85 Resist risk with blast-resistant infrastructure
22 A driving force from the US
David Stokes, Managing Director, Olly Spinks, Managing Director, David Duncan, Director LNG & Gas, Timera Energy, UK, explain how US supply contracts are driving LNG portfolio innovation.
29 The pivotal role of LNG in the global energy transition
Patricia Tiller, Partner, Hunton Andrews Kurth, UAE, provides an analysis of the environmental, economic, and regulatory hurdles facing LNG, and looks at innovative solutions and strategies that can be implemented to overcome these challenges.
35 Turbomachinery in LNG production plants – Part two
In the second part of a two-part article, Klaus Brun, Enver Karakas, Stephen Ross, and Brian Hantz, Ebara Elliott Energy, USA, outline the function of pumps in the LNG value chain.
43 Setting a new standard for corrosion protection in LNG plants
Jack Blundell and Abraham Sebastian, ROCKWOOL Technical Insulation, USA, discuss a new insulation innovation that keeps LNG pipework dry and less susceptible to the costs and risks of corrosion under insulation.
50 A brighter future
Justin Bird, CEO of Sempra Infrastructure, offers an insight into the Port Arthur Energy Hub, and its role in in delivering energy for a better world.
54 Better with biomass
Hans-Peter Visser, Analytical Solutions and Products B.V., the Netherlands, explores how to measure renewable and sustainable bio-LNG and carbon dioxide, creating a net-zero environment.
61 Fuelling confidence
Adam Lomax, Joey Walker, and Jonathan Britain, EffecTech, consider the crucial role of reliable calibration gases in fiscal metering.
70 Software and innovation: Revolutionising the LNG industry
Girish Mandhania, Director, Services, Quorum Software, discovers what software and innovation will do for navigating the operational technology landscape for various LNG import and export operations.
76 Embracing
the future with digital twins
Rob Homer, Senior Product Manager (Gas & Water) at Energy Exemplar, details how digital twins can be used to co-optimise power and gas sectors.
80 A new era in emissions monitoring and energy independence
Markus Haas, Global Industry Manager for Energy & Outdoor Automation, and Anette Schultis, Head of International Project Expertise, SICK AG, look at Germany’s LNG terminals as an example of how to reduce energy dependency and improve emissions.
Bryan Bulling, RedGuard, USA, addresses the importance of comprehensive safety planning in LNG plants, reducing risk, and ensuring compliance with blast-resistant infrastructure.
89 Consolidating LNG cargoes
Gary Gibson, STS Marine Solutions Ltd, UK, highlights a new option for traders.
93 Reducing risk for ship-to-ship bunkering
Denis Griffiths, B.Eng (Hons), MSc., Ph.D, Worldwide Marine Technology, outlines factors to consider for safe ship-to-ship bunkering operations.
99 Gastech 2024 preview
LNG Industry previews a selection of companies that will be exhibiting at this year’s Gastech in Houston from 17 – 20 September 2024.
111 A new chapter for ammonia at sea
Panos Mitrou, Global Gas Segment Director, and Jose Navarro, Global Gas Technology Director, Lloyd’s Register, examine how the maritime industry is positioning itself to carry increased volumes of ammonia, and its potential as a future fuel.
115 H2S removal in challenging CO2 streams
Raul Llorens and Kevin Young, Johnson Matthey, introduce the non-regenerable fixed bed absorbent technology for the removal of hydrogen sulfide, its strengths and disadvantages in carbon dioxide purification, and the impact of oxygen presence.
121 The final frontier
Paul Trcka, Director, Sales and Operations Aerospace, and Paul Theberge, Aerospace Business Development Manager, ACME Cryogenics, part of the OPW Clean Energy Business Unit, summarise the equipment that can optimise the handling of cryogenic substances in aerospace applications.
125
To 2030, 2050, and beyond
Eliminating the methane slip is key to achieving net zero in shipping, and innovation is already paving the path, argues Steve Esau, COO, SEA-LNG.
132 Q&A with...
LNG Industry talks to Dr Tobias Eckardt, Global Expert Gas Treatment for
Sempra Infrastructure is championing workforce development in the communities where they operate through innovative programmes and partnerships with educational institutions and organisations. Mariam Hernandez, a pipe welder for Bechtel working on the Port Arthur LNG project, was recruited from a local high school welding programme in Jefferson County, Texas, and is now a pipe welder working on the Port Arthur LNG project. Learn more about Sempra Infrastructure’s commitment to workforce development at https://semprainfrastructure.com
JESSICA CASEY EDITOR
COMMENT
It’s September, which can only mean one thing for the oil and gas industry’s calendar: it’s time for another edition of Gastech.
2024 will see Gastech take place in Houston, Texas, a city with a long history in the oil and gas sector. It is therefore apt that it will welcome Gastech this year, with 50 000 attendees, 800 exhibitors, 1000 speakers, 160 conference sessions, representing 125 countries, to descend on the US state in mid-September.1
North America, and the US in particular, has emerged as a particularly heavyweight player in the LNG industry in recent years, having overtaken Qatar and Australia to become the world’s largest exporter of LNG for the very first time in the industry’s history.2
The U.S. Energy Information Administration (EIA) forecasts that US LNG exports will continue to lead growth in the US natural gas trade, with three LNG export projects currently under construction due to start operations and ramp up to full production by the beginning of 2025.3 In its Short-Term Energy Outlook,4 the EIA forecasts net exports of US natural gas to grow 6% to 13.6 billion ft3/d in 2024 compared with 2023, with net exports expected to increase another 20% to 16.4 billion ft3/d in 2025.
This growth would’ve certainly been driven by conflict in Ukraine and the Middle East, as countries considered their options for achieving energy security amidst impacted supply chains and trade routes, along with an increasing approach to improving countries’ likelihood at achieving climate goals.
This isn’t to say the US industry has been without its troubles; President Biden’s temporary pause on the approval of permits to non-FTA countries for new LNG export projects is one example of this. Nevertheless, I think the attitude towards and within the LNG industry has remained largely positive,
Sales Director RodHardy rod.hardy@palladianpublications.com
Editorial/Advertisement
with many conversations to be had about balancing supply and demand in the market, energy security, and how the industry can work towards global emissions targets.
LNG is an ever-increasing topic of discussion, and its role in the future energy mix is becoming more prominent, especially as an established alternative fuel option for use in the marine industry. With so much to discuss, the September 2024 issue of LNG Industry is another bumper issue, so make sure to visit our stand at Gastech (D386) to discuss editorial and advertising opportunities for 2025, and to collect your copy of the magazine packed with articles on cryogenic technology, safety solutions, metering and monitoring, ship-to-ship transfer, software, managing methane emissions, and much more. This issue also includes our Gastech 2024 Preview, which features a handy guide to help you navigate the event.
As the LNG industry continues to grow, change, and develop, the team here at LNG Industry will be with you every step of the way, keeping you informed and continuing to showcase and celebrate the work of key players in the industry through a range of insightful articles, news, webinars, and more.
2. SHARMA, G., ‘U.S. Overtakes Qatar To Become The World’s Top LNG Exporter’, Forbes, (5 January 2024), www.forbes.com/sites/ gauravsharma/2024/01/05/us-overtakes-qatar-to-become-theworlds-top-lng-exporter
3. ‘U.S. natural gas trade will continue to grow with the startup of new LNG export projects’, EIA, (17 April 2024), www.eia.gov/ todayinenergy/detail.php?id=61863
4. ‘Short-Term Energy Outlook’, EIA, www.eia.gov/outlooks/steo/
James Fisher Fendercare conducts first LNG ship-to-ship transfer off UK coast
James Fisher Fendercare, part of James Fisher and Sons plc, has completed the first LNG ship-to-ship (STS) transfer off the coast of Southwold, UK, for an energy major, delivering a safe and efficient solution.
James Fisher Fendercare demonstrated its LNG STS experience, applying safety and quality standards to the highly complex operation. Due to the extremely low temperatures of LNG cargo at -162˚C, safe and reliable operations are of paramount importance. With meticulous operation coordination from its specialist operations team, all pre-operational studies, compatibility assessments, detailed risk assessments and dynamic mooring analyses were conducted to support the STS transfer.
The operation was to support a gas-up/cool-down service for an LNG carrier coming out of dry dock in readiness for her next cargo. This specialised operation involves removing the inert gas from the vessel’s storage tanks by transferring LNG to slowly reduce their temperature, to -162˚C, so that the tanks are ready to safely load new cargo.
James Fisher Fendercare also worked closely with the Maritime Coastguard Agency (MCA) to gain all the necessary permissions from local authorities and the entire operation was overseen by JF Fendercare’s experienced LNG STS Superintendents.
South Korea
BNCT performs Korea's first simultaneous operations
Busan New Container Terminal (BNCT), Busan New Port Pier 5, has performed simultaneous operations of LNG bunkering and containership cargo loading/unloading for the first time in Korea at 12:30 on 8 August 2024.
The LNG bunkering vessel Blue Whale berthed alongside CMA CGM VISBY, which was berthed at Berth #1 of BNCT, and supplied about 270 t of LNG by the ship-to-ship (STS) bunkering service.
Simultaneous operations with LNG bunkering (SIMOPS) refer to the act of simultaneously performing LNG bunkering operations and port loading/unloading operations is a core competitiveness of the LNG bunkering project as it saves additional berthing time and costs in port. Despite the growing preference of global carriers for eco-friendly fuels, SIMOPS has not been actively carried out at domestic container ports due to safety concerns.
BNCT made thorough safety preparations in advance to ensure the safe execution of the project. Following a detailed safety manual, the company strictly conducted work environment investigation and emergency drills, and safety training for workers. During the actual bunkering operation, which lasted about three hours, BNCT strictly adhered to the work procedures and safety standards, resulting in the successful completion of the project without any safety incidents.
UAE ADNOC signs long-term HOA with Osaka Gas for Ruwais LNG project
ADNOC has announced the signing of a long-term heads of agreement with Osaka Gas, one of the largest utility companies in Japan, for the delivery of up to 0.8 million tpy of LNG.
The LNG will primarily be sourced from ADNOC’s lower-carbon Ruwais LNG project, which is currently under development in Al Ruwais Industrial City, Abu Dhabi, and is expected to start commercial operations in 2028.
Under the agreement, LNG cargoes will be shipped to the destination ports of Osaka Gas and its Singapore-based subsidiary, Osaka Gas Energy Supply and Trading Pte. Ltd.
The agreement with Osaka Gas is one of several long-term LNG sales commitments ADNOC has signed with international partners for Ruwais LNG, which take the long-term sales commitments to 70% of the project’s total production capacity.
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Mexico
New Fortress Energy's Fast LNG asset resumes production
New Fortress Energy Inc. has announced that the scheduled maintenance outage of its 1.4 million tpy Fast LNG 1 asset located offshore Altamira, Mexico, has been completed, and the floating LNG (FLNG) unit was returned to production as scheduled on 22 August 2024.
This planned outage followed the significant milestone of its first LNG cargo, which occurred on 9 August 2024. The company expects the FLNG 1 unit to continue its production ramp up and reach full production at the end of August.
Sweden
Gasum powers Equinor's platform supply vessel with
bio-LNG
Gasum is collaborating with Equinor on a series of bio-LNG bunkering operations in the Port of Dusavik, Stavanger. Gasum is bunkering ISCC-EU certified mass balanced bio-LNG to Equinor’s chartered platform supply vessel, Island Crusader.
The first bio-LNG delivery was successfully carried out in mid-July 2024. Gasum will continue to supply Island Crusader with 2 – 3 truckloads of bio-LNG approximately every other week. Each truckload contains about 22 t of bio-LNG.
Both Gasum and Equinor are committed to ambitious sustainability goals to enable a cleaner energy future. Equinor’s goal is to become a net-zero emissions energy company by 2050 and the bio-LNG deliveries to Island Crusader is one step on the journey towards achieving this goal.
Biogas is a fully renewable and environmentally-friendly fuel with lifecycle greenhouse gas emissions that are, on average, 90% lower when compared with fossil fuel use. Biogas can be used in all the same applications as natural gas, including as a road and maritime transport fuel and as energy for industry.
The Island Crusader also features battery hybrid technology, which further improves its environmental performance.
Achieving this goal would mean combined carbon dioxide reduction of 1.8 million tpy for Gasum’s customers.
Malaysia
Amigo LNG signs long-term agreement with Malaysia
Amigo LNG SA de CV, a subsidiary of LNG Alliance Pte Ltd, has entered into a long-term LNG supply agreement with E&H ENERGY SDN BHD of Malaysia.
Under the agreement, Amigo LNG will supply 3.6 million tpy of LNG to E&H for the Malaysian market over 20 years, beginning in 3Q27. This agreement marks a significant milestone for E&H in the evolution of Malaysia's gas market liberalisation, regulated by the Energy Commission of Malaysia. The future outlook of the Malaysian gas market is positive, driven by increasing demand for gas, particularly in the Malaysian power sector.
Amigo LNG is a large scale 7.8 million tpy liquefaction and export facility, and the only project in the region with both FTA and non-FTA permits from the U.S. Department of Energy, valid until December 2027. The project is being developed in close co-operation with the State of Sonora and is located adjacent to the Port of Guaymas in Sonora, Mexico. Amigo LNG is a cornerstone of Sonora's strategy to position itself as a hub for near-shoring, maritime decarbonisation, and connectivity to Asian markets via Pacific shipping routes.
THE LNG ROUNDUP
Osaka Gas joins SEA-LNG
Tunable raises NOK 40 million to accelerate growth
OrbitMI takes innovative tack to navigate complexities of LNG operations
LNGNEWS
17 – 20 September 2024
Gastech 2024 Texas, USA www.gastechevent.com
22 – 23 October 2024
Gas, LNG & The Future of Energy 2024
London, UK www.woodmac.com/events/ gas-lng-future-energy
04 – 07 November 2024 ADIPEC 2024
Abu Dhabi, UAE www.adipec.com/visit/registration
20 November 2024
Global Hydrogen Conference 2024 Online www.accelevents.com/e/ghc2024
09 – 12 December 2024
World LNG Summit & Awards 2024
Berlin, Germany www.worldlngsummit.com
10 – 12 March 2025
The 11th International LNG Congress (LNGCON) 2025 Amsterdam, the Netherlands https://lngcongress.com
19 – 23 May 2025
29th World Gas Conference (WGC2025)
Beijing, China www.wgc2025.com/eng/home
South Korea ANGEA enters MoU with Korea Private LNG Industry Association
The Asia Natural Gas and Energy Association (ANGEA) and the Korean Private LNG Industry Association have announced a new Memorandum of Understanding (MoU).
The MoU aims to foster cooperation between the two organisations on natural gas development in Asia and the role of LNG in the energy transition and marks the Private LNG Industry Association’s first international agreement.
The Private LNG Industry Association was formed in 2021 to secure expertise in Korea’s LNG industry and new LNG business through research activities, support for technology development, and dissemination of relevant information.
Current members include SK E&S, SK Gas, GS Energy, GS EPS, GS Power, Posco International, Boryeong LNG Terminal, and Hanyang Corp.
Through the MoU, the two organisations will focus on developing policies that enable sustainable development in the natural gas sector, sharing research and data, and working on joint projects.
The agreement is anticipated to enhance the role of LNG in the era of energy transition and to initiate more active and substantial exchanges within the gas industry across Asia.
Jordan ADC to develop LNG port in Jordan
Aqaba Aqaba Development Corp. (ADC) and the global consortium of AG&P International Holdings Pte and GAS Entec Co. have signed an agreement to implement the development of Sheikh Sabah LNG Port at a cost of US$125 million. The agreement, signed by ADC CEO, Hussein Al-Safadi, and the consortium (contractor), included the establishment of an onshore refrigeration unit in addition to development works on the existing natural gas port.
The Sheikh Sabah Natural Gas Port development project is a strategic project that represents a qualitative leap in the port system in Aqaba, developing and modernising it according to the highest international standards regulating this sector, in co-operation and direct co-ordination and joint committees formed with the Ministry of Energy and Mineral Resources, the Ministry of Planning and International Cooperation, and the National Electricity Company.
The Sheikh Sabah Natural Gas Port development project aims to maintain the option of importing LNG, used for the purposes of generating electricity and supplying industries as a strategic option in cases of interruption of any of the current supply sources, while achieving financial savings on the costs of producing electricity.
The project involves establishing onshore facilities and an onshore gasification unit to convert natural gas stored in the FSU from a liquid state into compressed natural gas with a capacity of up to 700 million ft3/d, which is pumped from the port to the Arab Gas Pipeline that connects to the power generation stations in the country (this capacity is similar to the current capacity of the port), as the project implementation period is 22 months from the date of commencement of implementation.
Al-Safadi appreciated the efforts made by the Ministry of Planning and International Cooperation and the Kuwait Fund for Arab Economic Development to finance part of the project cost of US$125 million by the Kuwait Fund for Arab Economic Development under a soft loan and to provide all the facilities required to proceed with the project.
LNGNEWS
NNPC Ltd commences LNG shipments to Japan and China
The Nigerian National Petroleum Co. Ltd (NNPC Ltd) has commenced shipment of LNG cargoes to Japan and China on delivered ex-ship (DES) basis.
NNPC Ltd achieved the milestone through the collaboration of two of its downstream subsidiaries –NNPC LNG Ltd and NNPC Shipping Ltd – which delivered its first DES LNG cargo from the 174 000 m3 LNG vessel Grazyna Gesicka at Futtsu, Japan, on 27 June 2024.
Since then, it has expanded its footprint to China with the delivery of one LNG cargo on DES basis.
DES is an international commercial term that requires the seller to deliver the products/goods at a specific port. The seller takes responsibility for the shipping and insurance for the products/goods until they get to the specified port of delivery. It requires expertise and a higher level of efficiency to execute than the free on board (FOB) system.
The collaboration between NNPC LNG Ltd and NNPC Shipping Ltd in executing the LNG supplies on DES basis has strengthened the latter’s position as a world class shipping provider in the LNG sector.
NNPC LNG Ltd, in collaboration with NNPC Shipping Ltd, is scheduled to deliver at least two more LNG cargoes to the Asian market on DES basis by November 2024. Many more orders are expected before the end of year.
Mexico
EGA ships bauxite cargo using LNG-fuelled ship
Emirates Global Aluminium, the largest ‘premium aluminium’ producer in the world, has announced the world’s first bauxite cargo shipment using an LNG-fuelled vessel.
The shipment, in a capesize ship, is carrying bauxite mined by EGA subsidiary, Guinea Alumina Corp., to a customer in China.
LNG-fuelled ships can achieve up to 28% lower greenhouse gas emissions on a tank-to-wake basis compared to vessels using traditional marine bunker fuel, according to SEA-LNG, a multi-sector industry coalition. The global shipping industry as a whole was responsible for over 2% of the word’s greenhouse gas emissions in 2022, according to the International Energy Agency.
The bauxite shipment is on-board the Ubuntu Empathy, an LNG dual-fuelled vessel operated by Anglo American and chartered by EGA. The vessel is one of Anglo American’s 10-strong chartered fleet of lower emission LNG dual-fuelled vessels.
Capesize vessels are amongst the largest bulk cargo carriers in the world, and are up to 300 m long – the length of two football fields – and 50 m wide. Capesize vessels can carry around 180 000 t of bauxite ore.
EGA predominantly uses capesize vessels to ship bauxite ore from the Republic of Guinea to the company’s alumina refinery in Abu Dhabi and to third-party customers around the world. Last year, EGA exported some 14.1 million wet t of bauxite from Guinea.
GFI LNG and Pilot LNG to develop Salina Cruz LNG
The Salina Cruz LNG JV will develop, construct, and operate an LNG bunkering and transhipment terminal in Salinas del Márquez, Salina Cruz, Oaxaca, Mexico. Strategically located on the Pacific side of the Panama Canal, the project is ideally positioned to supply North and Central American bunker and fuel markets.
GFI LNG LP, a diversified energy solutions company, and Pilot LNG LLC, a Houston-based clean energy infrastructure developer, have formed a partnership to develop, construct, and operate a small scale LNG terminal in Salina Cruz, Mexico.
At full build-out, the facility is anticipated to produce 600 000 gal./d of LNG, or roughly 0.34 million tpy. The partners anticipate operations to commence in mid-to-late 2027. With speed-to-market in mind, the project is being designed to include modular, land-based liquefaction equipment and an
optimised storage solution. The project will deploy an FSU with an estimated capacity ranging from 50 000 – 140 000 m3 to be moored inside the newly expanded breakwater in the Port of Salina Cruz.
Salina Cruz will use domestic Mexican gas supply from the Veracruz gulf region to access new high-value markets along the Pacific Coast, including LNG marine fuel deliveries at the Pacific entry of the Panama Canal and into Southern California, sales into Central American power markets, and trucked volumes into the local region of southwestern Mexico.
GFI and Pilot plan to commence FEED development for the project shortly. The partners expect a 12 – 18-month development and permitting timeline and anticipate announcing a final investment decision in 2H25.
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LNGNEWS
South Korea
Capital Gas Ship Management takes delivery of three newbuilding carriers
Capital Gas Ship Management Corp. has taken delivery of the newbuilding LNG carriers Assos, Apostolos, and Aktoras from Hyundai Heavy Industries, South Korea.
The sister vessels with a cargo capacity of 174 000 m3 are highly efficient, propelled with MAN MEGA engines, and equipped with the latest technologies, including an air lubrication system, shaft generators, and increased filling limits (above 99%). The vessels represent the vanguard of the new generation of LNG carriers, setting an industry benchmark with their exceptionally low environmental impact. They achieve this by employing cutting-edge technologies designed to minimise methane slip and substantially reduce carbon dioxide emissions, making them the most eco-efficient additions to the global fleet. They are three of 18 LNG vessels delivered to Capital Gas between 2020 – 2027.
Delivery festivities were well attended by high-ranking officials from Capital Gas, HHI, and other organisations and companies.
Germany
Deutsche Energy Terminal achieves 100th LNG delivery
Deutsche Energy Terminal (DET) has reached a significant milestone: the 100th LNG delivery. On 7 August 2024, another 165 000 m3 of LNG for the German market was delivered to Wilhelmshaven (WHV01), strengthening Energy Security for Germany and its European neighbours.
Since the beginning of DET’s operations last year, the company’s journey has been marked by close co-operation and strong teamwork with its business partners and suppliers on its sites at WHV01: Brunsbüttel Gasfin Development S.A, Reganosa Deutschland, Höegh, LTeW GmbH, Brunsbüttel Ports GmbH, KN Energies, and Niedersachsen Ports GmbH & Co. KG., who all have contributed with their expertise to this accomplishment. Out of the 100 deliveries now reached, 71 arrived at Wilhelmshaven and 29 at Brunsbüttel.
USA
NextDecade executes EPC contract with Bechtel for Train 4 at the Rio Grande LNG facility
NextDecade Corp. has announced that its subsidiary, Rio Grande LNG Train 4, LLC, has executed a lump sum turnkey EPC contract with Bechtel Energy Inc. for the construction of Train 4 and related infrastructure at the Rio Grande LNG facility.
Rio Grande LNG Train 4 agreed to pay Bechtel approximately US$4.3 billion for the work under the EPC contract for Train 4. Price validity under the contract extends through 31 December 2024. NextDecade currently projects that owner’s costs, contingencies, financing fees and interest during construction will total approximately US$1.7 – US$1.9 billion, based on current estimates and expected interest rates. Total estimated project costs are expected to be US$6 – US$6.2 billion for Train 4 and related infrastructure, in line with the per train cost of the three-train Phase 1 at the Rio Grande LNG facility, which is currently under construction.
NextDecade continues to target a positive final investment decision of Train 4 in the 2H24, subject to gaining appropriate commercial support and obtaining adequate financing to construct Train 4 and related infrastructure.
THE LNG ROUNDUP
X NextDecade withdraws CCS proposal X Cheniere and Galp sign long-term LNG SPA X WinGD and CMA CGM collaborate on trial of first VCR technology deployment at sea
LNGNEWS
Germany
Bernhard
Schulte Shipmanagement joins SEA-LNG
Bernhard Schulte Shipmanagement (BSM), an integrated maritime solutions provider, has joined the SEA-LNG coalition. BSM’s decision to join SEA-LNG reflects the decision of many others joining this year who recognise LNG as a practical and realistic lower-emission marine fuel.
BSM brings abundant operational experience and has a proven track record as the world’s largest third-party ship manager of gas carriers. It has more than 100 gas carriers under management, over half of which are LNG carriers. It also manages close to 30 LNG dual-fuel ships and presently two LNG bunker vessels, with more coming into management soon.
