LNG Industry October 2021 Issue by PalladianPublications

October 2021

ISSN 1747-1826

CONTENTS 03 Comment

OCTOBER 2021

28 Leave refrigerants out in the cold

Michael Cacciapalle, Mark Roberts, Chris Ott, and Fei Chen, Air Products and Chemicals, Inc., USA, describe the advantages of gas-expansion processes and why these cycles are particularly attractive for arctic applications.

04 LNG news

33 A floating lifeline for cleaner power

10 Triumphant return from the desert

Zongqiang Luo (Norway) and Priya Walia (India), Rystad Energy, explore the dynamics of the LNG industry in the Middle East, which is primarily led by the gas powerhouses of Iran and Qatar.

Mehmet Katmer, Karpowership, Turkey, explains how floating LNG assets can help alleviate energy poverty by providing countries with access to this transitional fuel.

37 To float or not to float

Tor-Ivar Guttulsrod, ABS, Norway, explains how class support continues to be critical for a new generation of export and fuel supply projects.

40 One platform for data

Steffen Zendler, Heavy Industry - Strategy and Marketing Manager, EMEA, Rockwell Automation, Germany, illustrates the implementation of a new automation system for onboard LNG applications.

45 Motors in beast mode

10 16 It's a bunkering business

Jeff Pollack and Peyton Heinz, Port of Corpus Christi, USA, provide an overview of how LNG bunkering is advancing decarbonisation, focusing specifically on port infrastructure developments.

21 Keeping an eye on n the transfer of heat

Paul Heinz and Christoph Heckmann, Linde Engineering, e being developed for Germany, explain how digital twins are plate-fin heat exchangers.

25 Sustaining LNG growth Richard Bowcutt, Heatric, UK, indicates how heat ng the exchangers are fundamental to realising benefits of LNG and cleaner energy.

Marek Lukaszczyk, WEG, UK, explains how optimising motor performance can contribute to more efficient and effective production processers in the oil and gas industry.

49 Rise to the challenge

Ingo Emde, R. STAHL, Germany, discusses the challenges of fuel gas supply systems and how these can be addressed through the installation of a remote I/O system.

52 How much do you lift?

Garima Khanna, Sarens, Belgium, takes us through some of the company’s most recent LNG projects and details the technicalities of performing lifts for this sector.

56 15 facts on... the Middle East

ON THIS MONTH’S CO COVER The cover features the Port of Co Corpus Christi, t largest energy export port in the US. the Located L Loc ated on the Texas Gulf Coast, tthe Port ccontinued on ntinued to set tonnage records in 1H21, llargely lar rgely attributed to an increase iin LNG exports. ex The Port is making major strides tto balance critical global energy demands, wh while transitioning to longer-term, susta sustainable solutions in emission reduction. Pa Partnering with industry leaders, investing in LNG infrastructure, and utilising clean e energy sources, the Port is maintaining the pathway to be the energy port of the Americ Americas. www.portofcc.com

CBP006075 LNG Industry is audited by the Audit Bureau of Circulations (ABC). An audit certificate is available on request from our sales department.

Copyright Copy C Co opy o p right © Palladian Publications Ltd 2021. All rights reserved. No part of tthis hi h publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without the prior permission of the copyright owner. All views expressed in this journal are those of the rrespective i contributors and are not necessarily the opinions of the publisher, neither do the publishers endorse any of the claims made in the articles or the advertisements. Printed in the UK.

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LYDIA WOELLWARTH EDITOR

COMMENT T

o describe the LNG industry as a picture of stability would be incorrect to say the least. It feels like just yesterday that my comment for this magazine outlined a record low for LNG spot prices, and now I am about to detail the record highs. In the space of 18bmonths, the LNG industry remains a rollercoaster ride for all involved in the sector – but I guess it keeps everyone on their toes. In May 2020, the LNG market was oversupplied and demand was low, causing spot LNG to fall to a record low of US$1.85/million Btu. Ultimately this was the culmination of several factors, when COVID-19 containment measures destroyed demand just as new supplies from major producers flooded the market. The record low price of LNG allowed for new buyers to arrive on the scene, whilst exporters looked on with disdain. Now jumping to October 2021 and the industry has been turned on its head. Competition for LNG is currently at a high, with Europe’s low inventory of the resource butting heads with the self-indulgence of the global top importer for LNG – China. Last week, an all-time high of Asian spot LNG prices was recorded at US$56.34/million Btu, according to S&P Global Platts’ JKM. Prices as high as this, in fact anything above US$20/million Btu, act as a major deterrent to price-sensitive buyers such as India, Pakistan, and Bangladesh. Back in May 2020, these buyers relished the low spot prices and imports flourished, however the current rally is not so welcomed. At the opposite end of the scale is China, which is focusing on purchasing LNG irrespective of the cost. The country seems to have no budget because it is actively trying

to prevent power outages and factory closures that could dampen its economic growth. Despite its efforts over the last year to stockpile fuel, it is still at risk of running out of coal and natural gas when heating demand jumps in the coming months when winter temperatures arrive. Those Asian nations with smaller pockets than China are coping with the global energy supply crunch by switching from natural gas to oil for power generation, according to Rystad Energy. This flexibility is enjoyed in Asia but not in Europe, since steeper carbon regulations are in place to limit European utilities burning oil in power plants. Europe’s inability to fall back on oil in times of gas shortages is of concern particularly this year, as the continent is preparing to enter the winter with its lowest gas reserves in at least a decade. The UK is set to find times hard since it has some of the lowest gas storage capacity in Europe – having cut storage to 1.7% of annual demand – thus many fear the country is exposed to higher prices and the risk of shortages in the upcoming cold months. It is understandable that the UK has avoided investing in storage sites because its ultimate goal is to replace the majority of its reliance on fossil gas with cleaner alternatives in order to achieve net-zero emissions by 2050, however in the interim, gas power plants still need to be relied on as they produce near to 50% of the UK’s electricity. In essence, a cold European winter combined with a cold Asian winter could spell disaster for Europe as there may be insufficient gas available to meet demand. With Asia confidently snapping up LNG, it leaves limited supplies for Europe to import. Does Europe really have enough gas to meet demand? We will have to wait and see.

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LNGNEWS Spain Russia

First modules for Arctic LNG 2 Train 1 successfully delivered

echnip Energies, in a joint venture with its partners Saipem and Nipigas, has successfully loaded, shipped, and delivered as planned the first modules for Train 1 of the Arctic LNG 2 project. The Arctic LNG 2 is located in Gydan, Northern Russia and is one of the world’s largest LNG projects under construction with a total capacity of 3× 6.6 million tpy. On 26 August, the two first pipe-rack modules left the Zhoushan port in China. The modules, each weighing more than 9000 t are to be skidded onto the gravity-based structure (GBS) platform for Train 1 at the LNG Construction Centre in Murmansk, Russia. Once the GBS1 platform is integrated with all topside modules, the complete structure will be towed to the western shore of the Gydan Peninsula, and placed onto the river bed in its final location. In total, three GBS platforms will be installed in Gydan. Alain Poincheval, Fellow Executive Project Director of Arctic LNG 2 at Technip Energies, commented: “We are proud to have achieved this key project milestone with the first modules completed and shipped in a record time despite the COVID-19 challenges. This major achievement demonstrates a strong involvement of thousands of people and robust collaboration between Technip Energies and all parties, especially our customer Novatek and its partners along with our partners and subcontractors. "We will continue the same path to complete all shipments and installations for the first GBS by the beginning of the next year.”

Repsol kick-starts LNG bunker terminal construction

epsol has started the construction of the LNG bunker terminal at the port of Bilbao, Spain, to supply Brittany Ferries' vessels Salamanca and Santoña, which will start their operations in 2022 and 2023 respectively. The construction of this terminal is part of the long-term collaboration agreement formalised in 2019 between Repsol and Brittany Ferries for the supply of LNG to their operations in Spain. This facility is scheduled to be commissioned in 1H22. The Bilbao terminal will have a cryogenic tank with a storage capacity of 1000 m3, which allows the natural gas to be kept in a liquid state at -160˚C. The flexible design of the terminal will allow it to service different vessels in the future, representing an important decarbonisation opportunity for port operations. The start of construction is on schedule due to the efficient collaboration between Repsol's engineering teams, the different administrations involved, and the Port Authority of Bilbao. This project is a clear example of Repsol’s commitment to industrial development and will involve an investment of more than €10 million. This terminal will be joined by the construction of a second terminal of the same capacity in Santander, Spain, where the Port Authority of Santander has already begun work on the conditioning of the quay where the bunker station will be located. Both terminals are co-financed by the European Commission through the CEF – Connecting Europe Facilities Programme. The construction of the Bilbao and Santander terminals is another step towards the company's goal of achieving zero net emissions by 2050, with LNG as an alternative fuel for ships. Specifically, the gasification of the Brittany Ferries’ lines operating from Bilbao and Santander will reduce annual emissions by approximately 73 000 t/CO2.

Jamaica

Höegh LNG and New Fortress Energy sign FSRU deal

ayer Brown advised Höegh LNG, which provides maritime transportation and storage of LNG, on the long-term charter and operation and service agreements for an FSRU. Höegh LNG has agreed to receive, store, and regasify LNG to supply natural gas, as well as provide other FSRU operations and services, to a subsidiary of New Fortress Energy Inc. for a term of 10 years. The FSRU, which is scheduled to begin operations in

October 2021

the 4Q21, will be deployed at the Old Harbour Bay in Jamaica. “This transaction cements Höegh LNG’s position as a market leading FSRU provider, and we are optimistic the FSRU market will continue to grow as a number of developing economies look to utilise FSRUs as a solution to meet rising energy demands in the post COVID-19 environment," said Mayer Brown LNG Practice Leader for Asia Nick Kouvaritakis.

LNGNEWS Malaysia France

Gasum has bunkered LNG to new polar explorer

he energy company Gasum has delivered LNG as maritime fuel to the French luxury cruise operator La Compagnie du PONANT (PONANT) in Le Havre, France. The LNG was delivered to PONANT ’s newly built polar explorer Le Commandant Charcot in its inaugural call to a French port on 24 September 2021. This bunker operation was Gasum’s first LNG delivery in France and marked a further milestone in the extension of the company’s delivery network. It was also the first LNG bunkering ever performed in Le Havre, which is the second largest commercial port and the largest container port in France. Gasum and PONANT share the dedication both to excellency and to reducing the environmental footprint of the shipping industry. Le Commandant Charcot, named after the renowned French polar scientist and explorer Jean-Baptiste Charcot, is the first hybrid-electric polar exploration ship powered by LNG. This polar exploration vessel is the latest addition to PONANT’s fleet and is set to sail the Arctic and Antarctic regions. “We have been working on this natural gas-powered polar exploration ship project for six years and this is already the second LNG bunkering operation we have carried out with Gasum since the delivery of the ship on 29 July 2021. “These LNG bunkering operations represent the culmination of several years of analysis, engineering, and testing to perform these operations safely and with maximum efficiency. “Le Commandant Charcot is the first passenger ship equipped with high-pressure membrane LNG tanks offering up to two months of autonomy on natural gas, greater flexibility in its bunkering and operation, and guaranteeing enhanced safety. “Le Commandant Charcot paves the way for new and more environmentally friendly natural gas propulsion methods and helps to meet the CO2 reduction targets set out in the Paris Agreement” said Hervé Gastinel, CEO of PONANT. Reducing emissions is crucial as Le Commandant Charcot will be operating in fragile environments, such as the waters of the North Pole and Antarctica. LNG is currently the most environmentally friendly maritime fuel available – switching to LNG completely removes SOx and particle emissions and reduces NOx emissions by up to 85%. LNG also emits at least 20% less CO2 when compared to traditional maritime fuels.

October 2021

ABS approves GTT and Deltamarin tanker design

t the Gastech 2021 exhibition in Dubai, UAE, GTT and Deltamarin received an Approval in Principle (AiP) from the classification society American Bureau of Shipping (ABS) for their new design applied for LNG-fuelled tankers of Aframax type. This new LNG-fuelled tanker design employs membrane tank technology developed by GTT. GTT has designed the tank, while its integration into the vessel has been studied by Deltamarin. The approval from ABS certifies that the onboard integration of the membrane fuel tank solution is technically feasible for an LNG-fuelled tanker and that it complies with all safety regulations. This new design provides a solution which fully complies with environmental regulations adopted by the International Maritime Organization (IMO) until 2030. Compared to a conventional oil-fuelled tanker, this new LNG-fuelled tanker design reduces CO2 emissions by at least 20%. It also offers increased autonomy without reducing the cargo volume. Philippe Berterottière, Chairman and CEO of GTT, said: "This new design further demonstrates GTT's ambition to innovate and support the maritime industry in facing the challenges of the energy transition. With Deltamarin and ABS, we are very proud to be able to offer a new LNG-fuelled tanker solution that is more respectful of the environment and without making any compromise on cargo."

