December 2023
GAS TURBINE AIR INTAKE FILTRATION SYSTEMS MEETING THE ENERGY NEEDS OF CUSTOMERS AROUND THE WORLD
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ISSN 1747-1826
CONTENTS 03 Comment 05 LNG news 10 Africa: the making of a major
DECEMBER 2023
30 Gas treatments from beginning to end
Alan Garza, Gas Analysis Product Marketing Manager, Endress+Hauser USA, looks at ideal analysis methods for LNG from gas treatment to liquefaction.
exporter
Chris Strong, Chris Taufatofua, Jonathan Roberts, and Steven Wilson, Vinson & Elkins, examine the development of the African LNG industry, as well as its future challenges and opportunities.
30 10 16 Filter out unnecessary downtime
Peter McGuigan, Parker Hannifin, UK, explores the importance of gas turbine combustion air intake filtration to efficient, reliable, and lasting gas turbine operations.
21 Handling LNG
Ingo Emde, R. Stahl, Germany, analyses how safety on ships and on shore can be prioritised when handling LNG.
26 Evolution, not revolution Andrew Scott, Business Development Director, Babcock’s LGE business, UK, outlines developments in the company's single mixed refrigerant LNG reliquefaction system.
35 LNG Industry project overview
LNG Industry's project review highlights some LNG projects and expansions currently under construction from around the world that are due to be operational by the end of the decade.
41 Keeping control of valves
Dr Nicolas Spiegl and Jules Oudmans, UReason, the Netherlands, discuss when to inspect, maintain, or replace control valves to ensure a safe and efficient operation.
45 Giving value a whole new meaning Jason Chadee, Director at SparkCognition, USA, details how artificial intelligence can help bring a new meaning to terminal value.
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JESSICA CASEY EDITOR
COMMENT T
he ICC Men’s Cricket World Cup took place in November, with Australia beating India by six wickets. This makes Australia the most successful nation in cricket (by a lot), having won the tournament a record six times; India and the West Indies are the only other two nations who have won the World Cup more than once.1 Although Australia has recently been overtaken by the US and Qatar as the world’s largest LNG exporters, it is still a major producer of LNG, and one that Asia is heavily reliant on. Roughly three-quarters of Australia’s LNG exports go to four Asian buyers (China, Japan, South Korea, and India), with almost none going to Europe.2 Australian LNG has been a hot topic for the industry’s news as of late, notably because of the worker strikes at Woodside Energy’s Northwest Shelf and Chevron’s Gorgon LNG and Wheatstone projects. Woodside managed to avert strikes after reaching a deal with workers in August,3 while workers at the Gorgon and Wheatstone facilities began striking in early September. In October 2023, Reuters announced that Chevron Australia and employees at its two LNG plants had reached agreement, ending the strikes. A positive outcome considering these two projects alone account for approximately 7% of global LNG supply.4 In November, the third liquefaction train at the Gorgon LNG plant in Western Australia was reported to have returned to full production.5 In other news, GR Production Services Pty Ltd has been awarded a three-year contract with INPEX Operations Australia for the provision of operations and maintenance support services at the Ichthys LNG upstream and downstream facilities. The project,
a joint venture between INPEX group companies, major partner TotalEnergies, and the Australian subsidiaries of CPC Corporation Taiwan, Tokyo Gas, Osaka Gas, Kansai Electric Power, JERA, and Toho Gas, is expected to produce up to 9.3 million tpy of LNG and is one of the few energy projects to incorporate the whole chain of development and production.6 In addition, the Santos-operated Darwin LNG and KAEFER Integrated Services have recently announced the establishment of a new pathway to skilled, well-paying, secure jobs for Aboriginal Territorians through a training and employment programme commencing in Darwin in early 2024. The companies intend to provide ongoing employment for participants in the programme at their worksites; construction of Darwin LNG began 20 years ago and the facility is now being readied for the next 20 years, in preparation for the start of Barossa gas production in 2025.7 Our project overview (p.35) looks at some LNG project expansions currently under construction from around the world, including the Outer Harbor LNG import terminal and Pluto LNG project in Australia, as well as various others from Africa and the Middle East, the Americas, Asia Pacific, and Europe. As 2023 comes to an end, and we start looking forward to the New Year, LNG Industry thanks all our readers for their support throughout the year. We wish you all a happy holiday season, and we look forward to continuing to provide you with current and informative LNG market news and developments as we move into 2024.
References
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ED I T I ON
OCTOBER 31 - NOVEMBER 3, 2023 NEW ORLEANS ERNEST N. MORIAL CONVENTION CENTER
INDUSTRIES
LNGNEWS Mexico
Mexico Pacific and Government of Chihuahua announce strategic collaboration
T
he Government of the State of Chihuahua and Mexico Pacific have entered into a strategic collaboration agreement, attracting key financial investment in Chihuahua and supporting the construction and operation of Mexico Pacific's Sierra Madre Pipeline. The Sierra Madre Pipeline will originate at the border of the US and Mexico transporting approximately 2.8 billion ft3/d of natural gas across the states of Chihuahua and Sonora to the company's Saguaro Energía LNG facility on the West Coast in Puerto Libertad, Sonora. Comprising a key part of the broader LNG project, the Sierra Madre Pipeline will bring employment opportunities, infrastructure development, community improvement, and economic growth to Chihuahua and the nation while positioning Mexico as the fourth-largest LNG exporting country worldwide, significantly contributing to global energy security. Among the main tenets of the agreement are the State's commitment to support Mexico Pacific in areas of mutual interest relating to the construction and operation of pipeline infrastructure in Chihuahua. These include logistics, construction, technology, security, and community engagement.
Greece
Seatrium delivers Greek FSRU
S
eatrium Ltd has delivered the FSRU Alexandroupolis, which has completed its near shore testing works and set sail to Greece for final gas commissioning of the regasification system. The project was successfully delivered to GAS-fifteen Ltd, a wholly-owned subsidiary of GasLog LNG Services with a high safety standard, achieving a remarkable feat of 2.9 million man-hours without any recordable injury and loss-time incident. As the first FSRU for Greece, the INGS project will become a critical energy gateway, supporting its energy security while advancing the energy transition trajectory of South-eastern Europe. Seatrium’s scope of work for this project includes refurbishment and life extension works, engineering and procurement, fabrication, and installation of a new regasification skid, as well as supporting systems such as boilers, offloading, electrical and automation systems. When completed, FSRU Alexandroupolis will be deployed in waters some 17 km southwest of the Port of Alexandroupolis, Northern Greece, and will have an overall delivery capacity of approximately 5.5 billion m3/y, with a peak send out of 22 million m3/d. The 155 000 m3 LNG carrier, recently reflagged to the Hellenic Register, is the first FSRU conversion under the Greek Flag for operation in the Thracian Sea. The FSRU will eventually be owned and managed by GASTRADE S.A and will supply the markets of Southeastern European with natural gas.
Canada
Cedar LNG executes HoA with Samsung Heavy Industries and Black & Veatch
T
he Haisla Nation and Pembina Pipeline Corporation, partners in the development of the proposed Cedar LNG project, have announced the signing of a heads of agreement (HoA) with Samsung Heavy Industries (SHI) and Black & Veatch. The HoA provides Cedar LNG, on an exclusive basis with SHI and Black & Veatch, secure access to shipyard capacity to meet Cedar LNG’s target commercial operations date. The parties expect to finalise a lump sum engineering, procurement, and construction agreement in December 2023.
This agreement builds further momentum for the project and follows receipt of all major regulatory approvals and the signing of memorandums of understanding for long-term liquefaction services with investment grade counterparties for the project’s total LNG capacity. Target final investment decision (FID) continues to be by the end of 2023; however, given the complexity and sequencing of aligning the multiple work streams, which are required to facilitate project financing, FID may move into early 2024.
December 2023
5
LNGNEWS Europe
Alice Cosulich meets growing demand for LNG and bio-LNG bunkering
L
NG bunker vessel, Alice Cosulich, has set sail for Europe from Qidong, China. The Fratelli Cosulich-owned, 8200 m3 capacity vessel is on a long-term time charter agreement to Titan, an independent supplier of clean fuels. Alice Cosulich will be operational in Europe from early December 2023 and will be immediately busy facilitating supply. The bunkering vessel has an LNG and bio-LNG bunkering capacity of 8200 m3 and will operate predominantly in the Amsterdam-Rotterdam-Antwerp (ARA) area for now. The addition of Alice Cosulich to Titan’s fleet increases the flexibility of its clean fuel operations. This new addition to the fleet will enable better loading efficiencies – larger fuel parcels can be delivered and better combinations for various bunkering can be made, making scheduling easier with less dependence on reloading slots.
Papua New Guinea
Sparrows Group lands LNG crane maintenance contract
S
parrows Group, a maintenance and engineering services specialist for the global energy and industrial sectors, has been awarded a contract through Altrad Cape for the provision of comprehensive crane maintenance services to the ExxonMobil Papua New Guinea (PNG) LNG project. This three-year contract, which includes a one-year extension option, marks Sparrows' first long-term venture into PNG and continues the company's strategic expansion into the region. Under the terms of the contract, Sparrows will deliver crane maintenance services including both planned maintenance and breakdown/repair services. Sparrows will play a vital role in the operational integrity of Exxon’s fleet of mobile cranes across its sites, including both the upstream Hides gas plant and downstream LNG facility, ensuring that crucial lifting equipment is consistently maintained to the highest standards. Additional overhead and engineering scopes may be required in the future.
6
December 2023
Singapore
Trafigura to supply LNG cargo to First Gen
F
irst Gen Corp. (FGEN) has awarded a contract to Trafigura Pte Ltd following the conclusion of its international tender for an LNG cargo. Trafigura will supply one LNG cargo of approximately 154 500 m3 (subject to an operational tolerance of +/- 3%) within the required delivery window of 25 November – 25 December 2023, on a delivered ex ship (DES) basis to FGEN’s wholly-owned subsidiary, First Gen Singapore Pte. Ltd (FGEN Singapore). The LNG cargo to be provided by Trafigura will be delivered by an LNG carrier which will be unloaded into the storage tanks of the BW Batangas FSRU that is currently berthed at the First Gen Clean Energy Complex (FGCEC) in Batangas City. The LNG will be utilised by FGEN’s existing gas-fired power plants also located in the FGCEC. FGEN has a portfolio of four existing gas-fired power plants with a combined capacity of 2017 MW that have been supplied for many years with gas from the Malampaya field, an indigenous offshore gas field. FGEN LNG Corporation has constructed its Interim Offshore LNG Terminal Project and executed a five-year time charter party for the charter of the BW Batangas, which will provide LNG storage and regasification services as part of the project.