All BSM vessels under management undergo reviews and audits from Oil Companies International Marine Forum’s (OCIMF) Tanker Management and Self-Assessment (TMSA) to ensure full compliance with International Safety Management (ISM) requirements, with no major safety incidents reported to date.
Kuwait
QatarEnergy and KPC sign 15-year SPA
QatarEnergy entered into a 15-year LNG sale and purchase agreement (SPA) with Kuwait Petroleum Corp. (KPC) for the supply of up to 3 million tpy of LNG to the State of Kuwait.
Pursuant the terms of the SPA, the contracted LNG volumes will be delivered ex-ship to Kuwait's Al-Zour LNG Terminal onboard QatarEnergy’s conventional, Q-Flex, and Q-Max LNG vessels, starting in January 2025.
The agreement was signed during a special ceremony held in Kuwait City by Saad Sherida Al-Kaabi, the Minister of State for Energy Affairs, the President and CEO of QatarEnergy, and Shaikh Nawaf Saud Al-Nasir Al-Sabah, Deputy Chairman and CEO of KPC. The signing was witnessed by senior executives from KPC and QatarEnergy.
This new agreement is the second long term LNG SPA with KPC, and is considered pivotal in further boosting bilateral trade between the State of Qatar and the State of Kuwait.
China
PIL orders five new dual-fuel container vessels
Pacific International Lines (PIL) has ordered five new container vessels with 13 000 TEU capacity, equipped with LNG dual-fuel engines. The neo panamax-sized vessels are expected to be delivered progressively from end-2026. Construction of the vessels has been awarded to Hudong Zhonghua Shipyard, a leading Chinese shipbuilder.
Designed with a focus on efficiency, safety, and sustainability, the modern vessels will also have the flexibility to meet the demands of different voyages, weather conditions, and load capacities. They will be equipped with dual-fuel engines and auxiliaries to be able to run on both LNG and low sulfur fuel oil.
The vessels will incorporate the latest technological and energy-saving features including an optimised hull-form, variable-frequency drive (VFD) motors for larger pumps and ventilation blowers, lower-energy LED lightings, as well as premium hull coatings. When completed, the vessels will be fully compliant with the International Maritime Organization’s (IMO) Energy Efficiency Design Index (EEDI) for newbuilds and the Carbon Intensity Indicator (CII).
In addition, increased digitalisation such as artificial intelligence (AI) and Internet of Things (IoT) has been incorporated in the design and equipment for the automation of tasks. All of these improvements will contribute to more efficient operations, provide a safe and modern working environment, as well as enhance the welfare of seafarers. The vessels’ digital features will further boost the ability of PIL’s Centre for Maritime Efficiency to optimise vessel operations and routes, increase safety and security, as well as minimise energy usage.
PIL is currently building four 14 000 TEU and four 8200 TEU LNG dual-fuel container vessels. The first two of the 14 000 TEU vessels are expected to be delivered later in 2024. PIL’s order of modern innovative vessels demonstrate its approach of leveraging its expertise and technology to provide efficient and sustainable solutions.
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LNGNEWS
Canada
CIMC SOE delivers first LNG bunkering ship to Seaspan
Nantong CIMC Sinopacific Offshore & Engineering Co., Ltd (CIMC SOE) has delivered the first 7600 m3 LNG bunker barge (S1061), named SEASPAN GARIBALDI, to Seaspan Energy.
It is reported that this series of 7600 m3 LNG bunker barges consists of three vessels, with the remaining sister ships scheduled for delivery before the end of 2024. The vessel measures 112.8 m in length, 18.6 m in breadth, and has a design draft of 5.1 m. It has a capacity of 7600 m3 and is designed to travel at a speed of 13 knots. The vessel is classed by Bureau Veritas and flies the flag of Panama, meeting the requirements of the Canadian flag state. The vessel features an advanced DC power distribution system and is equipped with three dual-fuel generators for power supply. Two 1600 kW azimuth thrusters provide propulsion, and there is provision for battery installation. This design ensures flexibility to meet various operational scenarios while providing comprehensive LNG loading and bunkering services. It offers both high economic benefits and environmental sustainability, supporting the shipowner in achieving IMO 2030 emission reduction targets.
The S1061 vessel commenced construction in early February 2023 and was launched at the end of December. It is set to sail to the northwest Pacific region, becoming Seaspan Energy’s first LNG bunker barge in North America. The successful delivery of the S1061 marks the entry of CIMC SOE's mid-size liquefied gas vessels into the North American market.
Mozambique
UK
VTTI completes acquisition of 50% of Dragon LNG
VTTI, an industry leader in energy infrastructure, has completed the acquisition of 50% of Dragon LNG Group Ltd. The other 50% of the terminal is owned by Shell. This follows the announcement of the intention to acquire the stake in the terminal from leading infrastructure manager Ancala, communicated on 8 May 2024.
As part of VTTI’s Strategy 2028, VTTI is building on its foundation as an energy storage and service terminal operator at key ports around the world, while investing in and developing additional energy infrastructure needed for the energy transition, including LNG regasification terminals, renewable natural gas (RNG) and waste-to-value production facilities, biofuel storage, and ammonia and hydrogen infrastructure.
Dragon LNG’s regasification terminal is located near Milford Haven in Wales, and consists of LNG receiving, storage, reliquefication, regasification, and send-out facilities. The facility can achieve maximum gas send out to the UK national transmission system of up to 9 billion m3, supplying approximately 10% of the UK’s annual gas demand.
Dragon Energy Ltd, a fully owned subsidiary of Dragon LNG Group Ltd, has also developed a solar farm at the facility and is developing additional renewable power projects at the site in support of decarbonising Scope 2 emissions at the LNG terminal. They have also recently announced the Milford Haven CO2 project, which will be done in collaboration with RWE Pembroke Net Zero Centre, exploring carbon capture, pipeline transfer, liquefaction, temporary storage, and ship loading to enable CO2 shipping from a new Dragon jetty via non-pipeline transport to sequestration sites around the UK.
Coral Sul FLNG achieves 5 million t of LNG production from offshore Mozambique
Eni, as the delegated operator of Area 4, on behalf of its Area 4 partners namely ExxonMobil, CNPC, GALP, KOGAS, and ENH, has achieved 5 million t of LNG produced from the Coral Sul floating LNG (FLNG), located in the ultra-deep waters of the Rovuma Basin, offshore Mozambique. This is a significant milestone for the project, and it represents not only a major technical and operational accomplishment, but also stands as a testament to the dedication, commitment, and collaboration of all the team and stakeholders.
The Coral Sul FLNG started production in October 2022 and has exported so far 70 cargoes of LNG and 10 of condensate, contributing significantly to the country´s economic growth.
Coral South is a landmark project for the industry, and it placed Mozambique among the global LNG producing countries, laying the foundation to a transformational change of Mozambique through development of gas resources, while also supporting a just and sustainable energy transition.
LNGNEWS
Mexico
Gato applies for DOE FTA approval for Mexico LNG plant
The Office of Fossil Energy and Carbon Management gives notice of receipt of an application filed on 10 May 2024 by Gato Negro Permitium Uno, S. de R.L. de C.V.
The application requests long-term authorisation to export domestically produced natural gas via pipeline to Mexico in a volume up to approximately 236 billion ft3/y (0.647 billion ft3/d), and to re-export approximately 203 billion ft3/y (0.556 billion ft3/d) of this natural gas as LNG to free trade agreement (FTA) countries.
Gato seeks to re-export this LNG by vessel from its proposed liquefaction and export terminal project, the Gato Negro Manzanillo LNG plant, to be located in the State of Colima, Manzanillo, Mexico.
The authorisation is requested for a term extending through 31 December 2050. Gato requests this authorisation on its own behalf and as agent for other parties who hold title to the LNG at the time of export.
No Federal Register Notice will be issued.
Middle East
WinGD takes 100th VCR technology order for dual-fuel X-DF engines
WinGD has received its 100th order for variable compression ratio (VCR) technology, which further optimises combustion for X-DF dual-fuel engines depending on the fuel used and engine load. The solution was launched in June 2023 and has become a favoured option for dual-fuel engine orders, especially in the LNG carrier segment.
The order came via a series of four LNG carriers to be built for a Middle Eastern shipowner at a Korean shipyard. Overall, nearly 10 owners have selected the new technology as an option with their X-DF engines.
VCR technology enables the engine’s compression ratio to be dynamically adjusted for the fuel type being used, engine load and combustion behaviour. This means higher compression ratios can be used when running on diesel, improving efficiency, while compression can also be tweaked during LNG use to optimise efficiency and reduce emissions. The simple hydraulic solution represents the first application of dynamic compression ratio adjustment in a marine engine.
China
Silverstream receives orders for 18 new LNG carriers
Silverstream Technologies has surpassed 200 orders for its air lubrication system with its latest confirmed deal. The Silverstream® System will be installed onboard 18 new 271 000 m3 ‘QC-Max’ class LNG carriers, which will be chartered by a global energy company and owned and operated by shipping majors.
Silverstream’s current orderbook includes 57 LNG carriers, spans nine vessel segments, and includes 20 repeat customers, including seven major ship owners and 13 of the world's largest shipyards. The company also has 82 systems in operation onboard the existing fleet.
These are the first 271 000 m3 LNG carriers to be wholly designed, built, maintained, and serviced in China.
The Silverstream System shears air from air release units (ARUs) in the hull to create a uniform carpet of microbubbles that coats the full flat bottom of a vessel. As a result, frictional resistance is decreased, cutting average net fuel consumption and GHG emissions by 5 – 10%. The system is fuel agnostic, effective in all sea states, and is applicable to all shipping segments. As the shipping industry’s decarbonisation transition progresses, evolving regulatory and market drivers are strengthening the rationale for adopting vessel fuel efficiency solutions. LNG carriers could fall into non-compliant categories (D and E) of the IMO’s Carbon Intensity Indicator (CII) framework, largely because of the way in which they handle boil-off gas. Meanwhile, the EU’s Emissions Trading System (ETS) is adding a progressive cost to emissions, increasing in scope from 40% of emissions in 2024 to 70% in 2025 and 100% in 2026. This means that technologies, such as the Silverstream System, not only lower fuel consumption and emissions, but also help to cut the costs of regulatory compliance.
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MIDSTREAM NEWS
USA
Brazos Midstream completes new gas processing facility
Brazos Midstream has announced the completion of a new gas processing facility and further expansion plans, as reported by GlobalData.
The Sundance I facility in Martin County, Texas, with a capacity of 200 million ft3/d, is set to commence operations in October 2024.
Brazos is also nearing the end of constructing roughly 280 km of high-pressure natural gas gathering pipelines ranging from 16 – 24 in. in diameter. These pipelines, along with additional midstream assets, span Ector, Glasscock, Howard, Martin, Midland, and Reagan counties in the Midland Basin. Once this phase is finished, Brazos will manage around 418 km of natural gas-gathering pipelines and 10 compressor stations in the region.
To support anticipated production growth, Brazos has also revealed plans to build another cryogenic gas processing facility with a 300 million ft3/d capacity, projected to be operational in 2H25.
USA
Blackcomb pipeline reaches final investment decision
WhiteWater, MPLX LP, and Enbridge Inc. through the WPC Joint Venture, the joint venture that owns the Whistler Pipeline, have partnered with an affiliate of Targa Resources Corp. to reach final investment decision to move forward with the construction of the Blackcomb Pipeline after having secured sufficient firm transportation agreements with predominantly investment grade shippers, including Devon Energy, Corp., Diamondback Energy, Inc., Marathon Petroleum Corp., and Targa Resources Corp. I Squared.
The Blackcomb Pipeline is designed to transport up to 2.5 billion ft3/d of natural gas through approximately 365 miles of 42 in. pipeline from the Permian Basin in West Texas to the Agua Dulce area in South Texas.
Supply for the Blackcomb Pipeline will be sourced from multiple upstream connections in the Permian Basin, including gas processing facilities in the Midland Basin and the Agua Blanca Pipeline in the Delaware Basin, a joint venture between WhiteWater and MPLX.
Mexico
Pemex gets approval for expansion of natural gas project
Mexico's hydrocarbon regulator has approved a request by Pemex to expand a natural gas project in the Gulf of Mexico, which requires extra investments of just over US$400 million, according to Reuters.
The Lakach field has been hailed as a potential gateway to a new deepwater Mexican gas frontier.
Pemex had requested to update the field's production strategy with the recovery and termination of wells, the management of production, and the commercialisation of hydrocarbons.
Of the US$2.218 billion in costs that were approved for the years of 2024 and 2041 by the regulator CNH, US$1.667 billion are earmarked for investments and US$551 million for operational expenses.
An earlier plan, authorised last year for 2024 – 2035, listed an estimated US$1.815 billion. Its production deadline was also pushed back from 2025 to 2026.
The project now contemplates the construction of gas pipelines up to the ground – instead of using boats to collect the gas and transport it, as previously planned.
THE MIDSTREAM ROUNDUP
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David Stokes, Managing Director, Olly Spinks, Managing Director, David Duncan, Director LNG & Gas, Timera Energy, UK, explain how US supply contracts are driving LNG portfolio innovation.
he global gas market is approaching a major market regime shift. A new wave of LNG liquefaction capacity is set to ramp up from late 2025, with around 200 million tpy to come online by 2030.
Expansion of US LNG export capacity is a key component of this new wave of supply. The flexible hub indexed nature of
US supply contracts is set to increasingly influence the evolution of LNG market pricing dynamics.
This article explores the growing influence of US Henry Hub price signals and how this has much broader commercial implications for evolution of LNG portfolio value and risk.
Anatomy of the new supply wave
The new LNG supply wave is dominated by two main regions. The largest volumes come from North America, predominantly from the US, but is supported by Canada and Mexico. The pricing of this supply is strongly influenced by the US benchmark Henry Hub price. The second key source comes from Qatar’s expansion of its giant North Field.
The US and Qatar are set to account for 62% of new global LNG supply (2025 – 2029). Timera Energy’s global gas model shows the global share of North American supply rising from 22% in 2023 to 34% by 2030 (volume growth of 116 million tpy), as summarised in Figure 1.
US volumes from this new wave are particularly important because of the structure of supply contracts. Contracts are typically structured with a US hub indexed contract price (Henry Hub being the most common). Standard contract cost structure consists of:
z Feed gas cost (e.g. 100% of Henry Hub price).
z Very large volume (100+ million tpy) of US LNG exports can be cancelled as price levels fall.
z US cancellation range represents elastic and strong price support, providing a ‘soft’ global price floor.
z Large volume of EU coal plants (approximately 20 million tpy) can be switched for gas, creating incremental demand (and vice versa).
z Price responsive switching band has historically played a strong role anchoring TTG and global LNG prices.
z Large volumes (approximately 50+ million tpy) of fuel switching and industrial price response, impacting Asian LNG import volumes as prices move.
z Asian flex sources typically less elastic/price responsive and often have lagged effects to price changes.
z Variable cost (e.g. 15% on top of feed gas price to cover variable costs of liquefaction).
z Fixed tolling fee (e.g. US$2 – 3/million Btu to cover fixed costs of the liquefaction terminal).
Cargoes are contracted on an FOB basis providing valuable destination flexibility for the buyer. This flexibility is enhanced by a liquid US domestic market, where feed gas can be resold in case of oversupply (i.e. if cargoes are cancelled due to low netback prices). The structure of US supply contracts has important implications for the evolution of LNG market pricing.
Three key sources of flexibility to dominate global price setting
US LNG supply is one of three key sources of marginal flexibility that act to clear the global gas market and drive pricing dynamics. These three sources are summarised in Table 1 and show the ranges across which they act to influence marginal price setting in Figure 2.
US export flexibility is the most important influence on global gas prices in a well-supplied LNG market. As prices fall, there is a very large volume (100+ million tpy) of US LNG export cargoes that can be cancelled if netback prices decline below the Short Run Marginal Cost (SRMC) of US export contracts. This US cancellation range represents elastic and strong price support, currently in a US$5 – US$7/million Btu range at current Henry Hub forward prices (and variable liquefaction and shipping costs).
European power switching is important across a US$10 – US$15/million Btu gas price range (at current forward coal and carbon prices). This is why TTF and JKM forward prices are currently highly correlated with European coal and carbon prices.
Asian demand flexibility is increasingly important as a marginal driver across all price ranges, given large volumes of demand growth focused on relatively price sensitive shorter-term cargo purchasing.
It is important to note that the US SRMC cargo cancellation price range move dynamically with Henry Hub forward prices. If US domestic gas prices rise, for example due to declining shale play quality and rising cost of capital, the US SRMC range in Figure 2 will move higher and interact more closely with European and Asian switching response.
The scale of the new supply wave is set to drive a major regime shift into a well-supplied market from 2026, supporting a rapid rise in the influence of Henry Hub price signals.
Increase in Henry Hub penetration driving changes in LNG portfolio management
Growth in US hub linked supply flexibility is set to result in a strong increase in the importance of Henry Hub exposures in LNG portfolios, via two mechanisms:
1. Directly, as US supply contract volumes grow.
2. Indirectly via the influence of Henry Hub on LNG market prices, particularly in a well-supplied market.
Figure 1. Projected global LNG supply change y/y. Source: Timera Global Gas Model, LNG Unlimited.
Table 1. Three key sources of marginal flexibility Flex source
1. US export flex
2. European power switching flex
3. Asian LNG demand flex
The hub indexation and inherent flexibility of US LNG supply contracts are driving an increased focus on LNG portfolio optimisation and exposure management strategies. US contract flex can unlock portfolio value (e.g. via diversion flex optimisation), as well as helping to manage risk (e.g. downside price risk management via cargo cancellation flex).
However, US contracts require innovation in commercial management strategies compared to other supply sources. These include:
z Innovation in contracting strategies to manage exposure to US hub indexation of supply (e.g. TTF/JKM
netback indexation, integrating US upstream exposure and indexed DES sales).
z Accessing liquid European hubs to manage price exposure and support monetisation of diversion flexibility.
z Forward hedging of liquid hub exposures (e.g. HH, TTF, JKM) and management of residual basis risks.
This is driving significant evolution of LNG trading and origination activity. Table 2 offers an overview of three key approaches that LNG companies are using to manage US supply contract exposures.
US contract flexibility drives value management challenges
Gas hub indexation and flexibility drive buyer enthusiasm for US LNG contracts. But these benefits come with material risk exposures. When signing up to US LNG it is important to understand how contract value is driven by price, volume dynamics and destination flexibility under changing market conditions, as well as the different commercial approaches for managing this value.
The two most important types of embedded flexibility options within LNG supply contracts are:
z Diversion flex (e.g. to send cargoes to Europe vs Asia).
z Cancellation flex (if netback prices fall below variable cost).
A. Hedging
B. European market access
z Financial hedging of underlying contract exposures, e.g. using TTF/JKM futures or swaps.
z Acquire regasification capacity to allow physical sale into hubs and mitigate DES NWE LNG vs TTF basic risk.
z Market liquidity and collateral constraints.
z In-house trading and risk management capability.
z Basis risk (physical vs financial exposure).
z Level of fixed and variable regasification costs key.
z ADP management key to align slots with US offtake.
z Value dependency on spot market liquidity.
z Origination capability to source effective sales contracts.
The relative value of these strongly depends on underlying market conditions (e.g. inter-regional price spreads, correlations, and volatility) and the timing of contract negotiation.
Conclusion
US supply contract value is currently driven by high intrinsic margins, given the substantial premium of JKM and TTF prices over Henry Hub. However, as the LNG market rebalances with new supply from 2025, the relative importance of extrinsic (or flexibility) value of contract options is set to increase substantially.
C. Sales contracting
z Offset US toll exposure with sales contract(s), e.g. Henry Hub indexed Asian sale to offset toll cost exposure.
z ADP management requirement to align with US offtake.
z Trading capability requirement to act on backfill optimisation opportunities.
This is supporting a growing focus of LNG commercial and trading teams on negotiating, valuing, and optimising US contract flexibility options (including secondary trading of contracted US supply). It is also driving strong innovation in the valuation and optimisation of integrated LNG portfolio exposures, supported by evolution in the capabilities of LNG trading, origination, and risk management teams.
Figure 2. Price range influence of three drivers. Source: Timera Global Gas Model, prices real US$ 2024.
Table 2. Three key approaches for managing US supply contract exposures
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Energy security is national security.
Patricia
Hunton
Tiller, Partner,
Andrews Kurth, UAE, provides an analysis of the environmental, economic, and regulatory hurdles facing LNG, and looks at innovative solutions and strategies that can be implemented to overcome these challenges.
The pivotal role of LNG in the global energy transition
In the ongoing search for sources of energy that offer sustainable alternatives to fossil fuels, LNG has emerged as a pivotal player in the global energy transition.
LNG, colloquially called the ‘transition fuel’ in the transition to net-zero carbon emissions, has a comparatively limited impact on the environment when measured against other fossil fuels such as
coal and crude oil. The overall environmental impact of LNG is well-known, measurable, and controllable, reinforcing its role as an energy source that can reduce the carbon intensity of the world’s energy mix. However, LNG faces several regulatory challenges if it is to be used as the preferred low emissions-intensive fuel until renewable energy technologies evolve to provide for a full energy transition.
The environmental impact of LNG
If LNG’s place as a major source of energy is to be maintained, the environmental challenges associated with LNG production and consumption must be addressed. Each step in the LNG production process – from extraction to liquefaction, transportation, and regasification – consumes limited energy resources, and results in emissions of methane, carbon dioxide (CO 2 ), sulfur dioxide, and nitrogen oxides. While the CO 2 emissions in the LNG value chain are relatively small compared to other fossil fuels, reducing methane emissions has been a recent (and somewhat controversial) focus for the industry. Uncombusted methane has the potential to trap heat in the atmosphere, with studies reporting a greater global warming effect than CO 2 . The extent of methane emissions during the whole lifecycle of an LNG project remain subject to debate. Reductions in flaring and venting vary greatly across jurisdictions, with several natural gas hubs failing to place any limits on flaring activities.
Industry players and environmental activists are aligned in their desire to reduce these emissions and there is a push for technologies to lessen the environmental impact across the LNG value chain. New technologies such as leak detection and repair (LDAR) programmes, as well as innovations in measurement technologies, are being implemented across the LNG value chain in most jurisdictions.
Regulatory hurdles for LNG
There are two key regulatory hurdles impacting the extent to which LNG will maintain a dominant position in the energy transition:
1. Inconsist ent or overly burdensome regulation of greenhouse gas (GHG) emissions throughout the LNG value chain.
2. Re gulations incentivising investment in renewable energy, at the expense of investment in LNG projects.
Firstly, industry players, environmental action groups, and consumers diverge in the extent to which external regulation should govern changes in the emissions intensity of the LNG industry. LNG buyers in many jurisdictions are reluctant to pay a premium for lower-emission LNG, and sellers have consequently been slow to invest in costly LDAR technology or production overhauls to reduce carbon intensity. Forcing an economic model that only permits the sale of lower-emission LNG may hinder energy security and increase energy poverty across much of the world, in both developed and developing nations.
Regulating GHG emissions
One example of emissions regulations increasing energy prices is the extension of the EU’s Emissions Trading Scheme (EU ETS) to shipping. Since 1 January 2024, the EU ETS has applied to all ships over 5000 gross tonnage in size entering an EU port. The extension of the EU ETS to the maritime sector means that LNG cargoes into Europe are now subject to a carbon tax, requiring shipping companies to bear the cost of purchasing EU carbon certificates or surrender EU allowances for each tonne of reported GHG emissions, consequently increasing shipping costs (a cost that will be passed onto buyers). The scheme covers 50% of CO 2 emissions from voyages starting or ending outside of the EU, and 100% of the CO 2 emissions between two EU ports. From 2026, the EU ETS will also apply to methane and nitrous oxide emissions. The flow-on effect of the change in the EU ETS is an increase in the cost of European gas prices. Whether the cost differential will be enough to impact the coal-to-gas switching price is yet to be seen, but an unintended consequence of the EU ETS extension to shipping may be a slow down in fuel switching by key power producers.
A second example of external regulation placing pressure on LNG’s role in the energy transition is the Global Methane Pledge, launched in 2021 at COP26. While the goal of the Global Methane Pledge
Figure 1. Increased carbon-reduction costs for LNG carriers entering EU ports.
Figure 2. Planned hybrid LNG-rewewable energy projects.
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is commendable – reducing methane emissions by 30% no later than 2030 – the worldwide rollout of methane abatement action plans and regulations has been sporadic and inconsistent. Measurement and reporting standards for methane emissions have not been harmonised across the industry, and targets set for the petroleum industry vary significantly across jurisdictions.