THE LNG ROUNDUP X Stonepeak to acquire Teekay LNG X Ship-to-ship LNG bunkering MoU signed in Japan X Petronas delivers 50th LNG cargo Follow us on LinkedIn to read more about the articles

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LNGNEWS Qatar

Vietnam

Qatar Petroleum orders new LNG carriers

Stena completes successful model testing for Vietnam LNG-to-power project

atar Petroleum announced that it has ordered four new LNG carriers from Hudong-Zhonghua Shipbuilding Group Co. Ltd (Hudong), a wholly owned subsidiary of China State Shipbuilding Corporation Limited (CSSC). These four carriers are the first batch of orders in Qatar Petroleum’s massive LNG shipbuilding programme, which will cater for future LNG fleet requirements for the North Field expansion projects as well as for existing vessel replacement requirements. This order is also the first ever placed by Qatar Petroleum or any of its affiliates with a Chinese shipyard for LNG ships, and the first with Hudong in connection with the agreement to reserve ship construction capacity that was executed in April 2020. His Excellency Mr. Saad Sherida Al-Kaabi, the Minister of State for Energy Affairs, the President and CEO of Qatar Petroleum said, “We continue to push forward with our LNG expansion projects, and [this] announcement is yet another step in our journey. I am especially pleased with the signing of this order as it marks our first ever new LNG carrier to be built in the People’s Republic of China.” Qatar Petroleum’s LNG carrier fleet programme is the largest of its kind in the history of the LNG industry and will play a pivotal role in meeting the shipping requirements of Qatar Petroleum’s local and international LNG projects, as well as replacing some of Qatar's existing LNG fleet.

tena Power & LNG Solutions has completed successful model testing of its LNG receiving terminal technology for the Delta Offshore Energy (DOE) LNG-to-power project in Vietnam. Scale model testing of the jettyless floating terminal (JFT), the self-installing regas platform (SRP), the floating storage unit (FSU), and an LNG carrier was completed at the Maritime Research Institute Netherlands (MARIN) to verify and calibrate Stena’s computer simulations and research, ahead of construction and deployment of the assets to waters off Bac Lieu Province in Vietnam. Large scale models (up to 10 m in length) were created in a scale of 1:30 to obtain test results with the highest possible accuracy. A number of various tests were performed by engineers from both Stena Power & LNG Solutions and MARIN to simulate critical wave, wind, and current conditions specific to local conditions in Vietnam, including 100-year cyclonic and monsoon events. Knut-Erik Johansen, Engineering Manager, Stena Power & LNG Solutions, said: “We are delighted to have successfully verified the performance of our JFT, SRP, and FSU through an extensive engineering examination with the support of the highly reputable and experienced engineers at MARIN. Bureau Veritas (BV) has recently also issued an Approval in Principle (AiP) for the complete LNG receiving facilities engineered by Stena Power & LNG Solutions for the DOE project. A similar AiP has been issued by DNV for the JFT.

21 - 22 October 2021

15 - 18 November 2021

30 November - 03 December 2021

Downstream USA

ADIPEC

Houston, USA

Abu Dhabi, UAE

21st World LNG Summit & Awards Evening

www.reutersevents.com/events/downstream

www.adipec.com

Rome, Italy www.worldlngsummit.com

05 - 09 December 2021

14 - 16 December 2021

31 January - 02 February 2022

23rd World Petroleum Congress

European Gas Conference

Houston, USA

Turbomachinery & Pump Symposia 2021

www.23wpchouston.com

Houston, USA

www.energycouncil.com/event-events/

www.tps.tamu.edu/

european-gas-conference

Vienna, Austria

October 2021

LNGNEWS Global

USA

ADC Energy wins rig inspection contract

DC Energy, a specialist provider of dynamic integrated rig inspections, has secured a contract with a US-based global infrastructure organisation, as the business accelerates its strategic diversification plan. ADC Energy has begun conducting a series of audits for an LNG company to help select and identify drilling rigs which can be repurposed for the firm’s LNG operations globally. As part of the workscope, the company’s specialist engineering teams from the US, UK, and Asia Pacific will evaluate a number of oil and gas drilling rigs to determine energy efficiency and suitability for being repurposed for LNG deployment. ADC Energy will utilise its bespoke criteria to evaluate the functional design, physical condition, and operability of each asset, before advising on the process to repurpose the rigs in line with industry safety and operating standards including API and OEM functional design specifications. To date, ADC has conducted the initial assessments of the Maersk Gallant and Maersk Guardian jack up units prior to their departure from their North Sea locations to South America. The business has also been advancing the oil and gas industry’s efforts to decarbonise existing assets in recent months, providing inspections to evaluate environmental, social, and governance (ESG) ratings, reducing non-productive time, and highlighting how operators can gain greater efficiencies from their installations. Austin Hay, Director at ADC Energy said: “While the oil and gas industry remains a key focus for ADC Energy, it is exciting to see our diversification strategy come to fruition with our latest contract in the LNG sector.

LR, HHI, and KSOE sign digital twin MoU

loyd’s Register (LR), Korea Shipbuilding & Offshore Engineering (KSOE), and Hyundai Heavy Industries (HHI) have signed a Memorandum of Understanding (MoU) to develop digital twin technology to support the digitalisation of the maritime industry and the growing demand for large scale LNG carriers. As part of the MoU, KSOE and HHI will further develop its Hyundai Intelligent Digital Twin Ship (HIDTS) for a type B gas containment tank suitable for a 174 000 m3 LNG carrier. LR’s role is to perform audit, review, risk assessment, verification, and validation activities to support KSOE and HHI with the successful development and implementation of the digital twin. LR’s ShipRight Procedure for Digital Compliance will be applied to the HIDTS, including stages Digital Twin READY, the certification of KSOE and HHI as Digital Twin Developers, and Digital Twin APPROVED, the verification of HIDTS. LR will then apply stages Digital Twin COMMISSIONED, which requires a risk-based, resiliency analysis of HIDTS, and Digital Twin LIVE, the validation of HIDTS. LR’s approach will cover the entire lifecycle of the digital twin technology, from conceptual design stage to the operation and large scale commercialisation of HIDTS. “The HIDTS solution creates a digital twin environment in a cyber space which is identical to the maritime environment where a vessel is operated and tests the performance of key equipment and facilities of LNG carriers, such as the dual-fuel engine, gas supply system, and power and control systems. Spurred by the development of this HIDTS virtual commissioning solution, we plan to launch the new digital ship management solution that covers artificial intelligence technologies such as asset management, energy optimisation, and risk assessment” said Byoung-Hoon Kwon, Vice President of KSOE.

Australia

Woodside awards agreement extension to Worley

oodside Energy Ltd (Woodside) has awarded an extension to a non-binding frame agreement for Worley’s brownfields engineering, procurement, and construction management services to continue supporting the Karratha Gas Plant and Pluto LNG assets in Western Australia. The agreement covers brownfield engineering services including engineering studies and technical support, front-end engineering and detailed design services for sustaining capital projects, procurement, commissioning, project management and

October 2021

construction, and shutdown management. Worley has provided brownfield engineering services to Woodside for over 30 years, utilising a variety of contracting models. The original agreement was established in 2018 and this extension is for a further two years with the option to extend. The services will be executed by Worley’s Perth, Australia office with support from Worley’s Global Integrated Delivery team in India.

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Zongqiang Luo (Norway) and Priya Walia (India), Rystad Energy, explore the dynamics of the LNG industry in the Middle East, which is primarily led by the gas powerhouses of Iran and Qatar.

lobal gas markets have started to recover after a tumultuous year in which COVID-19 cut gas consumption by approximately 3%. Demand is expected to return to pre-COVID-19 levels this year and continue to rise through 2022. Typically linked to oil growth, the Middle East is now shifting investments towards gas developments as the region’s countries strive to attain gas self-sufficiency and unlock or boost their export potential. In this article, Rystad Energy takes a closer look at the natural gas projects and demand outlook for the top producers of the Middle East, led by gas powerhouses Iran and Qatar. Before the pandemic, the Middle East’s gas output was rising, despite geopolitical conflicts and US sanctions, putting the region on track to overtake Russia as the world’s second-largest gas producer by 2021 - 2022. However, last year’s slump has delayed this milestone until 2028 (Figureb1). The Middle East will produce approximately 680bbillionbm3 of gas in 2021 and around 900 billion m3 by 2030, according to Rystad Energy estimates. The Middle East’s gas production has been neck-and-neck with that of Asia in recent years, after output surged to 630 billion m3 in 2018 from approximately 455 billion m3 in 2010. More than two-thirds of the region’s meteoric rise can be attributed to Iran and Qatar (Figure 2).

Iran Two waves of US-led sanctions have been imposed on Iran’s oil industry since 2010. During the first wave, which lasted until 2016, Iranian players responded by developing domestic gas projects to add approximately 105 billion m3 of annual production by 2021 to the 146 billion m3 produced in 2010 – the biggest addition in the Middle East. The second phase of sanctions, which began in 2018, had a limited impact on producing fields because they are owned and controlled by national firms and the gas is mainly consumed domestically. Furthermore, even though gas exports to Iraq were briefly halted in December 2020 owing to payment difficulties, total deliveries grew by 13% in 2020 from 2019, and it is expected that exports will keep rising this year. At the same time, gas supplies from Iran to Turkey fell 33% last year after a pipeline disaster in March 2020 that halted exports for two months, and repair work has

been slow due to COVID-19. As a result, Iran’s total gas exports fell 5% last year, but Rystad Energy expects this to turn around this year with gas exports exceeding 2019 levels by 5%. Overall, Iran’s gas production is set to climb from approximately 250bbillion m3 in 2021 to 265 billion m3 in 2030.

Qatar Qatar has, along with Iran, been a driving force in Middle Eastern gas production for many years and will account for approximately one-quarter of the expected gas output growth in the region between 2010 and 2030. After the country in 2017 lifted its self-imposed ban on further development of the giant North Field, new projects like Barzan and Qatargas’ North Field Expansion (NFE) have been kicked off as the country seeks to boost gas output from 120bbillion m3 in 2010 and 158 billion m3 this year to a target of 220 billion m3 in 2030. The country aims to lift its LNG capacity to 126bmillionbtpy from the current 77 million tpy through two phases of the NFE project. The recently sanctioned first phase includes four new liquefaction trains to raise the capacity to 110bmillion tpy, and the remaining capacity will come from the two-train second phase which is currently at the front-end engineering design (FEED) stage (Figure 3). Key facility work for the first phase of NFE is divided into four main packages: Package 1 for building the four liquefaction trains was awarded to a consortium of Chiyoda and France’s TechnipEnergies in February; Package 2 for LNG storage tanks, associated pipelines, and expansion of loading facilities went to Samsung C&T in March; Package 3 for pipelines and utility facilities at the terminal was recently awarded to Tecnicas Reunidas; and Package 4 covers the sulfur-handling facilities. Qatar Petroleum has also invited ExxonMobil, Chevron, and ConocoPhillips to form a joint venture for the NFE project. Leveraging the cost advantage with gas breakeven prices, Qatar Petroleum is pushing ahead with the second phase of NFE and is currently finishing up the prequalification process for the initial tenders for offshore jackets. In addition to NFE, Qatar has also announced further phases of the North Field Sustainability project, worth over US$6 billion, with an award due later this year. These

developments aim to sustain current gas production levels from the giant North Field. The first two phases, worth approximately US$3 billion, were awarded in 2019 and 2021, respectively.

Saudi Arabia Saudi Arabia and the United Arab Emirates (UAE) are expected to double their combined gas production from 110bbillionbm3 in 2010 to 225 billion m3 in 2030, with Saudi Arabia accounting for 70% of this increase. Saudi Arabia’s goal is to meet local gas consumption while also unlocking gas export possibilities. The government has initiated a three-pronged strategy to expand gas production capacity from non-associated, associated, and

unconventional gas resources. Associated gas is being targeted in the Marjan, Zuluf, Berri, and Khurais fields, while compression efforts are underway at the Haradh and Hawiyah fields. On the unconventional front, the nation is making progress toward tight gas development at the Jafurah field, where Saudi Aramco expects to begin construction of a 6bbillion m3 gas processing plant. Rystad Energy believes that conventional associated and nonassociated gas may be sufficient to meet domestic consumption, while unconventional developments would be crucial in unlocking gas export potential. However, the country has taken an active role in balancing the market, which may affect the forecast for associated gas.

UAE The UAE, led by Abu Dhabi National Oil Company (ADNOC), is tapping into sour gas fields, developing gas caps and exploring unconventional deposits to meet the national target of becoming a net gas exporter by 2030. The Dalma sour gas project is first in line, followed by Hail and Ghasha (sour gas), Umm Shaif (gas cap), Shah (sour gas), and Bab (sour gas). The spending plans assume an oil price range of US$55 - US$80/bbl. Even with a breakeven gas price of US$5 - US$6/1000 ft3, a steady pricing environment has opened the path for these projects to be scheduled from 2021 - 2027. On the unconventional front, TotalEnergies is exploring and appraising the Ruwais Diyab concession. The UAE intends to use most of its excess natural gas as a fuel source for power generation.

Figure 1. Global natural gas production split by continent.

Figure 2. The Middle East’s gas production split by country.

Oman Oman has not succeeded in boosting its crude oil output, and has instead turned its attention to accelerating gas development. By 2022 - 2023, Rystad Energy expects Oman will become the first Middle Eastern country whose gas production levels will overtake oil production levels. The Omani government has improved the economics of upstream gas projects by raising domestic gas prices and pledging to use gas in the industrial and electricity sectors, prompting operators to shift toward gas production. Omani state player Petroleum Development Oman will add gas output via the Saih Rawl, Saih Nihadya, Barik, Yibal Khuff, Kauther, and Fahud fields. International majors such as BP and Shell are also active in gas developments in the country – the BP-operated Khazzan and Shell-operated Mabrouk gas projects are set to add annual output of up to 16 billion m3.

Israel

Figure 3. Qatar’s LNG production outlook.

October 2021

In Israel, the Leviathan basin has uncovered massive gas finds like Tamar, Leviathan, Karish, and Tanin, but the country is still waiting for a gas export route to reach its full gas output capability. Israeli production is now at 19bbillionbm3/y, with a projected increase to 40 billionbm3 by 2030. Israel and Egypt have worked together to reverse the flow of the Eastern Mediterranean Gas pipeline between the two countries, allowing Israel to export approximately 7bbillion m3 of gas each year. To establish more gas export capacity, Israel is working on a pipeline project to send gas from the eastern Mediterranean via Cyprus and Crete to Greece, known as the EastMed pipeline, and the country is also investigating possibilities for a possible floating LNG project.

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Figure 4. Natural gas demand by sector in top five countries.

Figure 5. The Middle East’s gas exports by country.