THE LNG ROUNDUP
X Delfin Midstream signs long-term supply agreement with Gunvor X Cheniere announces long-term integrated production marketing agreement with ARC Resources X Galileo Technologies helps India produce first LNG Follow us on LinkedIn to read more about the articles
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LNGNEWS USA 16 – 19 January 2024
The 20 Americas Energy Summit & Exhibition th
Louisiana, USA www.americasenergysummit.com
11 – 12 March 2024
10th International LNG Congress (LNGCON 2024) Milan, Italy https://lngcongress.com
12 – 13 March 2024
StocExpo
Rotterdam, the Netherlands www.stocexpo.com
03 – 05 April 2024
26th Annual International Aboveground Storage Tank Conference & Trade Show Florida, USA https://www.nistm.org
07 – 08 May 2024
ITLA 2024 Annual International Operating Conference & Trade Show Texas, USA www.ilta.org/Events-Training/ ILTA-2024-EXPO-
07 – 09 May 2024
Canada Gas Exhibition & Conference Vancouver, Canada www.canadagaslng.com
11 – 13 June 2024
Global Energy Show Canada Calgary, Canada www.globalenergyshow.com
8
December 2023
ABB to deliver integrated automation, electrical, and digital solutions to Phase 1 of Rio Grande LNG
A
BB has been awarded an order by Bechtel Energy Inc. to deliver integrated automation, electrical, and digital solutions for Phase 1 of the Rio Grande LNG facility (RGLNG Phase 1) in Brownsville, Texas, a project developed by NextDecade Corp. Bechtel Energy Inc. is undertaking construction of RGLNG Phase 1 under an EPC contract. RGLNG Phase 1 includes three liquefaction trains and supporting infrastructure, and was the largest greenfield project financing in US history, according to NextDecade. This order, booked in 3Q23, marks ABB’s first fully-integrated scope on a major LNG facility. When fully operational, Phase 1 of the facility is expected to produce 17.6 million tpy of LNG. RGLNG Phase 1 will utilise ABB products and services to ensure the safe and efficient operation of its LNG production. Automation control systems, digital electrification components and industrial drives will enable RGLNG Phase 1 to optimise production assets, increase energy efficiency and operate more sustainably.
Canada
Woodfibre LNG selects Bridgemans to provide floatel accommodation for project workforce
B
ridgemans Services Group has been selected to provide on-site workforce accommodation for Woodfibre LNG’s LNG export project near Squamish, British Columbia (BC), beginning spring 2024. Woodfibre LNG, designed to be the world’s first net zero LNG export facility, chose Bridgemans for its commitment to sustainability and ability to deliver turnkey, safe, and secure live-work offshore accommodation for more than 600 workers at the site. Bridgemans will moor the MV Isabelle at the Woodfibre LNG project site, so workers can easily move between the vessel and their workplace. The MV Isabelle underwent an extensive refit of its environmental systems and living, dining, recreation, and gathering areas in Europe and is in the final stages of preparation before being deployed to site in spring 2024. The floatel will offer a home away from home with 652 newly renovated single cabins with private en-suites, a high-end dining room, lounges, meeting rooms, fast Wi-Fi, offices, medical care, a state-of-the-art 8000 ft2 fitness facility, billiards and games room, and dedicated accommodations for crew members. Project workers will have every comfort of home during their rotations, while working within recent BC Environmental Assessment Office and Squamish Nation amendments that restrict non-emergency access to Squamish. The floatel will also offer a wide array of advanced environmental systems including an ultraviolet water purification system, the ability to run on shore hydro power, industrial-sized heat pumps, and sewage treatment that includes ultrafiltration, a low intensity UV unit, and shipping to a waste management facility in BC. In addition, Bridgemans is designing the MV Isabelle to eliminate waste and recycle as much as possible.
10
Chris Strong, Chris Taufatofua, Jonathan Roberts, and Steven Wilson, Vinson & Elkins, examine the development of the African LNG industry, as well as its future challenges and opportunities.
I
n 1964, Africa became the first continent to export LNG when Algeria delivered its inaugural cargo from the Arzew gas terminal to the UK. Since then, Africa has remained a vital part of the global natural gas network, with the continent estimated to hold around 10% of worldwide proven reserves. In 2022, Africa exported approximately 42 million t of LNG – or around 5.7% of global LNG exports.
11
Historically, Algeria and Nigeria have been the largest African exporters of LNG, with several exporting terminals operating for decades. This may all change in the near-future, as the African natural gas landscape develops. In the past decade, there has been a series of significant natural gas discoveries made across the continent – between 2010 – 2020, approximately 40% of all natural gas discovered worldwide was in Africa, with most of those discoveries located in Sub-Saharan Africa. With a number of African LNG export projects planned or under development, even more African states stand to become LNG exporters. There are also substantial changes on the demand side, with an increase in European appetite for African LNG particularly to replace Russian gas imports. In 2022, in response to Russia’s invasion of Ukraine, the European Council adopted the Versailles Declaration, which included a target to “phase out […] dependency on Russian gas, oil, and coal imports as soon as possible” including by diversifying supplies and routes. In May 2022, the European Commission published the REPowerEU Plan that proposes to end EU reliance on Russian fossil fuels before 2030. Africa is playing, and is likely to continue to play, a key role in supplying replacement volumes of LNG into European markets. In 2021, African LNG accounted for approximately 10% of Europe’s gas imports. In 2022, as many importers scrambled to source alternatives to Russian gas in the wake of the invasion of Ukraine, African LNG exports rose by over 7%. Nigeria, with Africa’s largest natural gas reserves, was Europe’s fifth-largest LNG supplier in 2022.
A snapshot of major new developments
African states with large natural gas reserves generally seek to harness them for both domestic consumption and monetisation via developing LNG export projects, subject to limited exceptions in which African natural gas is exported by existing pipeline infrastructure (e.g. via the Medgaz and Transmed pipelines that ship natural gas
from Algeria to Europe via Spain and Italy, respectively), where this is geographically more convenient. African states export around 40% of the natural gas volumes produced, and LNG export provides both a practical way of accessing the global export market and a valuable source of foreign exchange. The number of LNG export projects planned or under development in Africa has been increasing in recent years, fuelled by both new discoveries and an increase in support from investors and financiers. Several key LNG export projects have delivered their first shipments or are planned to come online next year, with several additional states in advanced discussions on developing their first LNG export projects or new expansion projects later on in the decade. In 2022, the first cargo of LNG produced from the Coral gas field was shipped from Mozambique’s Coral South floating LNG (FLNG) facility. On the northern coast of Mozambique, the US$20 billion Mozambique LNG project has been under force majeure since spring 2021 following attacks by insurgents. Senegal and Mauritania have co-operated on the exploitation of adjacent offshore natural gas fields through plans to develop the Greater Tortue Ahmeyim (GTA) FLNG export facility. The commissioning of the first phase with production capacity of around 2.3 million tpy has been delayed but is expected to come online in 2024. As its neighbour Angola marked 10 years of LNG export, construction commenced on the US$5 billion Congo LNG project in April 2023. The Republic of the Congo’s first LNG project will include two FLNG plants and is expected to reach capacity of 3 million tpy from 2025. In May 2023, Tanzania’s government announced that it had concluded negotiations with investors for a US$42 billion onshore LNG project, with execution of binding documentation to follow. Final investment decision is expected by 2025, indicating that the project could come on-stream from 2030 onwards. Egypt continues to be a major exporter of LNG and could benefit from the significant discoveries in the Eastern Mediterranean over the past decade, as Israel, Cyprus, and Greece explore ways to ship East Mediterranean natural gas to European markets.
Africa-specific challenges and opportunities
Figure 1. LNG tanker at port with LNG liquefaction plant in background. 12
December 2023
Africa contains many distinct and varied regions, geographies, political systems, and cultures, so the challenges of developing large scale LNG projects across the continent are complex and often particular to that state or region. Alongside the general risks that all
LNG projects face, particularly with regard to technical and demand-side risks, LNG projects in Africa often face additional challenges due to the interplay of these factors on planning, developing, and financing LNG projects.
political risks both through cover or insurance, as well as their engagement with host governments at a diplomatic level.
Legal and political frameworks
African developers and projects often struggle to access capital markets and, despite the growing role of domestic banks, the large amounts of foreign exchange that is typically required for the financing of large scale LNG projects has led to international commercial banks, multilateral development organisations, and export credit agencies all having a significant role in financing recent African LNG projects. There are often conflicting interests in such a diverse creditor group. Political and reputational sensitivities around resource management, domestic development, and an increasing focus on decarbonisation and sensitivity in financing new oil and gas projects may lead to new LNG projects competing for financing with energy transition projects as financiers and governments increasingly push capital towards less carbon intensive sectors. First-in-country developments or complicated technical or regulatory issues have often required financiers to consider more novel financing structures when financing African LNG projects. Sponsor support, and, given the importance of some of these projects for the national economy of the host state, occasional government guarantees, are often sought by financiers to mitigate some of the risks of developing a large scale LNG export project.
A key challenge for developing large scale export projects in some African states is that the legal and regulatory framework is less suitable for large scale international investment. Despite substantial progress being made both at individual state level and multilaterally, newly enacted laws and regulations are often untested in the courts, and the consequences of enforcement uncertain, leading to an increased perception of risk. That said, many successful African LNG projects have been developed within such regimes, and the key themes for each of these are long and focused engagement with the host government and local regulatory authorities to predict and manage legal and regulatory challenges if they arise. A well-structured financing, often involving the political support of governments or multilateral agencies, can increase the level of comfort of investors and financiers in supporting the project. There are certain legal and political risks that usually cannot be structured around, so at an early stage in the development process, sponsors should look to investment treaty protections with their own home states. They should also consider the involvement of international development financing institutions or export credit agencies to potentially mitigate certain
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Cost, delay, and security risks
Existing African LNG projects have historically been subject to increasing levels of cost overrun and delays. This is for a variety of reasons, including security-related issues, the COVID-19 pandemic, the rising cost of resources, particularly due to certain projects replacing Russian steel supplies following the Ukraine invasion, and geopolitical instability, most notably with Total’s Mozambique LNG project that has been in a state of force majeure since 2021 as a result of the security situation in Northern Mozambique. African LNG projects also face a number of structural issues that each carry an increased risk of delays, cost overrun, and barriers to financing. Inflation and the availability of materials and parts remain issues in the shorter to mid-term, pushing up the likelihood of cost overruns for construction, though this can be mitigated through robust construction and operation contractual arrangements. An increased focus on environmental factors is requiring newbuild LNG projects to consider carbon mitigation measures, such as carbon capture and storage projects or co-located renewable energy projects. Not only does this increase the overall CAPEX, but the development of multiple projects increases the likelihood of a delay. Moreover, it is unlikely that a developer will be able to employ a single contractor to ‘wrap’ several different projects in a single construction contract, leading to an increased level of construction risk sitting with the developer. Similarly, unpredictable revenue streams from carbon capture projects or even hydrogen capacity may require lender flexibility on underlying contracts and repayment terms due to potential uncertainty in predicting cashflow from such future sources. With increasing technical challenges, both the technical viability of the LNG project and the speed of execution are both critical factors in achieving successful financing and development of African LNG projects. These are also important in phasing the development of LNG projects into trains to reduce the overall capital expenditure and to de-risk additional trains through the commercialisation of initial LNG trains coming into operation. This approach has consistently been utilised in US LNG projects and has been successfully replicated in Africa, for example with the recent development of Nigerian LNG train 7 at Bonny Island.