In the US, new limits to methane emissions were approved by the Department of Interior in March 2024. The new rules, which come into force from June 2025, significantly increase loss control obligations for natural gas producers and increase the compensation payable by producers for failing to control losses at required levels. Similar regulations are in force in the EU under the EU Regulation on Methane Emissions Reduction in the Energy Sector, adopted in May 2024, but the EU requirements will be difficult to satisfy for LNG volumes originating in the US. In particular, LNG exports from the US are often sold on a tolling basis, meaning that the LNG seller does not control the entire LNG value chain commencing from the extraction and production of natural gas. The EU Regulation stipulates maximum methane intensity values originating from the ‘level of the producer’, but a US LNG exporter often has only limited information on the methane intensity of the gas during the upstream phase.
Nigeria implemented major changes in 2023 with the introduction of Methane Emissions Reduction Guidelines, overseen for the petroleum sector by the Nigeria Upstream Regulatory Petroleum Commission. However, countries such as China are yet to apply mandatory methane intensity requirements to natural gas production, and China is yet to introduce standards for emissions intensity of imported LNG. India, whose energy sector accounts for a significant portion of its annual GHG emissions, has opted not to sign the Global Methane Pledge, arguing that the primary contributor to climate change is CO 2 rather than methane emissions. Mitigating methane emissions is a vital aspect of meeting global climate targets, but the lack of co-ordinated emissions regulations and abatement targets are hindering the LNG industry’s ability to implement consistent and effective strategies.
Many industry players would prefer to self-regulate their GHG emissions, rather than navigate the distinct mix of regulations across multiple jurisdictions. A growing list of companies have signed the Oil and Gas Decarbonization Charter, launched at COP28, with targets for reduction of methane emissions by 2030. It may be that stakeholder pressure to comply with the targets of the Charter are sufficient to encourage investment in emissions detection or emissions reduction technology.
Disincentivising continued investment in LNG projects
The other key challenge to LNG’s continued role in the energy transition lies with regulations intended to encourage investment in renewable energy, but that fails to recognise the continued importance of natural gas in the energy transition. This is the second key regulatory hurdle impacting the extent to which LNG will remain a dominant fuel in the energy transition.
In Australia, for example, the Capacity Investment Scheme for renewable energy projects, under which the Australian government will underwrite 32 GW of renewable energy and storage capacity to be installed by 2030, excludes natural gas. The exclusion is understandable because natural gas is not a renewable energy source, but industry players worry that the exclusion of natural gas will hinder the transition to a renewable dominated power grid given that recently-commissioned renewable energy projects have failed to reach full output and power producers are consequently unwilling to switch from burning harmful fossil fuels such as coal. Also in Australia, Environmental Protection Authority guidelines implemented in 2023 that require new-build LNG plants to be carbon-neutral from start-up will increase the costs of an already high capital cost project, reducing the likelihood of reaching final investment decision on these mega projects.
Similar disincentives to investing in LNG projects exist in the US, with the tax credits available under the Inflation Reduction Act likely to exclude blue hydrogen (produced with natural gas and carbon capture), potentially taking investment away from the natural gas industry at a time when affordable energy with a hydrogen-dominated supply is not yet viable. The flow-on effect to LNG exports is yet to be seen.
Hybrid LNG projects
Perhaps the future role for LNG lies in hybrid projects designed to produce lower-emissions LNG, allowing LNG to remain in the energy mix but with less (virtually zero) environmental impact. One recent approach is using a renewable energy source to produce lower-emissions LNG, rather than the traditional approach of using the natural gas feedstock to power the plant’s operational needs. A notable example is the Marsa LNG plant in Oman, a joint venture between TotalEnergies and OQ that reached final investment decision in April 2024. The planned Marsa LNG plant will be 100% powered by solar energy during the day, drawing from the national grid at night, making it one of the lowest GHG emissions intensity LNG plants ever to be commissioned. Coupled with a zero-flaring approach, the GHG intensity is predicted to be below 3 kg CO 2 e/boe (in comparison to the 35 kg CO 2 e/boe usually produced during liquefaction). By using a renewable energy source for powering LNG production trains, the overall emissions intensity of the LNG plant can be reduced, with early predictions of up to 90% reduction of the emissions produced during the liquefaction process of cooling raw natural gas.
Outlook
Solutions to reduce carbon emissions to net zero, while providing reliable energy supplies (at the right price) do not yet exist. LNG will provide fast firming capacity as more coal-fired and oil-fired power plants are phased out, but an overall reduction in GHG emissions throughout the LNG value chain is required. Whether the reduction in GHG emissions is industry led or led by a harmonised (or disharmonised) effort from governments around the world remains the challenge.
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In the second part of a two-part article, Klaus Brun, Enver Karakas, Stephen Ross, and Brian Hantz, Ebara Elliott Energy, USA, outline the function of pumps in the LNG value chain.
n the global race for cleaner energy, demand for natural gas is climbing. Delivering natural gas to end users is dependent upon producing, processing, and converting it to LNG for transport, storage, and regasification. Based on a short course given at the 2023 Turbomachinery Symposium, this article is part two of a review of the turbomachinery at the heart of the LNG value chain. Part one, ‘Turbomachinery in LNG Production Plants’, covers compressors in the LNG value chain, and was published in the February 2024 issue of LNG Industry. Part two focuses on LNG pumping applications and equipment.
Pumps for LNG applications
Natural gas is liquefied for transportation and storage. The liquefaction process, along with transportation, storage, and refinery processes, requires pumps at various locations. Due to the very cold operating temperatures of LNG pumping applications, around -265˚F (-165˚C), these pumps are classified as cryogenic pumps, requiring design features specific to the pumped fluid and operating conditions.
LNG pumping applications
Pumps for LNG applications pressurise and transport liquefied gas. The most common applications are located at import and export terminals. Figure 1 is a typical import (receiving) and regasification terminal, showing the location and types of LNG pumps within the process.
LNG is usually transported by LNG tankers to receiving terminals where it is unloaded via the ship’s cargo and spray pumps. Cargo pumps are usually operated in parallel to meet the required flow rate, assisted by smaller-size spray pumps to empty the cargo efficiently. A single cargo pump can handle flow rates around 2000 m3/h (8800 gpm). The maximum discharge pressure is kept below the pipeline rating, which is around 18.9 barg (275 psig), with rated differential pressures ranging between 5 – 8 barg (72.5 – 116 psig).
LNG is pumped to LNG storage tanks which are designed to handle very little pressure (less than 300 mbarg [4.35 psig]) due to their large size and construction. LNG is pumped out of the storage tank for regasification via retractable in-tank pumps located at the bottom of the tank. The retraction system enables operators to safely remove and install the cryogenic in-tank pumps into the discharge column of the storage tank. In-tank pumps are often low-pressure pumps with rated discharge pressures at around 7 barg (102 psig), with flow rates ranging from 400 – 2000 m3/h (1760 – 8800 gpm).
Cargo and in-tank pumps transfer LNG from the ship’s tank or the storage tank to the next point in the process without high discharge pressure. Discharge pressures from in-tank pumps are boosted to the required pressures of 100 barg (1450 psig) using vessel mounted (canned) send-out pumps. Due to rotordynamics and structural concerns, high-pressure send-out pumps have less flow output. To satisfy the required process flow rate, multiple high-pressure pumps are operated in parallel to each other.
LNG bunkering and peak shaving plants also require pumps to supply LNG to tankers and transport LNG for smaller scale applications. These pumps are much smaller in terms of flow rate, and are not required to be operated at all times.
Cryogenic LNG pumping technologies
In addition to performance requirements, the following must be considered in the selection of cryogenic pumps:
z Hydraulic components: Selection of hydraulic pump components is based on specific performance requirements.
z Shaft support configuration: The main shaft support elements are radial-type, deep groove, and angular contact ball bearings. Bushings and labyrinth style wear rings are installed between each stage to support the shaft and minimise back leakage.
z Thrust equalising mechanism: Submerged, motor-driven pumps cannot utilise thrust bearings due to the low viscosity and cryogenic temperatures of the pumped fluid. Because the axial load capacity is limited to rotating assembly weight, the resulting axial load, due to differential pressure of each stage, needs to be equalised by a thrust mechanism.
z Construction materials: While yield strength is often improved at colder temperatures, impact strength is significantly lower at cryogenic temperatures. Therefore, materials with both sufficient impact and yield strength must be used.
z Footprint, physical size, and weight.
z Motor cooling and lubrication: Motor cooling is crucial for stable operation of submerged motor-driven pumps.
z Condition monitoring and safe operation: Condition monitoring is conducted via accelerometers installed in close proximity to radial ball bearings. Overall vibration levels are monitored and recorded using accelerometers specifically designed for cryogenic fluids and temperatures.
z Electrical components: Electrical components and instrumentation (sensors) located at external tanks within certain proximity of process fluid must be certified according to the local and international hazardous area codes.
Submerged motor-driven LNG pumps
Since LNG is highly flammable and explosive, applicable local and international safety regulations and guidelines must guide electrical component design. Conventional LNG pumps with external motors require complex seal design, complex initial start and cool down procedures, and higher maintenance. Additionally, each electrical component must be designed, manufactured, tested, and certified according to the applicable hazardous area classification and code.
As a cryogenic fluid, LNG is an excellent insulator. Submerging an induction motor into a process fluid allows the induction motor to be completely isolated from oxygen in the atmosphere. For this reason, no hazardous area certification is required for induction motors. Induction motors also eliminate the need for rotating dynamic seals between the external motor and the hydraulics section of the pump.
Conventional external motors normally have a mechanical coupling located between the motor and the hydraulic components to drive the motor. This requires precise alignment during installation. The submerged design has a common shaft, and alignment or concentricity are accomplished at the factory during manufacturing and assembly, eliminating alignment concerns.
Conventional cryogenic LNG pumps with external motors often require an external lubrication system for the
Figure 1. Typical simplified LNG import and regasification terminal with various LNG pumps.
motor bearings, adding system complexity and increased maintenance. For submerged motor pumps, the bearings are cooled and lubricated by the process fluid in a subcooled condition. The induction motor is cooled by the cryogenic process fluid via cooling return lines and fluid travelling through the gap between the motor rotor and stator.
Three types of submerged motor pumps are commonly used in LNG plants and processes. They include suction vessel (canned) mounted pumps, retractable in-tank pumps, and marine pumps.
Suction vessel (canned) mounted pumps
Suction vessel mounted pumps are preferred for send-out or booster pump applications (Figure 2). These pumps are also
implemented for loading applications with high flow rates (approximately 2000 m3/h [8800 gpm]) and low differential pressure (<10 barg [145 psig]). Suction vessel mounted pumps are vertically suspended inside a pressure vessel that consists of the necessary process piping such as suction, discharge, and vent nozzles. Pressure vessels are designed per the ASME Boiler and Pressure Vessel Code (BPVC) and can be certified and registered to additional applicable codes such as PED, AS1210, etc.
Send-out and booster pumps require multi-stages to attain the high pressure required by the vaporisers during the regasification process. Discharge pressures can be in excess of 100 barg (1450 psig). As many as 20 stages can be used to achieve the required discharge pressure, while rotational speeds do not exceed 3600 rpm. To keep the stage span shorter, radial-type diffuser vanes are used. Since the diffusion of the fluid is achieved in the radial direction of flow, stage overall axial length is much shorter. However, greater radial spacing from the shaft centre is necessary, which increases the overall diameter of the outer pump casings. Each pump stage is identical and provides the same amount of head increase. Since the process fluid is incompressible in pumping applications, there is no concern of change in density, and the pressure ratio is constant across each stage for a given flow rate and fluid density.
Loading pumps are single-stage, cryogenic units that provide high-flow output (Figure 3). Similar to high-pressure applications, these pumps are installed vertically into a pressure vessel with identical piping configurations. An inducer can be installed downstream of the first impeller’s suction side to lower net positive suction head required (NPSHr). Instead of radial diffusers, axial-type diffuser vanes are used.
Retractable in-tank pumps
Retractable in-tank pumps are vertically suspended inside the discharge column of LNG storage tanks via a special retraction system. These pumps transfer LNG from storage tanks to booster pumps for regasification. They are also used to load carriers at LNG export terminals. Retractable pumps are installed over a suction (foot) valve, which closes when the pump is lifted off for maintenance. The suction valve has a spring-loaded mechanism to seal and minimise leakage from the storage tank to the discharge column once the pump is removed.
A typical in-tank retractable pump, along with a suction valve and LNG storage tank is shown in Figure 4. Every in-tank pump application is furnished with a helical inducer to delay the cavitation inception for safe operation at very low liquid levels with reduced suction pressure. LNG tanks for hydrocarbon applications can only handle a maximum tank pressure of 300 mbar (4.35 psi) or less due to cost and manufacturing constraints. Therefore, the suction pressure of an in-tank pump is often dictated by the static height of the liquid. Inducer design is crucial for these applications, as it ultimately determines the minimum liquid level in the tank required for safe and stable operation.
Marine pumps
Marine pumps are installed in ships to unload the storage tanks and supply fuel for the carrier. They are categorised based on their duty: cargo, spray (stripping), emergency, and fuel pumps.
Two cargo pumps are typically installed in each tank. These pumps can unload the entire cargo in approximately 12 hours. A single-stage design is most often used, although multi-stage pumps can also be used, depending on the differential
Figure 3.Typical single-stage suction vessel mounted high flow loading pump for LNG applications.
Figure 2. Suction vessel mounted submerged motor pump.
pressure requirement. Cargo pumps have similar design features to single-stage suction vessel mounted loading pumps. The main difference is that cargo pumps are mounted to a support plate inside the carrier’s tank. The pump’s discharge flange is directly connected to the tank’s discharge pipe.
Spray (stripping) pumps spray LNG onto the inside top of the cargo tanks to help keep them cold and reduce boil-off gas vapour. Spray (stripping) pump designs have relatively lower NPSHr requirements with low-duty flow rates. This allows cargo tanks to be offloaded with minimum to zero liquid levels. In some applications, these pumps provide fuel to the ship and can be used as a dual-duty pump (Figure 5).
Emergency pumps are identical in design to in-tank retractable pumps. They are used for emergency cases, where there is a malfunction in the main cargo pumps. Similar to retractable in-tank pumps, they are installed in the cargo tank column via a retraction system during an emergency to quickly empty the cargo tank.
Pumps for supporting functional units in LNG plants
Gas pretreatment takes place prior to the chilling, condensation, liquefaction, and refrigeration processes in LNG plants. It involves acid gas removal, precooling, dehydration, and mercury removal. Acid gases, mainly carbon dioxide (CO2) and hydrogen sulfide (H2S), must be removed from the process stream before the process gas is introduced into the cryogenic unit. Both CO2 and H2S will freeze and solidify if they are not removed to an acceptable level. Solvent-based processes are used to remove acid gases; alkanolamines are the most commonly used solvents.
Figure 6 shows a schematic of a solvent-based, acid gas removal unit. The process consists of the absorber column, which is used for removing acid gases from the raw ‘sour’ gas, and the stripper column, which is used for stripping acid gases from ‘rich’ amine solution. Multiple pumps pressurise and transfer ‘lean’ amine solution to the high-pressure absorber column where acid gases are absorbed from the sour gas by downward flowing amine. ‘Lean’ amine solvent is injected into the amine absorber column, makes contact with natural gas, and absorbs acid gas components, thus becoming ‘rich’ amine solution.
Amine pumping to the absorber is often handled by two separate pumps with an amine cooler to prevent the possibility of cavitation due to high-temperature pumping. A low differential head amine pump operating at a high temperature is followed by
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Figure 4.Typical configuration of a retractable in-tank LNG pump inside storage tank.
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a higher head pump operating at near-ambient temperature. A cooler is used to cool down the amine solution to increase the net positive suction head available (NPSHa). Another concern is the residual dissolved CO2 within the amine solution. To prevent pump damage, the NPSHa is reduced to prevent separation of dissolved CO2. A low-temperature, high-head pump is often a double-suction, single-stage unit with a low NPSH requirement. High-head pumps are typically multi-stage ring section, horizontal, electric motor-driven units. These units have external motors with mechanical seals.
Expanders for LNG applications
LNG liquid expanders
LNG liquid (hydraulic) expanders are important machines in almost every modern LNG liquefaction plant. Regardless of the proprietary liquefaction process, high-pressure LNG leaving the compression application must be let down to near atmospheric tank pressure. Joule-Thomson (JT) valves reduce the pressure using a highly reversible isenthalpic process. However, a portion of the gas is lost due to pressure relief, and required to be recompressed and sometimes flared-off to the atmosphere. Another option to reduce the pressure is through LNG liquid expanders, which reduce enthalpy and recover the lost energy during the let-down process.
Liquid expanders consist of a cryogenic hydraulic variable speed turbine to adjust the performance of the expander for different process requirements in terms of pressure drop and flow capacity; a cryogenic shaft seal; and an air-cooled, explosion-proof induction generator. The hydraulic section uses axial nozzle vanes with radial inflow reaction type turbine wheels which are capable of exceeding an isentropic turbine efficiency of 85%. In order to achieve a high differential pressure, multi-stages with multiple hydraulic components are used.
The entire rotating assembly, including the hydraulic turbine and the generator, is completely submerged similar to LNG pumps with submerged motors. As the entire unit is submerged in LNG, there is no need for a dynamic rotating shaft seal or any kind of coupling between the hydraulic and generator sections. The expander assembly operates safely within a stainless-steel containment vessel designed and tested in accordance with applicable pressure vessel codes.
Using LNG liquid expanders in the main LNG stream of a liquefaction plant in lieu of J-T valves delivers a 1 – 3% increase in liquid production gain. The compression power requirement can also be lowered by the same amount for both the precooling loop and the main LNG stream, which overall allows a reduction in heat exchanger and compressor sizes.
Using a liquid expander in the LNG main stream provides:
z Energy recovery and reduction in compression requirements by mechanical integration or electrical feed to the compressor.
z Enhanced cooling by enthalpy change, which improves LNG production by reducing vapour percentage at the flash process, which in turn, directly reduces the vapour recompression requirement.
LNG flashing two-phase expanders
Similar to liquid expanders, two-phase expanders are used in lieu of J-T valves to reduce LNG pressure. The hydraulic energy of the pressurised fluid is converted by first transforming it into kinetic energy, then into mechanical shaft power, and finally to electrical energy through the use of an electrical power generator. The generator is submerged in the cryogenic liquid and mounted integrally with the expander.
The main difference between liquid and two-phase expanders are the additional hydraulic components to handle the vapour formation within the machine internals. Two-phase expanders can take greater energy out of the process, bringing greater cooling to the main LNG stream. Harnessing the energy of two-phase expansion increases the expander’s generator output, reduces boil-off losses, and improves overall liquefaction process efficiency with a 3 – 7% production gain.
Summary
With worldwide demand for natural gas steadily rising, LNG liquefaction, transport, and storage is key to supplying end users. A wide range of centrifugal compressors and cryogenic pumps and expanders are at the heart of LNG production and processing applications. In light of operational and market realities, this two-part article focused on how these turbomachines fit into the LNG value chain, their ongoing contributions toward reduced emissions through advanced technologies, and the roles they play in LNG production, transport, storage, and regasification.
Figure 5. Cross-sectional view of a spray/stripping pump used in LNG carriers.
Figure 6. Acid gas removal process flow diagram.
Jack Blundell and Abraham Sebastian, ROCKWOOL Technical Insulation, USA, discuss a new insulation innovation that keeps LNG pipework dry and less susceptible to the costs and risks of corrosion under insulati on.
cross the oil and gas asset chain — from upstream production to downstream processes and everywhere in between –operators must ensure that their processes operate with optimal safety, reliability, and energy efficiency. LNG facilities are no exception. They rely upon insulation around pipes and other equipment to keep cryogenic
applications from warming up while protecting against thermal energy losses and keeping plant workers safer in higher-temperature applications.
The selection of the proper insulation for LNG facilities requires careful consideration of the insulation’s placement and purpose in the facility. Questions to consider include:
z What are the design criteria for the insulation? (e.g. heat flow limitation, condensation control, etc.)
z Will the insulation be used around pipework or on storage tanks?
z What are the ambient conditions in the facility?
z What is the temperature range required for the particular operation to function as required?
For very cold LNG applications (-258˚F [-161˚C] or below), insulation with low thermal conductivity is required
1. Stone wool insulation with CR-Tech is applied easily around pipe, with minimal manpower and no need for special installation equipment.
Figure 2. A technician prepares an ASTM G189 test cell by applying a section of ProRox PS 965 with CR-Tech around a pipe section containing carbon steel coupons. The standard guide for laboratory evaluation of CUI, ASTM G189 simulates an accelerated corrosion environment to compare corrosion rates of different combinations of insulation systems.
to avoid heat gain and prevent the liquefied gas in the tank from converting back to its gaseous state. Because LNG plants are known for generating significant noise, one must also consider insulation systems with effective acoustic properties that bring noise down to an acceptable level, ensuring safe plant operations and long-term hearing safety for plant personnel.
At the same time, insulation and outer jacketing should be evaluated based on their ability to minimise water ingress and mitigate corrosion under insulation (CUI). CUI is an aggressive, localised corrosion phenomenon that occurs when water migrates through the insulation and reaches the metal surface of pipes and plant equipment.
Water can come from various sources, including rain, saltwater mist, condensation, temperature cycling, washdown water, and process leaks or spills. Regardless of the source, some of this water will find its way into even the most well-jacketed insulation. Because this corrosion occurs under the insulation and outside of plain view and is considered a ‘hidden problem’, it can spread quickly to cause severe metal loss and pitting of the steel surface.
CUI has dangerous and costly consequences if not properly addressed, including an increased risk of heat loss, unplanned downtime, leaks, and spills. These risks are often more extreme in cyclic LNG plant operations running between cold and hot temperatures (typically -4˚F – 608˚F [-20˚C – 320˚C]). At the colder temperatures of the cycle, water — both liquid and vapour — can enter the insulation more readily. As process temperatures rise through the water’s dew point, the corrosion rate and susceptibility to CUI risks increase as well. During each temperature cycle, the concentration of chloride salts in the insulation and on the metal surface increases as water evaporates during the higher temperature period of the cycle. As the temperature drops and more water enters the insulation, the higher salt concentration leads to an increased rate of corrosive attack on the steel.
By some estimates, CUI accounts for 10% of a plant’s overall maintenance costs and up to 60% of pipeline maintenance costs. 1,2 Leaks caused by CUI pose hazards for plant personnel while damaging the plant’s reputation as a safe, environmentally-responsible operation.
Given these potential high costs and safety risks, a number of solutions aim to passivate the metal surface under insulation and protect it from corrosive attack, including protective coatings or high-quality insulation.
Mitigating CUI from within the insulation itself
ROCKWOOL Technical Insulation mitigated the effects of CUI in process-intensive operations like LNG facilities by developing solutions that make the insulation less likely to create a corrosive environment. Using its proven stone wool insulation material as a starting block, the company has developed new additive technologies that impart superior water repellency and corrosion protection to the insulation.
The most recent additive advancement is CR-Tech (Corrosion Resistant Technology), a proprietary corrosion inhibitor embedded within ROCKWOOL’s ProRox insulation to specifically mitigate CUI on pipe surfaces. The CR-Tech inhibitor is embedded into the inner surface of mandrel
Figure
The best defense against corrosion.
ROCKWOOL ProRox® with CR-Tech™ shields your piping from the dangers and costs of corrosion.
Corrosive conditions are an ever-present threat to your plant’s infrastructure. Arm yourself with ProRox stone wool insulation with CR-Tech – our proprietary corrosion inhibitor provides water repellency and long-lasting corrosion defense in one.
ProRox insulation with CR-Tech gives you wide-ranging protection and cost control:
• Achieves 5x better corrosion mitigation than alternative insulation materials with inhibitors in CUI test method ASTM G189
• Includes the power of WR-Tech™ Water Repellency Technology to help minimize the insulation’s moisture content
• Provides superior acoustic and thermal insulation to improve health, safety and wellbeing
• Arrives in easy-to-handle sections that help lower installation time and costs
wound pipe sections, right where the insulation touches the pipe. In the event that external water finds its way under the insulation, the inhibitor activates on the pipe surface to form a thin protective layer that prevents the corrosive cocktail of water, salts, and acidic species from contacting the pipe wall. The inhibitor also alters the chemistry of the water to make it less acidic and, by extension, less corrosive.
Stone wool insulation products with CR-Tech also contain a hydrophobic additive called WR-Tech (Water Repellency Technology). This low-chloride, water-repellent binder coats each individual insulation fibre to minimise water absorption in the insulation. Since 2017, WR-Tech has been keeping critical plant systems drier and less susceptible to corrosion. The technology has been selected as a winner of the Association for Materials Protection and Performance’s (AMPP’s) 2019 Corrosion Innovation of the Year Award, one of 10 technologies honoured out of more than 50 nominees.
