwestern Canada and continue to be an industry leader in regional LNG supply, distribution, and on-site equipment.

Cryopeak is exploring opportunities to provide alternative energy solutions to help reduce the greenhouse gas emissions of energy for off-grid communities while utilising the abundant natural gas resource, as well as supporting the transition to sustainable energy solutions.

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Andreas Glud, Hempel A/S, Denmark, outlines how the LNG carrier fleet can be optimised to trade flexibly, with a focus on hull biofouling.

E

ven before the COVID-19 pandemic, the LNG market was expected to remain oversupplied in 2021, with new projects set to outpace demand growth – but lower oil prices for a sustained period in 2020 have increased pressure on the segment further. It can be assumed, however, that this will likely be a temporary issue, rather than a protracted problem, as many of the world’s leading energy companies remain committed to a future in gas. While it may only represent a small segment of LNG demand overall, the market for LNG as a marine fuel presents obvious opportunities for owners, operators, and managers of LNG carriers able to move product to new and emerging markets for LNG bunkering.

Currently, there is no panacea for shipowners, operators, and managers when it comes to future fuel choices – but what has been seen is a significant upsurge in adoption of LNG dual-fuel capabilities across a wide range of vessel segments. This is because, across vessel segments, LNG provides a reliable and viable interim fuelling solution for meeting the International Maritime Organization’s (IMO) 2030 greenhouse gas emissions target; however, it will not be able to deliver the emissions reductions required for longer-term decarbonisation goals.

Many owners and operators, keen to reduce their emissions, are now opting for LNG dual-fuel solutions. According to figures cited in Tradewinds, the LNG dual-fuel fleet is expected to double by 2023, to a total of 475 vessels. By 2023, total marine LNG demand is expected to reach approximately 3.6 million t, with 45bbunker vessels expected to be in service. This means that there is likely to be a short- to

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medium-term surge in demand for LNG bunkering capability, which will have an impact on demand for LNG carriers.

The marine fuel market alone has the potential to influence not just demand, but some trading patterns and operational requirements in the LNG carrier segment to meet demand growth in new markets for LNG bunkering and small scale LNG storage and distribution. To secure favourable charter terms, owners and operators of LNG carriers must consider factors such as flexible deployment capabilities and increased efficiency, which are expected to drive the market for LNG carriers in the coming years. Given that the longer-term future for LNG bunkering is less clear, it is crucial that the existing LNG carrier fleet is optimised to trade flexibly. This requires LNG carrier hulls to be protected from the biofoul that can limit operational efficiency, reduce the ability to idle, increase maintenance costs, and restrict where the vessel is able to trade.

A ticket to trade anywhere Hempel, a global coatings manufacturer, has developed a solution that empowers vessels to trade flexibly, which is called Hempaguard MaX. This smooth three-coat system achieves a remarkably low average hull roughness for less drag, and its improved fouling protection delivers a guaranteed maximum speed loss of 1.2% over five years (according to the ISO 19030).

The three coats comprising Hempaguard MaX are: Hempaprime Immerse 900, tie-coat Nexus II, and Hempaguard X8. The topcoat – HempaguardbX8 – drives the antifouling performance and incorporates Hempel’s patented Actiguard technology that combines the smoothness of a silicone coating with an improved fouling defence solution.

This unique system enables vessels to trade in all water environments, from the cold oceans of the north Atlantic to the warm waters of the Mediterranean, while providing the same level of protections against biofoul. Vessels can also trade at slow and normal speeds, including the ability to sit idle for up to 120 days, which many hull coatings cannot deliver. It also takes less time to apply in dry dock than the traditional five-coat offerings, meaning further time and cost savings.

Keeping an eye on costs Given that the LNG market is oversupplied, competition is fierce, margins are thin, and regulations are growing more

Figure 1. Hempel SHAPE digital analysing tool, based on the ISO 19030 framework, combines all the elements of efficiency optimisation.

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onerous, owners and operators of LNG carriers must seek out efficiencies in every corner of their operations, and the right hull coating can make a measurable difference. The efficiency savings delivered by applying a quality, long-lasting, and durable hull coating can make a tangible difference to operating costs, but demonstrating this is more complicated.

Having empirical evidence of fuel saving potential can, ultimately, provide an important strength when it comes to securing charter agreements in what is an increasingly dynamic, highly competitive, and rapidly evolving market.

To keep track of hull performance, Hempel recommends that vessel owners and operators utilise SHAPE, Hempel’s System for Hull and Propeller Efficiency. To explain in the simplest terms, SHAPE is a process of measurement over time that monitors the long-term efficiency trends through a range of in-service performance indicators to measure, monitor, and implement coatings systems that improve hull and propeller efficiency. It is based on the ISO 19030 standard that defines the methodology for determining changes in hull and propeller performance and details industry standard measures for propeller efficiency.