Net zero and energy transition agendas
While Europe’s appetite for African natural gas has grown recently, European governments’ commitment to net zero carbon emissions by 2030 has caused some European importers to be wary of signing up to long-term offtake commitments for large volumes of natural gas vital to finance the development of African LNG projects. It remains to be seen whether major Asian importers are likely to move away from the spot market to fulfil this role. Increasingly, non-governmental organisations are taking a role on challenging the financing and development of new oil and gas projects. Previous financiers of African oil and gas projects, and in particular
14
December 2023
those bound by political objectives, such as export credit agencies, are being targeted by these groups when financing new oil and gas projects, leading to additional issues raising finance for large scale LNG projects. In the longer term, the pressures of decarbonisation cannot be ignored. With an estimated 600 million Africans lacking access to power, and over one-third of African power being produced from coal, oil, and diesel, Africa faces the dual challenge of increasing its generation capacity while looking to decarbonise its energy supply, with African natural gas likely to take a key role in moving thermal power generation away from more carbon intensive oil and coal.
The future of African natural gas
The long-term future of global natural gas demand is uncertain, and with limited domestic markets for natural gas and few strongly creditworthy off-takers, African LNG projects face a considerable amount of price and demand risk, particularly as the impact of the war in Ukraine on European natural gas prices lessens. African energy demand is set to double by 2040. With a lower carbon intensity than oil and coal, the two other leading power generation fuels in Africa, and a flexible generation profile, many African governments are considering natural gas-fired power to assist with their transition towards a lower carbon economy while meeting the growing energy demands of their citizens. For natural gas producing states, this could create conflict between the revenues and foreign exchange generated by LNG exporting projects and the need to utilise natural gas for domestic power production and local industry. While African demand for natural gas is likely to increase substantially in the coming decades, the timeframe of this, and the uncertainty of how this will occur, are unlikely to mitigate investor and lender concern as to the viability of some African LNG projects. The advantages of allocating natural gas to LNG export projects are numerous, particularly the access to valuable foreign exchange for host governments, the higher price available for the export of LNG compared to supplying the domestic wholesale market, and the access to long-term offtake contracts with counterparties with strong balance sheets. Yet this needs to be balanced with the domestic requirement for natural gas, most notably for power production. While domestic wholesale prices are generally lower than the price available for LNG exports, there is a strong political drive to retain natural gas for domestic usage, which is likely to play a role in allocation of natural gas to LNG export projects in states such as Tanzania and Nigeria. In the near-future, African natural gas producing states are likely to focus their natural gas resources on exporting to Europe and Asia, taking advantage of higher prices and access to foreign exchange. However, in the medium-term, the increasing industrialisation and population growth of African nations, as well as a clear focus on decarbonisation of industry and the energy supply, is likely to require more of a balancing towards diverting natural gas from LNG export projects to supply domestic natural gas demand, both in natural gas producing states and their neighbours.
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Peter McGuigan, Parker Hannifin, UK, explores the importance of gas turbine combustion air intake filtration to efficient, reliable, and lasting gas turbine operations.
COVER STORY
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as turbine (GT) combustion air intake filtration is a crucial aspect of ensuring the efficient and reliable operation of LNG production facilities. GTs play a pivotal role in the process of converting natural gas into its supercooled liquid state. They either provide mechanical energy as directly coupled refrigerant compressor (GTC) drivers or provide electrical energy as the front end of turbo generators (GTGs) for motor-driven refrigerant compressors. Similar GTGs are also commonly used for general site power needs. GTs are powered by internal combustion processes, requiring enormous volumes of clean and properly filtered atmospheric air for combustion.
Importance of air intake filtration
GTs are highly-sensitive internal combustion engines that ingest and compress atmospheric air, mix, and then burn it with fuel and release it. The energy of the released hot gas is converted into mechanical shaft power in the power turbine. Airborne particulates, such as dust, pollen, and industrial pollutants, can adhere to and clog the GT’s highly optimised internal components, leading to reduced efficiency, increased fuel consumption, significant maintenance issues, and – especially important for LNG production demands – potentially very expensive plant downtime. Moreover, in the salt-laden coastal and offshore environments in which LNG production facilities are located, corrosive particles and liquid salts which are always present in the ambient air, will, if ingested, eventually destroy the GT cold and hot gas path internals. Corrosion within GTs does not normally show up on measurements within the control room and can remain undetected until mechanical failure occurs. In LNG production facilities, any unplanned disruption to GT operations will result in production slowdowns or even complete plant shutdowns, leading to significant financial losses. The implications of unscheduled interruptions are even more acutely felt when operating floating LNG (FLNG) vessels offshore. Limited personnel and spare parts on board will likely mean specialised crew and equipment need to be mobilised at great time and expense. To mitigate these risks both on land and offshore, high-quality multi-stage LNG air intake filtration systems are employed.
Filtration requirements
The inlet filtration system for an LNG process turbine can have three, four, or even five unique functional stages, providing an ability to change filters online without the need to shut down the turbine. The first few (prefilter) stages are designed to coalesce liquids and remove larger particles and thereby extend the life of the later (high efficiency) stages. As prefilters can typically be changed out without taking the turbine offline, designs that facilitate quick filter changeout need to be incorporated. The final filtration stage should use high-efficiency (EPA – Efficient Particulate Arrestance) hydrophobic media, typically rated E10 to E12 (International standard EN1822) to achieve optimum particulate removal results. Options to use an extended 24-in. (600 mm) deep final filter (compared with traditional 12 – 17 in.
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filter depths) provides for extended filter dust holding and service life if required to meet operating goals. A lower efficiency ‘guard’ filter may also be employed as a ‘final-final’ stage, allowing changeout of all the main filter stages online, including the EPA stage. Another area for consideration in correct filter selection is the type of high efficiency pleated media (‘cloth’) used. Levels of moisture are obviously going to be very high in offshore and coastal environments, and small moisture droplets can quickly block the pores of thinner 2D membrane (expanded PTFE) cloth, typically around 0.05 mm thick. Sudden blockages equate to sudden and unpredictable pressure spikes (the ‘hockey stick’ effect as the loaded filter quickly limits airflow passage downstream and the pressure loss [delta P] quickly escalates), which can result in turbine trip and shutdown. 3D microfibre glass media (around 10 times thicker [0.5 mm]) is the preferred filter cloth employed in advanced filtration systems today for most LNG applications. Microfibre glass offers excellent particulate removal efficiency, but the vastly increased depth provides better resistance to blockages and much more predictability in its performance, with slow, gradual pressure increases as contaminants and liquids are captured. To avoid unplanned maintenance, filters should be designed for long life. Prefilters should require changing no more than around once per year. Second stage filters once every two years, and third or fourth stage filters around just once every 3 – 4 years to achieve the 32 000 hrs+ continuous operation frequently requested by LNG operators. If a filtration system requires more regular maintenance, a review of its
design and the choice of staged filter grades is recommended. It is not uncommon to adjust product selection as the reality of site requirements becomes clear during actual operations. The ‘best’ fit filter solution may therefore change with operating profile and/or season and differ from that originally supplied. A well designed filterhouse should allow direct interchangeability of various products in this regard and, equally importantly, should be future proofed to allow for the introduction of new products as filtration innovation continues at pace and new products are released to market. One job of the rotating equipment and maintenance engineers is to align filter replacement intervals with a strategy for spare parts planning within the pre-defined GT maintenance and inspection windows (BSI, HGP, major inspection). These inspection windows are normally defined by the GT OEM based on fired hours and/or the number of starts. Defining a maintenance programme that reduces the owner’s costs and keeps the gas turbine available when needed requires careful thought, as well as early and frequent engagement with filter system professionals. Filter system designers are continually developing and improving technology to enhance performance in challenging offshore and onshore LNG installations. Filter selection needs to be reviewed in terms of the risk/cost of reduced plant production efficiency created by contaminants bypassing the filters and moving downstream into the GT, an equation highly dependent on the duty cycle and reliability needs of the processes. There are very few more critical applications than GTs when used for LNG production. The filtration requirements for gas turbine air intake systems in LNG production facilities are stringent and involve several key factors:
Particle size
Filtration systems must be capable of removing dry particles of varying sizes. Commonly used standards to define this are EN779, EN1822, and ASHRAE 52.2. The more recently introduced ISO 16890 standard classifies filters based on their ability to remove particles in different size ranges, such as PM1 (particles smaller than 1 micron), PM2.5, and PM10. A comprehensive filtration system will address all particle sizes expected on site and allow flexibility to temporarily change stages online should weather events and/or seasonal variations alter that Figure 1. Four-stage PARKER gas turbine (GT) air intake filtration particulate size profile. Where sub-micron sized filterhouse in the shop (GE Fr.7E refrigerant compressor mechanical drive [six units, GTC]). 18 million tpy LNG facility, US Gulf coast. dust levels are high and identifiable, or extended operations is a key demand, thoughts will turn to installing high efficiency (EPA) filters as the final stage of filtration. These filters capture the very smallest particles and minimise fouling of the compressor blades. However, if moisture remains in the airflow by the time it reaches the EPA stage, then the filtration media selected must be carefully considered as previously discussed. Having materials and medias not prone to pressure spikes and that do not require frequent monitoring is desirable and will help avoid sudden Figure 2. Three-stage PARKER GT air intake filtration filterhouse (GE PGT25+G4 and unplanned turbine outages. Moisture refrigerant compressor mechanical drive [four units, GTC]). 3.2 million tpy FLNG is one contaminant (especially when facility, offshore Cameroon.