Figure 6. Turkey’s natural gas imports by source.

Iran remains the top consumer of natural gas in the Middle East, even after an estimated decline of 7% last year. The country’s consumption is estimated to be little changed at 214 billion m3 in 2021, or approximately 40% of total Middle Eastern demand (Figure 4). Gas demand from the power sector is still strong as a warmer-than-normal summer triggered significantly higher electricity use for air conditioning, exceeding the power supply by approximately 11 000 MW at a time when drought reduced hydropower generation. However, the US sanctions on Iran may keep discouraging investments in upstream exploration which would limit the availability of gas in the domestic market. This would mean that natural gas demand could peak at 265bbillion m3 in 2024 and then decline slowly in line with production. Saudi Arabia has recovered from COVID-19 with an estimated demand increase of 9 billion m3 in 2021 from 2020, mainly stemming from the power sector. The country is prioritising natural gas for two main reasons: to be able to export more oil and oil products that are currently used for power generation, and to reduce carbon emissions. Rystad Energy expects Saudi Arabia’s gas demand will continue to rise at a rapid pace to approximately 166bbillion m3 in 2030, led by higher power sector demand and a potential ramp-up in gas supplies. LNG imports could be an option to meet the rising gas needs for power generation and industrial use – indeed in 2019 Saudi Aramco already signed a preliminary 20-year agreement with Sempra Energy to buy 5 million tpy of LNG from the US Port Arthur LNG project; however, the country still needs to move ahead with the Final Investment Decision (FID) of the regasification plant that would allow the import of this volume. The UAE, the third-largest consumer in the region, is one of the few countries that may see gas demand drop in the coming years, driven by the country’s ‘Energy Strategy 2050’ plan launched in 2017 which calls for gas to make up 38% of the energy mix in 2050. Electricity supply from natural gas currently accounts for approximately 79% of the UAE’s electricity production. This figure is expected to drop to 42% by 2050, falling short of the country’s target despite rapid growth in renewables such as solar. Other countries in the Middle East such as Qatar, Turkey, and Iraq have also gradually recovered from the effects of the COVID-19 crisis, with a minor increase in gas demand since last year’s downturn has made more domestic production available, or increased gas imports.

Firm gas demand will be fulfilled by abundant gas supplies

When will Qatar recoup the crown as the world’s largest LNG exporter?

Total gas demand in the Middle East will rise by an estimated 5% or 30 billion m3 in 2021. Gas demand for power generation will stay resilient with a 4% or 8 billionbm3 increase from 2020, while industrial demand is set to rise by 6% or 2.4 billion m3. Global natural gas prices rallied early this year due to strong gas demand during the winter with tight supplies. This has been followed by a bullish summer for natural gas prices because of lower-than-normal storage levels in Europe and strong gas consumption for power generation in Asia, combined with a warm summer. What will be the main drivers for Middle Eastern gas demand towards 2030?

Australia overtook Qatar as the world’s largest LNG exporter in 2020 with 77.8 million t as volumes from the Ichthys projects were ramped up and utilisation rates at existing projects remained high – sailing past Qatar with 77.1 millionbt of exports. Qatar remains the largest gas exporter in the Middle East with more than 70% of the region’s exports (Figure 5). The two phases of the NFE are set to lift the country’s LNG export capacity from 77 million tpy to 126bmillion tpy – and it is expected that Qatar’s total LNG and pipeline gas exports will keep rising to 165 billion m3 by 2030. This would allow the country to reclaim the crown as the top

October 2021

global LNG exporter, with a breakeven price range of between US$4 - US$4.2/million Btu destined for Asian markets. Among other Middle Eastern exporters, Egypt may be able to sell more gas abroad in coming years if plans to link Israel’s Leviathan field to Egyptian LNG facilities via an offshore pipeline go ahead. The UAE and Oman are currently estimated to maintain stable exports until 2030 with their existing liquefaction capacities, while Yemen’s exports have been muted in 2020 and 2021 as a result of the country’s protracted civil war.

Turkey to supplement gas imports with domestic development Turkey is the largest gas importer in the Middle East region with an expected domestic demand of 46 billion m3 this year as power and industrial demand bounces back after COVID-19. This gas use is currently entirely met by imports, which surged to 46.5 billion m3 in 2020 from 14 billion m3 in 2000. LNG imports jumped 20% last year as a result of cheap LNG spot volumes, but pipeline imports from Russia, Iran, and Azerbaijan will continue to be the backbone of Turkish gas supply with approximately 33.2 billion m3 or 73% of total imports this year. Gazprom recently indicated that its gas deliveries to Turkey doubled in 1H21, while Turkish LNG imports from the US are seen to have dropped approximately 20% to 2 million t in the first eight months this year from the same period last year due to higher prices. All in all, Rystad Energy expects LNG imports to Turkey to fall to approximately 9bmillion t this year.

Fluctuating LNG prices are not the only factor affecting Turkey’s gas imports at the moment. The country’s existing 25-year supply agreement with Gazprom expires next year, which means negotiations are required for both state-owned importer Botas and private Turkish buyers for volumes currently totalling 8 billion m3/y. In addition, work is under way to secure domestic gas supply by developing the Black Sea Sakarya gas field, discovered last year by state-owned TPAO. The operator expects that the field could produce up to 10 million m3/d by 2023 in phase one, rising to 40bmillionbm3/d if a second pipeline is installed in a later phase. Much remains to be completed if first gas is to be delivered before 2023, however. Therefore, over the next years, Turkey will continue to rely on pipeline imports from Russia and Azerbaijan, combined with LNG imports from France (under a 1.2 million t deal between Botas and TotalEnergies), as well as from Algeria and spot cargoes from the US (Figureb6).

Conclusion Rystad Energy expects a notable increase in Middle Eastern gas development and production in the coming years. This will not boost gas exports immediately but could allow the region to overtake Russia as the world’s second-largest gas supplier by 2028. Gas powerhouse Qatar will continue to raise LNG export capacity, and Egypt could also return as an LNG exporter of gas from Israel. Even with growing capacity in renewable energy like solar and wind, gas demand in the power sector of most countries in the Middle East will remain resilient at least until 2030.

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It’s a bunkering business

Jeff Pollack and Peyton Heinz, Port of Corpus Christi, USA, provide an overview of how LNG bunkering is advancing decarbonisation, focusing specifically on port infrastructure developments. 16

he maritime industry is under mounting pressure to accelerate the energy transition in support of aggressive decarbonisation objectives. The sobering outlook in the Sixth Assessment Report, issued on 7 August by the Intergovernmental Panel on Climate Change, will further this imperative. The International Maritime Organization (IMO) has announced the ambitious goal of reducing the greenhouse gas (GHG) emissions from international shipping by at least 50% by 2050. This climate action complements more stringent air quality regulations, such as the IMO 2020 global sulfur

Figure 1. The Port of Corpus Christi ended June 2021 with a record first half of the year, moving nearly 80.5 million t of cargo, largely due to a 72% y/y increase in LNG exports.

cap, which are targeted at protecting community airsheds and human health. Since the onset of the COVID-19 pandemic, growing concerns have been seen regarding both health and environmental issues and how the two intersect. This has not gone unnoticed by the public and private sector and as such will serve as a major determinant for viable port activities moving forward. The maritime industry has an opportunity to coalesce around new operational standards and efficiencies to capture public trust. While there is no one silver bullet for addressing the environmental challenges of the industry, there should be a strong focus on increased utilisation of LNG as a cleaner, more efficient fuel. LNG fills a niche as a transitional marine fuel in a market where there is a shortage of commercially viable alternatives to diesel. Natural gas is one of the cleanest burning fuels available with negligible sulfur or ash content. Worldwide reserves of natural gas are thought to be significantly higher than for petroleum, and the

International Energy Agency estimates there is sufficient supply for 250 years of consumption. As compared to diesel-powered vessels, vessels powered by LNG reduce emissions in every major category: z Sulfur oxide (SOx) by almost 100%. z Nitrogen oxide (NOx) by 85% or more. z Particulate matter (PM) by up to 99%. z GHG by approximately 21%.

In contrast, diesel-powered vessels and equipment account for nearly half of all NOx and more than two-thirds of all PM emissions from US transportation sources. Its composition frequently includes a multitude of chemical elements, including sulfates, ammonium, nitrates, elemental carbon, condensed organic compounds, and even carcinogenic compounds and heavy metals such as arsenic, selenium, cadmium, and zinc. In addition to air quality and decarbonisation benefits, LNG offers 24% more energy output per tonne than heavy fuel oil. The transition in the world fleet is well underway. The world fleet currently includes 191bLNG-powered vessels, and an additional 251bLNG-powered ships are on order. The world fleet also includes another 146 LNG-ready (e.g. dual-fuel and/or plumbed for LNG but requiring moderate modification) vessels either in operation or on order. This active LNG fleet includes 44bLNGpowered tankers in operation; another 53bare on order as of April 2021. There is also a strong market for dual-fuel engines that can burn conventional fuels, biofuels, LNG, LPG, and ammonia, all with a high and consistent thermal energy efficiency. These fuels will require some modifications to accommodate changing fuels, but these modifications are relatively simple compared to the need to replace the engine and fuel system. Dual-fuel diesel engines can achieve nearly zero methane slip if LNG is injected while pressurised. The low-pressure engines inject LNG as a gaseous methane by utilising a Figure 2. A VLCC enters the Corpus Christi Ship Channel, currently low-pressure nozzle that allows LNG to revert back under construction to deepen to 54 ft. The Port hopes to attract LNGcapable vessels and encourage the transition to LNG fuelling solutions. to a gaseous form, thereby reducing NOx emissions.

Commitment at the Port of Corpus Christi

Figure 3. As a major energy hub, the Port of Corpus Christi is committed to providing a clean energy source for its customers and vessels that call at the port.

October 2021

As ships take between three and five years to build, it is incumbent upon the Port of Corpus Christi, as the largest energy export port in the US, to send a clear signal to ship builders that it is committed to this clean energy source by investing in LNG infrastructure. In April, the Port of Corpus Christi Authority announced that it will be partnering with Stabilis Energy to begin offering LNG bunkering for vessels calling at the gateway. This partnership signals the Port’s broader commitment to sustainability and comes on the heels of the recent announcement that the Port joined the Environmental Protection Agency’s (EPA) Green Power Partnership. Several other ports within the US already offer LNG bunkering, including Jacksonville, Tacoma, and Port

Fourchon, and several others, including Galveston, Los Angeles/Long Beach, Geismar, and Ontario, Canada, have LNG bunkering projects in development. There are approximately 40bports that use barges to bunker LNG in ship-to-ship bunkering operations worldwide and another 21 additional ports bunker LNG via either truck or tank. The Port of Corpus Christi is endowed with abundant, affordable natural gas, due to multiple direct connections to production fields in the Permian Basin and Eagle Ford Shale. The primary natural trading hub for natural gas in South Texas is Agua Dulce, right outside of Corpus Christi, which affords the Port of Corpus Christi with some of the most cost-competitive natural gas prices in the world. LNG bunkering operations at the Port of Corpus Christi will begin in 4Q21, but the Port and Stabilis are partnering on targeted outreach with the hope of attracting more LNG-capable vessels to the gateway and to the western Gulf of Mexico overall, with the ultimate objective of accelerating conversion of the world fleet. Stabilis initially will provide shore-to-ship LNG bunkering, deploying its existing fleet of mobile cryogenic assets from its LNG production plant in nearby Three Rivers, Texas. The nimble, on-demand approach will allow the Port and Stabilis to scale LNG fuelling operations as demand grows with the potential to invest in additional fixed or floating infrastructure assets as needed.

New collaboration In February 2021, the Port of Corpus Christi announced an exciting collaboration with the Port of Rotterdam, Europe’s leading industrial deep seaport, around a shared

customer base and a shared commitment to environmental stewardship. The Memorandum of Understanding (MoU) between the two ports defines pathways for co-developing trade and commercial opportunities, fostering an exchange of information, and advancing the development and deployment of innovative technologies specifically related to navigational safety and environmental protection. The Port of Rotterdam is recognised globally for its high-quality infrastructure, connectivity, and economic development including a strong support of LNG bunkering. The Port of Rotterdam is Europe’s first and largest LNG bunkering port. Every year, approximately 11 million m3 of bunker fuel is supplied to vessels in Rotterdam from heavy fuel oil (HFO) to biofuels. The Port of Rotterdam also is capitalising on the density of carbon emitters and the existing infrastructure at the Port to develop centralised carbon capture and storage infrastructure; the Port of Corpus Christi – which has a comparable industrial customer composition – has been declarative about its intention to develop a similar hub in the Coastal Bend region of Texas. Dr Tip Meckel from the Bureau of Economic Geology at the University of Texas at Austin, one of the world’s top experts on industrial carbon capture and underground storage, has mapped the geology of Gulf State Waters (up to nine nautical miles from shore) and has determined this area to be uniquely suited for injection and storage of pressurised CO2. The Port, a political subdivision of the state, hopes to partner with the Texas General Land Office to establish a centralised hub for carbon capture and geologic storage.

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Paul Heinz and Christoph Heckmann, Linde Engineering, Germany, explain how digital twins are being developed for plate-fin heat exchangers.

very industrial plant is unique, as are the plate-fin heat exchangers (PFHE) at the heart of many of these plants. PFHEs can be found in cryogenic processing plants such as air separation units, petrochemical and natural gas treatment facilities, as well as helium and hydrogen liquefiers. They transfer heat between various fluids in different phase states. Linde’s PFHEs measure up to 8bm in length. Their compact design belies their strong performance. With a heat duty of up to 20 MW, a single core is as powerful as a small natural gas power plant. Moreover, a single PFHE can handle up to 20 process streams simultaneously.