Through careful data analytics and measurement, SHAPE is designed to deliver a tangible, cost-effective solution, offering real savings to every operator, regardless of the age, size or operating pattern of the vessel, and using this methodology those savings can be refined and delivered year-on-year. Importantly, the empirical measurements that result can be utilised to showcase a vessel’s performance to customers, financiers, and other stakeholders – to show how a vessel stacks up against its competition. This data intelligence is evidence of the latent efficiency savings to be made and adjusted into overall operating costs.

Driving sustainability The shipping industrybhas evolved significantly over the past few years and both industry and individual stakeholders are driving more sustainable industry solutions with the adoption of eco-efficient solutions, helping savvy shipowners and operators one step closer to achieving their sustainability goals. At Hempel, sustainability is without a doubt at the top of the company’s agenda and at the very heart of what it does. Hempel strives to continue to reduce its own waste, energy consumption, and use of hazardous rawbmaterials, and recently launched its sustainability framework ‘Futureproof’ which sets out ambitiousbgoals for the company.

One example of this is for Hempel to become carbon neutral in its ownboperations by 2025, whilst simultaneously helping to reduce the carbon footprint of its customers. The company has set itself the target to enable its customers to reduce up to 30bmillion t of CO2 in total by 2025. This is no mean feat and Hempel is looking forward to the challenge.

As sustainability continues to grow as a requirement for all maritime carriers, with the LNG segment being no exception, it is vital to implement sustainable business practices to drive competitive advantages and improve the bottom line. Armed with a hull coating that allows carriers to trade in all waters and the data intelligence to prove the efficiency of hull and propeller performance, owners and operators of LNG carriers can better understand and adjust their operations to gain a competitive advantage in what is a dynamic and rapidly evolving global market.

Chongmin Kim, Senior Surveyor and Researcher, Korean Register, South Korea, discusses the research, standards, and achievements that are at the forefront of the LNG industry. he Korean Register (KR) created an LNG ship task force more than 20 years ago and has remained at the forefront of technology development within the sector ever since, working on the development of the moss spherical tank system and the first GTT Mark III membrane cargo containment system in 1990.

Today, KR classes an international fleet of 3000 vessels totalling 72bmillion gross tonnage, 30% of which are bulk carriers, 22% tankers, 16% containerships, while RoRo comprises 8% and gas carriers 7%.

As of June 2020, KR was responsible for surveying 39b registered LNG carriers, a number which will increase when the vessels that are being surveyed during construction, go into operation.

On 1 January 2020, the International Maritime Organization’s (IMO) global sulfur cap came into effect. LNG emits no SOx, virtually no particulate matter, and up to 90% less NOx emissions, and so unsurprisingly, it has been chosen by many as the alternative fuel of choice. As a result, LNG vessels are expected to dominate the industry for at least the next 30byears.

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LNG bunkering Conventional LNG carriers use boil-off gas (BOG) as fuel and do not need additional LNG, but LNG fuelled ships need bunkering and with an increasing number of these vessels, LNG bunkering is becoming more and more important.

LNG fuelled vessels and LNG bunkering use closely related technology and face a variety of safety-related issues. As a result, KR is developing its survey technology and conducting more research into this area.

The society has developed and released class rules and notations for LNG bunkering systems installed in LNG bunkering vessels to ensure their safe design, construction, and operation. The rules specify the design, construction, and survey requirements of LNG transfer systems (transfer arms, transfer hoses, hose supporting, and handling equipment), and cover the relevant control, monitoring, and safety systems (alarm, ESD, ERS), inert systems, and communication systems.

With the support of the Korean Agency for Technology and Standards, and in conjunction with the Korea Marine Equipment Research Institute (KOMERI), KR has also developed two ISO standards covering the integrated performance test procedures for LNG Fuel Gas Supply System (FGSS) for ships. These ISO standards are: z ISO/DIS 22547 Ship and marine technology – Performance test procedure for high-pressure pump in LNG FGSS for ships. z ISO/DIS 22548 Ship and marine technology – Performance test procedure of vessel LNG FGSS.

Figure 1. The signing ceremony for KR’s new LNG fuel and bunkering simulation centre (KR LSC) which is located at KR’s headquarters in Busan, South Korea, and officially opened on 15 September 2020. The KR LSC has been established to facilitate industrial growth across the LNG propulsion and bunkering sector.

These standards will form the performance test procedures for LNG FGSS and any related industry development will use these standards as a technical base, while KR can act as technical advisor and secure class approval.

KR is also working closely with KOGAS to provide technical services covering LNG bunkering technology and LNG bunkering compatibility and risk assessments. In this regard, KR has completed new construction surveys for 7.5K LNG bunkering vessels built by Samsung Heavy Industry (Januaryb2020), and is deeply involved in the subsequent LNG bunkering vessels scheduled to be built by Hyundai Heavy Industry.

LNG fuel propulsion and bunkering simulation centre Anticipating the growing demand for LNG, on 15 September 2020, KR announced the official opening of its new LNG fuel propulsion and bunkering simulation centre (KR LSC) in Busan, South Korea.

The KR LSC has been established to facilitate industrial growth across the LNG propulsion and bunkering sector based on the society’s long-standing and high-level expertise with LNG technology.