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combined with hydrocarbon mists) that will make airborne dust or corrosive salts ‘sticky’ and much more likely to leach through a filter and travel downstream into the clean air path. One advanced way of stopping this is by using hydrophobic (water/liquid resistant) filtration media.
Efficiency
Filtration efficiency is measured as a percentage of particles removed from the airflow. Higher efficiency filters can remove a greater proportion of contaminants, but they might also cause higher pressure drops, affecting the turbine’s performance. Striking the right balance between filtration efficiency and pressure drop is crucial.
Salt removal
A filtration system needs to efficiently defend the turbine from both liquid and solid phase corrosive contaminants. Salt can be difficult to handle as it readily absorbs moisture and can move easily from solid to liquid form with changes in ambient relative humidity in a process known as deliquescence. It is very common to see a GT filter system capture salt in its dry state, only then for this dry particle to swell and become semi-liquid when the ambient humidity increases. The semi-liquid salt droplet can then leach through
non-hydrophobic media and reach the GT, eroding and corroding the internals. Chlorine in the salt acts as a pitting corrosion initiator in the colder compressor section of the GT and in the hot section, accelerated corrosion (known as sulfidation) can occur when ingested salts combine with sulfur from the fuel, creating sodium sulfate. To ensure that a filter system offers adequate protection, laboratory and field validation needs to allow, define, and test for the expected salt concentrations, the salt aerosol droplet size distributions, and needs to do so with changes in the salt’s state (solid to liquid and vice versa).
Airflow capacity
GTs require significant airflow to function optimally. The filtration system must have sufficient capacity to accommodate the required airflow without causing excessive pressure drops. Individual filters operate with airflow sweet spots, whereby particulate removal, salt removal, dust holding capacity, and pressure drop are optimised. Move outside of this window and performance and/or system cost is unduly impacted. The total number of filters becomes an even more significant issue for more compact, high velocity intake systems typical offshore, where space is very limited. Whether compact or not, an uneven velocity airflow creates more turbulence, is inefficient and leads to increased pressure drop across the system.
Environmental conditions
The location of an LNG production facility influences the types of contaminants present in the air. Facilities near deserts might deal with high levels of fine sand particles as an example, which may or may not be seasonal in nature. Due to the nature of LNG operations, GTs employed here will always have to contend with salt-laden air. Filters should be selected to address the specific environmental challenges expected on site and have flexibility to adjust to new requirements as they are presented.
Maintenance Figure 3. A PARKER gas turbine filtration (GTF) filter element manufacturing line.
Regular maintenance is essential to keep filtration systems operating effectively. Filters need to be inspected, cleaned, or replaced based on manufacturer recommendations or actual performance indicators to ensure consistent and reliable operation.
Conclusion
Figure 4. PARKER-supplied GTF system, 24 000 hrs BSI
(GE LM6000 refrigerant compressor mechanical drive [16 units, GTC and GTG]). 9 million tpy LNG facility, Western Australia.
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In the context of LNG production, GT combustion air intake filtration is a critical consideration to ensure the efficiency, reliability, and longevity of gas turbine operations. Both mechanically and electrically driven refrigerant compressor systems employing GTs rely on multiple stages of filtration to deliver clean air. While the basic filtration stages are similar between the two applications, differences in energy consumption, maintenance, and installation make each system designed to its specific application. A well-designed and serviced filtration system is essential for maintaining the performance and integrity of gas turbines in the demanding environment of LNG production. When it comes to filters, one size does not fit all – the right gas turbine air intake solution requires very careful assessment and product selection and, when done correctly, provides operators with lightening quick return on investment.
Figure 1. LNG meets explosion protection.
Handling LNG Ingo Emde, R. Stahl, Germany, analyses how safety on ships and on shore can be prioritised when handling LNG.
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oading and unloading tankers requires the utmost care. Product loss is not tolerated; measuring solutions must be reliable and suitable for custody transfer applications. Preparations for the operation are undertaken on board the ship and at the terminal, long before the ship docks. There are many rules that must be observed when it comes to loading and unloading. Ancillary processes such as balancing the ballast tanks
must be successfully implemented alongside this operation. The number one rule is safety first, especially when dealing with cryogenic substances like LNG. Communicating with one another is crucial. This is certainly the case when a fully laden LNG tanker is approaching the terminal. The ship’s crew must contact the operations team at the terminal well in advance of their arrival. There are many details to discuss before the
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tanker docks at the jetty and unloading commences. One of the key details is the estimated time of arrival, which must be disclosed in good time (e.g. 72 hours prior to arrival) and regularly updated. This tells the team at the receiving terminal when they need to start preparing the tanks that are to be filled, be they on shore or on an FSRU.
Discussing unloading procedures
It goes without saying that before LNG tankers can be unloaded, the personnel at the plant terminal need the cargo documents. The pre-operational ship/shore procedures then need to be discussed, and the safety checklists must be completed. LNG comprises around 95% methane. If it mixes with oxygen and the oxygen concentration exceeds a certain level, this can constitute an explosive mixture. To counter this risk and the risks associated with the LNG temperature of -163˚C, certain precautions must be taken in order to guarantee maximum safety during loading and unloading operations. Before loading and unloading operations can take place, the tanks that will be filled with the cryogenic LNG must be prepared. They must be brought to a sufficiently low temperature to prevent excessive quantities of LNG
from violently vaporising when introduced into the tanks. Additionally, the amount of residual oxygen in the tanks must be minimal.
Inerting and pre-cooling storage tanks and loading apparatus is essential
Hours before the supply ship arrives, the team at the unloading terminal must start pre-cooling and inerting the onshore tanks using dry nitrogen. Once the amount of oxygen in the tank drops below 2% and the temperature is around -45˚C, some LNG that is kept in reserve is introduced into the tank. This vaporises, further cooling the inside of the tank to around -130˚C. Likewise, the loading arms and manifold pipes are purged multiple times with nitrogen until the oxygen content of the purge gas that has been repeatedly discharged is less than 2%. This ensures that explosive methane-oxygen mixtures cannot form during the unloading operation.
Skilful control of the loading arms
Once these preparations are complete, the tanker can dock. As with any large tanker, the LNG carrier must always be securely moored and anchored (or moored to the FSRU, if the terminal is a floating one) before it is unloaded. The next step is one of the most critical: the terminal or terminal ship must be connected to the tanker loading system by means of loading arms, pipes, and hoses. This is no easy task. It takes a certain amount of skill to guide the pipes on board using the remote-controlled loading arms and then line them up at the correct angle. The flanged joints must then be properly sealed and secured. To eliminate the possibility of human error, at least two workers are assigned to this. Electrohydraulic LNG loading arms use game-changing, purpose-built technology that continually compensates for the ship’s movements due to the action of the waves. Where they are installed on an FSRU, they can Figure 2. Control systems for LNG loading arms must be protected even compensate for the action of the waves against explosions. between the two ships. In an emergency, the loading arm will automatically disconnect from the ship; ideally, this will happen without much LNG escaping. The use of an emergency release coupling makes this possible. If, however, large quantities of LNG do escape as a result of an operating error, the hydraulic system prevents the plant from being damaged, while the explosion-protected electrical system prevents an explosion.
Careful cooling prevents vapour locks
Figure 3. The importance of LNG as a fuel for new ships has been growing for some time now.
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Before the unloading process can begin, the cargo pipelines and loading arms must also be cooled. This largely prevents deformation as the cargo passes through at -163˚C. If the pipelines are relatively warm when the LNG is introduced, the resultant rapid vaporisation of the natural
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gas can cause vapour locks to form, which can block the path of any LNG that flows along the line subsequently. This may in turn result in damage to pipelines, valves, and flanges. One of the things used for cooling is actually LNG, which is sprayed into the arms either from the ship or from the onshore terminal.
Pressure build-up and equalisation using boil-off gas or onshore fans
The LNG can now be pumped to shore by submersible pumps installed at the bottom of each tank. Pressure differences between the onshore tanks and the ship’s cargo tanks facilitate this process. LNG is conducted to the tank filling lines via the loading manifolds; compressors are then used to help deliver the LNG to the LNG tanks on shore or on the FSRU. To maintain the pressure on board the ship, LNG can be vaporised there and conducted in the form of boil-off gas (BOG) to the cargo tanks. One possibility is to use an onshore fan to force the natural gas into the ship’s tanks. Once the unloading process is complete, nitrogen is flushed through the pipeline connections. They must not be reopened until they have returned to atmospheric pressure, no longer contain any liquid, and have undergone the inerting process.
Loading LNG tankers from the dry dock
The preparations that must be undertaken at export terminals before loading LNG tankers are much the same as for unloading them. It goes without saying that the supply lines must be free of oxygen. There are some specific procedures that must be performed on board the tanker, however. If the tanker has come directly from the dry dock, the cargo tanks may need to be dried. This can be carried out separately or as part of the inerting process. In the latter case, the inert gas must not be too cold, otherwise it may cause any moisture present
to condense. Insulation and inter-barrier spaces must also undergo the inerting process.
Eliminating oxygen from inter-barrier and insulation spaces in membrane-type tankers
Inter-barrier and insulation spaces in membrane-type tankers must also be purged with dry nitrogen when the tankers are loaded or unloaded. Any pressure fluctuations that occur at this point as a result of cooling or warming must be mitigated. The pressure should be maintained slightly above atmospheric pressure to prevent the ingress of gases. If the ship’s LNG tanks have been filled with an inert gas that contains carbon dioxide (CO2), they must be injected with LNG vapour before they are filled with LNG. During this process, they are cooled and the heavier inert gas is displaced downwards. The ship’s pipework and the inert gas must additionally be free of water and CO2. To ensure that this is the case, it is purged with nitrogen. Methane is then conducted through the vent mast riser, initially at a concentration of approximately 5%, before finally reaching a concentration of 98% by volume. Ideally – and depending on the local port authority’s regulations – this gas will be recovered for reliquefaction rather than being vented into the atmosphere. The pipelines are now successfully oxygen-free, fulfilling a fundamentally important safety requirement.
Gradually increasing the loading rate, factoring in the maximum possible pressure
LNG is now sprayed into the cargo tanks and pipelines to further cool them. Otherwise, LNG would rapidly vaporise, expanding to 600 times its volume in its gaseous state. The loading process must not commence until the temperature in the tanks is approximately equal to that of the LNG that is to be loaded. Once the process is under way, the loading rate is gradually increased. The tank vapour pressure is continuously monitored throughout this process. It should be kept below the value at which the pressure-relief valves would open. Temperature profiles are also recorded at various locations. The predetermined maximum pressure and maximum temperature must not be exceeded. The thermodynamics involved in this process are incredibly complex. Relevant factors include the transfer of heat between the liquid and the tank wall, the compression of the gas phase above the liquid, the vaporisation process, etc. The better the process is understood, the safer and faster the loading operation. Gradually, all tanks are filled in accordance with the cargo plan. The loading rate must be reduced in good time, before the tanks are completely full. Membrane tanks can normally be filled to 98% capacity. Moss-type tanks can be filled to Figure 4. Number one rule: safety first, especially when dealing with 99.5% capacity. cryogenic substances like LNG.