Design considerations Heat transfer performance is one of the key factors in determining PFHE size. In Linde’s PFHEs, the surface-to-volume ratio can measure up to 2000 m2 per m3. This exceptionally high specific heating area maximises heat transfer efficiency, helping

to limit investment costs by reducing the column height and weight. Optimised heat transfer performance also enables very small temperature differences – down to 1 K. Other design highlights of Linde’s PFHEs include low-pressure drops and fast responses to flow and temperature changes. These factors combine to maximise operational efficiency, making PFHEs the most economical exchangers available. In addition, increases in heat transfer efficiency speak to the current trend towards larger process equipment designs. In recent decades, plants and equipment have grown steadily larger and have to handle more and more operational scenarios. Natural gas liquefaction plants are a case in point here. As a result of this, mass flows have also increased, as has the volume of heat that PFHEs have to handle. This calls for higher specific heating surfaces inside a PFHE. Linde designs and builds its PFHEs for industrial plants based on the individual process requirements of every customer, factoring in variables such as heat transfer targets and the permissible pressure drop. In short, every PFHE is tailor-made. Plant operators are presented with a PFHE that aligns perfectly with their overall process flow.

Optimising performance through detailed data analyses From the outside, all of these plant components look the same. Inside, however, the temperature profile of every PFHE

Figure 1. Linde manufactures plate-fin heat exchangers (PFHEs) at its sites in Germany and China.

is unique. For a long time, heat exchangers were like black boxes, providing limited or no insights into temperature behaviour. It was therefore practically impossible in the past for plant operators to assess process conditions. Yet this information plays a vital role in efforts to optimise performance and maintain long-lasting, reliable, robust operations. To close this information gap, Linde’s experts have been developing methods to optimise PFHE efficiency and extend its service life for many years. Linde now offers a service that provides valuable insights into what is happening inside heat exchangers. The operator of Australia’s largest LNG plant is one of the first customers to award Linde in 2020 with a contract for the continuous remote monitoring and diagnostics of Linde-supplied PFHEs. The objective of this service is to identify and avoid potentially critical operating conditions beyond the specifications and thus minimise the risk of costs due to unexpected downtime. As part of this service, Linde continuously monitors PFHE operations and warns the plant manager if the on-site team creates operational conditions with the potential to reduce PFHE lifetime. Furthermore, Linde experts support the on-site team in optimising operational efficiency and avoiding these situations.

The best way to avoid material fatigue PFHEs can be prone to thermal stress, resulting from localised temperature fluctuations, which can be as high as 200˚C. This causes thermal shrinking and expansion inside the heat exchanger, placing the unit under increased mechanical stress. Over time, microscopic damage and small cracks can develop into localised leaks. Changes in the metal’s microstructure ultimately lead to material fatigue, which can shorten the operating life of these exchangers. Linde’s PFHEs are designed with a high stress margin. When operated within their design specification and in compliance with industry best practices, they offer a long lifetime. However, repeated thermal loads beyond specification can have a major negative impact on PFHEs in the long-term, as confirmed by countless studies under real-life process conditions run by Linde’s experts. The studies revealed that occasional excursions from optimal operating parameters were not a major problem but that repeated excursions are a very different matter. This challenge can be solved by monitoring PFHEs remotely. Combined with advanced diagnostics, remote monitoring gives operators the insights they need to track thermal conditions inside the heat exchanger, detect potentially critical instances of thermal stress, and take corrective action.

Insights into the inner life of PFHEs

Figure 2. Aluminium PFHE, proven technology in a variety of designs.

October 2021

For Linde, this process starts with a detailed temperature profile of the metal wall. One tried-and-tested solution here involves installing sensors on the surface of the heat exchanger. Benefits include the fact that these can be retrofitted to existing plants and heat exchangers. These sensors collect temperature readings to assess the possibility of thermal stress. The more sensors that are installed, the more accurate the findings. However, design constraints can limit the number and placement of sensors

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on the PFHE and this, in turn, can compromise the insights possible with these sensors. Linde’s LINEX® sensor system was developed to take measurement accuracy and speed to the next level by overcoming the design constraints of other sensor systems. It is the first solution of its kind to provide detailed, real-time insights into the inner workings of a PFHE. To achieve this, multiple sensors are installed at various points of interest inside the PFHE. The technology is integrated seamlessly into Linde’s engineering and fabrication process and does not affect the thermal performance or size of the PFHE. Depending on the size and operational requirements, PT100 sensors or glass fibre sensors can be used to take

Figure 3. PFHEs in numbers.

Figure 4. Options for measuring temperature.

Figure 5. Thermal stress fatigue mechanism.

October 2021

high-resolution measurements of temperature profiles and material strain.

Predicting the future with digital twins The data collected by the PFHE sensors is transmitted directly to Linde’s Industrial Internet of Things (IIoT) cloud using a ‘Smart Box’, which transmits data via Ethernet, WLAN, or a SIM card. Linde’s experts have already verified this set-up using a test rig and integrated it into the company’s own plants. One of the great benefits of the system is that it is compatible with any plant control system and can even be shipped preconfigured to customers. Local technicians can then install it on-site, significantly reducing implementation costs and time. The system can easily be retrofitted into existing plants. The quality of the simulation model is ultimately what determines the extent to which the digital PFHE twin matches its real-life counterpart. Linde’s tool is able to simulate the thermal status of a heat exchanger in detail together with all relevant correlations for heat transfer and pressure drop as well as dynamic conditions. It then uses this information to generate predictions. Linde’s experts also work with computational fluid dynamics (CFD) to provide detailed analyses of flows inside PFHEs. For larger scale analyses, Linde has developed a model that can simulate the complete geometry of a PFHE using the company’s proprietary performance and pressure drop correlations. This three-dimensional CFD/FE analysis can be used to evaluate the impact of rapid warm-ups or cooldowns, for example.

Extending lifetime and improving performance Linde’s vision is to create a complete digital replica of a PFHE based on its precise properties, the customer-specific process technology, and the instrumentation in use. The idea is for this twin to be able to respond dynamically. In other words, actual data from the heat exchanger and/ or its process values will be fed into an algorithm, which will then use this information to continuously simulate and evaluate the thermal status of the unit and make predictions. For the Australian reference customer mentioned earlier, the temperature and flow data from the process streams are transmitted to the Linde cloud at regular intervals, along with surface temperature readings from the heat exchanger. A digital twin calculates temperature distribution, etc. and displays the health of the plant 24bhours a day, also sending alerts to Linde experts if any issues arise. Plant operators can monitor the operational status via a special online dashboard and also assess the impact of current conditions on the performance. Linde experts support this process with consulting on the resulting impact on the operating life of heat exchangers. Digital twins are thus paving the way for nextgeneration PFHE operations, offering enhanced transparency and continuous monitoring. In addition to prolonging the service life of heat exchangers, digital twins also provide options for improving overall plant performance by visualising PFHE operations.

Richard Bowcutt, Heatric, UK, indicates how heat exchangers are fundamental to realising the benefits of LNG and cleaner energy.

s governments look to overhaul their energy systems and their economies in support of the green agenda, an increasing number of renewable energy, carbon capture, and biofuel sources are entering the supply grid. Against this backdrop, LNG is an energy source with the potential to support countries’ green ambitions. LNG is the fuel of the future. However, with a complicated and lengthy value chain, from source processing to liquefaction, transport, regasification, and onshore infrastructure, significant investment and expertise is required to scale LNG to support emissions targets being set by governments around the world.

The climate change race, and transition to clean energy, is well underway. Countries around the world have adopted goals for net-zero emissions by 2050, and hundreds have joined the 2015 Paris Climate Accord, which aims to limit global warming to below 2˚C. Clean-burning and low-carbon, natural gas is an effective, proven, and more sustainable alternative to gasoline and diesel, releasing 45% less carbon dioxide than coal and 30% less than oil. With the clock ticking for businesses, and the gas industry itself to become compliant with environmental legislation, natural gas is playing an increasingly vital role in reducing the

emissions of pollutants. LNG can also power low-polluting modes of transport, and as such, is becoming an increasingly popular marine fuel to support clean shipping. With the green energy transition accelerating, demand for natural gas is growing. As more countries increase their usage of natural gas as an efficient source of energy, structural global LNG demand could rise 14% by 2025 from 2020, resulting in a 26b-b34bmillion tpy call on balancing markets over 2022 - 2025, of which Europe would be the biggest driver, with China, South Asia, and Southeast Asia as key growth regions. Indeed, there is potential that use of LNG could overtake the supply of natural

Figure 1. Höegh Grace FSRU. Image courtesy of Höegh LNG.

gas through pipelines. Therefore, it is critical that LNG processes are as efficient and sustainable as possible. Heat exchangers, which perform fundamental and essential heat transfer operations for numerous oil and gas applications, can support the reduction of emissions in LNG processes to enable the drive to net-zero.

LNG process challenges Whilst LNG serves as an important component of a more sustainable energy and fuel supply, liquefaction and LNG transportation create greenhouse gas (GHG) emissions. In a nutshell, the liquefaction and regasification processes require significant energy, with associated parasitic losses due to boil-off during storage and transportation. Pure LNG or dual-fuel engines also release GHGs from methane slip but still offer an overall reduction compared to conventionally fuelled engines from between 14 - 23% for two-stroke and 6 - 14% for four-stroke. Alongside environmental efficiency challenges, there are complications involving the regasification process and distribution of LNG once it has reached the shore. For projects where space and cost make a land-based facility unfeasible, floating storage regasification units (FRSUs) can be a more practical, economic, and environmentally friendly alternative for converting LNG that has been shipped from the offshore platforms back to its gaseous state for piping inland. However, as with offshore oil and gas platforms, these units have very specific requirements and space is much more compromised vs land platforms.

Heat exchanger developments to support reduced emissions

Figure 2. A close-up of Heatric’s chemically-etched plate channels.

Figure 3. A fully-constructed Heatric printed circuit heat exchanger (PCHE) awaiting final testing.

October 2021

Heat exchangers play an essential role in all stages of the LNG value chain. The design of heat exchangers has evolved to meet the demands of the LNG industry; with enhanced efficiency, energy savings, ease of maintenance, and increasingly, modularity. Designing heat exchangers to withstand high pressure and large temperature spans can often lead to heavy and bulky equipment. On FRSUs, where space is extremely limited, it can be challenging to find a suitable and effective solution to enable the liquefaction and regasification processes. Meggitt’s Heatric division has designed printed circuit heat exchangers (PCHEs) to meet the specific requirements of high-productivity, space compromised platforms such as FRSUs, by providing space and weight savings, high thermal effectiveness, low pressure drop, and high design pressure capability. Capable of operating with a very close temperature approach, PCHEs enable higher thermal efficiencies throughout the LNG value chain to reduce waste energy and emissions by enabling optimum process conditions to be met. Manufactured to be 85% smaller and lighter than traditional technologies, Heatric PCHEs’ unit size provides significant space and construction savings due to the elimination of extra pipework and associated equipment. This reduces the overall weight impact on FRSUs and therefore the fuel impact, with significant cost and emissions savings. As with any oil and gas offshore platform, safety is paramount, meaning equipment has to be extremely robust. PCHEs are not susceptible to vibration and do not suffer from catastrophic failure modes. Heat exchangers manufactured using a specialised solid state joining process known as ‘diffusion bonding’ are extremely durable, capable of

withstanding temperature shocks and mechanical damage, to both optimise system up-time and ensure the highest safety levels.

Greener shipping: LNG – the fuel of the future In the climate change fight, LNG is not just being used as a cleaner energy supply. Demand for LNG is also being driven by the marine industry. Shipping is the fundamental facilitator of global trade and is under growing pressure to reduce its carbon footprint. As a result, LNG is increasingly being seen, at least as an intermediate solution, as a cleaner fuel to help power shipping. Traditionally the shipping industry uses variants of marine diesel oil (MDO) for power and propulsion. LNG produces up to 30% less carbon dioxide than diesel equivalents used in the industry. LNG-fuelled ships also emit almost zero sulfur oxide emissions. A small percentage of ships globally have made the transition to run on LNG, with most having dual-fuel capability, enabling the switch between MDO and LNG. However, the number of ships powered purely by LNG is increasing exponentially, and is expected to increase as existing LNG infrastructure grows and comparative cost approaches other fuel solutions. The effort to reduce carbon footprint is being partly driven by a deadline set by the International Maritime Organization (IMO), the United Nations marine regulator, to cut carbon emissions in half by 2050 compared with 2008 levels. Several IMO regulations have already been imposed on vessel owners to reduce several key emissions such as SOx and NOx, in an attempt to kick-start a green revolution in global shipping. It is also being driven by consumer and therefore logistics customer demands for cleaner supply chains. Shipping companies know that if they want a long-term chartering contract with a big client, they will be assessed on how green their ships are. Royal Dutch Shellbplc and Australian miner BHP Group have, for example, been offering long-term charters to shipowners willing to build natural gas-fuelled tankers and bulk carriers over the past 18 months. Bulk tankers that transport LNG across the seas have been using LNG for many years. Even with sophisticated storage tanks, a small amount of LNG turns back to gas while it is being transported, rather than wasting it, the boil-off gas (BOG) can be used as a fuel source for the engines or reliquefied and returned to the LNG storage tank using specialised BOG reliquefaction systems. Other LNG powered ships require a fuel gas supply system (FGSS), which is a complete system comprising of an LNG storage tank, LNG process system, and control and safety system that turns the LNG into gas to power the ships. Incorporating this infrastructure onto cargo ships has significant space efficiency and weight ramifications. PCHEs are an integral part of both BOG reliquefaction systems and FGSSs, delivering space and weight benefits which make them a vital component to delivering on the emissions promises of LNG. The LNG value chain needs optimised equipment and systems at every process stage, to give the market the best opportunity at maximising impact through reducing emissions whilst demand growth is highest. Current gas prices are volatile and demand is expected to fluctuate for the short-term in the UK for example, where a long, windless summer has prompted the start-up of coal plants to cover energy recesses from offshore wind. LNG remains the critical transition fuel whilst

development of alternatives such as hydrogen are matured and become economically viable. In the meantime, the imperative is to sustain the growth in LNG applications as a key aspect of delivering the sustainable energy mix required for global emissions reductions. Otherwise, LNG will miss the boat altogether.