Stone wool insulation containing the unique combination of water repellency from WR-Tech and corrosion inhibition from CR-Tech was proven to shield pipes from CUI in a number of industry-standard tests.
z The ASTM G189 test standard measures corrosion on metal under insulation in laboratory conditions In rigorous testing that includes exposing an insulated pipe section to wet and dry cycles ranging from 140˚F – 302˚F (60˚C – 150˚C), stone wool insulation with CR-Tech
demonstrated 5x better corrosion mitigation on steel than other insulation materials containing inhibitors.
z ASTM C1617 measures the corrosion tendency of metals in the presence of solutions containing ions leached from thermal insulation. The standard test was modified to evaluate the effect of different concentrations of chloride. The corrosion inhibitor-treated insulation performed better than several popular insulation materials at elevated chloride levels, with minimal corrosion at chloride concentrations up to 600 ppm.
z EN 13472 testing simulates water absorption in the insulation due to rain exposure. After immersing insulation samples in water for 48 hours without high-temperature heat ageing, the WR-Tech binder kept water absorption below 0.2 kg/m 2. This result is comparable to other leading mineral wool insulation pipe sections. However, in a series of tests in which the insulation was preheated at 482˚F (250˚C) for 24 hours to simulate real-world cyclic heating and ageing, the WR-Tech-treated insulation maintained water absorption below 0.2 kg/m 2. Other mineral wool insulation products lost their water repellency after heat ageing and absorbed significant volumes of water.
Testing to ensure durable performance
Since CR-Tech is water-activated, the amount of water to which the insulation is exposed plays a role in the overall durability. ROCKWOOL set out to test the durability of the additive by exposing insulation containing CR-Tech to 15 years’ worth of rainwater in a modified version of CUI test method ASTM G189. This test method simulates an insulated pipe spool exposed to cyclic high-to-low temperatures and moisture directed under the insulation, right at the metal-insulation interface. These are the ideal conditions for rapid CUI development.
For comparison purposes, testing also included stone wool without CR-Tech to show the difference in corrosion-inhibiting technology. A third-party insulation often used in CUI-risk applications was also tested.
The test conditions were:
z 15-year rainfall total from the US Gulf coast at an infiltration rate of 1% as per ASHRAE 160.
z Distilled water was used to mimic rainwater.
z Cyclic wet-dry conditions were executed, ranging from 284˚F (140˚C) for dry conditions to 140˚F (60˚C) for wet conditions.
Figure 3. Carbon steel coupons after modified ASTM G189 testing shows that coupons wrapped in stone wool with corrosion inhibitor (middle) showed minimal corrosion compared to the stone wool without inhibitor (left) and another type of insulation commonly used in CUI applications (right).
Figure 4. Modified ASTM G189 test results with elevated chloride levels show that the stone wool with corrosion inhibitor (left) provided far superior corrosion protection to carbon steel coupons compared to either third-party insulation commonly used to counter CUI.
ProRox PS 965
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Hear more from Mariam.
Mariam Hernandez, a Pipe Welder at Port Arthur LNG, turned opportunity into a career with the support of Bechtel’s high school training programs.
z Insulation was installed directly on the pipe without spacers or an air gap.
z Testing lasted for 30 days.
z Carbon steel pipe coupons were used and were insulated and cladded with 0.016 in. aluminium.
Corrosion was measured across six separate carbon steel coupons and an average uniform corrosion rate was calculated using the weight difference before and after the 30-day tests.
Figure 3 shows the post-testing corrosion on the coupons after cleaning. The bottom half of the pipe, where water tends to pool, is anticipated as the area for the highest level of corrosion due to the duration of water exposure. Visible corrosion is seen in the pitted and roughened surface, as opposed to the polished, shiny surface, which shows areas unaffected by corrosion.
The average corrosion rate with stone wool without corrosion inhibitor was 358 um/y. The same stone wool with inhibitor provided a corrosion rate of just 7 um/y while the third-party insulation delivered a corrosion rate of 51 um/y. The significant difference in corrosion between stone wool with and without corrosion inhibitor shows the protective powers of CR-Tech. The corrosion protection with CR-Tech results in a better performance than even the third-party insulation, which also features corrosion inhibitor properties.
Stone wool with CR-Tech showed a high level of protection even after 15 years of rain exposure, which indicates that the inhibitor-treated insulation retains high durability over extended periods in the field.
Examining the effect of chlorides
Chlorides are a well-known corrosion catalyst. One of the benefits of CR-Tech is its ability to counteract chlorides, as demonstrated in the ASTM C1617 test. The stone wool insulation with inhibitor was tested to ASTM G189 again, but modified to include 100 ppm chloride injected under the insulation for a period of 96 hours, as suggested within the standard.
Two different insulation materials used in CUI applications were also tested for comparison purposes.
As Figure 4 demonstrates, the stone wool with inhibitor (left) again ensured better corrosion protection by buffering the acidic environment and shielding the carbon steel surface to provide an average uniform corrosion rate of 17 um/y. The corrosion rate under perlite insulation (middle) was 412 um/y and aerogel (right) averaged 895 um/y. With the latter, the hydrophobic blanket may have trapped water and not allowed for fast enough drying during the heating cycles.
Installing quickly, easily, and at low cost
Mandrel wound stone wool insulation containing CR-Tech is delivered to LNG facilities in split and hinged pipe sections that apply easily to pipes with less downtime. In addition to lower installation costs, the mandrel wound sections reduce logistics, handling challenges, and material costs, making it very user friendly.
Conclusion
As existing LNG facilities expand and new projects break ground, LNG operators will need proven, cost-effective CUI solutions to ensure the safety and long-term productivity of their facilities. Material advances, such as ProRox stone wool insulation with CR-Tech and WR-Tech, offer proven corrosion resistance and water repellency while providing effective noise suppression and thermal performance to keep personnel safer and plant equipment running longer.
References
1. The NACE International Impact Study, (2016), Annex D, p D-10.
2. FITZGERALD, B. J., DROZ, C., and WINNIK, S. ‘Piping System CUI: Old problem, different approaches’, European Federation of Corrosion (EFC), Minutes of meeting, presentation by ExxonMobil Chemical Co., (2003).
Figure 6. Field technicians apply ProRox PS 965 with CR-Tech insulation sections in the field. The lightweight, mandrel wound sections apply easily and efficiently, with minimal downtime and safety risks.
Figure 5. ProRox insulation with CR-Tech improves plant safety by reducing noise and thermal losses while mitigating the effects of CUI – all in a single product.
Justin Bird, CEO of Sempra Infrastructure, offers an insight into the Port Arthur Energy Hub, and its role in in delivering energy for a better world.
n the Gulf Coast of Southeast Texas, a transformative project is taking shape. The Port Arthur Energy Hub, a concept that has been in the making for nearly a decade, is now becoming a reality. Sempra Infrastructure’s collection of energy infrastructure projects has the potential to redefine the global energy landscape and substantially benefit local communities.
A change for the better…
Sempra Infrastructure views the hub as a driving force for change. It has the potential to create thousands of jobs, improve local infrastructure, and inject millions of dollars into the local economy. As this vision becomes reality, the surrounding communities have new opportunities for employment, education, and local business development.
Figure 1. A rendering of the Port Arthur Energy Hub site.
As the world faces the pressing challenge of balancing energy demands, environmental stewardship, and economic stability, the energy hub stands out as a vision of the future of global energy by combining the capability for large scale LNG production and export facilities with low carbon solutions designed to meet the growing demand for lower carbon intense fuels. The hub is created to meet growing global energy needs, enhance energy security for America’s allies, and advance environmental goals. At the same time, the hub is creating jobs and fostering economic growth in local communities.
…One phase at a time
The Port Arthur LNG Phase 1 project, the cornerstone of the hub, is over one year into construction. Once completed, it is expected to deliver approximately 13 million tpy of LNG to customers worldwide. This output will help customers around the globe shift away from coal and fuel oils for electricity generation and industrial applications. It will also provide emerging markets access to US natural gas, contributing to global efforts to reduce emissions and enhance energy reliability.
The proposed Port Arthur LNG Phase 2 expansion could double the site’s export capacity, and has garnered significant interest from international markets eager to partner with the US to curb emissions and stabilise energy supply. In June 2024, the company announced a non-binding heads of agreement with a subsidiary of Aramco that contemplates a 20-year sale and purchase agreement for 5 million tpy of LNG offtake and a 25% equity investment in the proposed Phase 2 project. If realised, this agreement could play a pivotal role in advancing the shared energy goals of the US and Saudi Arabia, as underscored in recent bilateral discussions on energy co-operation between the two nations. In July 2024, Sempra Infrastructure and Bechtel announced the signing of a fixed-price EPC contract for the proposed Port Arthur LNG Phase 2 project.
The development of the proposed Port Arthur LNG Phase 2 project would be an integral part of the Port Arthur Energy Hub, which also includes a series of related development projects that, if commercially viable
and technologically feasible, could help lower the carbon intensity of the LNG the company exports to customers around the globe. This holistic development approach is designed to position Port Arthur as a flagship hub that leverages the integrated capabilities of Sempra Infrastructure’s business lines to allow the company to continue building energy systems for the future. The related projects and opportunities could potentially play a pivotal role in reducing the carbon intensity of the LNG value chain.
Considering the local impact
Sempra Infrastructure is equally committed to its local impact. Since the inception of the Port Arthur LNG Phase 1 project in 2015, the company has demonstrated its priority of investing in the communities of Jefferson County, where the hub is located, and in the broader nine-county region of Southeast Texas. To date, Sempra Infrastructure has invested over US$3 million to support local non-profits, schools, and other community-based organisations, reinforcing its role as a responsible corporate citizen. This community engagement is a testament to the integral role of local communities in the hub’s success.
In April 2023, Sempra Infrastructure announced a US$500 000 investment in workforce readiness and development programmes. This initiative aims to prepare the local workforce for the opportunities that will arise as the Port Arthur LNG Phase 1 project becomes operational. In a show of collaboration, Bechtel, the EPC contractor for the Phase 1 project, matched the contribution, bringing the total investment to US$1 million. These funds are being channelled into bolstering local programmes focused on job training and skills development, to help Port Arthur area residents be equipped with the skills needed to thrive in a rapidly evolving energy sector.
During a recent Port Arthur City Council meeting, where a proclamation was presented to recognise Port Arthur LNG’s commitment to championing workforce development, Port Arthur City Councilman, Donald Frank, thanked Port Arthur LNG and congratulated the efforts that have been made to positively impact the community.
Hiring locally
Mariam Hernandez, a pipe welder on the Port Arthur LNG project (featured on the front cover), graduated from another of Bechtel’s supported high school programmes and has become a skilled welder on multiple LNG projects and a community role model.
As a young mother and sole provider for her family, Mariam showcases the life-changing opportunities of a career in construction. She exemplifies the impact of Sempra Infrastructure and Bechtel’s commitment to local talent development. Mariam, along with six recent graduates and many others who are gaining valuable skills through these programmes, represents the success of building a thriving workforce in the community.
Sempra Infrastructure’s investment in the community goes beyond financial contributions and workforce training. The company is deeply committed to hiring talent from the communities where it
Figure 2. Port Arthur Mayor, Thurman Bartie, congratulates the most recent cohort of apprentices to graduate from workforce development programmes sponsored by Sempra Infrastructure.
operates and proactively engages local suppliers to support project development. This rings true for Port Arthur LNG and helps strengthen the local economy while fostering a sense of ownership and pride among community members who directly contribute to the project’s success.
As the Port Arthur LNG Phase 1 project progresses, the impact of this local hiring initiative is already evident. In 16 months of construction, the project has created more than 1000 jobs, with over 600 of these positions filled by residents of the greater Port Arthur area. These roles span various functions, including office work, field operations, construction, and management, reflecting the diverse skill sets present within the local workforce.
The economic ripple effect extends even further through the engagement of local vendors and suppliers. The Port Arthur LNG Phase 1 project has partnered with over
Sempra Infrastructure is a proud community partner and looks forward to investing time, talent, and resources to help improve the quality of life for its neighbours and employees in Port Arthur and the surrounding area. The company’s active involvement in the Port Arthur community is fundamental to the success of its Port Arthur LNG Phase 1 project and potential Phase 2 project, and it is underpinned by the company value to ‘do the right thing.’ Sempra Infrastructure is also focused on positively impacting the community through rigorous safety programmes and environmental initiatives to improve safety for employees and the local community.
Planning for the future
The Port Arthur Energy Hub models how large scale energy projects can integrate global ambitions with local priorities. Its success demonstrates the power of collaboration –between corporations and communities, between industry
Hans-Peter Visser, Analytical Solutions and Products B.V., the Netherlands, explores how to measure renewable and sustainable bio-LNG and carbon dioxide, creating a net-zero environment.
he terms ‘renewable energy’ and ‘sustainable energy’ are often used interchangeably. However, their meanings are actually different. Renewable energy is energy that is created and replenished naturally. Sustainable energy, on the other hand, is energy that reliably meets both the short and long-term needs of a society.
Biomass is one of the five forms of renewable energy. Biomass from an anaerobic digester generates biogas. Raw biogas contains roughly 60% methane (CH4) and 40% carbon dioxide (CO2) saturated with water and some impurities (impurities are dependent on the source of the biomass). Once the biogas is treated, a relatively pure form of CH4 remains. This pure CH4 can be liquefied to a constant and lean bio-LNG that is very well suited for long-haul road transport and maritime industry.
In the biogas treatment processes, natural-based CO2 can also be reclaimed in a very pure form. The pure CO2 can be of such a high quality, it becomes feedstock for the food and beverage industry. In this case, CO2 is also liquefied.
The combination of these biomass processes means biomass can even generate a negative CO2 footprint while producing LNG as a non-fossil fuel.
Regardless, for the production route of bio-LNG and natural based CO2, analytical measurements are paramount and a must. Proof of Sustainability is mandatory according to the Renewable Energy Directive.
Keep it simple
The biomass market, originally started as heavily subsidised industry, is a very price sensitive market. It was known as a low-cost market, hence with low-quality instrumentation.
While the biomass industry is evolving, maturing, and taking advantage of the lessons learned, the willingness to explore other technical solutions increases.
Bio-LNG
A typical bio-LNG plant has one or occasionally two LNG truck loadings per week, varying between 30 – 60 minutes per truck load.
The bio-LNG has to comply with EN 16723-2: 2017 (Natural gas and biomethane for use in transport and biomethane for injection in the natural gas network – Part 2: Automotive fuels specification). A bio-LNG measurement system has a relatively high investment due to the LNG vaporiser and the downstream analyser. ASaP has developed a price attractive bio-LNG vaporiser which is a derivative of the field proven and successful Phazer series for fossil LNG. Additionally, ASaP applied a gas chromatograph (GC) which has a significant wider dynamic range of the traditional energy content measurements of biogas/LNG, as well as the capability of measure trace analytes.
The benefits of this GC are substantial. The GC has large dynamic ranges due to its applied proven capillary technology allowing one GC to measure nearly all processes of the biomass plant. With this solution, the cost per measuring point is the lowest in the market.
This measurement strategy is feasible because the capillary GC technology has a maximum cycle time of just 45 seconds.
The analysis results are for the compositional measurements but additionally for all trace analytes as well. This combines multiple traditional analysers to just one GC, hence lowering the cost while gaining on analytical performances like accuracy, repeatability, and cycle time, etc.
Besides the CAPEX, the operational cost of carrier gas and sample filters are reduced to the bare minimum with the ASaP method. By using ASaP proprietary software called AIM-AMADAS, the GC performance can be
Figure 1. Five renewable energy sources.
Figure 2. Typical biogas/bio-LNG plant set-up.
continuously monitored and operated locally and remotely. This allows for a reduction of the maintenance cost to a bare minimum because upcoming maintenance can be planned and anticipated. This is essential for cost reduction and reliable and safe operation for unmanned and remote locations.
In conjunction with an inline bio-LNG flow meter and/or the signal of the truck weighing bridge, the GC results and the bio-LNG temperature are used to generate the automatic quality certificate and bill of lading.
This minimises personal involvement while the automatic actions can be either initiated remotely and/or by the truck driver, which is an additional effort and cost saver.
Natural-based or non-traditional sourced CO2
The early days of CO2 measurements systems were based on a combination of several traditional, complex, and laboratory analysers, GC’s, chemiluminescence, Quartz Crystal Microbalance, etc.
The challenge for the CO2 analysis system is the source of the CO2. The source will determine the kind of impurities and their trace levels. Some of these analytes are very difficult to measure. Not only did these analysers have analytical performance limitations way back when, they require a high level of maintenance.
With the ASaP Spectra analyser, all trace and compositional analytes can be measured with one combined analyser independent of their source. The Spectra analyser is flexible in analytical configuration allowing to add analytes, even while the system is in operation.
Due to its principle of operation, a full spectrum of analytes is measured in seconds. This allows one system to measure at multiple sample points, also reducing cost per measuring point.
Identical to the bio-LNG measurement system, the (liquefied) CO2 can be quantified and qualified, allowing automatic generation of the quality certificate and bill of lading.
ASaP provides complete assembled, tested and calibrated (liquid) CO2 measurement systems, including sensory equipment, all in an effective enclosure including the glove box with sensory equipment. The whole system complies with the international standards for the food and beverage industry like ISBT and EIGA.
The same technology is applied for post-combustion carbon capture utilisation and storage applications.
Conclusion
Although the analytical requirements are stringent and demanding for both bio-LNG and (liquefied) CO2 analysis, the analytical performance can be maximised while minimising the cost for both investment and operation. The systems are proving sustainability of the renewable resources and their net-zero carbon footprint while complying with all relevant international standards.
Figure 4. Certificate of analysis.
Figure 5. Phazer 2.0 installation.
Figure 3. Proof of Sustainability certificate.
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Amedium-sized LNG terminal has the capacity to transfer up to 5 million tpy of LNG, which is approximately 7 billion m3 of gas.1 The measuring devices that determine the value of this gas should be set up to accurately report the total metered energy with a high degree of confidence to minimise fiscal risk during custody transfer. The critical importance of high-quality calibration gases with assigned low uncertainties in ensuring the highest level of confidence in total metered energy, is often overlooked. These reference materials are essential in reducing financial risks associated with fiscal flow metering.
Adam Lomax, Joey Walker, and Jonathan Britain, EffecTech, consider the crucial role of reliable calibration gases in fiscal metering.
The gas industry offers a wide variety of calibration gases with defined uncertainty levels that typically range from 0.1 – 5%. However, the impact on financial risk of the propagation of this uncertainty through the various calculations required for total energy determination, is not well understood. This article examines the effect of different quality calibration gases on fiscal risk, focusing on a hypothetical natural gas export meter transferring gas from an LNG terminal to a national transmission system.
The measurement of gas quality and volume are prerequisites for determining total metered energy.
A fiscal metering system consists of a flow element and a natural gas chromatograph (GC). Combining the measurements from both the flow and composition elements results in a total energy output described by the following equation: Where:
z H is the gross volumetric calorific value at standard conditions (ISO 6976:2016). 2
z ρs is the density at standard conditions (ISO 6976:2016).
z ρL is the density at line conditions (AGA 8). 3
z V is the volume of gas at line conditions.
The first of the three inputs to the equation are determined from the gas composition, illustrating the importance of an accurate and reliable measurement from the GC.
Assessing the performance of gas chromatographs
The industry standard of assessing the performance of a GC is by carrying out an ISO 10723 performance evaluation. 4 This evaluation allows one to model the relationship between what the instrument thinks is correct and what is truly correct, allowing the errors in mismeasurement due to nonlinearity to be assessed. The model produced by the performance evaluation can be used to simulate the measurement of any gas composition within the standard’s scope and output a measured composition with an associated uncertainty.
An ISO 10723 performance evaluation requires the measurement of a suite of reference gases which encompasses the expected measurement range of the instrument under test. First, the raw instrument response data is collected, then, using generalised least squared (GLS) regression (in accordance with ISO 6143 5 ), a model of the instrument is generated. The model consists of:
z f, a function to calculate amount fraction from instrument response.
z g, a function to calculate instrument response from amount fraction.
z p, a function to calculate precision from amount fraction.
Assuming the instrument uses a typical single point through the origin calibration model, the measured amount fraction is given by:
The uncertainty on the measured composition is given by:
The composition is then normalised in accordance with ISO 6974, 6 providing the inputs required for both ISO 6976 and AGA 8. The function ( f) can be used to correct for nonlinearity within the GC, however that is beyond the scope of this paper.
The physical properties calculated in accordance with ISO 6976:2016 have well-defined analytical uncertainties included in the standard. The results of the simulation combined with the covariance calculated during normalisation gives the required uncertainties on the calorific value and the density at standard conditions.
However, the density at line conditions is calculated via an iterative root-finding approach that does not have an easily calculable analytical uncertainty, therefore necessitating the need for a Monte-Carlo approach. In this approach, the AGA 8 density is calculated for 10 000 sub-compositions; the uncertainty is then estimated from the standard deviation of the entire population of AGA 8 values.
Method for propagating calibration gas uncertainties
As this article is primarily concerned with propagation of the calibration gas uncertainty through the metering process, an uncertainty of 0.2% (k=2) relative for the metered volume will be used and the flow metering elements will be assumed to be fixed. Since the equation for the total energy is a simple product, the relative uncertainties of the variables can be added in quadrature to give the uncertainty in terms of energy.
For each simulation, a daily average volume flow of 20 million m 3 of gas was assumed, closely resembling that of a medium-sized LNG terminal. The calculated uncertainties for total metered energy were converted to a monetary uncertainty assuming a natural gas spot price of US$3/million Btu. 7
This work utilised data from a real ISO 10723 performance evaluation of a GC that demonstrated an acceptable bias and uncertainty based on the UK’s national transmission system benchmarks.
In this example, 10 000 gas compositions were produced using a bespoke software. The software ensures that ‘real’ gas compositions are produced by enforcing specific mixing rules based on a statistical analysis carried out on 10 000 real gas compositions measured within the UK transmission system.
The model of the GC requires a calibration gas composition and uncertainty input; therefore, it is possible to see how altering the uncertainty of the calibration gas affects the total metered energy uncertainty. A bespoke piece of software was developed to allow rapid iteration of gas compositions with a wide range of possible gases to be simulated. The data presented is based on a random data set of 10 000 gas compositions. For repeat simulations, the same seed was used to
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ensure reproducibility. This allows the effect of different calibration gas uncertainties to be assessed throughout the measurement process by fixing all other parameters.
For the AGA 8 calculation, an additional 10 000 sub-compositions were generated for each of original 10 000 gas compositions; allowing the uncertainty to be estimated from the standard deviation of the entire population of AGA 8 values.
Table 1 displays the simulated gas range which covers a broad range of gas compositions based on that expected for the UKs national transmission system (NTS). 8 The data is based on a single GC model and calibration
gas composition, the only variable is the calibration gas uncertainty.
Table 2 shows the five sets of calibration gas uncertainties that will be trialled. The first two sets represent mixtures produced by an accredited calibration laboratory with rigorous uncertainty budgets. The uncertainties represent the calibration and measurement capability (CMC) for two classes of mixture; a primary reference gas mixture (PRGM) and calibration gas mixture (CGM). The other three gas mixtures (GM) A, B, and C represent lower quality mixtures, which have had blanket uncertainties applied to all components, an expanded uncertainty of 1%, 2%, and 5% was selected to cover the range of gas mixtures available on the market.
The method of how total metered energy uncertainty is decided is illustrated in Figure 1.
Results and discussion
Figure 2 shows the risk profiles for each calibration gas, and this is represented by the uncertainty on the total metered energy cost at a confidence interval of 95%. Each point represents a composition and its associated risk. For example, the point (90.256, 11 000) represents a composition with 90.256% methane and an uncertainty of US$11 000, so the total metered energy would have a value of US$2 721 000 ± US$11 000, this means that with 95% confidence the true value of the metered energy will be US$2 710 000 – US$2 732 000. The lower the uncertainty the tighter this band will be, and hence the lower the risk.
The risk profile has contributions from the flow and composition/property uncertainties, similarly the composition/property uncertainties have several sources; the precision of the instrument, the uncertainties on constants used during the calculation of properties and the calibration gas uncertainties. All sources other than
Table 1. Gas simulation range and calibration gas composition used in the Monte-Carlo assessment
Table 2. Calibration gas categories used in the Monte-Carlo assessment
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the calibration gas uncertainty were kept constant for all risk profiles so any differences are caused by the calibration gas alone.