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Keep an eye on the ballast tank fill level and LNG flow rate
Multiple processes take place on the ship alongside the loading or unloading operation. For instance, the fill levels in the ballast tanks need to be adjusted as appropriate – when an LNG tanker is not carrying cargo, the ballast tanks will be more or less full; if it is carrying cargo, the ballast tanks will be mostly empty. The flow rates during loading and unloading operations also need to be accurately measured for billing purposes. Special Coriolis mass flowmeters are available for measuring cryogenic liquids in preparation for custody transfer – these flowmeters also measure entrained BOG (two-phase flow) and boil-off loss.
Classification into zones 0 to 2 on the ship and on shore
It can take 20 – 30 hours to fully load or unload a large LNG tanker. A multitude of different devices and machines are used over the course of the operation: temperature gauges, flowmeters, pressure gauges, various pumps (e.g. spray, stripping, ballast, and submersible, motor-driven pumps), compressors and fans, inert-gas systems, heat exchangers, etc. Owing to the increasing price of LNG and the demand for environmentally friendly processes, there is also growing interest in reliquefaction systems, which are now a good option even for smaller LNG tankers and bunker vessels. These also help to
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cool the LNG tanks, which means that the workers can commence the loading process sooner when the ship arrives at the terminal.
Safety assured by and for the crew
The ship’s onboard equipment must comply with all the applicable marine standards, which means it must be exceptionally robust. In addition, the ship’s electrical devices and installations must satisfy the requirements set out in the IGC (IMO gas code) for type 2G tankers. Explosion protection classifications apply depending on the type of hazardous area – there is Zone 0 (e.g. in tanks), 1 (in the vicinity of valves), or 2 (areas further away, where explosive gas-air mixtures are rare and are not likely to occur). Aside from the devices mentioned, any control systems, operating panels, isolators, etc. within these zones must therefore also possess appropriate Ex approval such as IECEx, ATEX or CCC certification. This also applies to devices and installations at the terminal. The control systems for the LNG loading arms, for example, must be protected against explosions. In addition, suitable visual and audible alert systems on ships and on shore play a key role when it comes to safety. As a result, the responsible, safety-conscious conduct of the ship’s crew and terminal workers is not the sole line of defence to ensure safe loading and unloading. Appropriate equipment and systems are in place to protect the people, the ship and the terminal when working with this sensitive cargo.
EVOLUTION, NOT evelopment of any new technology for an existing market sector implicitly requires that the new solution must provide something more than already in play. The ‘Streamlining the System’ article that appeared in the February 2021 issue of LNG Industry detailed the safety and operational aspects of ecoSMRT® – a single mixed refrigerant (SMR) LNG reliquefaction system developed by Babcock’s LGE business. This update covers the ongoing development of the system and the incorporation of operational feedback from close to 500 000 hours of operation. To achieve this, the company defined a set of criteria at the beginning of the journey as integral components of the value proposition of ecoSMRT, i.e. to be more efficient, physically smaller, and easier to operate. In the end, the system succeeded in meeting all three criteria, resulting in a 1.9 tph reliquefaction unit that is installed on more than 110 LNG carriers ranging in size from 174 000 – 200 000 m³.
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Andrew Scott, Business Development Director, Babcock’s LGE business, UK, outlines developments in the company’s single mixed refrigerant LNG reliquefaction system.
REVOLUTION
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Initial and ongoing development of ecoSMRT could not be done in isolation. By closely working with the owners and operators through Owner Support and Service Packages (OSSP), the development items could be tailored to give the customer maximum benefit. As a key enabler of improvements to the existing ecoSMRT solution, and in addition to the conventional correspondence and meetings (both office-based and onboard the LNG carriers), Babcock’s LGE business utilised live operating data from the plant, allowing for a greater degree of reliability and accuracy of actual plant performance and enabling more efficient analysis and informed development decisions.
Increase in reliquefaction capacity
As with all technologies, there are numerous incremental improvements which occur as the system matures. Many of these are simple within themselves, but the value added far outweighs the apparent change and often the maxim of ‘1 + 1 = 3’ applies. Since the first ecoSMRT system was ordered in 2018, it is now on variant number seven. It is important to note that the fundamentals remain unchanged throughout, but operational feedback plus innovative engineering practices internally has meant several improvements have been identified and implemented as the system has evolved. The two main changes which have been introduced based on feedback from gas trials, first loadings, and voyages are:
One of the most immediate changes to come from the operational feedback was the increase in guaranteed reliquefaction capacity. Guaranteed reliquefaction capacity refers to the quantity of boil-off gas (BOG) generated onboard the ship which can be continuously captured, reliquefied and returned to the cargo tanks. The initial capacity guarantee on ecoSMRT – developed in line with competing systems in the market at the time – was for a reliquefaction unit that would give 1.5 tph, based on pure methane, and this became the guaranteed performance figure. With growing feedback from plants in operation and analysis of the data, it was shown that ecoSMRT could offer 0.2 tph more than suggested and thus it was possible to raise this guaranteed figure to 1.7 tph. This guarantee was disseminated across all ships with ecoSMRT, installed as a zero-cost added benefit for owners. As more operating data becomes available, it may be possible to further increase this guaranteed value but for the present time it remains at 1.7 tph.
z Incorporation of the stand-alone refrigerant top-up skid into the main module.
Figure 1. Separate modules – desk space 83 m3.
Design concept evolution
Figure 2. Combined modules – desk space 71 m3.
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Incremental improvements
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z Option to remove the condensate flash drum. The earlier variants of ecoSMRT had a primary module which contained the reliquefaction plant components and a secondary module which contained the refrigerant bottles for the automatic system that ‘topped up’ the mixed refrigerant to maintain the composition as close as possible to the design optimum. This, of course, required interconnections between the modules which impacted on where access ways could be defined etc., and a higher CAPEX considering the full design and build cost. The decision was made to incorporate the filling skid into the main module but at the same time to not increase the footprint of same, the end result being as depicted in Figures 1 and 2. One of the more obvious changes that was made was to alter the orientation of the expansion vessel from horizontal to vertical to free up more floor space, which does not compromise the operation in any way. During the work around the filling skid and the top-up system, the need for a continuous automatic top-up was reviewed and the decision made to change this to a more operator driven system as feedback showed that the system was tolerant to greater changes in the refrigerant mix composition than initially thought. Another change that was introduced was to change the gas analysis from a chromatograph to an infra-red based system, thereby removing the continuous consumption of carrier gas, one less thing for the crew to worry about.
The condensate flash drum (CFD) was included in the original design concept to provide a buffer between the condensate produced in the BOG condenser and the condensate return to the cargo tanks in case of any impact from two-phase flow in the condensate return header feeding back into the reliquefaction system. After feedback from the operation of the first units in service, a bypass around the CFD was installed on two ecoSMRT plants to allow the system to be tested with and without the CFD in service. The results of the investigations were correlated against the desktop calculation work and found to be consistent. There was no negative impact on the capacity of the system with the CFD not in service and, in fact, in several cases the reliquefaction capacity was increased with the bypass open. However, as several shipowners looked to retain the CFD on the basis of consistency with vessels already in service, the module design
was not modified to remove the CFD, and it has become an option dependent on client preference. The next stage in the evolution of ecoSMRT is the design and delivery of increased capacity systems in response to market trends: z The increase in spot trading in the LNG market. z The growing demand for floating storage applications – FSUs, FSRUs, and floating LNG. z The high cost of LNG incentivising the capture of increase volumes of BOG. Based on these above factors, LGE has developed ecoSMRT solutions for up to 3.1 tph, all based on the 1.9 tph design. The increase in the conversion of older LNG carriers with less efficient insulation systems to floating storage and the lack of propulsion demand has pushed the capacity to significantly greater than would be necessary for modern vessels. The optimum solution for each application may not simply be a single increased capacity unit, but two smaller capacity units in parallel to give a wider range of operation and this can be developed with the shipowner at the early stages of the project. The fundamental aspects of the proven 1.9 tph ecoSMRT plant are unchanged in the increased capacity plants with all the operational benefits, e.g. fully automated operation, stringent focus on safety and reliability maintained. The rigorous review of any changes or modifications, including the application of HAZOP techniques etc. as appropriate,
ensures that safety remain at the forefront and is never compromised. The increased reliquefaction capacity of course requires larger components and an increased CAPEX. A larger plant also requires more in the way of utilities, e.g. electric power, cooling water and therefore the OPEX will also be increased. However, the commercial benefits of capturing and reliquefying more of the BOG can outweigh this investment when considering the cargo cost of incinerating excess BOG and the environmental impact and costs of generating additional carbon dioxide (CO2). The physical dimensions of the larger capacity ecoSMRT modules and the major components contained therein need to be looked at in conjunction with the shipyard to determine the envelope and weight, particularly for retrofit applications. Again, it may be that components being installed in parallel rather than in a single very large unit be the best solution, e.g. if there were height restrictions that would impact on the LNG condenser.
Conclusion
LNG is often referred to as a transition fuel on the road to net zero carbon, and will remain so for many years to come as alternative technologies are developed and then matured. As such, ecoSMRT will continue to evolve and grow in response to customer’s needs and desires whilst always maintaining the enviable safety record that the LNG carrier business holds. The system plays a part in this by offering an efficient way to reliquefy BOG. A more efficient reliquefaction system requires less electrical power and therefore emits less CO2 to the atmosphere from the power generation system.
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GAS TREATMENTS FROM BEGINNING TO END Alan Garza, Gas Analysis Product Marketing Manager, Endress+Hauser USA, looks at ideal analysis methods for LNG from gas treatment to liquefaction.
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atural gas must be treated before liquefaction to remove containments that can condense at cryogenic temperatures or damage equipment. As the disruption of the global hydrocarbon supply chain increases, LNG has become an important topic for buyers and sellers looking to satisfy energy demands. LNG is moved around the world every day, comes from a variety of sources, each with unique characteristics, and is worth billions of dollars. Tuneable diode laser absorption spectroscopy (TDLAS) can help ensure natural gas is contaminant-free before liquefaction and other analyser technologies can identify when LNG suffers value loss during an extended transit period. New techniques provide greater measurement accuracy and reliability combined with lower lifetime costs and maintenance.