Figure 4. A painted Heatric PCHE for a gas processing application.

Figure 5. An ‘exploded’ digital view of a Heatric PCHE, showing how the exchanger core is encased.

Figure 6. Alternating hot and cold fluid core plates.

October 2021

n 2018 - 2019, the LNG industry saw substantial investment in many large, conventional liquefaction projects needed to meet projected demand. However, the 2020 pandemic brought with it a glut of supply which drove natural gas demand down by 4%.1 As economies continue to recover, so too does demand for LNG. As projects become increasingly diverse in terms of geography and size, liquefaction processes continue to develop to meet customer needs for reliability, operability, efficiency, and cost. For example, in the floating LNG (FLNG) and small scale LNG markets, Reverse-Brayton (RB) liquefaction cycles, also known as gas-expansion processes, have gained acceptance. LNG plants in arctic climates have some specific needs.2 First, the ambient temperatures can vary widely, by as much as 30˚C within a month and over 50˚C during a year. Second, the plants should be simple and robust to minimise outside operator attention. Finally, minimising plot space is important due to soil conditions and to allow weather protection to be installed. The AP-C1™ liquefaction process efficiently responds to these needs by using an RB cycle while employing recent advances in coil wound heat exchanger (CWHE) technology. This article provides further insight as to how the AP-C1 process differentiates itself from more typical precooled, mixed-refrigerant, Reverse-Rankine (RR) cycles such as the AP-DMR™, AP-SMR™, and AP-C3MR™ processes.

The liquefaction process The AP-C1 liquefaction process is a unique RB process that has been considered an alternative solution for a wide range of applications.3 Figure 1 shows a simplified layout of the AP-C1 process. Feed gas is sent through a CWHE where it is liquefied at high pressure to approximately -105˚C. The highpressure LNG is let down through two successive flashes, produces LNG product at approximately -160˚C, and is sent to storage. The cold gas streams generated by the successive flashes are sent to CWHEs where they are warmed against slip streams of feed gas to produce more LNG. The low-pressure, warm flash gas is sent back to feed through a multistage recycle compressor. To prevent nitrogen and non-condensable accumulation as well as to satisfy the fuel requirements, a fuel stream can be taken off at an interstage pressure from the recycle compressor. As the name would suggest, the AP-C1 process shown in Figure 1 provides closed-loop refrigeration using feed gas as the refrigerant in an RB arrangement. The refrigerant is compressed, cooled in an aftercooler, and then split. The first portion is expanded to provide refrigeration to the precooling section of the CWHE. The second portion is sent to the CWHE precooling section, where it is cooled along with the feed and then expanded to provide refrigeration to the liquefaction section of the CWHE.

Specific power The efficiency of different liquefaction cycles can be compared using specific power. Specific power is defined as refrigeration power required to produce one unit mass of LNG, kWh/t for example. A lower specific power indicates a higher liquefaction efficiency because less power is needed to produce 1 t of LNG. The specific power depends on many factors, including compressor and driver efficiencies, line sizes, ambient

conditions, etc. In this article, to compare different cycles, specific power is normalised for each data point to calculate relative specific power. All processes are normalised using the same basis, so the relative specific powers can be compared. Also, to compare just the cycles, the specific power does not include any boil-off or tank flash recycle compressor power. For each cycle, a design case was completed using rigorous and high-fidelity simulation software. The major equipment was sized based on the design case. Subsequent cases rated the equipment at off-design points namely where ambient temperatures were varied. Specific power for each cycle is resultant of these rigorous simulations. Figure 2 shows the relative specific power for each cycle over the ambient temperature range. Here are some key takeaways from Figure 2: z First and most notably, when the ambient temperatures are approximately 10˚C to 15˚C colder than the design point, the AP-C1 process can be more efficient (i.e. lower specific power) than the RR processes. When the ambient temperature is 30˚C colder than the design point, Figure 2 shows that AP-C1 has a specific power approximately 10% better than either the AP-DMR or AP-C3MR processes.

Figure 1. The AP-C1™ liquefaction process.

z Second, while the AP-DMR and AP-C3MR processes certainly have their own distinct advantages, their efficiencies are very similar, only differing by approximately 2% in this example, even at the coldest ambient temperatures. The AP-C1 process achieves this relatively high performance at colder temperatures due to the method of adjusting for low temperature operation. Methane is removed from the refrigeration loop, thereby lowering the compressor power requirement while also keeping the volumetric flow and head closer to design best efficiency point.

Simplicity of operation

Figure 2. Liquefaction process efficiency comparison.

Figure 3. The AP-C1 process capacity control.

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Some of the other key differentiators for the AP-C1 process revolve around the fact that refrigeration is provided solely via sensible heat and not the latent heat of a boiling refrigerant. The AP-DMR and AP-SMR processes utilise mixed refrigerant and the AP-C3MR process utilises propane and mixed refrigerant to precool and liquefy natural gas. As liquid refrigerants are essential to operation, it is critical that composition, inventory, and condensation conditions are managed to create the required liquid refrigerants at varying ambient temperatures and production rates. With the AP-C1 process, capacity control of the refrigeration loop is very straightforward. As production increases or when ambient temperature increases, more refrigeration is required. High-pressure feed gas is sent to the suction of the methane compressor increasing the refrigerant loop pressures and therefore producing more refrigeration. Conversely, for reduced capacity or when ambient temperature is lower, less refrigeration is required. The refrigerant loop can be de-inventoried back to the feed which decreases the refrigerant loop pressures and produces less refrigeration. The ability to recover the methane refrigerant as LNG during turndown reduces or eliminates flaring during capacity adjustment and shutdown. Figure 3 shows how the methane refrigeration loop is inventoried and de-inventoried. Use of aeroderivative gas turbines as drivers for the methane refrigeration compressor and the end flash recycle compressor provides more operating flexibility because the

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Train size

Figure 4. Train size comparison.

The defining characteristic of the AP-C1 process is that the refrigerant is all-vapour. While there are many advantages to this, there are also some limitations that should be considered for project-specific requirements. All-vapour refrigeration means that the shellside of the CWHE is entirely vapour and requires more flow area compared to a liquid, boiling refrigerant. Larger flow area coupled with the typically higher operating pressures of the methane refrigeration loop reduces the achievable heat exchange duty per unit of CWHE, pushing the design envelope for CWHE technology if large single-train capacity is required. A single-train capacity in excess of 4bmillion tpy in hot climates is feasible with the AP-C1 process, although some parallel equipment may be required. Figure 4 shows the approximate maximum single-train capacity for each of the liquefaction cycles discussed. Note that the AP-N™ process, while not discussed here, is a similar RB cycle where the refrigerant is nitrogen rather than methane.

Adapting CWHEs for the AP-C1 process

Figure 5. Integrated end flash unit. drivers have a wide speed range. When production must be reduced for short periods of time, the refrigerant inventory can be kept constant by slowing the aeroderivative gas turbine and their associated compressors. This produces less refrigeration and therefore produces less LNG while keeping each compressor operating near its maximum efficiency point. This is compared to a fixed speed driver which has limited turndown capability before the compressor must be recycled. Below that flow, the power does not decrease.

No refrigerant production or storage required The implicit advantages of all-vapour methane refrigerant are: no requirement for importing or fractionating refrigerants for make-up, no storage requirements, and very low flammable inventory. Arctic LNG opportunities are often in remote locations so eliminating the need for hydrocarbon refrigerant importation is very attractive for lean gas. For rich gas, while hydrocarbon refrigerants can be fractionated from the feed, reducing the field construction and operational complexity of a fractionation unit and storage is likewise attractive. Any liquid formed in the refrigeration loop upon start-up would be knocked out downstream of the cold expander before entering the cold end of the CWHE. These liquids would be sent to the LNG product. Should the feed be very rich, hydrocarbon removal may be desirable to meet product LNG heating value specifications, in this case a much simpler heavy hydrocarbon removal fractionation system may be appropriate.

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There are two end flash exchangers in the AP-C1 process that economise cold, low-pressure flash gas against fresh feed to produce more LNG. Since the duties of these CWHEs are much lower than the main exchanger, they are much smaller in diameter. Plot space optimisation may often be required when configuring the overall layout for these exchangers, vapour liquid end flash drums sized for low-pressure vapour flow, and the accompanying large bore piping. Recent advancements have made it feasible to integrate a CWHE with end flash drums. Rather than having a flash drum for vapour-liquid separation, the disengagement now takes place within the shell of the CWHE. Integration also reduces plot space and large bore piping runs.4 Figure 5 shows the proposed arrangement for the integrated end flash unit.

Summary The choice of liquefaction process is undoubtedly multifaceted and requires a detailed evaluation of all project needs. There are many cycles – such as precooled, mixed refrigerant AP-C3MR, AP-SMR, and AP-DMR processes – that will produce LNG reliably and efficiently. However, gas-expansion cycles such as the AP-C1 process should also be evaluated as its unique features may better meet project-specific goals. This article shows that gas-expansion cycles can provide significant power savings when operating at ambient temperatures well below the design point. Additionally, the process is operationally simple and flexible, especially operating in climates such as the arctic where monthly and annual ambient temperatures change significantly and rapidly. These features make it particularly attractive for arctic applications.

References 1.

IEA, ‘Gas 2020 - Analysing the impact of the COVID-19 pandemic on global natural gas markets’, 2020.

SCHMIDT, W. P., OTT, C. M., LIU, Y. N., and WEHRMAN, J G., LNG-17, ‘Arctic LNG Plant Design: Taking Advantage of The Cold Climate’, 2013.

ROBERTS, M., et.al, Gastech 2018, ‘Liquefaction Cycles for Floating LNG: From Concept to Reality’, 2018.

OTT, C.M., Beard, J.D., and Pearsall, R., Gastech 2018, ‘Debottlenecking: Getting the Most Out of Your LNG Plant’, 2018.

Mehmet Katmer, Karpowership, Turkey, explains how floating LNG assets can help alleviate energy poverty by providing countries with access to this transitional fuel.

A floating lifeline for cleaner power I

t has been extremely encouraging to witness calls to action and fresh pledges aimed at advancing climate targets coming at a rapid pace, despite the ongoing global health crisis. Amidst the human tragedy and economic hardship, there has been an increasing alertness to climate change – an issue that is as important to collective long-term safety as anything else could be. Now, the world is looking at COP26 to sustain that momentum as nations and advocates work to ensure goals can be met within achievable timeframes and critically, given the current context, within budget. This is where LNG delivered via floating LNG (FLNG) assets and infrastructure can play a vital role.

LNG is key to advancing universal access to electricity and securing a more sustainable and inclusive energy transition, but many markets lack the infrastructure or supply to readily access and benefit from natural gas.

Countries without indigenous natural gas supply need to be given the opportunity to harness the benefits of LNG as a transitional fuel – and at the forefront of this will be mobility and flexibility. Floating assets can solve this problem. Powerships (floating mobile power plants) utilising LNG as a fuel source have the ability to provide countries with a reliable, practical, and affordable means to bridging the energy transition. They are ready to deploy and can generate electricity within tight timeframes – but enhancing this already speedy access to energy will be the combination of powerships and FSRUs. The use of FSRUs and powerships together is a pioneering solution in the mission to bring LNG-utilised power generation to countries with no natural gas infrastructure, and at the same time offer a reliable, cost-effective solution to alleviating energy poverty.

Floating assets deliver success Figure 1. One of Karpowership’s LNG-to-power sites in Amurang, Indonesia.

FSRUs are FLNG import terminals capable of both storing and regasifying large volumes of LNG. Since the world’s first FSRU hit the seas in 2005, the vessels have proved ground-breaking in the transportation, storage, and supply of LNG, fuelling growth in the market and opening up access. The growth has been significant. According to the US Energy Information Administration, between 2015 and 2019, global LNG trade has expanded by 45%, driven by record growth in both 2018 and 2019. While the global pandemic produced a dip in demand in 2020, consultancy Wood Mackenzie estimates global LNG demand is still expected to grow by another 53% to 560bmillion tpy by 2030. A critical component to meet this demand will be FSRUs as governments and energy companies see the benefits of using the vessels to import LNG. The market is already ensuring that to service this demand, more FSRUs are being built and utilised around the world.

An LNG-to-power solution Figure 2. KARMOL FSRU, LNGT Powership Africa, moored in Dakar, Senegal.

Figure 3. KARMOL FSRU, LNGT Powership Africa, docked at Sembcorp Marine’s Singapore shipyard.

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Karpowership strongly supports the use of these gamechanging vessels and is working proactively to support this shift. FSRUs are at the heart of Karpowership’s ongoing LNG-to-power mission to ensure access to electricity is universal. Using FSRUs to supply powerships with natural gas is vital to realising LNG’s vast potential as a transitional fuel in new markets. FSRUs can store up to 260 000 m3 of LNG and enable an immediate yet durable connection to the LNG supply chain. The combination is the simplest, quickest, and most effective way of bringing the benefits of LNG to countries with no domestic supply or infrastructure. The solution is simple: two vessels connect via gas pipelines allowing the FSRU to feed regasified LNG to the powership, which then creates gas-fuelled power that can be delivered directly into a country’s grid from the onboard high voltage substation. The combination of floating assets involves little on-land infrastructure and importantly helps to ease reliance on dirtier fuels. This is good for the environment, significantly cutting

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demand for development on land, largely eliminating the costs and challenge of decommissioning assets, and cutting emissions compared to other fuels. This reduction in the environmental impact of power is vital to those who operate in the energy sector. The sector is always looking forward, committed to finding new ways of providing cleaner fuel options. This is a responsibility that needs to be taken seriously. LNG is a pragmatic solution while the world continues to develop renewables to a point where they are both an economical and practical solution for baseload power. An LNG-to-power solution means markets with small, medium, and large scale power demand can get fast access to reliable electricity, and no longer need to rely on expensive and environmentally damaging methods such as diesel generators or coal-burning power plants.