There is significant overlap between the PRGM and CGM – this indicates that the contribution from the calibration gas is small, and the other sources of uncertainty dominate the final risk profile. For GM-A, the calibration gas uncertainty is a significant contributor to the risk profile and for GM-B and GM-C, the calibration gas uncertainty is discernibly the dominant source of uncertainty for the risk profile.
Table 3 represents a single gas composition taken as a snapshot from Figure 2 (marked as example composition on Figures 2a and 2b) when measured with each of the calibration gas uncertainties from Table 1. The table includes the uncertainties on both the composition and physical properties. The properties marked with a † are dependent on flow; the remaining properties are independent of flow.
For the physical properties calculated from composition, both PRGM and CGM uncertainties have low contributions to the overall measured uncertainties. The dominant uncertainty contribution here is the precision of the instrument. However, for GM-A, the contribution from the calibration gas uncertainties starts to become a major contributor to the measured uncertainties. Subsequently, for the GM-B and GM-C calibration gases, the dominant contributions to the measurement uncertainties are the calibration gas uncertainties.
For both PRGM and CGM calibration gases, the flow-dependent properties, energy and price, exhibit measurement uncertainties that are overwhelmingly dominated by the flow uncertainty. Looking at columns PRGM %U(x) and CRM %U(x) in Table 3, the flow uncertainty accounts for 0.2% of the total uncertainty budget, while the compositional uncertainties contribute a negligible 0.01%. Consequently, the impact on total energy metering uncertainty is negligible for these two calibration gas categories. In contrast, GM-A shows a significant contribution of 0.07% from compositional uncertainties to the overall uncertainty budget for total energy and price. For GM-B, the compositional uncertainties slightly outweigh those from flow, contributing 0.2% to the final uncertainty budget. For GM-C, the compositional uncertainties are the primary contributors to the total uncertainty, with a 0.69% contribution, significantly exceeding the flow uncertainty.
Conclusion
This article has demonstrated that calibration gas uncertainties play a significant role in reducing overall measurement uncertainty for total metered energy. By simulating different categories of calibration gases with real data, it was possible to show the impact of how those calibration gas uncertainties propagate through to
Figure 2. (a) monetary uncertainty (US$) for total metered energy with different quality calibration gases for 20 million m3 gas daily exported to NTS. (b) log plot of monetary uncertainty (US$).
Figure 1. Inputs required to model the total metered energy uncertainty.
physical properties and finally to total metered energy. The main conclusions that can be drawn from this work are:
z PRGMs have no real benefit to fiscal risk.
z GM-A, -B, and -C mixtures contribute significantly to fiscal risk with higher uncertainties leading to a substantial increase in risk.
z CGM mixtures reduce fiscal risk; the cost difference between a CGM and lower quality gas is less than the amount of risk introduced by using a lower quality gas.
These findings underscore the importance of selecting high-quality calibration gases to minimise fiscal risk and improve the reliability of energy metering, ultimately improving confidence in custody transactions.
References
1. ‘Global LNG Outlook 2024 – 2028’, Institute for Energy Economics and Financial Analysis, (2024).
2. ‘ISO 6976 - Natural gas — Calculation of calorific values, density, relative density and Wobbe indices from composition’, International Organization for Standardization, 3rd edn., (2016).
3. ‘AGA Report No. 8 – Part 1, Thermodynamic Properties of Natural Gas and Related Gases, DETAIL and GROSS Equations of State’, AGA, 3rd edn., (2017).
4. ‘DS/EN ISO 10723 - Natural gas - Performance evaluation for analytical systems’, International Organization for Standardization, (2013).
5. ‘ISO 6143 - Gas analysis — Comparison methods for determining and checking the composition of calibration gas mixtures’, International Organization for Standardization, (2001).
6. ‘ISO 6974 - Natural gas — Determination of composition and associated uncertainty by gas chromatography’, International Organization for Standardization, (2012).
7. ‘Henry Hub Natural Gas Spot Price’, U.S. Energy Information Administration, (2024).
8. ‘Gas Ten Year Statement (GTYS)’, National Gas Transmission, (2023).
Table 3. Uncertainty propagation through physical properties for a typical LNG gas composition for different category calibration gases
s the information technology (IT) industry experiences a transition into more efficient, scalable, and innovative cloud and artificial intelligence (AI) technologies, the oil and gas industry in parallel embraces more sustain able practices and technologies. For oil and gas, this transition to a low-carbon future falls under the banner of the energy transition, with LNG playing a pivotal role as a bridge fuel
due to its lower carbon footprint. This is why now more than ever, for the LNG industry to fully realise its potential and effectively contribute to the broader energy transition, it is crucial to harness each new innovative advancement in IT.
Whether it be the deployment of digital twins at LNG plants allowing for more precise monitoring, AI-driven
Figure 1. LNG carrier.
predictive maintenance, or Internet of Things (IoT) devices for supply chain optimisation – IT innovation allows the LNG industry to keep pace with an increasing demand. For example, per the U.S. Energy Information Administration, North America’s LNG production and terminals will more than double within the span of 3 – 5 years.1 Similarly, according to the Aggregated LNG System Inventory in Europe between 2021 – 2025, close to 20 FSRUs will be in operation. 2
Examining the pace and expansion of the LNG industry, this article aims to explore what is working in the LNG industry in terms of best practices. It will also peer into the future through a lens of great potential, asking what can be accomplished with Software-as-a-Service (SaaS) and a commercial operations system, purpose-built for LNG.
SaaS
In terms of best practices, SaaS applications significantly benefit LNG companies with accessible, scalable, cost-effective, and secure solutions to various operational requirements. No longer a ‘nice-to-have’, rapid plant operations and systems readiness have become essential in maintaining energy security when facing the gas demands of the current geopolitical market. Furthermore, LNG operations can leverage the following benefits of implementing SaaS:
z Immediate access: With a SaaS solution hosted in the cloud, the need for bulky hardware and software installation processes is eliminated so LNG plants can quickly test software, develop proof-of-concepts, and move forward with systems. SaaS solutions often come pre-configured with industry-standard templates, reducing required time and effort in customising a system for business-specific needs.
z Scalability and resource elasticity: SaaS solutions can scale and add resources on demand as the LNG operation grows over the years.
z Cost efficiency: Adoption of a SaaS solution requires zero or minimal upfront CAPEX on infrastructure as compared to its on-premise alternative. SaaS providers handle all maintenance, updates, and security patches, reducing the need for building in-house expertise on various bespoke technologies used by different applications in the IT landscape. Hence it lessens the burden on the LNG plant’s IT staff, enabling them to focus on more strategic initiatives.
z Security: Application security is typically of utmost importance to SaaS providers to offer robust protection for customers’ critical data and operations in the cloud and over the internet. This is especially important for LNG companies that need to safeguard sensitive information against sophisticated cyber threats. A robust SaaS application goes through routine industry standard scans such as static application security testing (SAST), dynamic application security testing (DAST), and software composition analysis (SCA) uncovering any vulnerabilities in the tested version of the application. Encryption of data accessed over the internet is standard for a SaaS application.
Business process automation
Inherently, LNG business processes rely heavily upon interactions between different user groups: plant operations, commercial operations, terminal operations, marketing, accounting, trading, finance, and customers. Yet many of these interactions and processes have the potential to be fully or semi-automated, allowing users to interact only with the system during any exception. A system can automate tasks in a business process and create a to-do list of required manual interventions for the end user. For example, LNG contracts between buyers and sellers can have penalties tied to times or days for gas nominations as per the North American Energy Standards Board (NAESB) standard. 3 If the system is not automated to adhere to those times or days, then customers can incur fines. So, it is better to have an automated workflow. This process automation not only optimises end-users’ interaction with applications but also makes the overall system more efficient and less penalty prone.
Integrations within building blocks
LNG operational technology is a landscape mired with applications: production and operations management, measurements, gas nominations, commercial operations, vessel vetting, risk management, trading, document
Figure 2. LNG terminal.
Figure 3. LNG spherical storage tank.
The Cold Standard
management, invoicing, and health, safety, and environment (HSE). Today, most of these functions are managed disparately, possibly provided by different vendors and sometimes homegrown by LNG companies themselves. LNG companies that leverage modern industry standard ways of integrations such as Representational State Transfer Application Programming Interfaces (REST APIs) and cloud middleware services realise seamless interconnectivity over those reliant on their own bespoke integrations. REST APIs leverage hypertext transfer protocol secure (HTTPS) for encrypted communication over the web, ensuring data confidentiality and integrity during transit. REST APIs provide this common language for different systems to communicate with each other over the web. This allows disparate systems and applications to seamlessly exchange data and functionality, regardless of the technologies or platforms they are built on. To bridge any gaps, applications incapable of making REST calls can rely on cloud middleware services for integration flexibility. By adopting a standard way of integrating with REST APIs and cloud middleware services, businesses can realise a wider range of benefits including enhanced interoperability, agility, cost efficiency, resilience, and security. Such modern integration approaches streamline operations, improve collaboration, and drive innovation in an increasingly interconnected digital ecosystem by enabling the following:
z End-to-end visibility: Integrated systems provide stakeholders with a comprehensive view of the entire value chain, from production to liquefaction, transportation, regasification, and distribution.
z Scenario modelling: Integrated systems support what-if scenario analysis and impact assessments to evaluate the potential effects of operational changes or market fluctuations on different parts of the LNG value chain. For example, analysing the impact of various maintenance schedules, changes requested from LNG buyers, and pricing trends on production capacity and cargo schedule, and then determining the most optimised scenario from contractual and profitability perspective will be feasible in an integrated digital landscape.
z Data centralisation: Modern integration approaches also enable seamless integration of data from various sources across the LNG value chain into centralised repositories and ensure that data is standardised, validated, and stored in a consistent format, facilitating reliable analytics, reporting, and decision-making.
Development methodologies
When LNG companies engage so many different user groups via many different applications, traditional methods of software development have the potential to become sub-optimal. Using only one or two applications to address a business problem may be too narrow, thus Scaled Agile development methodologies like Scaled Agile Framework (SAFe), 4 can provide significant value to LNG companies. SAFe can empower LNG operations in the following ways:
z Ensure strategic alignment between all IT initiatives and business objectives.
z Promote cross-functional application development fostering collaboration and communication between teams consisting of members of various departments and responsible for commercial off-the-shelf (COTS), SaaS, and in-house systems.
z Encourage iterative and incremental development, adaptive to changing requirements and market conditions, allowing LNG companies to deliver value to users more frequently.
z Promote continuous integration and deployment (CI/CD) practices, automating integration, testing, and deployment of applications, reducing overall turnaround time and improving overall development efficiency.
Future: The art of possibility
If LNG companies have a SaaS mindset, combined with modern integrations, workflow automation, and scaled agile developments, then they are trending towards having a resilient digital foundation or ‘digital core’. The key to innovation for LNG enterprises resides in existing systems within their digital core. By leveraging cloud technologies and fostering connected workflows, alongside maintaining high-quality datasets and standardised processes across their operations, LNG enterprises can proactively adapt to market changes, optimise resource allocation, and achieve sustainable growth in the dynamic global energy landscape. This strategic alignment enables them to capitalise on emerging technologies and trends, driving forward with agility and informed decision-making to stay ahead in the competitive marketplace.
What we know
As the LNG industry continues to scale, contributing towards a more sustainable future, software and innovation will play a stronger role in unlocking significant value for LNG companies. The next 3 – 5 years will be crucial as new LNG operations reach a final investment decision (FID), become commissioned, and finalise their digital strategy. If the LNG industry continues to invest in modern and standard software practices and applications, such as solutions like Energy Components by Quorum Software that operates via SaaS, wherever they may be sourced, not only will efficiencies eventually pay for themselves but the entire industry will operate as a well-oiled machine (pun intended) and deliver on promises of sustainable future.
References
1. ‘LNG export capacity from North America is likely to more than double thr ough 2027’, U.S. Energy Information Administration, (13 November 2023), www.eia.gov/ todayinenergy/detail.php?id=60944
2. ‘Data Visualisation Map: Gas Infrastructure Europe’, Aggregated LNG System Inventory (ALSI), https://alsi.gie.eu/data-visualisation/map
3. North American Energy Standards Board, www.naesb.org
4. ‘What is SAFe®?’, Scaled Agile, https://scaledagile.com/ what-is-safe/
Rob Homer, Senior Product Manager (Gas & Water) at Energy Exemplar, details how digital twins can be used to co-optimise power and gas sectors.
n the evolving energy landscape, integrating gas with power sector operations has become a pivotal strategy. This approach, known as ‘co-optimisation’ or ‘sector coupling’, uses advanced energy modelling to ensure the security of supply and drives efficient, sustainable energy solutions. Digital twins play a crucial role in this transformation by enabling comprehensive and integrated modelling of both sectors within the same models and scenarios.
The role of digital twins in energy modelling
Digital twins – virtual replicas of physical assets and systems – allow energy stakeholders to unlock a more sophisticated approach to their planning and decision making. While traditional energy modelling has historically focused on production costs, capital investments, and short-term operations, the current demands of the energy landscape have precipitated a shift in emphasis towards modelling interdependent systems, federal emissions standards, and the effects of intermittent energy production. Digital twins are central to achieving these goals.
The enhanced detail offered by digital twins equips gas and LNG stakeholders with new insights to make better strategic decisions, such as those around the optimal sizing of facilities and investments in regasification or liquefaction facilities. In addition, digital twins enable the evaluation of long-haul LNG transportation alongside gas-fired generation and electricity demand within a single model, providing clarity on right-sizing assets throughout the energy value chain.
This integrated approach allows energy participants to identify blind spots in their operations, leading to more informed and effective decision making.
Strategic decisions driven by integrated modelling
Arguably the most important impact of next-generation energy modelling is that it allows for a comprehensive view of the interconnected energy landscape, encompassing both the power and gas sectors. The ability to model interdependencies between these assets is crucial for optimising resources, ensuring reliability, and meeting regulatory standards.
Recent studies highlight the paramount importance of integrated models over isolated simulations in navigating the complexities of energy transitions, which have long since moved beyond planning or creating simulations of individual standalone energy markets.
Energy Exemplar recently produced a coupled digital twin of power and gas systems by combining the New England ISO power system with the North American gas network. This is done by removing assumptions of fuel prices and limitless gas to gas-fired generators and connecting these generators directly to the gas network. This connection in a single model is forced to serve end-use gas demand while simultaneously also meeting power system demand. The outcome of this connection allows an energy system to adhere to weather assumptions, policy, build-out and retirement of generating assets, and price response. The results produce a more accurate representation of natural gas offtake in the New England region. This improved representation of fuel offtake at natural gas generators exposes a huge disparity in EIA’s 30-year natural gas demand forecast and what the output of the co-optimised model indicates.
The importance of this outcome shows that general assumptions about gas usage in the region are flat and even reducing; however, power demand assumptions, generation build-out schedules, and emissions standards indicate that this assumption is wildly off. Key policies and investments are based on these public demand forecasts. The variance shown below indicates gas-fired generation will be necessary for a significant time in the region and is shown to increase substantially. Without policy changes or significantly greater buildouts, the New England states could be in for very expensive power with the likelihood of brownouts or unserved gas demand in winter.
These studies also point out that co-optimisation approaches show significant improvements in the operational efficiency of the whole energy system and reduce carbon emissions. This is in addition to research that is increasingly uncovering that carefully designed co-optimisation models can help to achieve several key objectives – like minimising total costs and improving the integration of energy conversion – meaning the industry has only scratched the surface in terms of benefits.
Shorter contracts and market flexibility
The trend towards shorter LNG contracts reflects a shift in the market toward greater flexibility and responsiveness to changing global dynamics. Traditionally, LNG contracts have been long-term, often 20 years or more, providing stability for both producers and buyers. However, recent trends indicate a move towards shorter contracts, often in the range of 5 – 10 years, or even shorter spot market deals. Digital twin technology has helped to propel this. By providing a detailed visualisation of future events, digital twins offer a level of certainty that encourages companies to engage in shorter-term contracts. This flexibility is essential in a rapidly changing market environment.
Numerous market disruptions have also proven to be a boon for digital twins. For example, strikes at LNG plants in Australia have sent natural gas prices soaring in Europe. There have also been fundamental shifts in the supply-demand balance. After all, for the first time in the current energy landscape, there has been a European LNG premium, contrasting the almost paradigmatic Asian LNG premium the industry has been accustomed to.
These developments – and others – highlight the need for visualised digital twins and flexible multi-scenario models. By using this technology, stakeholders can better anticipate and quickly respond to market changes, ensuring more resilient and adaptive strategies in the face of uncertainty.
Enabling a market-driven approach
The ability to model future uncertainties and market conditions allows for adaptive strategies, fostering a more responsive and dynamic market-driven approach.
Digital twins facilitate this by enabling comprehensive modelling of market fundamentals, including supply and demand balancing and commodity price forecasting. This eliminates the complexity of evaluating individual contracts, allowing for a clearer representation of market responses.
Participants in the natural gas, LNG, and power industries can analyse which markets are most viable for investment and understand how market responses will impact those investments.
Furthermore, when discussing the creation of co-optimisation solutions, and integration of different sectors, flexible and adaptable tools are essential. These tools must be able to reflect the different characteristics of electricity, natural gas, and LNG. Not only do these resources operate in different units of measurement, but they also differ in time granularity, calorific value, and dispatch tasks.
Creating a cohesive, integrated digital twin that fully captures the nuances of different energy markets is a formidable task. Each market operates within its own ecosystem, governed by unique rules, dynamics, and nuances. From the hourly nuances of electricity generation and dispatch, to the stability of contracted volumes in the natural gas world, to the renewable-dependent nature of hydrogen production, every detail matters.
Reducing carbon emissions
In addition to operational efficiencies, digital twins are key tools used in the energy transition to lower carbon production. By simulating various scenarios, energy stakeholders can identify the most carbon-efficient pathways and strategies. This not only aligns with global emission reduction targets, but also helps companies meet increasingly stringent regulatory standards. As the energy ecosystem continues to prioritise sustainability, the role of digital twins cannot be overstated in achieving these goals.
1. Results from Energy Exemplar’s New England co-optimisation study comparing EIA’s expected natural gas usage vs the co-optimised offtake results in PLEXOS.
Overcoming challenges in the LNG market
The LNG market faces several challenges which include regulatory pressures, geopolitical issues, and the push towards green energy. Digital twins
Figure
play a crucial role in navigating these challenges by providing detailed, integrated analysis across interconnected systems. This capability is essential for evaluating the profitability of LNG projects and ensuring that the most beneficial projects are prioritised.
Simulation technology: A bird’s-eye view
Simulation technology, such as Energy Exemplar’s PLEXOS platform, provides a comprehensive view of potential outcomes across the LNG market’s interconnected segments. It offers both high-level insights, such as flows across countries, and detailed operational schedules at terminals. This breadth of analysis ensures accurate results by honouring all operational constraints and costs.
Traditional analysis methods often viewed assets and systems in isolation, leading to less comprehensive results. Digital twins overcome these limitations by providing an integrated perspective, essential for addressing the increasing interconnection between LNG and power sectors and the rising importance of emissions standards and renewable energy integration.
The future of digital twins in energy modelling
In the coming years, digital twins will continue to shape the LNG market by enhancing the ability to analyse new projects across the energy value chain. Advances in cloud computing and modelling software will expand the capabilities of digital twins,
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allowing broader groups to utilise these solutions for more comprehensive analyses.
As these tools become more accessible, they will play a critical role in investment decision-making and regulatory processes, further integrating and optimising the power and gas sectors.
As the energy ecosystem continues to evolve, integrating gas and LNG with power sector operations through digital twins and advanced energy modelling is essential. This co-optimisation ensures security of supply, drives efficient investments, and meets regulatory demands. Embracing these technologies and approaches will pave the way for a sustainable and resilient energy future.
Bibliography
1. DRANKA, G. G., FERREIRA, P., VAZ, A. ISMAEL, F., ‘A review of co-optimization approaches for operational and planning problems in the energy sector,’ Applied Energy, Vol. 304, (2021), https://doi.org/10.1016/j.apenergy.2021.117703
2. DONG, H., SHAN, Z., ZHOU, J., XU, C., CHEN, W., ‘Refined modeling and co-optimization of electric-hydrogen-thermal-gas integrated energy system with hybrid energy storage,’ Applied Energy, Vol. 351, (2023), https://doi.org/10.1016/j.apenergy.2023.121834
3. ‘ENTSOG and ENTSO-E publish their joint electricity and hydrogen Interlinked Model 2024 progress report for public consultation,’ ENTSO-E, (7 May 2024), www.entsoe.eu/ news/2024/05/07/entsog-and-entso-e-publish-their-jointelectricity-and-hydrogen-interlinked-model-2024-progress-reportfor-public-consultation/
4. ‘Progress Report on Interlinked Modelling. The Cross-Sectorial Integration of Energy System Planning,’ ENTSOG and ENTSO-E, (April 2024), www.entsog.eu/sites/default/files/2024-05/entsos_ ILM_progress_report_240430.pdf
"The co-optimization of the power module with the gas module is an area that is going to reveal some leading insights. Perhaps not just for BP."
-Ian Luciani, Head of Power Sector, BP
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Markus Haas, Global Industry Manager for Energy & Outdoor Automation, and Anette Schultis, Head of International Project Expertise, SICK AG, look at Germany’s LNG terminals as an example of how to reduce energy dependency and improve emissions.
ermany’s first LNG terminal, equipped with emissions monitoring technology from SICK, opened in Wilhelmshaven in 2022. Wilhelmshaven offers ideal conditions as a maritime port – it can accommodate all sizes of LNG tank ships regardless of tides and in compliance with the highest safety standards.
As LNG became a crucial resource, Germany quickly established the Höegh Esperanza, an FSRU. FSRUs are a critical component in shortening the timeline between engineering/procurement and production. An FSRU is a floating
vessel that can store and regasify LNG to destinations that do not have a dedicated onshore regasification terminal.
The Höegh Esperanza is docked in Wilhelmshaven. It supplies around 5 billion m 3 /y of natural gas, meeting about 6% of the country’s demand.
Reducing energy dependency
The German federal government expedited the FSRU project to reduce reliance on single energy sources, particularly Russian gas. The Höegh Esperanza, chartered for 10 years, regasifies LNG transported at -163˚C. The regasified gas is then metered using SICK Ultrasonic custody transfer ultrasonic flowmeters to accurately measure the gas production before it enters the country’s gas grid.
A notable feature of this FSRU is the use of SICK technology to measure emissions from the regasification process. An entirely new system that had not previously existed in this form was developed to meet specific requirements, including German federal emissions legislation.
In addition to the special requirements on explosion prevention, because it is in port for more than 10 days, German federal emissions legislation for large combustion plants applies to the ship instead of the requirements of the International Maritime Organization.
The MCS200HW has an ATEX hazardous area electrical classification which allows it to be used in an area that may have combustibles present, such as in LNG regasification processes.
Complex operations
This is a challenging project, not only because of these requirements but also because of the multitude of international players involved – from the shipyard and the
vessel’s owner to the authorities and various SICK offices in place such as South Korea, Japan, and Norway.
This international approach and the co-ordination involved made the project extremely dynamic and complex.
Uniper’s unit LNG Terminal Wilhelmshaven (LTeW) is responsible for the operational and technical management of the terminal, and acts on behalf of the state-owned Deutsche Energy Terminal (DET), which is responsible for the operation and marketing of all LNG terminals built on the German North Sea coast on behalf of the federal government. Due to the tricky situation surrounding the supply of gas, everything had to happen very quickly. SICK’s prior collaboration with Uniper, the terminal operator, facilitated the rapid deployment of the emissions monitoring system, which began operations in May 2023.
The first inquiries about emissions monitoring equipment for flue gases at LNG terminals were made back in 2016. In 2019, SICK worked with the boiler manufacturer, engine manufacturer and emissions experts from SICK to draw up a plan for monitoring eight sampling sites on-board an FSRU in accordance with emissions regulations.
The system was commissioned in 2022, with the installation of flanges and other preparatory work completed in October 2022 while the Höegh Esperanza was docked in Brest. The emissions measurement system began operations in May 2023.
When SICK received Uniper’s inquiry for the Höegh Esperanza in spring 2022, the existing plans proved advantageous, despite the ship’s unique technical specifications Its preliminary work, expertise, and the availability of the MCS200HW product enabled SICK to deliver its solution promptly.
Figure 1. Future FSRUs must be capable of zero-carbon energy generation, such as regasifying liquid ammonia.