Pretreatment and natural gas liquefaction
Compared to locally produced gas, LNG has fewer contaminants due to them being removed during the extensive pretreatment process. The contaminant levels involved in this pretreatment stage call for TDLAS analyser to be implemented at transfer points in each stage. TDLAS analyser can then verify the quality of the catalyst and the overall pretreatment process by the level of contaminants in the gas before reaching further into the liquefaction process.
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Once pretreatment is complete, the gas moves to liquefaction and onto the transport mechanism.
What challenges or pain points does the industry face during the gas treatment cycle when it comes to natural gas and water measurement?
Water (H2O) is a critical measurement in LNG production. H2O can cause many problems from pipeline degradation due to oxidation to a very possible freeze-up of the cold box heat exchanger tubes in the liquefaction trains, which of course will prevent loading and shipment of the LNG. The first challenge is acquiring accurate and repeatable measurements. Depending on the type of analyser and the measurement technique behind the software and hardware, accuracy can range from +/- ppbv (parts per billion by volume) to lbs/million ft3 of a difference. TDLAS technology is a good solution for H2O contaminant measurements in methane prior to liquefaction as it can provide accuracy of low ppmv. When TDLAS is then paired with differential spectroscopy technique, such as that offered by Endress+Hauser, it will enable detection and quantification of low ppm to sub-ppm concentrations in H2O in natural gas streams. This combination will provide industry leading accuracy and the user the ease of mind that his liquefaction process will be safe from freeze up due to H2O in the natural gas stream. Once the proper analyser has been selected, a different challenge can emerge. This is when expertise is very important. An initial challenge post analyser selection is sample transport. When sending the gas sample to the TDLAS analyser, the gas travels from the tip of the probe to the analyser. To stay in the same (gas) phase that is flowing through the pipeline, a few things must be known, including the distance from the tap, environment, gas composition, and analyser location. Once this data has been collected, an application engineer’s team can advise what is needed for the sample conditioning and the proper analyser that could maximise the customer’s best results. Ideal hardware for contaminant measurements should be:
z Laser based. z Proper wavelength. z Compatible with natural gas and all the different contaminants in the system. z Easy and convenient to interface with. z Utilises differential spectroscopy.
LNG transport
Natural gas is liquefied and transferred onto a ship. Arriving shoreside, the LNG is then transferred to a storage tank for regasification before entering the pipelines. LNG changes while in transport, it boils off its light components, causing them to escape into the tank. The typical LNG tank load can have a value of up to US$50 million or more, so a change of even 1% is worth US$500 000. Basic contaminant levels and calorific values must be verified. The challenge at hand is finding an analyser technology suited to the application.
Traditional gas chromatography
The traditional method when it comes to analysing natural gas after the pretreatment stage is gas chromatography (GC). A typical GC analysis takes a sample of the natural gas, mixes it with an inert carrier gas, and pushes it through a packed column enclosed in an oven. GC tends to be more on the complex side. The analyser is often near the source because it depends on a sampling system to deliver gas to the analyser. Due to the need for an ongoing supply of carrier gases and test gases for calibration, this can also start to become costly. For a GC analysis, an LNG sample must pass through a vaporiser to change from liquid phase to a gas phase. Where the issues generally arise are, according to the Gerg Report, at the vaporiser stage.1 This is usually more problematic than the analyser itself and must ensure that it does not lose the lighter fractions or stop the process while some of the heavier fractions remain partially liquefied. The basic challenges while using GC analysers are: z Can be operationally complex. z Requires daily calibration performed by feeding a premeasured test gas into the analyser, or calibration prior to each batch. z Requires consumables and which means taking the analyser offline. z Can provide highly precise analysis, but if a sample is not representative of the LNG composition, then the underlying problem remains unresolved.
Figure 1. RXN-41 cryogenic probe for inline LNG measurement.
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z Requires LNG to be converted into gas for analysis.
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z Analyser must be near the source due to the tubing and valving at a limited distance.
Raman spectroscopy
Various gas and liquid analysis technologies have been developed around the ability of a laser to produce highly specific wavelength of light. Raman Spectroscopy uses a laser to produce light of visible light spectrum. When certain molecules are exposed to the monochromatic light, then the light’s energy excites Raman Active molecular bonds. This interaction causes photons that scatter and return to the detector which a shift in frequency due to the specific Raman shift. Scattered light provides highly specific chemical composition data about the Raman active molecule it interacts with. Raman can measure in most liquid phases which means that there is no requirement of extraction or excessive sample conditioning. This gives the user the ability to insert a probe directly into the LNG stream which then eliminates the need for a traditional handling system. When Raman analysis technique is applied to LNG analysis, a probe is inserted into the pipe to analyse the flowing liquid or gas. Laser light is emitted from the end of the probe into the LNG sample, and the Raman light is collected back through the same probe tip. The collected Raman light travels through a second fibre-optic cable and then enters a detector in the analyser, where the resulting individual wavelengths are identified and quantified. Using this approach results in several critical advantages when compared to GC analysis, including:
SEEING IS
BELIEVING
z The probe inserts directly into the LNG stream, so that it takes the reading in-situ, with the moving liquid constantly refreshing the sample. z Measuring LNG in-situ means there is no vaporiser and no need for sample transport lines, valves, heaters, or regulators. z A single analyser can be connected with up to four probes, so readings can be taken at multiple locations in the process stream. z Output from the probe changes in real time, and the analyser can take a snapshot of the composition in less than 10 seconds with no delay between readings. z Measures stream up to 500 m from the analyser using cryogenic Raman optical immersion probes, and industrial fibre optic cables. z Operates virtually maintenance-free, ensuring that the analyser is ready any time measurements are needed. z Can operate for up to two years without needing to be calibrated.
References 1.
‘Raman method for determination and measurement of LNG composition’, The European Gas Research Group, (February 2017 – December 2021), www.gerg.eu/projects/ liquefied-natural-gas-lng/raman-method-for-determinationand-measurement-of-lng-composition
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LNG INDUSTRY PROJECT OVERVIEW AFRICA AND THE MIDDLE EAST The Americas asia pacific europe
F
ollowing Russia’s invasion of Ukraine, the need for energy security and independence has never been greater. With LNG widely considered as a ‘transition fuel’ in the world’s steps to net zero, especially in regards to the benefits of using LNG in the marine and heavy transport industries, its demand (at least in the short term) is only going to increase. This is evidenced by the fact that according to IEEFA, Europe has added six new LNG terminals since the beginning of 2022.1 In order to meet this demand, new projects will need to be implemented, constructed, and built. The projects listed in this overview are broken down by region: Africa and the Middle East, the Americas, Asia Pacific, and Europe. Each section provides some key facts and information about LNG projects and expansions currently under construction that are due to be operational by the end of the decade.
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Africa and the Middle East
Mozambique
Iran
Coral South FLNG
Iran LNG Iran LNG is one of three LNG export projects the country had planned to launch in the early 2000s. The other two projects – 10 million tpy Pars LNG (TotalEnergies) and 16.2 million tpy Persian LNG (Shell) – have since been abandoned.2 It comprises of two 5.4 million tpy trains (10.8 million tpy in total), expandable to four trains in the future. Works restarted in March 2023 and, once operational, the Iran LNG project would be the country’s very first LNG project. The LNG project’s midstream development consists of the plant, including storage and loading facilities, and has been divided into three packages: 1. LNG plant, including process, utilities, and offsite areas, as well as: Gas treatment. Liquefaction. Combined cycle power plan. Sulfur solidification, storage, and loading. Loading facilities and buildings. 2. Storage tanks, including both LNG and LPG tanks: Three 140 000 m3 LNG storage tanks. Two 30 000 m3 LPG storage tanks. 3. Harbour and jetties, including: LNG/LPG jetties. Break water. RO-RO berth. General cargo and temporary berth. Sulfur berth. Tug boat berth. West/east dick. Seawater lines. In September 2023, it was reported that progress on the project had neared 50%.3 The project is expected to be operational by mid-2025, when the current administration’s time in office comes to an end.
Coral South is the first project initiated within Mozambique, and develops the gas resources that were discovered in offshore area 4 in the Rovuma Basin. The floating LNG (FLNG) plant has a capacity of 3.4 million tpy, and was inaugurated on 23 November 2022. The shipment of LNG produced from the gas field departed from the Coral South FLNG facility on 13 November 2023. The Coral North proposed project would be a duplicate of Coral South, providing a capacity of 3.5 million tpy alongside the 3.5 million tpy already in place. It is expected to commence in 2027.
Mozambique LNG The Mozambique LNG project reached final investment decision (FID) in 2019, but development stalled due to concerns of stability and security within the area. TotalEnergies had to declare force majeure on the project in April 2021, but recently announced it was in the process of re-starting construction. Originally expected to deliver its first LNG cargo in 2024 with plans to produce up to 43 million tpy of gas, it could now take place in 2028.4 Mozambique LNG is the first onshore development of an LNG plant in the country.
Senegal
Yakaar-Teranga is on the world’s largest gas discoveries in recent years. It holds around 25 million ft3 of gas with negligible carbon dioxide content and minimal impurities, which helps reduce the need for processing ahead of transportation/liquefaction. Kosmos Energy has recently increased its working interest of the Yakarr-Teranga gas discoveries offshore Senegal to 90%, and assumed operatorship (subject to customary government approvals) following bp’s exit from the field. Kosmos has been working closely with PETROSEN and the Senegalese government on a development concept that prioritises cost-competitive gas to the increasing domestic market, combined with an offshore LNG facility targeting exports into international markets. The currently envisioned concept is an offshore development producing approximately 500 million ft3/d of gas, with domestic gas transported via pipeline to shore and export volumes liquefied on a FLNG vessel. The concept is now being optimised to best meet the domestic and international requirements, after which the project will move into FEED.
Tanzania Tanzania LNG
Figure 1. The Coral South FLNG. 36
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The Tanzania LNG project was initially proposed in 2016. Negotiations have been slow, but Equinor, Shell, and ExxonMobil recently reached an agreement with the government on a regulatory framework and how the LNG produced at the facility (10 million tpy worth of capacity) will be shared. The Acting Director of Tanzania’s Petroleum Upstream Regulatory Authority, Chrales Sangwemi, stated: “We are happy it is a big step towards the implementation of the project although we have a lot to do. If everything goes well as planned, I am confident that the final investment decision will be reached in 2025.”5
The Americas Canada
Developers expect the first LNG exports from the offshore unit in December 2023, and LNG exports from the onshore units in 2025.