South Africa: A case study

Karpowership has moved quickly to deliver on this vision. In September 2020, the company initiated its first LNG-to-power operation in Amurang, Indonesia, after the conversion of dual-fuel engines in its powership. The transition from fuel oil to natural gas utilises Indonesia’s natural resources and reduces the carbon output of electricity generation. Choosing to expand investment in the LNG value chain, Karpowership has also established a 50/50 joint venture with Mitsui O.S.K. Lines, Ltd under the brand name ‘KARMOL’. KARMOL is building three FSRUs, one of which is completed, designed specifically to be compatible with powerships. This makes them unique to other FRSUs on the market and will boost Karpowership’s LNG-to-power projects around the world. The intention is to at least double the company’s LNG assets over the next five years. With the conversion of its Amurang operations to LNG, Karpowership has hit its 2021 target of ensuring 50% of operational supply is powered by natural gas and LNG. The ambition is to raise this to 80% by 2025 – and in time to 100%. Currently, the company has 30 completed powerships exceeding 5000bMW installed capacity, across 11binternational markets. These powerships are equipped with dual-fuel engines and the aim is to reach 8500 MW by 2026.

A strong case for where an FSRU and powership solution could rapidly alleviate a country’s energy challenges, is in South Africa. There is a mounting awareness of the challenge of balancing increasing demand for reliable power with the need to protect the environment. In addition, there is a critical focus on rebuilding the economy following the pandemic. Currently, more than 90% of South Africa’s energy is generated from coal. In 2020, the South African government called for the reduction of greenhouse gas emissions to net zero by 2050. Karpowership strongly supports the government’s ambitions in this area. There is mounting recognition that LNG is an important part of the energy transition towards net zero because it emits less than the legacy plants currently powering South Africa and it is based on established, reliable technology. South Africa’s lengthy coastline also means it is an ideal location to host FLNG infrastructure. Following a government tender for 2000 MW of new dispatchable electricity, in March 2021, Karpowership was named as one of the South African government’s preferred bidders to alleviate the energy crisis by mooring powerships at three sites – 450 MW at each of Coega and Richards Bay, and up to 320 MW at Saldanha Bay. Actual power output will be determined by the grid operator, Eskom, to best suit demands on the grid at any given time. Karpowership’s projects were selected alongside a range of other technologies – most of which use a combination of renewables and thermal fuels, and three solar/battery projects. The selection is a hybrid: using LNG as a backbone to the power grid as renewables develop and expand. This is exactly what South Africa needs to proceed with the energy transition. The introduction of FSRUs to supply the powerships is an opportunity to develop an entirely new gas industry for South Africa. Critically, the project will also help reduce load shedding during peak periods and boost supply when unplanned breakdowns occur at other power plants in the system.

Fuel switchover success

Conclusion

As a continent in search of cleaner power generation and reliable electricity – natural gas offers increasing potential in Africa. Senegal’s national electricity company, SENELEC, has set an ambitious gas-to-power strategy to speed up the conversion of key energy facilities. In August 2019, Karpowership signed an LNG-to-power contract with SENELEC, and within just 58 days delivered the powership to start supplying base-load power to the grid. The powership has a capacity of 235 MW and is supplying 15% of the country’s electricity. The arrival of the first KARMOL FSRU earlier this year, with a capacity of 125 000 m3, and the switchover to natural gas, means Senegal is now Karpowership’s first LNG-to-power project in Africa. Senegalese authorities also plan to switch their existing 90 MW Bel-Air power plant to natural gas and procure the LNG that will be

As the world continues on the path towards a zero-carbon energy mix, natural gas will play an increasingly important role in bridging the gap from phasing out coal to the development of renewables. To deliver on the ambitions of the UN sustainable development goals and the Paris Agreement, a strong gas sector will ensure meaningful progress and create a viable commercial environment for the long-term development of renewables. The ability to provide LNG to countries with no natural gas infrastructure will be critical in this mission. This can be achieved by making use of FLNG assets and boosting what has already been done for generations – using the world’s waterways to deliver fuel. In the case of LNG – floating assets, such as FSRUs and powerships, are delivering access to a vital fuel along with the promise of meeting the immediate power needs of countries around the world.

Mobile LNG mission

supplied by the FSRU. The project means Senegal will have access to over 300 MW of reliable power via natural gas.

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Tor-Ivar Guttulsrod, ABS, Norway, explains how class support continues to be critical for a new generation of export and fuel supply projects.

loating LNG (FLNG) production units had been contemplated for almost three decades before the Final Investment Decision (FID) was made for Prelude FLNG offshore Australia in 2011. With that decision, the long road to making FLNG a reality began in earnest. While the support of major energy players and the energy transition towards natural gas helped to kick-start the development of FLNG, more recent projects are focused on smaller scale applications, including direct gas exports and LNG bunkering. Demand for natural gas continues to grow as a substitute for coal and oil in power generation, as fuel for transportation, and as an industrial feedstock. It is therefore prudent to have workable solutions for storage, handling, and loading of gas as a means to bring it to a diverse range of consumers. FLNG can typically be the preferred solution where conditions make it challenging to pipe the gas due to distance, water depth, pipelaying difficulties, or a combination of these. Another element that can push towards FLNG rather than onshore plants is remote locations, because a floating plant can be built under controlled conditions in a shipyard. The search for viable, safe, and cost-effective solutions for producing what used to be deemed

stranded gas and bringing it to market has gathered pace. Gas has continued to gain traction as a fuel for power generation and its position as the cleanest burning hydrocarbon continues to make it an important part of the energy transition away from more polluting fuels.

Project criteria When in the planning and feasibility stages of an FLNG project, desktop exercises are commonly required to determine cost-effective and safe solutions for processing, storage, and liquefaction of gas. Projects will often require an application of new technologies as well as merging technologies from: onshore gas processing and liquefaction, offshore production and processing from the upstream energy business, and LNG storage and offloading from the LNG shipping business. The regulatory environment for FLNG units must also ensure that risk issues related to cryogenics and large inventories of gas and pressurised gas are fully addressed. It has to ensure there is a seamless transition between the FLNG hull and the topside facilities from a regulatory framework point of view. Regulations and compliance for FLNG units will need to be co-ordinated to encompass the requirements of class, flag, and international regulations, as well as the local requirements where the units are intended to operate. Some assistance in moving this forward has been gained by the advent of floating regasification units, although most of these units are classed as ships and not as facilities. These units did however move forward the concept of a floating unit with integral LNG storage, ship-to-ship transfer of LNG, and simple processes onboard as the LNG is liquefied before being supplied for its end use.

Figure 1. Pilot LNG is focused on midstream LNG greenfield and acquisition opportunities across North America and internationally.

Figure 2. Woodfibre plans to construct an LNG export terminal incorporating floating storage on the site of a former pulp mill.

October 2021

Current projects ABS is currently supporting two projects, both of which demonstrate new approaches to FLNG; extending the concept to international exports and the supply of fuel for LNGpowered cruise ships. Pilot LNG is focused on midstream LNG greenfield and acquisition opportunities across North America and internationally. The company’s belief is that by mitigating environmental impacts it is possible to provide innovative midstream and downstream solutions that create efficient pathways to market. The venture plans to originate and develop new market access to LNG via floating storage and regasification units (FSRU) and floating LNG bunker terminals as the fastest and most cost-efficient means to unlock new global markets. Its portfolio of LNG import, downstream, and LNG bunker solutions includes the proposed Galveston LNG bunker port which will supply the growing market for LNG as marine fuel in one of the US’s busiest port complexes, serving the ports of Houston, Texas City, and Galveston. The project is designed to take advantage of the strong demand outlook for LNG as a bunker fuel market due to its ability to meet IMO requirements for carbon emission reductions whilst also meeting the most stringent standards for SOx, NOx, and particulate matters as well. This is particularly prevalent for the Galveston/Houston region in Texas as it is already designated as a non-attainment area due to its poor air quality. The rapid growth of LNG-powered vessels in operation and on order in Asia and Europe, together with LNG’s competitive position when compared with low sulfur marine fuels, suggests the long-term economics favour LNG over petroleum-based marine fuels. A bunkering vessel will deliver LNG to client ships, principally targeting the cruise terminal at the Port of Galveston which handled around 300 port calls and sailings in 2019. A new, third cruise terminal was announced in October 2019, adding 59 future sailings and with the capacity to add a further 100 sailings. LNG can also be supplied to the increasing number of dual-fuel vessels including tankers, containerships, and car carriers expected to call at the ports of Houston/Galveston/ Texas City. Located on the northeast corner of Pelican Island, the FLNG terminal to be positioned at Galveston features a liquefaction capacity of 0.5 million tpy and a storage capacity of 18 000 m3, with electricity supplied by renewable energy sources. The Tango FLNG unit, which shares several design features with the Pilot LNG bunker liquefaction floater, held successful gas trials in September 2016, at the Wison Nantong Shipyard, China and was delivered in January 2017. The unit has until recently been operating successfully in Argentina at Bahia Blanca for energy major YPF. Providing LNG bunker fuel via an FLNG unit in Galveston Bay avoids costly transportation from distant supply sources along the US Gulf Coast. The vast intrastate pipeline grid in Texas allowing gas supply to the FLNG unit is a key contributing factor in the regulatory/permitting process here. Associated distribution logistics and terminal costs are lower when compared to the delivered cost of LNG bunkers in Europe or Asia. The decision to employ an FLNG unit was influenced by both a reduction in the time necessary for the Texas

permitting process by around two years compared to the federal (FERC) regulatory timeline for energy infrastructure, and by the very competitive capital costs of the terminal compared to traditional land-based facilities. Pilot LNG has exclusivity on the site and has completed initial due diligence and fatal flaw analysis with no issues. FID is expected in 2Q22 with an in-service date estimated for 2Q25. The Woodfibre LNG Project is owned and operated by Woodfibre LNG Ltd, a privately held Canadian company based in Vancouver, British Columbia (BC). It plans to construct an LNG export terminal incorporating FLNG storage on the site of the former Woodfibre pulp mill (located approximately 7bkm southwest of downtown Squamish), sourcing natural gas from Pacific Canbriam Energy, a Canadian company with operations in north-eastern BC.b Woodfibre LNG will convert two existing Moss-type LNG carriers for storage service, moored to a jetty at the site. FLNG storage means the venture can repurpose existing ships with a potentially long service life left in LNG containment, saving space on-site whilst also saving money and time on the schedule. By not building new storage tanks onshore at the site, the project is less intrusive to the local environment as the storage units can simply be towed away after the life of the project ends. Since the project was announced, Woodfibre LNG has received three environmental approvals from: the state and Canadian governments and from the Squamish Nation. The process of gaining consent from the Squamish Nation was the first of its kind and resulted in the first-ever environmental approval by an Indigenous people in the absence of a treaty. Woodfibre will employ renewable hydro-electricity for power,

making it one of the cleanest LNG export facilities in the world, shipping LNG principally to Asian markets. Woodfibre LNG has recently signed a second LNG Sales and Purchase Agreement (SPA) with BP Gas Marketing Ltd (BPGM) for the delivery of LNG from the LNG export facility. Under the terms of the agreement, BP will receive 0.75bmillionbtpy of LNG over 15 years on a free onboard basis. This latest agreement will increase BPGM’s total LNG off-take to 1.5bmillion tpy – over 70% of Woodfibre LNG’s future annual production.

Conclusion Class involvement is an integral part of a successful FLNG project, whether for safety assessment, verification, regulatory approval, or the most suitable application of technology. With a growing variety of FLNG units, locations, and potential climates to consider, each project must be considered on its own merits. Some of the prescriptive rules traditionally employed for onshore LNG storage may not work as well for an FLNG unit as a marine installation. For these reasons, probabilistic tools as well as different types of risk analyses and workshops are used to demonstrate the safety of the design within acceptable safety criteria. To develop the appropriate safety and operational criteria, operators should consider the regulatory elements of the project at the earliest possible stage. Class can provide valuable assistance in this phase and help develop the regulatory compliance matrix, dialogue with the local regulatory body and other stakeholders, and support continued innovation in FLNG.

Steffen Zendler, Heavy Industry - Strategy and Marketing Manager, EMEA, Rockwell Automation, Germany, illustrates the implementation of a new automation system for onboard LNG applications.

he LNG Portovenere and LNG Lerici are two ships designed for the transportation of LNG. Built in 1997 by Fincantieri and having reached the middle of their lifespan, their owner, in collaboration with their management company, the Belgian firm EXMAR Ship Management, made the ships the object of a significant, total renovation project to prolong their lifespan by at least 15 years. In addition to revamping the boilers, pumps, and turbines, the project also included modernisation of all the control systems, from the central management system to the system used for the turbines and turbopumps. The design and implementation of the new automation system was assigned to the Safety Systems and Information Division of the Italian company Leonardo. A high-tech global company and one of the main players in the aerospace, defence, and security sectors, the company is a leader in the design and provisioning of high-integrity security systems and process safety systems.

Based on its in-depth knowledge of Rockwell Automation solutions and a long-term collaboration with its team, Leonardo opted for the deployment of a new infrastructure controlled by the PlantPAx® DCS.

Challenge Dedicated to transporting LNG, the ships, with a capacity of 65b000 m3 each, underwent an extensive refit project, in which Leonardo was involved for automation control, sensors, and field instrumentation. At the time of their construction, both the LNG Portovenere and the LNG Lerici were equipped with a Bailey

Figure 1. In addition to revamping the boilers, pumps, and turbines, the project also included modernisation of all the control systems.