The MCS200HW is a Hot-Wet Extractive analyser, which is uniquely suited to the LNG regasification application. The MCS200HW analyser can measure multiple components in a single analyser and keeps the sample heated above dew point, which in turn preserves acid gases from condensing and is ideal for dirty particulate laden samples.
This robust measurement provides reliable, accurate measurement capabilities even under the most adverse conditions, ensuring both compliance and maximum up-time and a very low cost of ownership. Also, filter wheels and cuvettes can be utilised for daily verification checks and positive indication of performance without the need for costly cylinder calibration gases.
Furthermore, the MCS200HW can be equipped with remote condition monitoring capability which monitors the status of key analyser components and provides customers with the ability to manage many different analysers in multiple locations with minimal human intervention, saving time and money.
The SICK emissions monitoring system began operations on the Höegh Esperanza in May 2023, following the transition period for emissions monitoring. Looking forward, the system can be adapted for zero-carbon energy generation, such as regasifying liquid ammonia, making the Höegh Esperanza a pivotal project with significant potential for future energy solutions. Additional FSRUs are planned for other locations in Germany, including Lubmin,
Stade, and Brunsbüttel. SICK, Inc. hopes to be a trusted partner for all future developments.
The green gas revolution
For the Höegh Esperanza, a natural gas supply was quickly established, and an effective emissions control system was implemented. Since LNG is considered a transitional fuel for climate change mitigation, future FSRUs must be capable of zero-carbon energy generation, such as regasifying liquid ammonia. Regasifying liquid ammonia will allow for the safe transportation of hydrogen to assist in the zero-carbon journey.
The MCS200HW analyser can be reconfigured to add additional measured gas components by minor modifications of the calibration curves in the spectrophotometer while utilising the same mechanical hardware. This allows the analyser system the flexibility to add an ammonia measurement in the future.
Conclusion
The inauguration of Germany’s first LNG terminal in Wilhelmshaven marks a significant stride toward energy independence and environmental accountability. The deployment of the Höegh Esperanza FSRU, with its advanced SICK emissions monitoring technology, not only diversifies Germany’s energy sources, but also ensures compliance with stringent safety and emissions standards.
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Bryan Bulling, RedGuard, USA, addresses the importance of comprehensive safety planning in LNG plants, reducing risk, and ensuring compliance with blast-resistant infrastructure.
Resist risk with blast-resistant infrastructure
t an LNG export facility, several significant blast hazards have the potential to pose serious risks. Cryogenic liquid spills can lead to rapid vaporisation and explosive mixtures if they encounter a heat source. Boil-off gas (BOG) can become explosive if not managed properly. Combustible gases that ignite can cause vapour cloud explosions, resulting in powerful blasts. Failures in critical equipment such as compressors, pumps, or storage tanks can lead to sudden releases of flammable gases, causing explosions. Inadequate or
malfunctioning detection systems can delay the response to a gas leak or fire, increasing the risk of an explosion. As far as general fire hazards are concerned, leaks of LNG or associated gases can ignite, and fires have the potential to occur in LNG storage tanks.
Two major LNG producers in the US are currently engaging RedGuard for thermal protective and blast-resistant buildings in their facilities. RedGuard is involved at both ends of the LNG journey, including liquefaction and regasification plants – the company supports the production side, the transmission side with pipelines and compressors, and the large waterfront facilities where LNG is stored and loaded onto vessels.
What are ‘multi-hazard’ buildings?
Multi-hazard buildings are designed to address a range of potential threats based on the specific needs of the facility. They offer blast resistance by being engineered to endure the intense forces of explosions, safeguarding staff, equipment, and assets during catastrophic events while also reducing liability and enhancing peace of mind. For fire resistance, buildings are equipped to handle various thermal challenges, including protection against fire, extreme heat, flash fires, and jet fires, using fireproof materials, insulation, and intumescent coatings. Fragment protection focuses on minimising risks from flying debris or fragments produced by explosions. Additionally, toxic gas protection involves implementing containment systems, emergency response plans, personnel training, shelter-in-place strategies, and advanced HVAC systems with purge and pressurisation capabilities, along with gas detection systems and reinforced structures to guard against toxic releases.
Conversely, a ‘blast-resistant building’ is a structure that has been designed to withstand significant blast events. These buildings are often constructed with thick steel walls and interior features and fixtures designed to withstand the heightened psi levels associated with small-to-large blast events. They are often found in LNG export and import facilities, oil refineries, chemical processing plants, or similar operations. Blast-resistant buildings may also be constructed from concrete, modular, built on-site, permanent, temporary, or a combination of these selections.
Risk analysis cycle for LNG infrastructure
Facility siting, a requirement for oil, gas, and chemical facilities, is governed by EPA and OSHA Process Safety Management (PSM) regulations and falls under the Process Hazard Analysis section of PSM. Facility siting studies (FSS) should be performed every five years. These studies, along with quantitative risk assessments (QRAs), are crucial for identifying potential hazards and developing effective mitigation strategies. Mitigation measures might include relocating personnel, constructing permanent blast-resistant or other protective structures, retrofitting existing buildings, or using temporary blast-resistant buildings customised for specific threats. Designing for these threats involves structural analysis methods like the Single Degree of Freedom (SDOF) approach, Finite Element Analysis (FEA), and independent field testing. Additionally, non-structural considerations, such as interior components and thermal protections, are also considered.
However, many large LNG export facilities are relatively new. This means, in many cases, they have not yet completed the required five-year cycle after which an FSS or risk analysis would be due. As a result, the first hazard review cycle for these plants is just now approaching. Some operators have proactively identified and mitigated hazards from the beginning, while others have postponed this process to the future. It is important to think ahead and identify risks and hazards in order to properly prepare for hazard reviews.
Recognising the hazards, many LNG companies are now leasing temporary buildings from RedGuard to house personnel on site until hazardous areas can be rectified, as well as providing permanent capital-type buildings for long-term use.
A tailored, rather than catch-all solution
Solutions should be specifically tailored to each customer’s needs. RedGuard begins with steel modular buildings designed for blast resistance, offering protection levels up to 15 psi, and then incorporates additional safeguards as required. In contrast, some companies use a ‘one-size-fits-all’ approach by recommending multi-hazard buildings. While this method provides broad protection, it may not always be the most suitable strategy. A risk-based approach, which thoroughly evaluates the specific threats relevant to the location, often results in a more efficient, cost-effective, and customised solution.
Deploying ‘catch-all’ multi-hazard buildings in all areas that require threat mitigation can create additional problems, such as:
z Increased costs due to additional specialised materials, engineering, and construction.
z Increased weight – the larger the building, the more difficult it is to handle and ship.
z Over-engineering, resulting in inefficient use of materials and resources.
z More complex and costly maintenance.
z Larger facility footprint.
Precision for the LNG industry
Using precise safety measures is RedGuard’s customised approach to multi-hazard safety, addressing the unique risks and challenges of each location. Unlike a more generic approach to hazardous environments, this approach focuses on delivering targeted, effective solutions to safeguard lives and assets. It goes beyond basic multi-hazard strategies by tailoring solutions specifically to the needs of each facility.
Benefits
Modular construction
LNG plants often face controversial and delayed approvals, leading to a rush to become operational quickly. Modular construction is ideal in this scenario, enabling rapid deployment and immediate readiness. Blast-resistant modules can be used to provide temporary shelter during
plant turnarounds, which occur every 3 – 5 years, and then relocated or removed when no longer needed.
Fire and blast resistant
RedGuard’s buildings are specifically designed to resist fires and blasts, the two most prevalent hazards at LNG sites. The speed of modular construction, combined with features to withstand fire and explosions, makes the buildings highly effective for these environments.
Flood and corrosion resistant
Buildings in coastal areas are elevated to a level above the 500-year storm surge and can be designed to withstand the wind load of a category 5 hurricane, or 157 mph. These details are crucial to ensure that storms do not disturb the export process. Because we are in the midst of an active hurricane season, everyone is vigilant about potential storms. Since export facilities are all located on the waterfront, the company’s buildings are designed to be elevated to avoid flood risks and specially coated to resist the salt and corrosion that occurs in coastal environments.
A commitment to ethical practice
In any team project, especially in safety-critical fields like the oil and gas industry, it is crucial that all members offer unbiased recommendations. The team creating safety specifications must remain neutral and separate from the manufacturing and sales processes to avoid conflicts of interest. If the same team profits from constructing and selling the solution, they might face biases due
to pressures to meet deadlines, budget constraints, or sales targets, potentially compromising the integrity of their recommendations.
To counter the risk of bias in the process of installing blast-resistant buildings in the LNG industry, Dr Ali Sari, a world-renowned blast engineer with more than 20 years of experience in the analysis of onshore and offshore structures and blast resistance engineering, is regularly called upon to guide RedGuard’s best practices for fabricating buildings that can withstand explosions, especially on waterfront properties. RedGuard is also currently promoting a second opinion programme, which aims to offer an independent review.
When the buildings are tested, the setup and analysis are conducted by third parties. Third-party engineers, rather than in-house engineers, are always called upon to refine the designs and provide guidance, to eliminate the risk of bias. Some companies are entering their first cycle of hazard review and may benefit from understanding the importance of ethical practices and independent evaluations, as newer companies might not be aware of how these practices impact the quality and reliability of their buildings.
Ethics, responsibility, and safety
RedGuard believes it is important to commit to developing projects ethically, methodically, and correctly from the start, efficiently educating customers who may be new to implementing blast-resistant buildings along the way. Working closely with clients to identify their needs is the best way to maintain long-term relationships, ensuring a seamless journey from initial consultation to final delivery.
Gary Gibson, STS Marine Solutions Ltd, UK, highlights a new option for traders.
One of the primary drivers of the increase in a need for LNG cargoes is the growing global demand for LNG as a cleaner alternative to other fossil fuels. As more developing countries and companies commit to reducing their carbon footprints, the need for efficient and flexible LNG transportation solutions has become
more pronounced. Ship-to-ship (STS) transfers offer a way to meet this demand without the need for extensive onshore infrastructure.
Another contributing factor is the strategic positioning of LNG supply chains. By utilising STS operations, companies can optimise their logistics and reduce
transportation costs. This is particularly beneficial in regions where onshore facilities are either unavailable or insufficient to handle the volume of LNG being traded. As a result, STS operations have become an integral part of the global LNG supply chain.
According to industry reports and data from maritime organisations, there are hundreds of LNG STS operations conducted annually. For instance, in 2020, it was estimated that there were over 200 such operations globally. This number has likely increased in subsequent years as more countries and companies invest in LNG infrastructure and seek flexible delivery options.
A shift in LNG
One shift that is being seen are LNG traders and suppliers moving towards consolidation of cargoes.
Many developing nations and nations with smaller energy needs still require LNG, just not at the volumes often traded. This is where consolidation comes into the supply chain.
A typical LNG carrier chartered by the energy companies can deliver between 130 000 – 260 000 m 3 Many newer importers of LNG typically want cargo volumes of 100 000 m 3 or less.
Smaller LNG vessels can be difficult and expensive to charter and are often tied to long term deals, this is where consolidation comes into play.
Cargo traders can use their existing tonnage to deliver the cargo according to the clients’ need and then relocate to an established and safe STS location and transfer the remaining cargo to a waiting vessel, usually consolidating a new cargo for delivery in 4 – 5 operations – this maximises cargo lifted and vessel capabilities.
Putting it into practice
An example of this model is used in the Asian markets of Taiwan and Thailand.
A nominated vessel will offtake approximately 150 000 m 3 of LNG from a US terminal and sail the cargo to delivery in Thailand’s Nong Fab import terminal and offload approximately 130 000 m 3 . This results in either a under optimised vessel or the trader trying to sell a small parcel en route back to the US.
Using the consolidation method, the trader can then relocate the vessel to anchorage and the future remaining parcels can be loaded onto the vessel until it reaches the desired cargo volume for another delivery.
With charter rates of LNG vessels hitting US$70 000/d in January 2024, this can result in significant savings on a voyage from the US usually taking 30 days. With every five voyages delivering an extra cargo to Thailand.
Similar models have been used in Taiwan and other Asian ports through 2020.
The emergence of new players in Southeast Asia, such as Thailand, Vietnam, and the Philippines, is also noteworthy. These countries are developing LNG import facilities and seeking to diversify their energy mix. The growing interest in LNG in Southeast Asia is driven by the need for reliable and more bespoke cargo sizes.
The rise of FSRUs
The rise of FSRUs has facilitated the entry of LNG into emerging markets in Asia and beyond.
FSRUs offer a cost-effective and flexible solution for countries looking to quickly establish LNG import capabilities without the need for extensive onshore infrastructure. This technology has been instrumental in enabling smaller and emerging markets to access LNG in Asia. Inventory control can make it difficult for an LNG tanker to offload her full cargo. Once again, consolidation is a method being considered to help maximising LNG tanker delivery, particularly on long voyages from the US to the Asian markets.
Conclusion
Overall, the emerging LNG markets in Asia present significant opportunities for LNG suppliers and service providers. The region’s growing energy demand, coupled with the shift towards cleaner energy sources, underscores the importance of LNG in Asia’s energy landscape. As these markets continue to develop, STS LNG transfers will play a crucial role in ensuring efficient and flexible delivery of LNG to meet the region’s diverse energy needs.
Figure 2. Hose connection in preparation for cool down.
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Denis Griffiths, B.Eng (Hons), MSc., Ph.D, Worldwide Marine Technology, outlines factors to consider for safe ship-to-ship bunkering operations.
NG has a positive impact on the marine industry but it is also problematic. Burning of natural gas in ‘diesel’ engines, or its use in electricity generating fuel cells, is positive due to the reduction in greenhouse
gas emissions and other emissions such as nitrogen oxides, particulate matter, and sulfur dioxide. Natural gas in liquid form is readily transportable but that is where problems arise.
For use in marine internal combustion engines, LNG cannot stand alone due to its high ignition temperature; gas ignition is achieved by Pilot Injection of fuel oil which adds to the complexity (and cost) of the engine system, as well as the need for additional fuel oil tanks and equipment. These are relatively minor matters, but all equipment requires maintenance and increased complexity means that operator knowledge and training will cost more. Shipboard use of LNG requires education, knowledge, practical training, and experience; experience comes from operating equipment and competent operators are essential for the safe use of LNG aboard ship. Training and knowledge acquisition take time and it is not about learning facts, a well trained and experienced ship operator learns ‘on the job’. That is where good documentation is essential. Technical Operating Manuals, such as the comprehensive documents supplied by Worldwide Marine Technology, provide reasons for procedures and not just instructions. Such documents are educational.
Use of LNG in the marine industry poses problems concerning the safe delivery of LNG to the ship. LNG is a natural gas that at atmospheric pressure has been cooled into a liquid state at a temperature of approximately -162˚C. The liquefaction process to form LNG reduces the volume of the gas by a factor of approximately 600 times, making it more effective for transportation and storage. LNG is a mixture of substances, predominantly methane (which constitutes approximately 80 – 95% of the mixture). There are hazards that must be understood when handling LNG, especially during its transfer to the ship from a supply vessel. Foremost amongst the potential hazards of LNG is fire risk. Knowledge, understanding, and training are essential.
LNG fire risks
In its liquid state, LNG is not flammable; however, it is highly flammable in the vapour phase and will readily burn when there is a 5 – 15% by volume mixture with air. Leaking LNG vaporises rapidly, becoming gas (methane plus trace gases), and mixes with air. If this mixture is within the flammable range, there is risk of ignition which would create fire and thermal radiation hazards. Specialist equipment is used for LNG handling and specific procedures are designed to prevent formation of a flammable mixture and to ensure that sources of ignition do not exist anywhere near any flammable mixture. These problems are there for any transfer but are exacerbated when the delivery and receiving stations are afloat and attached to each other.
Fires can start in different ways and act with different characteristics:
z Flash fire: This occurs when a cloud of gas burns in an open area without generating any significant overpressure. An ignited cloud will ‘flash back’ and burn its way back to the LNG spill source.
z Pool fire: This occurs when LNG spills evaporate and the gas, in a combustible gas-air concentration above the pool of liquid LNG, ignites and burns, either on water or on land.
z Jet fire: This can occur due to gas or liquid release from a pressurised system (bunkering line). The flow velocity in a jet fire will be very high and is likely to cause damage to structure and equipment. Extensive damage results when there are many closely positioned rooms or spaces.
z Boiling liquid expanding vapour explosion (BLEVE): This is a vapour explosion which can occur if LNG in a closed containment is heated up. Onboard the ship, the LNG is usually stored in Type C tanks and delivered via a bunkering line; if a tank or bunkering line collapses, sudden decompression produces a blast resulting in drastic pressure reduction. This results in rapid boiling of LNG creating large quantities of vapour which ignites if the vapour is in its flammability range.
A vapour cloud explosion can occur when a large flammable mass of methane is ignited in a confined space (e.g. an enclosed box such as an engine or tank room, or in the bunkering station). In open spaces, there is no confinement and experimental evidence suggests that methane gas will burn relatively slowly with expansion resulting in a vertical rise of gas.
As can be appreciated from the above, there is a greater risk of a fire when loading (bunkering) LNG than during storage or use.
Ship-to-ship bunkering procedure
LNG bunkering hoses are designed and certified according to strict standards. Typically, the LNG bunkering hose is provided by the supplier. It should be suitably long and flexible, so that it can remain connected to the manifolds of the supply and receiving ships during normal relative movements, expected from wind, waves, current and surges from passing vessels. Ship-to-ship transfer of LNG is more problematic than transfer from a static depot ashore to a floating ship because ship-to-ship transfer has supply and receiving stations moving independently of each other. Cranes and transfer hose support structures on the supply vessel must support a full hose and allow for movement between both vessels without putting additional strain on the transfer hose.
The bunker hose should be capable of being released from its connection at the receiving vessel bunker pipeline without damage or significant spills. The hose and its support arrangements must allow for relative movement between the supply and receiving vessels. LNG bunker hose and receiving vessel bunkering pipe are typically fitted with connections of the quick-connect/release type with isolating valves which remain sealed until the connection is made and must seal the ends of the pipes before the connection is released. The connection part of the hose (receiver end) is also usually fitted with an emergency release system (ERS), a breakaway coupling. When there is excessive relative movement between the supply and receiving vessels, the ERS will give way and release the hose connection before excessive pull can cause the hose to break or other damage can occur. This type of coupling uses spring loaded shut-off valves, at the hose
Growth | Connections | Brighter Futures
and the receiving vessel loading manifold, to seal the break and stop any LNG or vapour release. Strict codes govern bunkering arrangements and the IGF Code is the International Code of Safety for Ships using Gases or other Low-flashpoint Fuels. All personnel involved with supplying and receiving LNG must know and understand the IGF code which defines three zones. Good Technical Operating Manuals provide this information:
z Hazardous Zone: An IGF Code Hazardous Zone area is intended to minimise the likelihood of ignition from electrical equipment. The hazardous zone restricts the type of electrical equipment allowed within prescribed distances from the line/hose connections on the ship and bunker supplier. Surrounding the LNG bunkering manifold connections, a hazardous area must be defined and the Port Authority must confirm, by inspection, that all personnel working in the defined hazardous zones are authorised and correctly trained.
z Safety Zone: A Safety Zone is an area present during bunkering and within which only essential personnel are allowed; potential ignition sources are controlled. This further minimises the likelihood of an LNG release and possible gas ignition. The Safety Zone is approved by the Port Authority and must be defined for each individual ship to ship bunkering situation in order to ensure effective gas dispersion.
z Security Zone: This is a defined controlled access area for port activities in the vicinity of the LNG bunkering operation. The Port Authority is responsible for the Security zone with the objective of controlling all possible elements that may interfere with the LNG bunkering operation. This includes any other vessels moving to or from ships involved in the bunkering procedure.
There are strict regulations governing ship-to-ship LNG bunkering with a number of parties involved. Each party must understand its role and all must work together to prevent incidents and ensure the safety of people should an incident occur.
Training for LNG bunkering
It is essential that all personnel involved in LNG bunkering operations have received appropriate training and are suitably qualified for the roles they undertake. Trained personnel must undergo frequent testing and appraisal regarding the roles they play. Individuals who have been trained on-board other vessels must receive additional training for the current vessel; a dedicated Technical Operating Manual for the ship provides necessary details. Training must cover the safety of other people on the vessel, avoidance of hazardous situations and appreciation of the dangers from other vessels and weather. Before bunkering, personnel in charge of operations on board the supply and receiving vessels must discuss the current weather situation and be aware of the weather forecast for the bunkering period. Strong wind
and high seas can put additional and unexpected loading on the bunkering hose with increased risk of hose detaching or breaking. Education, training, and experience are essential for all involved in LNG transfer operations. Common sense is essential if changing weather and other situations are to be correctly assessed; being able to ‘read’ a situation gives operators time for shutting down a bunkering operation before the situation becomes dangerous.
Emergency response plan
There must be a designated person in charge (PIC) who oversees the entire bunkering operation. The Port Authority should, in co-operation with other relevant competent authorities, approve an emergency response plan (ERP). This encompasses existing port emergency or contingency plans and is essential for major accident scenarios, where good co-ordination between all parties is indispensable. To ensure adequate implementation of the ERP, the Port Authority must provide an adequate training program for all relevant members of the emergency response organisation. The Port Authority must ensure that all staff concerned with ship to ship bunkering activities are aware of their emergency roles. Training for LNG bunkering emergency response teams must involve all relevant operators.
Conclusions
The points that have been discussed are fine aspirations and, if everybody plays their part correctly and works closely with others, then safe bunkering operations should result. Unfortunately, things do not always go according to the best laid plans as many people and items of equipment are involved. Trained personnel do not always get systems to react correctly or quickly enough to prevent a damaging incident.
Not all possible dangerous situations can be appraised, broken down into corrective steps, and memorised. Correct and frequent training is important, but common sense in assessing potentially hazardous situations, which have not been experienced before, is essential. Planning and rules are fundamental for dealing with known hazards but the unexpected can arise and operators must be able to ‘think on their feet’ devise a way out. Human error is often responsible for dangerous situations; bunkering during a storm can be avoided but some situations cannot always be predicted, that is where training and working together comes in.
If something goes wrong during bunkering between the receiving vessel and bunker vessel, there would not even need to be an impact – the wash from a vessel would be enough to disturb the pipeline connection between the bunkering vessel and the ship being bunkered. The only way around that is wide segregation and bunkering operations miles from any shipping routes. A possible solution is designated LNG bunkering areas well outside of the normal shipping lane and harbour with air exclusion zones. But the weather still cannot be controlled. That is when operating and training documentation expertise, such as what Worldwide Marine Technology provides, will offer great support.
CLEANER OPERATIONS TO DELIVER A BETTER TOMORROW.
Since 1966, altair ® gas turbine air intake filtration has delivered increased gas turbine protection, productivity and profitability.
Visit Stand A232 at Gastech 2024 to learn how we are helping to solve the world’s greatest engineering challenges.
LNG Industry previews a selection of companies that will be exhibiting at this year’s Gastech in Houston from 17 – 20 September 2024. Visit LNG Industry at Stand D386.
Aspen Aerogels, Inc.
Stand D204
Driving energy efficiency for a cleaner, more sustainable future, Aspen Aerogels has been delivering innovative thermal solutions for over 20 years. Cryogel® Z insulation is a top choice in cryogenic applications, offering protection against cold splash, jet fire, and acoustic attenuation all in an ultrathin, lightweight, and flexible blanket design. As a performance proven aerogel technology, Cryogel Z insulation has been specified and used in nearly 50 major LNG liquefactions and regasification projects around the world.
Axens
Stand C100d, France Pavilion
Axens offers a complete range of solutions for natural gas treatment and conversion options, cleaner fuels, the production and purification of major petrochemical intermediates, the chemical recycling of plastics, water treatment, and carbon capture. The company’s offering includes technologies, equipment, furnaces, modular units, catalysts, adsorbents, and related services. Axens is ideally positioned to cover the entire value chain, from feasibility studies to start-up and monitoring of units throughout their lifecycle. In the natural gas market, Axens is ideally
positioned to provide all the treatment, purification, and drying technologies needed for the production of purified natural gas in onshore and offshore conditions.
Baker Hughes
Stand C320
Baker Hughes is an energy technology company that provides solutions to energy and industrial customers worldwide.
Built on a century of experience and with operations in over 120 countries, the company’s innovative technologies and services are taking energy forward –making it safer, cleaner, and more efficient for people and the planet.