Woodfibre LNG
Energia Costa Azul export project
Woodfibre LNG is a proposed LNG export facility near Squamish, British Columbia (B.C.), currently in the pre-construction phase. Since the project was launched, it has received three environmental approvals from: the B.C. and Canadian governments, and the Sḵwx̱wú7mesh Úxwumixw (Squamish Nation). The Squamish Nation conducted an independent environmental assessment of the project and granted Woodfibre LNG an environmental certificate in 2015 – this was the first legally-binding, Indigenous-led project approval in Canada. Since the beginning of November 2023, Woodfibre LNG has started the site preparation for construction, part of which includes sweeps for invasive species, relocation of existing stockpiles on site, mobilisation of heavy equipment, and preliminary site grading. This work is being performed by the construction sub-contractor, LBLNG, and is part of Woodfibre LNG’s early works construction programme. The Environmental Assessment Office recently approved the amendment to the project’s environmental assessment certificate to allow for a temporary floating work accommodation (a ‘floatel’), along with the associated mooring, access infrastructure, and onshore drinking water treatment facility.6 The project has an export capacity of 0.3 billion ft3/d, and is scheduled to begin service in 2027. It will also use renewable hydroelectricity for power, making it one of the lowest-emission LNG export facilities in the world.
The Energia Costa Azul (ECA) export project is a 50:50 joint venture between Sempra LNG and IEnova, and was the only LNG export project in the world to reach FID in 2020. Located at the site of an existing LNG regasification terminal in Baja California which currently imports LNG, ECA LNG Phase 1 will consist of a single-train liquefaction facility wtih a nameplate capacity of 3.25 million tpy of LNG, and an initial offtake capacity of around 2.5 million tpy. First production is expected in late 2024.
Saguaro Energía LNG Along with other proposed export projects on Mexico’s west coast (including Salina Cruz FLNG and Vista Pacifico LNG), Saguaro Energía LNG is yet to have reached FID.7 Its position on the west coast of Mexico helps leverage gas from the Permian Basin and puts the project in closer proximity to Asian market, helping deliver low-cost LNG globally.
Mexico Altamira Fast LNG New Fortress Energy began developing ways to use FLNG in 2021, and is now deploying the first solution of its proprietary modular approach (the Fast LNG solution) at Altamira in partnership with CFE. The Altamira LNG project will consist of three units, each with a capacity to liquefy up to 0.18 billion ft3/d of natural gas. The first unit will be located offshore, and the other two onshore at the Altamira LNG regasification terminal. Pioneer II, the liquefaction rig that will chill and convert natural gas into LNG, arrived at its final destination at the beginning of October. All three rigs that make up FLNG 1 (Pioneer I [gas treatment rig] and Pioneer III [utilities and accommodating rig]) are now onsite and the team is preparing for first gas.
Figure 2. The Woodfibre LNG site.
Figure 3. Illustration of Mexico Pacific’s Saguaro Energía LNG facility.
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The project is now in the financing process through to FID, with FID expected this year on the first two trains (Mexico Pacific is hoping for 4Q23), with Train 3 to follow closely.8 The trains will have a capacity of 5 million tpy each, with the initial phase of the project (three trains) totalling 15 million tpy. Trains 1 and 2 have sold out, with agreements made with the big three super makers: ExxonMobil, Shell, and ConocoPhillips. The other two customers are Zhejiang Energy and Guangzhou Gas. There is only 1 million t left on Train 3, and plans are underway for Trains 4, 5, and 6, with 50% of options sold on these.
USA Corpus Christi Stage III Cheniere’s Corpus Christi Liquefaction facility is located in the Corpus Christi Bay in Texas. There are already three fully operational liquefaction units, each designed to produce approximately 5 million tpy of LNG. Corpus Christi Stage 3 will consist of seven ‘midscale’ trains that will around 10+ million tpy of production capacity – this will bring the Corpus Christi Liquefaction facility’s total nominal capacity to more than 25 million tpy. The company announced a positive FID in June 2022, and subsequently issued a full notice to proceed to Bechtel to continue the construction of the expansion, which had started earlier in the year under a limited notice to proceed. The facility initiated the pre-filing process in August 2022, and filed a formal application with the FERC in March 2023. It has requested an order from the FERC by September 2024. There is also a further proposed expansion project for midscale Trains 8 and 9.
Golden Pass LNG Golden Pass LNG is adding liquefaction and export capabilities to its existing facility in Sabine Pass, Texas. The project received authorisation from the U.S. Department of Energy (DOE) for Free Trade Agreement (FTA) countries in 2012; received Federal Energy Regulatory Commission (FERC) authorisation in 2016; and received authorisation for non-FTA countries from the DOE in 2017. Golden Pass will include three liquefaction trains with a total output of 18 million tpy, with five existing 150 000 m3
full-containment LNG storage tanks being used to store the LNG produced on site. The project also includes facilities capable of regasifying LNG to produce approximately 2 billion ft3/d of natural gas. The company anticipates start-up of Train 1 in 2H24.
Port Arthur LNG In April 2019, Port Arthur LNG received authorisation from FERC to site, construct, and operate its natural gas liquefaction-export facility. In May 2019, it also received authorisation from the DOE to export approximately 13.5 million tpy of US-produced LNG to countries that do not have a FTA with the US. As of March 2023, Sempra’s 70%-owned subsidiary, Sempra Infrastructure Partners, reached positive FID for the development, construction, and operation of Port Arthur LNG Phase 1. The project includes two natural gas liquefaction trains capable of production up to 13.5 million tpy, with up to three LNG storage tanks, and ancillary support facilities to liquefy and load LNG onto ships. In September 2023, the FERC approved the permit authorising the development of the Port Arthur LNG Phase 2 expansion project. The proposed Phase 2 project includes the addition of two liquefaction trains (Trains 3 and 4) capable of producing another 13 million tpy of LNG. With Phase 1 currently under construction, the development of Phase 2 could double the facility’s total liquefaction capacity to 26 million tpy. The long-term contractible capacity of around 10.5 million tpy is now fully subscribed under binding long-term agreements with ConocoPhillips, RWE Supply and Trading, PKN ORLEN S.A., INEOS, and ENGIE S.A. These all became effective upon reaching FID. Sempra Infrastructure is also actively marketing the Phase 2 project, which is expected to have a similar offtake capacity. Sempra is also evaluating potential carbon capture and/or hydrogen facilities on site in response to market interest.
Texas LNG Texas LNG is a 4 million tpy LNG export terminal to be constructed in the Port of Brownsville, Texas. The project is FERC permitted, with construction beginning in 2024 and commercial operations commencing in 2028. Texas LNG will be powered by renewable energy driving the facility’s electric motors. Baker Hughes was recently selected to supply gas compression technology equipment, including electric motor drives, for Texas LNG’s export terminal. Baker Hughes has a framework agreement as part of this to make a strategic pre-FID investment in the project’s late stage development.
Overview
Figure 4. A rendering of the Port Arthur LNG facility site.
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By the end of 2027, the EIA estimates LNG export capacity will grow by 1.1 billion ft3/d in Mexico, 2.1 billion ft3/d in Canada, and 9.7 billion ft3/d in the US from a total of 10 new projects across the three countries.7
Asia Pacific
The Philippines
Australia
Philippines LNG import terminal (PHLNG)
Outer Harbor LNG import terminal The proposed LNG import terminal is to be built at Port Adelaide, and would be the first in the world to operate exclusively on renewable energy. It secured government project approvals in December 2021, with up to 110 PJ of gas approved to flow through the terminal annually. Stage 1 enabling works were due to start in November 2023, with construction of the terminal and associated infrastructure to run for around 2 year. First gas is expected to flow into the network by May 2026, following a period of commissioning.
Pluto LNG Pluto LNG pipes gas from the Pluto and Xena gas fields in Western Australia to a single onshore LNG-processing train. Woodside is developing a brownfield expansion of Pluto LNG through the construction of a second gas processing train, Pluto Train 2. The Scarborough gas field is located in the Carnarvon Basin and will be developed through new offshore facilities that are connected by a 430 km-long pipeline to Pluto Train 2 at the existing Pluto LNG onshore facility. The 5 million tpy of Scarborough gas will be processed through Pluto Train 2, with up to 3 million tpy processed through the existing Pluto Train 1. The first LNG cargo is targeted for 2026.
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AG&P’s LNG import terminal will be the first LNG import facility in the whole of the Philippines. It comprises of two onshore 60 000 m3 tanks and a 137 000 m3 FSU. The FSU has been chartered by AG&P from ADNOC Logistics and Services for 11 years, with an option to extend for another four years to maximise availability, and has a terminal capacity of 5 million tpy. The hybrid terminal has been commissioned in two phases: the first phase was commissioned with the FSU storage in 3Q22, and the two additional onshore storage tanks will be integrated by the end of the second phase in 2024. The terminal will then have scalable onshore regasification capacity of 504 million ft3/d and 257 000 m3 of storage. It is expected to reach full capacity in 2025.
Vietnam Thi Vai LNG terminal The Thi Vai LNG terminal was inaugurated on 29 October 2023, 16 years after it was first suggested as an idea. It has been completed as part of PV Gas’ vision for national energy security, and 1 million tpy has officially been put into operation. It is Vietnam’s first LNG infrastructure, and is now heading towards the implementation of the terminal’s second phase, which will increase the capacity to 3 million tpy from 2027.
Europe Germany Wilhelmshaven LNG Wilhelsmhaven was the first landing terminal for LNG in Germany to be set up as an FSRU. The Höegh Esperanza is an LNG tanker that has been operating as an FSRU since mid-December 2022 at the jetty. In the initial phase, this FSRU at the first LNG terminal in Wilhelmshaven will replace around 6% of German gas demand, equating to around 11% of Germany’s gas imports from Russia. Höegh Esperanza has intake or discharge rates ranging from 6500 m3/h (closed loop) to 19 5000 m3/h (open loop). A letter of intent signed by the German government and the state of Lower Saxony stipulates the chartering of a total of four FSRUs. The terminal is looking at expanding the existing jetty, with the construction and planned commissioning of two additional FSRU terminals in Stade and Wilhelmshaven 2 in 1Q24.
Greece Alexandroupolis LNG terminal The Alexandroupolis LNG terminal consists of three regasification units, each with a capacity of 315 000 m3/h of LNG, and four LNG storage tanks with a total capacity of 153 500 m3. The European Commission recently approved €106 million to support the completion of the terminal. The strategic location of the FSRU will help with the security of Greece and the Balkans’ energy supply, along with the Regional and Intereuropean Gas Systems.