Figure 2. Navantia shipyard in Ferrol, Spain.

Infi 90 system, popular at the time, which became a legacy system at the end of its lifespan, maintained by the Leonardo service department. The desire to replace the legacy system with a modern, high-performing system was at the heart of the project assigned to Leonardo. In addition to the central system, in itself already a challenge because it represents the heart of these ships, Leonardo was also contracted for the modernisation project covering the automation systems for the turbopumps and turbines, which up to that point had been managed by separate systems. The replacement of all field instrumentation was also necessary, as it had become obsolete and at danger of imminent breakdown, especially in light of the difficult conditions in which these ships operate. The greatest challenge, however, was related to the timeframe given by the owner. For understandable economic reasons, the stoppage time for the ships had to be as brief as possible. This required perfect co-ordination with the other contractors in order to proceed with installation of the hardware and software in parallel with the revamping of the boilers, turbines, pumps, and other equipment – reducing the subsequent commissioning phase to a minimum. It was also necessary to consider that all internal inspection activities would also have to be scheduled during the time period. External certification by certifying bodies also had to be factored in as the ships have dual registry: specifically, RINA – Registro Italiano Navale (the Italian Naval Registry) and ABS – the American Bureau of Shipping. “In this context, with so many variables and rigid timetables, selecting the best solution and suppliers was a key factor,” explains Stefano Baccelliere, Homeland Security and Critical Infrastructure LoB/Project Manager of Leonardo. “On the one hand, our time was very restricted, but on the other we wanted to take advantage of the occasion offered by these large scale works to offer our client a solution that was decisively better than the incumbent solution, to allow for possible future developments. “We had to lean towards a solution that did not have hidden surprises of any kind and one that we knew very well that could satisfy the requirements for modernity, scalability, and flexibility,” he continues. “We also wanted a system that had high performance levels associated with the management of functional safety, while also being simple to implement, in terms of hardware and software, ultimately delivering fluid migration of the legacy system to the new system. We could not take for granted the importance of finding a supplier that could bring proven experience from three diverse markets – naval, oil and gas processing, and energy – and above all, one with the capacity to make these vertical skills a common thread throughout the project.”

Solution

Figure 3. Having combined all the systems into a single platform also means having a single supervision and control system.

October 2021

In light of all of this, Leonardo chose Rockwell Automation and its modern PlantPAx DCS, because both could satisfy all the requirements. The PlantPAx DCS made it possible to combine all of the control systems in a single platform. Now the central control system for the ships is managed by the Automated Integrated System (AIS), as are the turbines and turbopumps. Leonardo’s technicians are already very familiar with the hardware elements of the PlantPAx solution, meaning that the migration project could be completed without the need for

any field rewiring. Furthermore, in collaboration with the Rockwell Automation team, an identical mock-up of the software solution destined for the ships was created on land. This created the opportunity to undertake in-depth functional tests to check that the new system’s functionality was identical to previous levels, therefore making it possible to study possible improvements in the solution and new functionalities with the help of Rockwell Automation specialists. The land-based inspection phase was fundamental because it made it possible to arrive at the commissioning phase with the onboard software operationally ready, and it also overcame the problem of working with two ships located in two different shipyards. For the LNG Portovenere, commissioning took place in January 2016 at the Navantia shipyard in Ferrol, Spain, while the commissioning of the software on the LNG Lerici took place in 2018 at the Keppel shipyard in Singapore. The decision to use the PlantPAx DCS also made it possible to include the emergency shutdown system for safe functioning. A remote service line was installed with a satellite internet connection, to deliver continuous customer support during navigation. It also gave Leonardo the opportunity to offer continuous assistance during operations, along with troubleshooting support for maintenance personnel.

Results “Today the ships are equipped with a modern system with better performance than the former system, and all the advantages that come with that. Energy consumption

was also reduced thanks to the new generation-control system. Basically, using the PlantPAx DCS, we enjoy double advantages: in addition to progressing from a legacy system to a modern one, today we also have a single system instead of three separate systems, with improved performance and speed,” remarked Baccelliere. Having combined all the systems into a single platform also means having a single supervision and control system, which in this case is based on FactoryTalk® View SE, and provides a faster solution in respect to refresh times for the graphic pages and more intuitive for operators. From an assistance and maintenance standpoint, the ships are now equipped with a remote service system with a satellite internet connection; therefore, operators can count on continuous assistance as needed. Another advantage stems from the fact that if it becomes necessary to secure a spare part, a global company such as Rockwell Automation has a better chance of having spares available in the many different countries where the ships dock. This is especially true in light of the changes in operating area for these ships, from the Mediterranean basin to the Far East, and in particular between China and Indonesia. “We selected an open system like PlantPAx to give us the possibility of providing the client with additional functionalities backed up by Rockwell Automation, with which we have been developing successful projects for over 10 years, and whose mission is to continue to invest in R&D to improve the level of service to the client. All of these factors are the basis for further development of this specific project and future collaborations with other clients,” concluded Baccelliere.

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Marek Lukaszczyk, kaszczyk, WEG, UK, explains how optimising motor performance can contribute to more efficient and effective production processers in the oil and gas industry.

ccording to McKinsey, most oil and gas operators have not maximised the production potential of their assets and offshore platforms are, on average, running at only 77% of maximum production potential. Industrywide, this shortfall represents a considerable US$200 billion in annual revenue. Energy efficient oil and gas processing begins with efficient facility design, and this includes the choice of each piece of equipment in each individual process. More and more, an increasing number of oil and gas companies are being seen adopting a wider range of technologies that are helping them become more efficient and minimise costs. From the automatic monitoring of steam traps in LNG processes, to embracing advanced analytics, it is clear that this sector is stepping up its efforts to optimise its processes. While efficiency improvements should be considered as a facility-wide strategy instead of limited to one individual asset, electric motors play a key role in the oil and gas production and distribution infrastructure. They are widely used to drive equipment such as pump and compressor systems and thus offer great potential for efficiency gains. This article will explore five considerations to improve the efficiency of motors in the oil and gas industry.

High efficiency motor upgrades Europe has over 8 billion electric motors in use across industry, consuming approximately 63% of the electricity generated across the continent. Many of the electric motors in use in oil and gas applications are either low-efficiency or not properly sized for the application. Incorrect motor sizing can result in the performance of the motor not being at its most efficient, especially below 50% of rated power output. Similarly, older motors may have been rewound a few times during maintenance, lessening their efficiency. For this reason, a cost benefit analysis should be completed prior to rewinding any motor to determine if purchasing a new, higher efficiency motor is economically advantageous. Today it is possible to purchase a hazardous area motor with highefficiency ratings up to IE3 or IE4.

Because energy consumption accounts for 96% of the total lifecycle cost of a motor, paying extra for a premium efficiency motor will result in return on investment over its lifespan. The recent introduction of stricter ecodesign requirements (EU 2019/1781) for electric motors has accelerated this trend, not only in Europe, but worldwide. Until recently, some motors, including those designed for hazardous areas, were exempt from energy efficiency regulations. This will no longer be the case under the latest regulations. Additionally, these regulations will also be imposed on variable speed drives (VSDs) for the first time. The legislative changes will impact many industries, but sectors with high energy usage or using ATEX motors, such as the oil and gas industry, may see the greatest transformation. The new regulations replace the regulation EC 640/2009 and are expected to bring huge reductions in the energy consumption related to motor use, while maintaining the required level of safety. It is estimated that by 2030, this will deliver extra energy savings of 10 TWh/yr and greenhouse gas (GHG) emission reduction of 3 million tpy CO2 equivalent.

Motor sizing

Figure 1. Industrial pipelines at an oil and gas refinery.

Significant improvement to motor design can be achieved without incurring substantially increased costs. However, the use of high-energy class IE motors must not replace a fundamental rule: the electric motor must be properly dimensioned according to its real load. If a motor is oversized, with the actual load less than 50% of the rated load, it will reduce efficiency and power factor values. For this reason, it is important that efficiency and sizing considerations go hand in hand. There may also be additional factors to bear in mind when choosing ATEX motors for oil and gas applications. As a result of safety requirements, explosion proof motors (Ex db, Ex dc) may face design constraints such as derating for VSD operation or reduced starting current. This may sometimes result in a larger frame size, which could lead to additional considerations when retrofitting equipment with a need for motor interchangeability.

Installing a VSD or soft starter

Figure 2. WEG provides high-efficiency motors and drives for the oil and gas industry such as the WG20, W22X, and CFW ranges.

October 2021

Although very few oil and gas applications require 100% flow continuously, many of the motors employed in oil and gas applications, such as pumping systems, are started at full speed and remain running at full, fixed speed while in use. VSDs can effectively control rotating equipment such as fans, compressors, and pumps in industrial processes and offer the best efficiency advantages in variable torque applications. In fact, according to the European Committee of Manufacturers of Electrical Machines and Power Electronics (CEMEP), a 20% reduction in speed could lead to a 50% reduction in energy. For example, in LNG compressors, VSDs can offer many efficiency benefits. The majority of LNG plants feature refrigeration compressors driven by industrial gas turbines. However, if plants opt for a full electric solution by using an electric motor and a VSD, this increases the production flexibility, reduces emissions, and decreases the maintenance costs. To deliver the maximum energy saving potential, VSDs must be commissioned and installed correctly. Following the manufacturer’s guidelines can make the difference between installations that run reliably for years and those with much

shorter lifecycles. This is where partnering with an expert such as WEG can pay off. If the VSD has not been properly configured this can have a real impact on the performance of the system. To maximise the reliability of the installed VSDs, start by considering the application conditions and the speed at which the motor is required to run. Parameters usually have a ‘default’ setting which will probably be adequate for most applications. However, these should be checked and adjusted for optimum operation. Motors are often left to idle, as some operators believe that it is more economical than stopping and restarting the motor. Idling motors use energy unnecessarily and should always be shut down if they will not be needed. This is where soft starters should be considered. As the name suggests, soft starters allow the motor to start the load more gradually by limiting the voltage to the motor and providing a reduced torque. In addition to reducing energy consumption, a reduced voltage soft starter helps protect the motor and connected equipment from damage by controlling the terminal voltage.

Digitalisation and motor performance sensors Correctly implemented data analytics systems and tools can overcome the operational complexity of oil and gas operations. While most oil and gas companies have vast volumes of data, they are typically using less than 1% of it. By combining advanced engineering, the latest data science, and computing power, there is the real potential to make production optimisation improvements across the board.

Instead of replacing conventional methods of asset operation, digitalisation will supplement them. For example, to keep motors running optimally in LNG plants, managers can install retrofit sensors. With important metrics such as vibration and temperature monitored in real-time, built-in predictive maintenance analytics will identify future problems ahead of failure, preventing shutdown of processors.

Correct maintenance practices Regular maintenance should be carried out on the entire motor system. Performance will naturally decrease after prolonged heavy-duty use or the exposure to harsh conditions. This can be as a result of erosion, corrosion, or chemical attack. Engineers should firstly opt for products – such as those provided by WEG – that can provide energy efficient operation in harsh oil and gas environments. For example, voltage in-balance, where the voltage of power supplied to the motor does not match the voltage at which the motor is rated, can cause vibrations and mechanical stress, increased losses, and motor overheating. These issues increase the maintenance costs of running the motor and shorten its life. Like many energy-intensive industries, the oil and gas sector is exploring new solutions to increase production and energy efficiency. As the sector continues to evolve its processes and infrastructure, it will continue to rely on high-efficiency motors and drive control technology as a reliable pillar in the wider energy efficiency drive.

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Ingo Emde, R. STAHL, Germany, discusses the challenges of fuel gas supply systems and how these can be addressed through the installation of a remote I/O system.

nternational shipping today remains a growing source of greenhouse gas (GHG) emissions with, according to the International Maritime Organization (IMO), maritime transport emitting approximately 940 million tpy of CO2 and being responsible for 2.5% of GHG emissions. Furthermore, the use of heavy fuel oil not only causes CO2 emissions but also releases fine dust, nitrogen oxide, and sulfur dioxide that significantly contributes to air and water pollution. To this end, legal restrictions on the use of heavy fuel oil are becoming ever stricter. In 2006, the IMO tightened the specified limiting values for permissible sulfur content in ship fuels and expanded restrictions on the use of fuel in inland waters, in EU seaports, and in Sulfur Emission Control Areas (SECAs) such as the North Sea, the Baltic Sea, and the Californian coastal region of the US. As a result, ship owners must refuel their ships with much more expensive, reduced-sulfur marine diesel. In January 2020, the IMO introduced even stricter environmental requirements regulating the use of heavy fuel oil.

LNG – an environmentally friendly alternative It is against this backdrop of growing restrictions that the shipping industry has been undergoing significant changes in the way it considers the fuel it uses, with more attention paid to LNG and liquefied petroleum gas (LPG) drives as either an alternative or as a transitional technology that conserves resources. Compared to conventional maritime fuels, the use of gas-powered combustion engines reduces fine particle and nitrogen oxide emissions by up to 90% and sulfur dioxide emissions by 100%. LNG fuel also offers benefits in terms of cost. While the type of ship and the speed of the wider gas infrastructure will determine when the retrofitting and installation of LNG drives will yield a profit, current model calculations assume that gas drives on ships will pay off after an average of five years, based on strict environmental requirements, the price of maritime diesel, and decreasing costs of LNG supply.

Other cost benefits include the fact that there is no need to install an exhaust gas cleaning system, which can be expensive. LNG and LPG drives can also be used in ports – a key benefit as more and more port cities consider making the use of costly shoreside power supplies mandatory for marine diesel fuel ships to prevent air pollution. This technique is known as cold ironing (when ships had coal-fired engines) where the ship’s power load is transferred to the shoreside power supply without disrupting onboard service. The benefits of LNG-fuelled shipping are also being seen in the market and commercial decisions. In March 2021, E&P major Shell signed an agreement to charter 10 new very large crude carriers (VLCCs) powered by dual-fuel LNG engines. By the end of 2021, the operator will have 14 LNG-fuelled carriers in service. This is in addition to the hundreds of retrofits expected.