BASF
Stand A461
BASF’s gas treatment portfolio, featuring OASE® amine and Durasorb® adsorbent technologies, are instrumental in delivering essential gas treatment solutions to its customers. Throughout the value chain, BASF combines experience, reliability, and innovation, establishing itself as a distinct supplier and partner in the gas industry. The company’s diverse portfolio encompasses acid gas removal, heavy hydrocarbon removal, and dehydration, addressing fundamental gas treatment needs. Moreover, BASF actively promotes sustainability across the value chain, facilitating the transformation of the chemical industry towards achieving net-zero emissions.
Bechtel
Stand B470
For more than 125 years, extraordinary teams at Bechtel have been bringing to life inspiring projects and building a legacy of leadership, innovation, and progress. But as new challenges and opportunities shape the future, it is clear that a better world still has to be built.
At Bechtel, the people live for a challenge. The company is excited by tomorrow and the possibilities it holds to change lives and create a more prosperous, sustainable, connected, secure, and equitable world.
Black & Veatch
Stand C110
With more than 100 years of proven experience in delivering innovative and comprehensive solutions across the full gas value chain, Black & Veatch is helping clients navigate the energy transition as they seek to succeed in a lower carbon future through diversified, bankable energy products.
Burckhardt Compression
Stand D620, Hall D
Burckhardt Compression creates leading compression solutions for a sustainable energy future and the long-term success of its customers.
Burckhardt Compression. A reliable partner for boil-off gas compression.
Baker Hughes. Baker Hughes’ LM9000 aeroderivative gas turbine (73.5 MW, 50/60 Hz) – the most efficient gas turbine in the 65+ MW power range.
Solutions for Tomorrow‘s Energy Infrastructure
At NEUMAN & ESSER, a century of Hydrogen compression expertise meets the technologies required for a decarbonized society. As an OEM for reciprocating compressors, electrolyzers and reformer systems including HRS, we bring in all plant components along the value chain and balance them for the optimal overall solution.
Family-owned for almost 200 years, today more than 1,600 employees are committed to bringing challenging projects to life around the world –from evaluating project feasibility, through engineering, construction, and commissioning to digitally supported 360° service during operation.
Enjoy our new Web Presence: www.neuman-esser.com
Together with its brands (PROGNOST, SAMR Métal Rouge, and Shenyang Yuanda Compressor), the company is a global manufacturer that covers a full range of reciprocating compressor technologies and services. Its customised and modularised compressor systems are used in the chemical and petrochemical, gas transport and storage, hydrogen mobility and energy, and industrial gas sectors, as well as for applications in refinery and gas gathering and processing.
CB&I
Stand A560
CB&I is the world’s leading designer and builder of storage facilities, tanks, and terminals. With more than 60 000 structures completed throughout its 130-year history, the company has the global expertise and strategically-located operations to provide customers world-class storage solutions for even the most complex energy infrastructure projects.
Chart Industries
Stand B170
Chart is proud to work alongside others creating its shared goal of advancing LNG and hydrogen as key contributors to a lower carbon, sustainable energy future.
The company’s deep cryogenic and compression expertise and proven track record makes Chart an ideal project partner to deliver LNG and hydrogen as secure, clean, safe, and affordable fuels for energy and transportation. At the cornerstone of the business is a broad portfolio of complementary products and it is the integration of these products to deliver highly-engineered solutions, used from the beginning to the end in the liquid gas supply chain, that makes Chart unique.
Cheniere
Stand B252
Cheniere is the largest producer of LNG in the US and the second-largest LNG operator globally. The company provides secure, flexible, and affordable energy to the world. Its full-service LNG capabilities include gas procurement and transportation, liquefaction, vessel-chartering, and delivery. Cheniere is a Fortune 500 company headquartered in Houston, with liquefaction facilities in Louisiana and Texas and offices in Beijing, London, Singapore, Tokyo, and Washington, D.C. Its LNG has reached over 35 markets on five continents, and demand for its energy is expected to grow as countries seek lower-carbon solutions to power their economies. At Cheniere, they are energising a more secure future.
Chevron Corp.
Stand C150
Chevron Corp. is one of the world’s leading integrated energy companies. It believes affordable, reliable, and ever-cleaner energy is essential to achieving a more prosperous and sustainable world. Chevron produces crude oil and natural gas; manufactures transportation fuels, lubricants, petrochemicals, and additives; and develops technologies that enhance its business and the industry. The company is focused on lowering the carbon intensity in its operations and growing lower carbon businesses along with its traditional business lines.
DESMI Pumping Technology A/S
Stand D472
DESMI’s NDW pumps are energy-efficient and reliable, ideal for pumping LPG, LEG, and a range of chemicals, including CO₂. Features include:
z Pro ven double shaft seal to prevent leakage.
z Easy shipment and assembly.
z Reduced impeller stages.
z Count er-rotation capability for ice-blocking.
z Simple installation and maintenance.
z Energy efficienc y and NPSH compliance.
Chart Industries. Chart’s modular approach to LNG liquefaction results in smaller footprint, higher efficiency, less cost, reduced schedule, and faster LNG to market
Cheniere. Two vessels docked at Cheniere’s Sabine Pass Liquefaction Facility in Louisiana.
Efficiency on board with our compression solutions
Burckhardt Compression offers a complete portfolio of compressor solutions for marine BOG management.
Learn more: burckhardtcompression.com/marine
Our compressor systems supply BOG to low- and high-pressure dual-fuel engines, which is the most efficient way to manage BOG. In addition, Burckhardt Compression has a global network of local service centers that enables us to offer local support with a quick response rate. Visit us at
Founded in 1834, DESMI develops, manufactures, and services pumps for gas and chemical tankers, supporting the marine industry’s greener future and supplying over 150 countries globally. In 2022, DESMI relaunched its cargo pumps for liquefied gas.
EffecTech
EffecTech is a global leader in gas measurement, providing accredited products, support services, and consultancy. From its UKAS accredited calibration and testing laboratories in the UK, EffecTech supplies high-quality products and services to customers globally, ensuring traceability and accuracy for natural gas, and transition fuels, including LNG, biomethane, and hydrogen-enriched fuel gases.
Emerson
Stand D270
Increase throughput and safely optimise operations across the entire natural gas value chain using Emerson’s complete automation portfolio, including advanced intelligent devices, control systems, and design and optimisation software solutions. Whether it is an existing installation or a new greenfield operation, Emerson’s scalable floor-to-cloud automation solutions allow companies to digitally transform their operations, reduce energy intensity and emissions, and improve safety, productivity, and reliability.
Learn more at Emerson.com
Enbridge Inc.
Stand A550
Enbridge safely connects millions of people to the energy they rely on every day, fuelling quality of life through its North American natural gas, oil, and renewable power networks and its growing European offshore wind portfolio. The company is investing in modern energy delivery infrastructure to sustain access to secure, affordable energy and building on more than a century of operating conventional energy infrastructure, and two decades of experience in renewable power. Enbridge is advancing new technologies including hydrogen, renewable natural gas, and carbon capture and storage. To learn more, visit enbridge.com.
Endress+Hauser
Stand D670
Endress+Hauser is a global leader in measurement instrumentation, services, and solutions for industrial process engineering. The company provides process solutions for flow, level, pressure, analytics, temperature, recording, and digital communication, optimising processes in terms of economic efficiency, safety, and environmental impact.
Endress+Hauser Optical Analysis is the global leader in spectroscopic instrumentation for chemical composition and concentration analysis. The company’s offerings
harness the powerful analytical information of Raman spectroscopy, tunable diode laser spectroscopy (TDLAS), and quenched fluorescence (QF) to help its customers understand, measure, and control their laboratory and process chemistries.
Energy Exemplar
Stand D690
In an era where the world is rapidly advancing towards a cleaner future, stakeholders from across the energy value chain are navigating the complexities of the energy ecosystem. Energy Exemplar seeks to enable its customers to do so with confidence – the company is ‘Empowering Transformative Energy Decisions’. Founded in 1999, the PLEXOS ® modelling and simulation platform is trusted by companies across one-third of the world to revolutionise the future of energy.
At Gastech, learn how PLEXOS integrates gas and power sectors, driving efficiency and sustainability. Join Energy Exemplar’s daily booth sessions on ‘Co-optimising the New England States’ (11:00 am) and ‘The emerging hydrogen market in Europe’ (2:00 pm).
ExxonMobil
Stand C120
ExxonMobil, one of the largest publicly traded international energy and petrochemical companies, creates solutions that improve quality of life and meet society’s evolving needs.
The corporation’s primary businesses – Upstream, Product Solutions, and Low Carbon Solutions – provide products that enable modern life, including energy, chemicals, lubricants, and lower-emissions technologies. ExxonMobil holds an industry-leading portfolio of resources, and is one of the largest integrated fuels, lubricants, and chemical companies in the world. To learn more, visit exxonmobil.com and the Energy Factor.
With over 40 years of global leadership experience in LNG, ExxonMobil is active across the natural gas value chain. The company’s global presence, combined with its ability to leverage expertise across its businesses, enables it to create innovative integrated, lower-emission solutions and positions ExxonMobil to help meet the world’s growing natural gas and power demands.
Gas and Heat S.p.A.
Stand B150
Gas and Heat is a leading company in the design, construction, supply, and installation of plants and tanks for the propulsion and storage of liquefied gases for marine use. The company’s core business sees it also engaged as an EPC contractor of plants for the storage of LNG on land.
Gas and Heat is an Italian company that looks to the world: 70 years of history have taught the company the value of time and the importance of making quality choices, on which to invest also in terms of the future. The company design complete solutions, taking care of the
with heat pumps running on sustainable electricity
We’re unleashing the power of clean heat
Burning fuel to generate heat accounts for some 50 % of energy consumption and 40 % of carbon emissions. Our heat pumps extract heat from a lowtemperature source like water or air and amplify it to temperatures useful for district heating or industrial processes. The technology is extremely reliable, robust, efficient, and scalable to your needs. You get heating and cooling that is inexpensive and clean.
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feasibility study, the design, and the drafting of the construction specification, as well as the purchase of all the necessary components for the construction of the plants both in marine and on land.
Habonim Industrial Valves & Actuators Ltd
Stand E202
HABONIM has 75 years of experience and leadership in demanding applications, including the design, manufacture, and supply of superior valves, alongside professional support and co-operation with the leaders of the renewable energy market. With decades of proven safe and long-lasting use in hydrogen (H 2 ) and LNG applications and an unmatched product portfolio specially designed, tested, and certified for H 2 and LH 2 , the company is the right partner.
Habonim is part of ITTs Industrial Process segment.
Honeywell Stand C162
Join Honeywell at Gastech 2024, the world’s leading forum dedicated to delivering a more sustainable energy future. From transitional and renewable fuel process technology and modular equipment to advanced automation systems and cutting-edge digital solutions, Honeywell is there at
every step of energy transition, offering a comprehensive set of solutions to fit tailored business needs and sustainability goals. Learn more at honeywell.com
Johnson Matthey Stand E250
Removing impurities from LNG and sustainable feedstocks is critical to meet safety standards and specifications for downstream use. With 40+ years of experience, Johnson Matthey’s PURASPEC TM absorbents combined with its PURAVOC TM oxidation catalysts provide a highly efficient, easy-to-operate, and economic solution. Johnson Matthey’s leading expertise in Purification and Syngas chemistry are at the core in fulfilling the company’s mission of ‘Catalysing the Net-Zero Transition’ by developing catalyst technologies for sustainable fuels and chemicals. Visit Johnson Matthey’s stand at Gastech to discuss all of these topics with its experts.
Mexico Pacific Stand B550
Mexico Pacific’s anchor project, the 15 million tpy Saguaro Energía LNG Facility, is the most advanced LNG development project on the West Coast of North America. The Saguaro Energía LNG Facility achieves significant cost and logistical advantages, resulting in the lowest landed price of North American LNG into Asia by leveraging low-cost natural gas sourced from the nearby Permian Basin and a significantly shorter shipping route avoiding Panama Canal transit risk. Visit http://www.mexicopacific.com for more information.
MIB ITALIANA SPA
Stand B153
MIB is a world leader in the supply of emergency release system, and specifically in the supply of turnkey transfer solutions for the gas industry. Since the early 1970s, the company’s ongoing engineering developments have allowed it to provide the highest standard of equipment for the safe transfer of LNG, LPG, and other cryogenic and refrigerated, as well as high pressure gaseous, fluids. This result has been made possible thanks to the continuous close liaison with major oil and gas companies, vessel and terminal owners and operators, and to the company’s focus to match the ever-increasing and stringent demands of this industry.
OPW
Stand A360
OPW is committed to shaping the future of the clean energy industry, and strategically
Mexico Pacific. The Saguaro Energía LNG facility is a foundational pillar of the Sonora Plan that promotes clean energy development, investment, and economic prosperity. This world-class infrastructure will strengthen global energy security, reduce emissions, and improve the lives of millions of people around the world.
Johnson Matthey. Johnson Matthey oversees the loading of PURASPECTM absorbents at a customer site.
Visit us at Gastech 2024, Booth B210, in Houston to learn more
Panos Mitrou, Global Gas Segment Director, and Jose Navarro, Global Gas Technology Director, Lloyd’s Register, examine how the maritime industry is positioning itself to carry increased volumes of ammonia, and its potential as a future fuel.
Ammonia (NH3) is one of the most frequently traded commodities, with large volumes of the chemical compound moved by ocean-going vessels every year.
Lloyd’s Register’s (LR) Fuel for Thought’s deep dive into the use of ammonia as a fuel for ships reveals that around 180 million tpy of ammonia is produced, with a significant 20 million tpy moved on ships.
This demand stems from its use in a variety of industries, including plastics and synthetic fibres, with a significant 70% of production absorbed by the fertilizer industry. Whilst much of the ammonia currently produced is high emission grey ammonia made from natural gas, green ammonia is free of carbon dioxide (CO2). It is set to play a significant role in emissions reduction in
hard-to-abate industries, including maritime, as countries and industries aim to decarbonise by 2050.
Coal remains a staple component in electricity production in many nations, but firing coal with green ammonia cuts CO2 emissions. The fastest way to decarbonise coal plant assets is co-firing ammonia. LR projections show that using 20% green ammonia with 80% coal, can produce a rough 20% carbon emissions reduction. Green ammonia must be used, while the lifecycle analysis of its value chain must also be green, this will eventually also include shipping and ammonia carriers being requested to sail on ammonia. It may be possible to increase the ratio of green ammonia to coal to bring further emissions reductions.
Ammonia also offers an easier way to store and transport hydrogen, which is also gaining traction as a future fuel, due to its higher energy density, and unlike hydrogen does not require cryogenic storage.
Moving cargoes
As demand for green ammonia increases, so too does transport of the product. Quick to see an opportunity, shipowners have placed orders for further tonnage in recent months to support the expected increase in cargoes.
Clarkson’s data reveals that over the past 13 months, 45 ammonia/LPG carriers have been ordered. Greek companies account for nearly half of these vessels, whilst Denmark and Singapore have both secured several vessels.
Some of these vessels often supersede the traditional very large gas carriers (VLAC) size of 80 000-93 000 m3
One example is a LR and Guangzhou Shipyard International’s (GSI) joint development project (JDP) to build an ammonia carrier with a cargo-carrying capacity of 100 000 m3 announced in June 2024. In the same month, LR also awarded approval in principle (AiP) to Samsung Heavy Industries (SHI) and Amogy for an 88 000 m3 fuel cell-powered ammonia carrier, which uses ammonia cracking to create hydrogen for the fuel cell stored on board.
Ammonia carriers can also carry other liquid gases, such as LPG. The high toxicity level and corrosive properties of the product, requires ammonia carriers to be built with additional safety features, resulting in a higher build cost. But this does not prevent them from carrying other cargoes such as LPG, offering flexibility on the cargoes that these vessels can carry. When the new VLACs that have recently been ordered come online, they can be put to work straight away, carrying other liquid gases if the ammonia network is still developing.
Owners are examining their options. The vessels being ordered today will be ready to take full advantage of the market in 10 – 15 years’ time. But the higher specifications, and therefore increased CAPEX, may make the carrying of LPG, whilst the ammonia market develops, less attractive.
Establishing supply chains
Existing trade routes for ammonia are being expanded as new ammonia production sites start to emerge. Green ammonia is made using renewable energy, deriving hydrogen from water and nitrogen from air. Solar energy is required in the process and so prospective centres for green ammonia production are anticipated in sunnier climes.
Australia has the right climate and a proven track record in renewable energy performance including in wind energy. It is expected to be a key exporter of green ammonia to countries in Asia. Egypt, Morocco, and the Middle East are eyeing local markets in Europe, along with Chile, noting that additional volumes also include blue ammonia, which is made using natural gas with carbon capture incorporated into the process.
Trade routes will be determined by the ammonia producers and for seaborne cargoes, terminals will likely be located close to production and built to accommodate VLACs of 80 000 – 90 000 m3 or even larger.
Safety first
Despite ammonia’s toxic and corrosive properties, vessels carrying the cargo have a good safety record; vessels must be built in line with the International Code of the Construction and Equipment
of Ships Carrying Liquefied Gases in Bulk (IGC Code). Ammonia is not as flammable as LNG, but it has other hazardous properties and can be harmful even in small quantities. For these reasons, systems for ammonia carriers are designed so that failure is immediately detected, managed, controlled, and mitigated; noting that there has never been a total loss of an ammonia carrier at sea.
Looking at the long-term outlook for ammonia cargoes and the availability of suitable tonnage, LPG vessels can be converted to carry ammonia during regular dry docking, but this takes time and planning, particularly to consider material grade of ship’s cargo tanks. Other aspects to consider include cargo pump enhancement, motors, and electric cables, among other details.
More than a cargo
Maritime is also turning its attention to green ammonia inwards and examining the opportunities for its use as a fuel. Plans are in motion as ammonia carriers on order today will be ammonia-ready for when the technology and fuel supply chain is established. Engine manufacturers are onboard with the possibilities and in September 2023, LR awarded an AiP for WinGD’s ammonia two-stroke engine.
Since then, there have been a number of notable announcements, including four ammonia-fuelled projects.
LR awarded AiP for a 8200 TEU ammonia fuel containership design to Chinese design company SDARI, and approved the design of a 1300 TEU container feeder vessel powered by an ammonia fuel-cell, developed by Korean companies, HD Hyundai Mipo and HD KSOE.
The third announcement was an AiP for a 3500 TEU container vessel that culminated from a cross-industry taskforce including LR, A. P. Møller-Mærsk, MAN Energy Solutions, Deltamarin, Eltronic FuelTech, and the American Bureau of Shippinh. The Mærsk Mc-Kinney Møller Center for Zero Carbon Shipping is behind the new design. The result of this collaborative approach is considered a milestone in enabling ammonia as an alternative marine fuel.
In addition to these containership announcements, LR awarded AiP to MARIC for a 360 000 DWT ammonia-fuelled very large ore carrier.
Positive steps for ammonia’s use as a fuel onboard will broaden its carriage onboard to non-gas vessels. LR is currently working with clients to design ammonia fuel systems, although it is worth noting that special care must be taken to ensure bunkering and venting is designed and reviewed following a meticulous process to ensure inherently safe design for the ship, its cargo, environment, and crew. Examples of where LR is supporting the industry in this way include granting approval in principle to Babcock LGE’s ecoFGSS – Flex fuel gas supply system and the review of Wärtsilä Gas Solutions’ ammonia fuel system for two EXMAR ammonia carriers, among several others.
Other stakeholders in the supply chain will also need to understand the hazards of handling and carrying ammonia and manage their operations in line with the necessary safety requirements. But the company is learning a great deal from the safety practices already established for ammonia carriers to govern its carriage as cargo.
LR is looking beyond the design and construction of ammonia-fuelled ships to the complete lifecycle, from maintenance and operations, through to decommission and recycling. The training for ships’ crews will be paramount. Crews must understand the particulars and increased risks of handling ammonia during bunkering operations and the correct procedures during an emergency response, should an incident on board occur.
Raul Llorens and Kevin Young, Johnson Matthey, introduce the non-regenerable fixed bed absorbent technology for the removal of hydrogen sulfide, its strengths and disadvantages in carbon dioxide purification, and the impact of oxygen presence.
chieving global sustainability targets requires a multipronged approach to the prevention and reduction of harmful emissions. Carbon capture, utilisation, and storage (CCUS) is a very important technological solution to reduce carbon dioxide (CO2) – the most abundant greenhouse gas.
CO2 is generated from a wide variety of operations and at various scales. Broadly, the CO2 sources are split into industrial (post-combustion), and biogenic. The composition of the CO2 streams directly reflects the processes by which these streams are generated, but also how they have been handled. In some cases, the CO2 sequestration or utilisation is done at the point of generation, but the more likely approach is combining these streams and transporting them to CCUS hubs. The latter reduces the investment and risk for individual CO2 producers.
Purification of CO2 streams prior to liquefaction or pipeline transportation is a firm requirement; however, there are no agreed industry wide specifications. One of the most specified contaminants by transportation operators or downstream users is hydrogen sulfide (H2S) as it is harmful to human health and the environment, causes equipment corrosion, and is a poison to many catalysts in utilisation applications. H2S is most commonly present in pre-combustion CO2 capture.
There are a number of well-known technologies to remove H2S from hydrocarbon streams – these are transferable to CO2 streams; however, the full impurity composition needs to be considered as this is likely to impact their performance. One possible concern for efficiency of the H2S removal system is oxygen. Some of the streams where H2S and O2 are expected to be co-present include:
z CO2 from the fermentation process.
z CO2 from biogas upgrading.
z CO2 captured/removed from O2-containing natural gas, i.e.:
Natural gas from fracking.
Natural gas from recently commissioned pipelines – depending on the length of pipeline network, residual oxygen may be present in the feed gas for a long time (years).
O2 ingress in the process gas, typically during compression at well gas gathering /boosting stations.
z Pipeline CO2 from multiple sources, e.g. pre and post-combustion CO2
Non-regenerable fixed bed absorbent technology
Non-regenerable fixed bed absorbents are the most common solution for H2S polishing duties. H2S absorbents are simple to install and operate, require little intervention, and can achieve an outlet specification in the ppb range. The removal occurs via a stochiometric chemical reaction with the active components in the absorbent. This prevents any re-release into the stream or the environment in contrast to adsorbents which use physical interaction as their main removal mechanism. The absorbent removes the H2S until they reach full saturation or they breakthrough H2S at the bed outlet.
There are three families of metal-based absorbents that are most commonly used for H2S removal in CO2 streams – their features are described considering their techno-commercial applicability.
ZnO-based absorbents
ZnO absorbents have been used in natural gas and syngas purification applications to remove sulfur for many years. While they can remove H2S to very low levels, they suffer from some operational limitations:
z Their capacity to remove H2S is low at near ambient conditions – they only reach their optimum capacity at temperatures higher than 300˚C.
z ZnO can react with CO2 forming ZnCO3; the latter will block access of H2S to the active ZnO and will impact performance severely. This means the operation needs to be carried out outside the temperatures where ZnCO3 can be formed.
ZnO-based absorbents are therefore not the first choice for the removal of H2S from CO2 streams.
Iron oxide-based absorbents
Iron oxide-based absorbents are also a well-established H2S removal solution in natural gas and CO2. There are many
commercially-available iron oxide-based products which can contain a combination of iron oxide phases, such as Fe2O3, FeO, and Fe(OH)2
The iron oxide-based absorbents are designed to have a very high capacity, however, the achieved capacity in CO2 streams is often significantly lower for several reasons:
z Iron oxide absorbents have slow kinetics, meaning that very long residence times are required when a low H2S outlet specification is required. This means that bed volumes tend to be much larger compared to other technologies.
z The chemistry behind iron oxide absorbents means that they require the feed stream to be fully water saturated to maximise the H2S removal capacity. Therefore, steam injection or a water spray system is normally required if the stream is not continuously at water saturation conditions.
z Under these conditions, the absorbents can suffer from severe agglomeration if the water condenses onto the absorbent bed leading to progressive pressure drop (dP) increase (and premature changeout) and difficult and time-consuming discharge.
z Depending on the formulation, certain iron phases can react with CO2 to form carbonates which have a similar impact as ZnCO3.
Iron-based absorbents are often the preferred choice when the upfront cost is the primary decision driver and the feed stream is already water saturated. Their cost is significantly lower compared to other metal-based absorbents.
Other metal oxide-based absorbents
Metal oxides absorbents usually contain transition metals such as copper, manganese, or iron. Copper is the most active metal for H2S removal. These types of absorbents have been used in both natural gas and CO2 purification for many decades.
Metal oxide absorbents can reach very high sulfur capacities at low/ambient temperatures due to their inherently fast kinetics and high affinity for H2S. This allows the operator to reach low H2S outlet specifications using much smaller bed volumes and/or to extend the life of the absorbent, making the lifecycle cost for this technology the most attractive.