The centre will provide engineering and consulting services for LNG operations, including customised trial and optimal operations for LNG fuel supply and bunkering systems, and propulsion system commissioning simulation, while providing design education and operational training for crew, operators, designers, and future engineers. It will also conduct detailed risk analysis for liquefied gas for ships propelled by eco-friendly fuels such as LNG, hydrogen, and ammonia, and will offer a new range of technology services covering ventilation analysis, gas dispersion analysis, BOG analysis, fire radiant heat analysis, and evacuation and escape analysis.

The centre, which is being developed in co-operation with Trans Gas Solution (TGS), will support domestic shipping companies, small- and medium-sized shipyards, and the engine machinery industry, all of which are involved in the ordering of LNG propulsion ships and the activation of bunkering infrastructure.

KR has signed a Memorandum of Understanding (MoU) with TGS, with both organisations agreeing to build an operator training simulator (OTS) system which will be used to train the operators of LNG-propelled ships and for ship-to-ship (STS) bunkering. The resulting practical education and training programmes will be tailored for shipping companies, shipyards, and equipment companies, combining the use of an OTS and virtual reality (VR) to deliver a real-time simulation of the LNG vessel fuel processes.

KR has been procuring test technology for LNG-propelled ship engines and aftertreatment devices for many years through the Greenship Equipment Testing and Certification Centre (TCC) established in Gunsan, South Korea, in 2015. The newly established KR LSC will provide unified LNG technical services adding simulation technology and will now enable the implementation of a pretreatment device for LNG fuel propulsion.

A world first Figure 2. Ship-to-ship (STS) LNG loading for a gas trial is underway.

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Following on from this, in November 2020, KR and DSME completed the world’s first STS LNG loading for a gas trial.

In the STS gas trial, the SM JEJU LNG2 supplied LNG to a

173b400bm3 LNG carrier. The demonstration test took place at DSME’s Okpo Shipyard from 24 - 26 November 2020.

KR and DSME had been working together for many months following the signing of a MoU on joint research for LNG bunkering. The collaboration is part of a wider partnership agreement for LNG bunkering/transport work between KR and the Korean shipyards with the aim of developing standards for LNG bunkering procedures in Korea, conducting risk evaluations of LNG bunkering operations, and for the development of LNG bunkering to support technology based on standards and guidelines jointly developed by DSME and KR. By applying its extensive safety engineering technology, KR has identified a diverse range of potential hazards through its risk assessments for STS LNG loading/transport operations between two ships and has suggested effective ways to reduce this risk to DSME. In addition, safer work environments and enhanced safety work procedures have been developed for workers following a comprehensive study looking at the establishment of control zones around the two ships during the LNG transportation.

Using its extensive LNG experience, LNG offshore operations technology and its BOG control, DSME has developed unique technology to prevent vapour return to the bunkering vessel or venting to atmospheric areas during the STS LNG loading/transport operations.

Under normal conditions, the vessel would be supplied with LNG at the terminal because the terminal facilities would be required to manage the BOG. However, DSME’s new technology can be applied to the operations process preventing any methane emission (discharge/ventilation) – enabling STS transfer. As part of this process, KR worked with DSME to identify, eliminate, and mitigate the various risk factors involved, providing technical support for the customised STS LNG transportation safety procedures. To date, DSME and KR

Figure 3. One of KR’s surveyors conducting an LNG survey. have conducted eight gas trials without venting to atmospheric areas.

The KR is an International Association of Classification Societies (IACS) member and was established in 1960. The society celebrated its 60th anniversary last year and has experience covering all sizes and types of gas carriers including LNG carriers, LPG carriers, floating LNG, small scale LNG carriers, LNG bunkering shuttles, multi-purpose gas carriers, and VLGCs. As a result of three decades of expertise in the LNG carrier market and its dedicated LNG ship task force, today KR is at the forefront of LNG technology development. The society’s highly skilled scientists and surveyors work tirelessly to enhance the society’s services to support its LNG customers all around the world.

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15FACTS

Egypt, Algeria, and Nigeria were the top three natural gas producers on the continent for the year 2020

Africa has more than 2000 recognised languages

The largest desert in the world is the Sahara

African gas supplies are expected to hover around the 250 - 275 billion m3 mark for 2020 - 2025

AFRICA

Approximately 70% of the world’s cocoa beans are grown in West Africa

Forests cover approximately one fifth of the continent

Natural gas has accounted for more than 75% of the hydrocarbons discovered in Africa in the last 10 years

The continent has 54 countries In early March 2021, Brent surged past US$70/bbl

Estimates put Algeria’s gas exports at 28 billion m3 by 2025, 30% lower than 2020 levels of 40 billion m3

Nigeria currently has 22 million tpy (approximately 30 billion m3) LNG export capacity, and 2020 exports were approximately 27.3 billion m3

Africa is the second largest continent in the world, covering 30 365 000 km2 Mozambique is set to ship its first LNG exports from its Coral floating LNG (FLNG) project in 2022

The Nile crocodile is the second biggest

African elephants can weigh up to 6 t 56

May 2021

reptile on the planet

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