Fuel gas supply systems – a sophisticated network A key element of LNG-powered ships is the fuel gas supply system (FGSS) that supplies fuel to the motors and comprises the gas tank itself, as well as evaporators, compressors, pumps, and heat exchangers. FGSSs provide a sophisticated network with temperature, pressure, and flow value data provided to the ship control system and alarm control monitoring system (ACMS), if present. Yet, FGSSs come with challenges as well, particularly because of the hazardous areas in which the systems operate due to the high volatility and ignitability of the conveyed gas.

Retrofitting ships powered by heavy fuel oil to use FGSSs will therefore mean that there will be additional hazardous areas onboard that require the integration of explosion protected input/output (I/O) and display systems in the ship’s control system and onboard alarm control monitoring. In such cases, the measured values must not only be accurate but also be determined and transmitted using explosion-protected, intrinsically safe sensors and network components. The rest of this article will examine how these challenges can be met and how an effective, resilient, and safe FGSS can be put in place, thereby powering not only ships but the growing uptake of LNG in marine transportation.

FGSS challenges – data flow, flexibility, and resilience Yet, what are these challenges? Data flow is one such challenge with the need to not only transmit the sensor data from hazardous zones to the ship’s control centre without interruption, but also generate recorded data, visualisation, and monitoring for the ACMS. This is complicated by the additional hazardous areas onboard and the need to integrate hazardous areas in Zone 1 and 2 into the control systems. Other data flow issues include electromagnetic compatibility (EMC) where it is vital that devices do not interfere with other devices through electrical and electromagnetic interference. A flexible system is also important with the need to add or replace modules as needed in hazardous areas as well as expand the installation at any time. Finally, resilience and reduced maintenance is also vital with the need for the infrastructure around FGSSs to perform at all temperatures and to be made of resilient materials.

A remote I/O system

Figure 1. A key element of LNG-powered ships is the fuel gas supply system (FGSS) that supplies fuel to the motors.

With these issues in mind and the importance of safe networking in hazardous areas, R. STAHL, a supplier of explosion-protected components and customer-specific system solutions, has developed a solution for intrinsically safe sensor/ actuator networking around its IS1+ Remote I/O system. The system is designed for Hazardous Zone 1 – an area in which an explosive gas is likely to occur in normal operation and is particularly suited to FGSSs due to the additional hazardous areas onboard that require the integration of explosion-protected I/Os and display systems in the ship’s control system and onboard ACMS. The IS1+ Remote I/O system, which has all required ship approvals and certificates according to the EU RO Mutual Recognition Group, combines a series of robust human machine interfaces (HMIs) which are linked up with explosion-protected versions of all required network components. The result is problem-free, convenient access to process data in the environment immediately surrounding the applications and an addressing of the challenges of FGSS deployment.

Data transmission Figure 2. The IS1+ Remote I/O system for modern process automation offers support for PROFINET, EtherNet/IP, Modbus TCP, and PROFIBUS DP.

October 2021

The devices within R. STAHL’s system use multi-mode fibre optics for data transmission, offering a simple solution for all control systems or ACMSs, enabling signals from hazardous areas to be connected to the distributed control system via PROFIBUS DP, Modbus RTU, or Ethernet Modbus TCP, EtherNet/ IP, and PROFINET.

The IS1+ Remote I/O system features eight-channel analogue I/O modules with HART, 16-channel digital I/O modules, four- and eight-channel digital output modules, and eight-channel temperature modules for resistance temperature detectors and thermocouples. On analogue modules, line faults are indicated by a red LED. On digital modules, the switching state is also indicated by a yellow LED.

Resilience and maintenance When it comes to resilience, the IS1+ series Remote I/O systems feature seawater-resistant enclosure materials, a vibrationresistant design, and resistance to electromagnetic influence – very important in the maritime industry and a challenge already mentioned where there are strict EMC requirements, due to the mission critical nature of onboard wireless equipment and sea rescue call frequency. Due to the low-power technology designed specifically for the IS1+ I/O level, the modules are also suitable for an extended temperature range between -40˚C and 75˚C and reach a service life of 15 years. All modules are equipped with additional self-diagnostics functions based on NAMUR NE 107 and as a result, the ‘maintenance required’ warning message is sent 12 months before the end of the expected service life. A blue LED on the module also clearly indicates when maintenance is required.

The importance of flexibility Another key challenge that is being addressed through the I/O system is that of flexibility. Installation is seamless with the remote I/O systems coming in suitably sized enclosures ready for installation with the central processing unit (CPU) modules and used as gateways for connecting the remote I/O systems to the wider automation system. In addition, the remote I/O system provides the option to expand the installation at any time using the plug-and-play principle. If required, all modules can be added or replaced on-site without interrupting operations. Expanded diagnostics also provide other options, which is why all Zone 1 modules feature one or two LED displays per channel.

End users applications Many customers today are requesting an FGSS connection that works with remote I/O systems for quality assurance and safety reasons. R. STAHL has been implementing remote I/O installations on ships and offshore platforms for 30 years, and this

Figure 3. R. STAHL has been installing remote I/O systems on ships and offshore platforms for over 30 years.

experience is vital when installing the new IS1+ Remote I/O system, with the solution already tried and tested on several hundred LNG tankers and other oil and gas applications. The company initially received an order at the end of 2019 to outfit four freight ships, one tanker, and five container ships and business has built up from there – sometimes in particular regions. In South Korea, for example, shipyards are recording increasing demand for LNG-powered ships and many shipbuilders have opted for R. STAHL’s remote I/O system for sensor data transmission from the FGSS to command levels and alarm control monitoring systems. Over the past year, two of the largest shipyard operators in South Korea (as well as also being renowned companies in heavy industry) have approached R. STAHL. In these cases, the requests involved adjusting the specifications of existing ship control systems and the FGSS connection for use with R.bSTAHL products.

Rising to the challenge While there is a long way to go with LNG-fuelled shipping (in 2019, of the approximately 60 000 cargo ships in operation around the world, only 321 were powered by LNG drives, with orders in place for a further 510 ships), there is little doubt that the effective retrofitting and operation of FGSSs in hazardous areas will become even more important. Companies, such as R. STAHL, are rising to the challenge.

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he LNG sector has a bright future as it continues developing around the world, flourishing across countries such as Australia, Algeria, and Russia. In such a young industry with significant room to grow, key players in the sector are seeking to capitalise on this opportunity and maintain their competitive advantage over other fossil fuel producers. According to recent reports, a number of major projects in the industry are projected to begin development over the next 10 years as many countries seek to fight climate change and reduce greenhouse gases, posing a unique opportunity for developers involved in their construction and maintenance. Constructing an LNG terminal requires careful planning and equipment and can pose unique challenges to developers due to engineering constraints, specifics for gas pipelines, and selecting the most applicable technology for production. Heavy lifting firm Sarens has been involved in LNG projects around the world, adding a number of prominent projects to its roster over the past several years. With a growing expertise in the sector and the challenges that have been encountered on such projects – most notably through its work in Algeria and Russia – the firm has a grasp on the operational difficulties and technicalities of construction as well as maintenance projects required to keep LNG facilities operating efficiently. To highlight some of the most critical considerations, this article will outline the scope of two projects in distinct locations: the recent revamp of the Algerian Arzew plant and the Russian Yamal terminal construction.

Garima Khanna, Sarens, Belgium, takes us through some of the company’s most recent LNG projects and details the technicalities of performing lifts for this sector.

Figure 1. A CC8800 crane completing a lift at the LNG plant in Russia.

Arzew LNG Movement and lifts in a live petrochemical site with space constraints involve meticulous planning. Algeria’s role as the world’s first major LNG producer attracted Sarens’ team to the Arzew plant project, which plays a crucial role in

exports for the country while also helping it to lower its CO2 emissions. The Arzew LNG facility was completed earlier this year after undergoing a maintenance project to modernise the plant, which was originally constructed in the 1970s. Together with Renaissance for Airproduct, Sarens’ team was tasked with the role of lifting and carrying out the installation of refinery equipment at the plant, for which the team needed to strategically plan the lifts required in order to avoid disrupting operations and exports at the plant. “Through careful planning we were able to ensure that there were no additional disruptions in production at the plant while it underwent important maintenance,” said Saadi El Mehdi Zemmouri of Sarens, “We lifted several tanks as well as the cold box, which stretched 47 m long, weighed 150 t, and which will allow the plant to continue operating efficiently for years to come.” According to Sarens, the most important component of the project was successfully transporting the 47 m long cold box, for which the team decided to deploy its CC2800-1 crane with SSL 72 m main boom length and a lifting capacity that was able to sustain the 150 t cold box. The main crane was selected while taking into account the length of the cold box – which was the most critical section to be lifted – but also because the crane could easily be transported from Sarens’ Algeria offices and was able to be assembled in four days on the project site. The heavy lifts were successfully completed and will maintain LNG gas production at the GL1Z plant in Algeria, allowing the industry to continue expanding in the region. The Arzew plant’s renovations will reduce future maintenance costs and gas consumption rates, as well as maintaining LNG gas production, boding well for its future.

Yamal LNG project in Russia

Figure 2. A CC8800 crane completing a lift at the LNG plant in Russia.

Figure 3. A Sarens CC8800-1 crane at the Yamal project site in Russia.

October 2021

One of the LNG sector’s most iconic projects sits at the edge of the Arctic Circle in northern Russia. In this rural and almost completely uninhabited terrain, one of the most important natural gas projects in the country was developed in the form of the US$25 billion Yamal LNG project, led by Novatek and Total. As one of the most prominent natural gas projects in the country, it required extensive planning and tasked Sarens with transporting several 630 t tank modules as part of its construction. Braving the extreme cold, brutal winds, and isolated terrain, Sarens transported and lifted 630 t tank modules during its work on the project in 2017, where Vinci Construction was tasked with assembling four 160 000 m3 tanks, under the direction of the Technip-JGC-Chiyoda consortium, which led the LNG plant’s installation. To begin its work on-site, Sarens operators used the company’s CC8800-1 crane with a boom booster to lift a 300bt heat exchanger. Once completed, Sarens’ team sought to complete one of the project’s most challenging lifts: placing a 630 t main platform on top of a tank. The platform, which measured 42 m × 25 m × 15 m, was transported from the nearby Sabetta port site to the project site, a distance of approximately 3 km, before being lifted into place at a 30 m radius. Sarens project manager Abderahim Bouazza stated, “Operationally, this was the most difficult lift of the project, as it demanded 99.7% of crane capacity. Our team had to carefully plan each step and ensure that all actions were

perfectly executed. Engineering was very important for this special lift.” Once completed, the lift was repeated various times to set the other tank modules into place, also employing an Arctic Type SPMT with 24 axles. The company’s team imported special equipment from Canada and the US via ship, and later transported it to the site after stopping at its headquarters in Belgium. For the lifts, Sarens utilised a winter kit capable of withstanding temperatures of -30˚C to deploy its CC8800-1 BSFVL 108 m crane. “We are proud to be associated with one of the most important projects in Russia,” said Marco Torri, Key Account Manager at Sarens, “Not only was this an extremely complicated job due to its isolated location, but it was also a project that required temperatureFigure 4. A Sarens crane lifting a 630 t platform on top of a tank. special equipment in order to complete the work in very cold temperatures.” Cranes such as the CC8800-1 with boom booster are further displaying the impact that this technology will essential to such projects due to their heavy lifting shortly have on the world economy. With the global LNG capacity. At the project site for Yamal, the 630 t platforms market projected to see a boom in the coming years, it is could not have been lifted into place without the equipment important to consider the logistics behind the construction supplied by heavy lifters like Sarens or the expertise of the of new plants. team which is able to operate the machinery and engineer For this reason, investing in the tools needed to the lifts to be completed swiftly and on schedule. efficiently construct such plants is of vital importance, and The future of LNG terminals countries such as the US, Canada, and Qatar are already As the cleanest fossil fuel, an investment into this ideal getting projects underway in their respective regions. Sarens alternative to polluting energy sources such as coal has the plans to take on similar projects within the sector in the ability to shift the energy mix for countries on a global scale. coming years, adding to its LNG portfolio with works in Reports have shown that natural gas is expected to Mozambique and China, supporting one of the most account for one-quarter of the world’s energy mix by 2035, promising, up-and-coming sectors of the energy industry.

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15FACTS Gas supplies from Iran to Turkey fell 33% last year after a pipeline disaster in March 2020 The Yas Marina circuit in UAE is home to the Formula 1 Abu Dhabi Grand Prix

...ON THE

MIDDLE EAST Qatar aims to lift its LNG capacity to 126 million tpy from the current 77 million tpy through two phases of the North Field Expansion project

The Tropic of Cancer passes through Oman, UAE, and Saudi Arabia

Iran remains the top consumer of natural gas in the Middle East Overall, Iran’s gas production is set to climb from approximately 250 billion m3 in 2021 to 265 billion m3 in 2030

The national animal of Qatar is the Arabian oryx

Oman is expected to become the ﬁrst Middle Eastern country whose gas production levels will overtake oil production levels

Total gas demand in the region will rise by an estimated 5% in 2021

Qatar will account for

Burj Khalifa is 828 m tall and has more than 160 stories

approximately one-quarter of the expected gas output growth in the region

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LNG Industry October 2021 Issue

Articles inside

Rise to the challenge

How much do you lift?

Motors in beast mode

One platform for data

To float or not to float

A floating lifeline for cleaner power

Leave refrigerants out in the cold

Triumphant return from the desert

It's a bunkering business

Sustaining LNG growth

Keeping an eye on the transfer of heat

LNG news

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