Metal oxide-based absorbents may not reach the expected capacity in water-saturated streams if they are exposed to continuous water dropout. The free water would generate a diffusion barrier, blocking the active sites and making the H2S reaction more difficult. It is thus commonly recommended to pre-heat the stream above dewpoint by a few degrees to prevent water condensation.
Enabling metal oxides to reach their true potential requires extensive knowledge and experience in materials science and chemistry. Johnson Matthey (JM) has over 40 years of experience in this area and has optimised the formulation and manufacturing process of PURASPECTM absorbents throughout the years. The resulting solutions have the optimum properties required to reach maximum sulfur capacity and to withstand the demands of loading and operating conditions. The absorbents are robust with high crush strength until end of
bed life, meaning no pressure drop increase is typically observed and are free flowing upon discharge.
JM offers a range of copper-based and ZnO-based absorbents to remove H2S from natural gas and CO2 streams. For the purpose of this article, the following references to PURASPEC absorbents assume copper-based products.
The performance of PURASPEC products is not dependent on operating temperature, pressure or the nature of the feed, reaching their maximum capacity (i.e. complete copper active site utilisation) in the proven operating range:
z Temperature: 0˚C – 150˚C.
z Pressure: Atmospheric – 150 barg.
Under these conditions, H2S is removed to non-detectable levels using the company’s absorbents.
H2S removal from CO2 streams, even when O2 is present
At first glance, it might be thought that low-cost iron oxide absorbents would be the choice option for H2S removal from captured CO2 when O2 is present as there is precedence of
use in such systems. However, this has been associated with reduced performance under these conditions, increasing the size of the beds and the associated investment.
Copper-based absorbents’ capacity for H2S removal is not impacted by pure CO2. If oxygen is found to be ‘benign’ in the removal of H2S, then this technology should be preferentially considered from both a technical and commercial perspective.
It is important to note that removal of oxygen prior to removing CO2 is not economical as the most commonly used technology utilises precious metal catalysts which are highly sensitive to H2S.
JM carried out extensive research and testing on various copper-based formulations to evaluate the effect of O2 on H2S removal. PURASPEC 2058 has been found to have the right combination of chemical and physical properties to remove H2S efficiently in the presence of oxygen.
Testing and comparison to iron oxide-based absorbents
The experimental conditions for the H2S removal tests using PURASPEC 2058 and an iron oxide absorbent are shown in Table 1. 30 ml of absorbent material was charged to a fixed bed
Table 1. Experimental conditions for H2S testing in presence of oxygen
tubular reactor. A carrier gas mix of 0.35% O2, balance CO2 was dosed with 500 ppm/0.05% H2S.
For the tests carried out with the iron oxide-based absorbent, the carrier gas was first diverted through a water bubbler before mixing with H2S and passing over the reactor. This was done to give the iron oxide materials the best chance to reach its full potential in the test.
The gas exiting the reactors was analysed using a magnetic sector mass spectrometer to determine the H2S concentration. The test was set up using the rig software to automatically stop the flow of the H2S and carrier gases when the outlet H2S concentration was at 95% of the inlet concentration (475 ppm). An automatic purge using 100% N2 was then carried out for a minimum of six hours until the material was safe to remove from the reactors for post-mortem analysis (combustion analysis to determine sulfur content of the discharged material).
The comparative testing results are shown in Figure 1. The performance comparison between the two products is based on two main factors:
z Breakthrough time: when a clear deviation from the H2S baseline is detected.
z Sulfur saturation capacity: the total sulfur content of the absorbent when it reaches 95% H2S breakthrough and the experiment is stopped.
PURASPEC 2058 showed first signs of deviation from the baseline after more than 4800 min, i.e. 34% through the run length. In contrast, the iron oxide-based absorbent breakthrough was after 4% of the experimental run length. This indicates that PURASPEC 2058 has a much sharper reaction profile i.e. better absorbent utilisation which results in higher capacity. The experimental results show that JM’s copper-based absorbent had five times higher capacity than the iron-oxide-based material.
In addition, the spent samples were analysed using a Soxhlet extraction technique which uses n-hexane to extract and quantify any elemental sulfur (S8) which may have formed on the product during the sulfur removal reaction. S8 in the CO2 stream can lead to corrosion (by forming sulfuric acid if the stream is water saturated) or depositions and blockage in the narrow flow paths in the downstream systems. With time, S8 can be also accumulated in the pipeline network and can be even found in the end user delivery points due to its high solubility in CO2 streams at every pressure.
For the iron oxide-based absorbent, a significant amount of S8 precipitate was observed (Figure 2, left), whereas there was no visual indication of S8 for the PURASPEC 2058 sample (Figure 2, right).
To explore this observation further, the sulfur content of the spent absorbents was re-analysed after the extraction process. The reduction in sulfur content was found to be 95% for the iron oxide-based material compared to 10% for the PURASPEC absorbent, clearly indicating that the former had converted much of the H2S to S8. Another important observation was the condition of the absorbents on discharge. PURASPEC 2058 was found to be free flowing whereas the iron oxide-based product was agglomerated and difficult to discharge from the testing reactor.
Conclusions
A non-regenerable fixed bed absorbent technology comparison has shown that copper and iron-based absorbents are technologically and economically suitable for the removal of H2S from CO2 streams. In the presence of oxygen, copper-based absorbent technology, i.e. JM PURASPEC 2058 absorbent, has much faster sulfur removal kinetics, demonstrated by a much longer breakthrough time and five times higher sulfur capacity.
It was also determined that 95% of the sulfur removed by the iron oxide product was in the form of S8 compared to only 10% for the PURASPEC absorbent product. Therefore, most of the sulfur removed by the JM PURASPEC absorbent is permanently locked into the absorbent structure and cannot be released back in the feed.
Therefore, by selecting a copper-based absorbent, the operator will not only achieve much higher sulfur capacities i.e. smaller bed and/or longer bed lives but they will also minimise any S8 released into the CO2
Figure 2. Soxhlet extraction in hexane solution. PURASPEC 2058 (right) and iron oxide (left).
Figure 1. Graph showing the H2S reactor exit breakthrough profiles of PURASPEC 2058 vs an iron oxide-based product.
Johnson Matthey’s premium performance PURASPEC ™ absorbents and PURAVOC ™ oxidation catalysts are economic, reliable and easy to operate.
To learn more visit us in the Hydrogen theatre, booth E250 at Gastech.
Paul Trcka, Director, Sales and Operations Aerospace, and Paul Theberge, Aerospace Business Development Manager, ACME Cryogenics, part of the OPW Clean Energy Business Unit, summarise the equipment that can optimise the handling of cryogenic substances in aerospace applications.
The final frontier
There are both monumental challenges and limitless opportunities in the aerospace market, but one thing that remains constant amongst those various challenges and opportunities: the need for precise, reliable, and innovative technologies that are able to meet the demands of the next-generation manufacturing techniques that are being used to enable humankind’s expanded reach into the constantly evolving realm of space.
Specifically, this includes space-launch services that involve activities related to the manufacture, preparation, and launch of space vehicles and satellites. These services are among the most significant factors that are driving the growth of the aerospace market, with the looming introduction of space tourism expected to provide lucrative growth opportunities for both manufacturers and providers of space-launch services.
The role of cryogenic liquids
In many instances, this requires the use of cryogenic liquids, or those that have been intensely cooled below ambient temperature so that they have a boiling point – the point at which the liquid will return to its natural gaseous state –that can be -73˚C (-100˚F) and lower. This includes helium, the boiling point of which (-268.9˚C [-452˚F]) is lower than any other known substance.
No matter the element or its boiling point, the cryogenic-cooling process not only leaves these liquids intensely cold, but it also reduces their volume to mere fractions of what the substance is when in a gaseous state. This means that when a cryogenic liquid is exposed to the atmosphere, a relatively small amount of the liquid substance can rapidly expand into large volumes of a gas.
That makes it extremely important that the proper systems and equipment are used in all aerospace applications. It also means that these products should not only meet, but surpass, the exacting standards and demands that are inherent in ensuring the successful completion of an aerospace or space-launch mission. It subsequently makes it imperative that all OEMs produce solutions that are perfectly tailored for the unique needs of all mission-critical applications, since there are generally no cookie-cutter, one-size-fits-all solutions in the aerospace realm.
Key pieces of equipment
Admittedly, the sheer volume of valve and piping products that have been specifically designed to meet the precise demands of an aerospace manufacturing operation that relies on cryogenic liquids can be daunting or intimidating. With that in mind, here is an overview of the major pieces of equipment that can be necessary to
use in the creation of a safe, reliable, efficient, and costeffective aerospace-manufacturing regime.
Vacuum-jacketed piping
Vacuum-jacketed piping (VJP) systems are engineered to handle a wide spectrum of cryogenic substances, from liquid nitrogen, oxygen, and argon to helium, natural gas, carbon dioxide, hydrogen, and LNG, many of which are used extensively in aerospace applications. A properly designed VJP system will effectively and reliably mitigate heat leaks, thereby enhancing operational efficiency and minimising costs. When deploying a dual stainless-steel pipe setup, a VJP system can ensure optimal insulation, creating a vacuum-sealed layer that maximises thermal performance. This insulation capability, which surpasses that of traditional foam and dynamic vacuum-pipe systems, also delivers exceptional efficiency throughout the aerospace operation.
Non-jacketed valves
These items offer a blend of efficiency and reliability when used in an array of aerospace applications. These precision-engineered valves deliver seamless operation and robustness in diverse usage settings. Their design ensures optimal flow control while maintaining structural integrity. When crafted with quality materials and in accordance with stringent regulatory standards, these valves can offer durability and performance excellence, making them an ideal choice for critical aerospace processes.
Vacuum-jacketed valves
These jacketed valves are designed to combine the preservation of cryogenic temperatures with seamless flow control. Able to withstand extreme conditions, they guarantee reliability and safety in critical applications, safeguarding the integrity of cryogenic processes across diverse industries.
Pressure and safety valves
These valves are purpose-built for ensuring safe product containment in cryogenic-liquid containers. They are also compatible with a wide a spectrum of gases, including oxygen, nitrogen, argon, helium, LNG, and carbon dioxide. The design features an efficient and eco-friendly flow path that significantly reduces discharge noise, making them ideal for deployment in noise-sensitive indoor environments, such as aerospace laboratories.
Vaporisers and accessories
Vaporisers and accessories cornerstone components in
Figure 1. Acme Cryogenics provided large manual valves (6 in. and 8 in.) for large hydrogen tanks for the launchpad.
creating efficient gas-vaporisation processes in aerospace manufacturing operations. They play a vital role in transforming liquefied gases into usable forms, ensuring seamless transitions from liquid to gas states.
Non-jacketed hoses, piping, and accessories
Whether for use in fluid transportation or system integration activities, non-jacketed hoses, piping, and accessories are designed to deliver optimal performance in various aerospace applications. Effective hoses, piping, and accessories will ensure efficient flow while maintaining structural integrity within the aerospace system.
Pressure regulators and accessories
These are crucial component in precision gas control systems, possessing the ability to ensure reliable and accurate pressure management in aerospace processes. The regulators provide stability and control and the accompanying accessories complement the regulators while offering comprehensive solutions that result in the seamless functioning of aerospace systems.
Gas-handling and liquid-transfer systems
These systems encompass a wide range of solutions that are typically designed to facilitate safe and efficient handling, transfer, and distribution of cryogenic gases and liquids. From advanced pumping mechanisms to sophisticated transfer technologies, these systems ensure
STIRLING HYDROGEN LIQUEFACTION SYSTEMS
Capacities from 5 to 1.000 kg/day
seamless and controlled movement of fluids, optimising productivity and safety standards.
Repair kits and other accessories
These are the unsung heroes of maintenance and efficiency in cryogenic-liquid systems. Crafted with precision and built for durability, these kits and accompanying accessories are tailored to address a spectrum of operational needs. From quick fixes to comprehensive repair solutions, these kits ensure seamless functionality and sustained performance of cryogenics-related equipment. They are complemented by a range of accessories designed to enhance the operational capacity of cryogenic systems, offering versatility, reliability and ease of use.
Conclusion
If, as the old saying goes, “space is the final frontier,” then it will only be conquered if the equipment and systems that are needed to facilitate the exploration of space by human beings satisfy all of the application-specific characteristics that help ensure safe, reliable, and efficient operation.
When it comes to handling cryogenic liquids, numerous different types of components, all with precise duties to reliably perform, must function together harmoniously in order to not only ensure the success of the mission, but – more importantly – to guarantee that it is completed in the safest manner possible with little threat to humans or the greater environment.
• Energy Efficient Stirling Technology
• 4 -16 m2 footprint for small scale systems
• Containerized for large scale
• Internal GH2 pre-cooling at 80K
• Ortho-para conversion catalyst
• ATEX-compliant
• LH2 vessel BOG re-liquefaction by cold GHe flow
Stirling Cryogenics
+31 40 26 77 300
info@stirlingcryogenics.com
www.stirlingcryogenics.com
Eliminating the methane slip is key to achieving net zero in shipping, and innovation is already paving the path, argues Steve Esau, COO, SEA-LNG.
TO 2030, 2050, AND BEYOND
he pathway to net zero is not cut and dry; the argument that there is a single solution is not viable. And while it may be appealing, the idea that there may be a single solution one day is costing time and progress.
The International Maritime Organization’s (IMO) ambitious 2030 and 2050 targets are closer than many may think. As the options continue to be debated, more greenhouse gas (GHG) emissions are entering the atmosphere; the more GHG emissions, the less time to meet climate targets.
Ammonia, hydrogen, and methanol are amongst some of the most popular alternative fuels currently under discussion to help the maritime industry achieve net zero in 25 years’ time. However, with all these solutions, there remain significant challenges which could be costly and time-consuming to overcome.
Vast investment, development of new infrastructure, accessibility, and commercial sustainability are significant issues that all of these options face. Many challenges could take decades to resolve before these solutions are available at scale – decades which are not available given the urgent need to act now.
Hence, the importance of LNG. LNG presents a viable, realistic, scalable pathway to achieving key IMO and EU environmental milestones from now until net zero in 2050 through biomethane and later e-methane. And importantly, some of its most notable challenges are already being overcome.
LNG: A scalable pathway for the future
Amongst the alternative fuel options (and ongoing debates), LNG has great potential to help the shipping industry achieve net zero in 2050 and beyond. Critically, it supports key maritime milestones between then and now.
Currently, LNG can reduce GHG emissions from marine propulsion by up to 23%, immediately achieving the IMO’s target of a >20% reduction by 2030. Operating the fuel is relatively straight forward; owners and operators can use existing LNG bunkering infrastructure, and proven safe shipboard technologies.
Both investment in and positive sentiment towards LNG means that the fuel is far more readily accessible than it was just a decade ago. At time of writing, over 500 vessels actively use the fuel (excluding carriers), and LNG bunkers are available in 185 ports – with an additional 50 set to be made available by 2025.
With liquefied biomethane (or bio-LNG), the industry can accelerate progress. Using the fuel can result in a reduction in GHG emissions by up to 80%. And when produced from anaerobic digestion of manure, that figure can be as high as 188% compared to traditional marine fuels.
Biomethane adoption is increasingly accessible due to its compatibility with existing infrastructure. Bunkers are already available in approximately 70 ports across Asia, Europe, and North America, and there is no need to retrofit vessels and tankers that are already using LNG, making it a lower CAPEX solution.
As the world progresses to 2050, it is clear that the industry will need to continue to invest in the technology and subsequent infrastructure to reach net zero – and maintain it far beyond the deadline. But that is not to say there are not already realistic solutions to the goal.
Liquefied e-methane (or synthetic LNG) is fully compliant with the IMO’s 2050 regulations, and can reasonably lead to owners and operators achieving carbon-neutral operations. The fuel is fully compatible with existing LNG-fuelled vessels and bunkering infrastructure.
As a pathway, LNG is ready now and immediately scalable compared with other ‘future fuels’. So why is uptake not significantly higher?
The challenges facing the LNG pathway
As with any alternative fuel, there are challenges.
For LNG, scalability is often cited as one of the biggest concerns, particularly in reference to bio-LNG and e-LNG.
Figure 1. Grey and green fuel market sizes. Sources: GIIGNL, Methanol Institute, International Energy Agency, and IRENA.
Both of these may have very positive results in GHG emissions reduction, but they will also need investment in order to produce the amounts required for widespread uptake.
However, because both fuels are currently compatible with existing LNG supply and bunkering infrastructure, bio-LNG and e-LNG are some years ahead of common counterparts, many of which would require major new investment.
Arguably the most notable issue that feeds into negative perceptions of the fuel is that of methane slip. However, it is a recognised challenge in the industry, and one that is well on the way to a solution.
Today, approximately 75% of LNG-fuelled ships on order have engines with effectively no methane slip. For low-pressure engine technologies where methane slip remains an issue, manufacturers have already cut the levels of slip from low pressure four-stroke engines by more than 85%.
A future where the methane slip issue is fully solved could be a reality sooner than one may think.
Tackling methane slip in the market
Over the past two years, there has been a number of initiatives launched focused on innovating technologies to address methane slip.
As part of the EU-funded GREEN RAY project, Wärtsilä has piloted technologies on the AURORA BOTNIA
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During the ATEX assessment by the experts from the Danish Technological Institute it became evident that the Lopolight range is fit for the demanding Zone 1 – thereby also Zone 2.
This gives freedom to place the lights at the correct location without compromises, and to allow the continued use of the lights even in the event of a gas leakage situation.
RoPax ferry, resulting in further methane slip reductions of an average of 41% (but up to 56%) in one of its most popular dual fuel low pressure four-stroke engines. 1 It also has the ability to reduce nitrogen oxide emissions by up to 86%.
The Methane Abatement in Maritime Innovation Initiative (MAMII) has also begun a process of piloting methane abatement technologies in a bid to reduce and eventually eliminate the methane slip, as well as expanding collaboration and lobbying with regulators on a methane measurement, certification and validation protocol. 2
These are only two examples of innovative and effective methods of tackling the obstacle, and strengthening the case for LNG, as currently the only practical and alternative marine fuel pathway available to achieve 2050 goals. 3
Conclusion
As with many significant challenges currently being faced, continual innovation and investment into finding viable solutions is essential. The maritime industry must continue to work together to carve a path to a carbon-neutral future, and establish the technology to tackle emissions now and for the future.
While there is no silver bullet, SEA-LNG, with its membership drawn from across the LNG value chain,
CRYOGENIC PUMP
continues to bring together stakeholders to advance the LNG decarbonisation pathway, and has made major advances in addressing the issue of methane slip.
From today to 2030 and to 2050 and beyond, LNG provides a viable, realistic solution to the pressing regulations the industry is facing. Whereas many other alternative fuels face significant technological, safety and commercial hurdles which will take time to overcome, LNG and its bio and synthetic cousins provide a pathway to decarbonisation which starts now.
References
1. ‘New version of the Wärtsilä 31DF engine reduces methane emis sions by an additional 41% on average, when compared to previous market best’, Wärtsilä, (1 November 2023), www.wartsila.com/media/news/01-112023-new-version-of-the-wartsila-31df-engine-reducesmethane-emissions-by-an-additional-41-on-averagewhen-compared-to-previous-market-best-3351225
2. ‘Maritime gets behind methane abatement – MAMII membership doubles in first year’, Methane Abatement in Maritime Innovation Initiative (MAMII), (6 September 2023), https://mamii.org/maritime-getsbehind-methane-abatement-mamii-membership-doublesin-first-year/
3. ‘Methane slip b eing eliminated as LNG uptake accelerates’, SEA-LNG, (1 August 2024), https://sea-lng. org/2024/08/methane-slip-being-eliminated-as-lnguptake-accelerates/
...ON
THE USA
15FACTS
The global share of North American LNG supply is expected to rise from 22% in 2023 to 34% by 2030
The US and Qatar are set to account for 62% of new global LNG supply between 2025 – 2029
Houston is the fourth most populous city in the USA, after New York, Los Angeles, and Chicago
Since 2016, the US LNG export rate as grown at an average annual rate of 11 million tpy
Houston was founded in August 1836
Roughly 1 in 4 Houstonians were born outside the US
‘Houston’ was one of the first words uttered on the moon
The US opened its first LNG export terminal in 2016
Houston is home to 38 of the nation’s 85 publicly traded oil and gas exploration and production firms
There are more than 10 000 restaurants in Houston
Over 145 languages are spoken in Houston
Lollipops were invented in New Haven, Connecticut, in 1908
North America’s LNG production and terminals will more than double within the next 3 – 5 years
In 1Q24, 20% of US LNG exports transited via the Cape of Good Hope
There are over 5300 universities in the US
ADINDEX
Q&A WITH
Dr Tobias Eckardt, Global Expert Gas Treatment for BASF Adsorbent Solutions
Dr Tobias Eckardt studied at Universities of Göttingen and Dublin and graduated from University of Cologne with a PhD in chemistry. After joining BASF in 2005, Tobias held several positions in R&D and production support with increasing responsibility. In 2010, he became part of the technology team for the BASF Adsorbent Solutions business as Global Technology Manager. His responsibilities covered multiple applications along the value chain of natural gas treatment, including: dehydration, hydrocarbon removal, and mercury removal for pipeline gas and LNG production. In 2021, Tobias was appointed as Global Expert Gas Treatment for BASF Adsorbent Solutions business.
01 What are some of the challenges faced during the treatment of gas for LNG production?
The biggest challenge faced by LNG producers today is managing gas compositions that the plant was not originally designed for. This problem is particularly acute in North America, both the US and Canada, where the gas is very lean but has trace amounts of heavy hydrocarbons. To date, LNG plants in this region were not built to handle this type of gas composition, which causes freezing in the cold section of the plant. The solution is adsorptive heavy hydrocarbon removal, which BASF provides with the Durasorb ® LNG MAX technology. This technology is suitable for retrofit of existing facilities that are experiencing freezing, reduced LNG throughput, and operational complexity. Replacement of existing molecular sieve material in the dehydration vessels with Durasorb material and implementation of Durasorb LNG MAX technology removes heavy hydrocarbons prior to the cold section of the plant and eliminates freezing and operational complexity.
02 There is a lot of interest from LNG producers to improve operations at existing facilities. Can you elaborate on how BASF supported Kinder Morgan Elba Island facility to improve operations and increase production?
Elba Island was experiencing the challenge of lean gas with heavy hydrocarbon tail described above, similar to what we see in other LNG plants in the region. This is now a known and openly discussed challenge. At Elba Island, BASF worked closely with Kinder Morgan engineers to implement Durasorb LNG MAX materials and technology. Durasorb LNG MAX has been running in two of 10 Elba Island trains since July 2022 and was installed in three additional trains in 2023. The two trains operating since July 2022 have not had a freezing event since Durasorb installation, therefore eliminating about 10 would-be de-riming events. Clearly, Durasorb has reduced operational complexity at the facility and increased LNG production by eliminating de-riming events. More details on the implementation of Durasorb and the positive impact
on production can be found in our joint publication with Kinder Morgan, titled ‘The solution to coldbox freezing’, which was published in LNG Industry in August 2023.
03 What is unique about BASF’s technology for the LNG pre-treatment?
BASF has been producing and supplying adsorbents for heavy hydrocarbon removal from natural gas for decades, with the company’s products known to be among the most robust and reliable in the industry. Beyond being the leading supplier of adsorbents for adsorptive heavy hydrocarbon removal, BASF has also developed a new and improved product specifically tailored for aromatics removal called Durasorb ® BTX. This product is only available through the Durasorb LNG MAX technology and differentiates the product designs from competition. With this new product, BASF technology has higher capacity for aromatics, making greenfield units smaller or retrofit projects more feasible.
04 How can BASF’s products support the industry’s endeavour to decarbonise and optimise LNG operations?
When it comes to decarbonisation, BASF has a portfolio of products and technologies for carbon capture, purification, and dehydration. For carbon capture and separation, BASF offers OASE ® gas treatment technology. Purification and dehydration solutions are offered from BASF Catalysts and Adsorbents business. LNG plants are good candidates for carbon capture from the AGRU in the pre-treatment line-up. Downstream of the AGRU, the carbon dioxide (CO 2) needs to be dehydrated prior to transportation. BASF has been producing and supplying CO 2 dehydration applications with Sorbead ® adsorption products for several decades and has qualified this technology for carbon capture and storage (CCS) application with many major CO 2 producers and engineering companies. Sorbead is acid resistant and has a much lower regeneration temperature compared to molecular sieves, making it the ideal adsorbent for CO 2 dehydration. CO 2 dehydration is an important step in CCS to ensure the captured CO 2 is treated to the required transportation specifications.