The project is aiming to enable beneficiary to complete construction, as planned, by end-2023.
Finland LNG terminal Inkoo Gasgrid Finland Oy implemented the FLNG terminal project to secure Finland’s energy supply, and move the country away from its dependence on Russian gas. The agreement for an FSRU between Gasgrid and Excelerate Energy Inc. was signed on 20 May 2022, with the decision to place the FSRU in the Port of Inkoo, Southern Finland. The FSRU has a maximum capacity of approximately 151 000 m3, and a maximum LNG loading capacity of 4500 m3/h. Construction work for the pier and mooring structures, as well as the construction of a 2.2 km gas pipeline, began in August 2022. The FSRU vessel Exemplar arrived in Inkoo on 28 December 2022. On 5 November 2023, Gasgrid delivered the second LNG cargo to the FSRU terminal since the Baltic-connector gas pipeline between Finland and Estonia had suffered a rupture. As a result, the pipeline was closed at the beginning of October 2023, with repairs expecting to take at least five months. All Finnish gas demand must therefore be met through LNG imports.
Poland LNG terminal Świnoujście The decision to build an LNG terminal was made in 2006, and has been operational since 2016 with a current regasification capacity of 6.2 Nm3/y. There are also two cryogenic tanks for process storage of LNG, each with a capacity of 160 000 m3. The terminal is now undergoing an expansion programme as part of a larger investment plan by GAZ-SYSTEM Capital Group. The expansion is being implemented in two stages: z Stage 1 related to increasing the regasification capacity, and was completed at the beginning of 2022. z Stage II, the main points of which are the construction of a third tank with a capacity of 180 000 m3 and construction of new ship quay for the loading, unloading, and bunkering of LNG, will be completed at the end of 2023. This will then increase the technical capacity of the terminal to 8.3 billion m3/y.
Figure 5. The FSRU Examplar at the Port of Inkoo. Source: Excelerate Energy, Inc.
Gdańsk FSRU The FLNG terminal the Port of Gdańsk will be the first FLNG terminal in Poland. It was announced on 14 November 2023 that GAZ-SYSTEM had concluded the agreements term sheet with Mitsui OSK Lines and BW LNG for the delivery and use of the first FSRU, which is set to function as a regasification terminal. The FSRU will be adapted to conduct the regasification process at a level of 6.1 billion m3/y of gas fuel, and the provision of regasification services are planned to begin in early 2028. The programme also includes other investments necessary to launch the terminal, including maritime infrastructure (mooring platform and undersea gas pipeline), with works expected to commence 4Q24, or no later than 1Q25.
Figure 6. A new tank being built as part of the expansion of the LNG terminal Świnoujście.
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References
For a full list of references, please visit the LNG Industry website.
Dr Nicolas Spiegl and Jules Oudmans, UReason, the Netherlands, discuss when to inspect, maintain, or replace control valves to ensure a safe and efficient operation.
W
hen the vast majority of refining and chemical processing plants and pipeline infrastructure were built in the last century, nearly all controls were analogue. Analogue signals, sometimes even pneumatic signals, were used to transmit signals from flow, level, temperature, or pressure sensors
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to the control system and from the control system to the final control element – usually a control valve. Since then, a mixture of analogue technology and modern digital solutions have been used for extensions and modifications. As a result, the typical control valve asset base at any installation today will be a mix of vendors and technology, spanning several decades of technological development. This is a massive challenge for any asset management strategy. This article will review the four primary methods used today to manage the fleet of control valves and discuss the advantages and disadvantages of each of the methods. When managing a fleet of control valves, the fundamental question is when to inspect, maintain, or replace the control valves to ensure a safe and efficient operation. To answer this question, one needs to know the current condition of the valves and the changes in condition over time.
Option one: Manual inspection and testing
Manual inspection requires a trained maintenance technician to visit each control valve in some rotation frequently. A thorough inspection is done by taking the section with the valve out of operation, connecting external test equipment to the valve, and running comprehensive tests. This inspection method provides a spot analysis of the current control valve condition. This includes the functioning and performance of the valve and the pneumatic or electric actuator. The data from each inspection can be collected and uploaded to a database,
Figure 1. Manual inspection of a control valve.
which allows analysing the changes in condition and performance over time. Doing valve condition analysis this way is very costly. The analysis, which can take 2– 4 hours, requires a process stoppage and a permit to work and uses at least two staff members to ensure safety. The entire plant or unit may be shut down if the valve is on a main process line. As long as the asset owner or the third-party service company had the staff, this was a great way to collect valuable data with lots of parameters, conduct detailed tests and close visual inspection to determine if there were leaks, corrosion or other damage. Manual inspection and testing requires enough staff to assign and an expert technical team to execute it properly. As soon as plants started to lose people to layoffs and retirements, the frequency with which the control valves were inspected and tested decreased remarkably. It also introduces an increased risk, including accidents and injury, and the diagnostics only show what is happening right now. The expert does not know what happened to the valve last month or year. This method of valve condition analysis can only be scaled with additional staff.
Option two: Smart valves
Smart positioners are a game changer for control valve diagnostics. These new intelligent devices are equipped with limited data processing and storage capabilities. Operating data, like the number of cycles, the functioning of the actuator, and the difference between the desired and actual position value, are directly available at the device. This diagnostic information is available during the operation of the valve. Stopping production in the section with the valve is not required. Using smart positioners and their diagnostic information for the asset management strategy brings two main challenges. Firstly, only a fraction of a typical plant’s control valves is equipped with intelligent positioners. Many valves in brownfield installation will still be analogue valves. Upgrading the entire fleet of control valves requires a significant investment, meaning the information from the intelligent positioners cannot be used for a holistic asset management strategy covering all the valves. Secondly, how is the data accessed from the smart positioner? One option is to go to the actuator and manually download the information; however, this is labour intensive and again requires a visit and permits. The other option is to use either HART or field bus communication to transmit the data to a centralised asset management system. Even for available smart positioners in a plant, this infrastructure to communicate the diagnostic data is only sometimes available. Intelligent positioners provide valuable information and insights for an asset management strategy but this method is only scalable across some valves and requires a considerable investment.
Option three: Remote valve expert analysis Figure 2. Control valve setpoint (x-axis) and control valve actual position (y-axis). Valve condition analysis as part of the Control Valve App.
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The control valve, the control loop, and the controlled process produce a
considerable amount of data used by the OT systems (DCS/SCADA/PLC). More and more operators have started to save this data in dedicated databases (historians) to make it available for analysis. Seasoned operators and valve experts can judge the condition of a control valve by analysing this data. This involves typically plotting the relevant data in dedicated software and manually evaluating the condition and performance of the valve. Careful manual analysis of the available data can give a good insight into the control Figure 3. Overview of the valve condition analysis inside the performance of the valve and can also reveal Control Valve App. changes indicative of valve and actuator degradation over time. However, this process is time-consuming and requires experts with many years of into insights and information about the valve and actuator experience. It is a viable option for a few critical valves or condition. The developed algorithms combine so-called in reactive mode: valves flagged by the operators as expert algorithms and trained artificial intelligence (AI) problematic. This approach is unsuitable for monitoring models. This means it uses physical models, expert hundreds of valves and evaluating their condition. know-how, and the insights of extensive data analysis. UReason has packaged these algorithms into an industrial Option four: Automatic data-based app called the Control Valve App. condition monitoring The Control Valve App provides detailed insights Using data and intelligent algorithms to better into the valve and actuator condition and performance, understand the condition of industrial assets is the core including information about the control performance idea of Industry 4.0. What are the data points related to (overshoot, undershoot, hunting), detecting issues the operation of every single control valve, and how can (sticking, broken spring, bellow wear, positioner this data be used for valve condition monitoring? calibration), and calculating a reliable remaining The first data point is the setpoint of the valve useful lifetime. position, which signals the control valve to the desired The Control Valve App is used by chemical and position. The second data point is the actual position of pharmaceutical companies as well as operators of pipeline the valve. This value is only available for about 50% of infrastructure to optimise the asset management of their the installed valves at the OT level. Sometimes, no digital control valve fleet. Use cases include early detection of positioner is installed, and sometimes, the position signal failures (predictive maintenance), scope definition for is available at the valve, but the data is not transmitted to turnarounds, and optimised maintenance and inspection the OT layer or stored in the historian. When looking at work processes. the control loop, there is the measurement of the controlled process variable (flow, pressure, temperature, Conclusion etc.) and the setpoint of the process variable. The valve’s The key challenges asset managers face today are an actual position can be calculated using an algorithm and alarming shortage of experts, issues with the supply the two data points from the control loop. chain, and ever-increasing pressure to lower costs and This means that for every installed control valve, there improve performance. Inspection and maintenance of is the setpoint of the valve position and, directly or control valves are significant cost factors for asset owners indirectly, the actual valve position. Depending on the in any asset-intensive industry where gas or fluids flow. characteristics of the control loop, the position of the This article reviewed and discussed the four principal control valve changes frequently during operation to methods available today to analyse the condition of control the process variable. control valves for planning inspection, maintenance, As this data nowadays is logged over several months and replacement. in the OT systems or over years in dedicated historian Control valve inspections by experts, either directly at databases, they are readily available for analysis. The the valve or remotely by manually analysing the data, are movement of the valve can be described by the number of only suitable for a selected number of valves because of strokes, the speed and duration of strokes, and the the associated costs and risks. The diagnostic data from difference between the setpoint and actual position. The smart positioners is limited to the small fraction of valve’s movement pattern and how it changes over time control valves already equipped with this technology and contains valuable information about the valve’s health. cannot be scaled across the entire install base. Using the However, the amount of data is too large, and the available operation data of the valve, in combination with correlations in the data are too complex for visual intelligent algorithms, allows for automatic condition analysis. Instead, highly specialised mathematical analysis of every installed control valve. The results cover algorithms are required to extract the information about predictive maintenance to detect failures early, remaining the valve condition. useful lifetime calculation to optimise the scope for the UReason has developed a number of algorithms to next turnaround, and valve performance analysis for transform the raw data from the control valve operation energy savings and process improvements.
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Giving
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Jason Chadee, Director at SparkCognition, USA, details how artificial intelligence can help bring a new meaning to terminal value.
T
he volume of LNG traded globally has quadrupled in the last two decades, and is set to double in the next two. The development and operating costs associated with the value chain have shifted due to an abundance of low-cost gas supply from the shale revolution, which unlocked vast natural
gas reserves previously inaccessible or economically unviable to extract. This significant increase in natural gas supply has led to lower domestic natural gas prices and allowed for more extensive LNG production to meet global demand. There are currently seven operating LNG terminals that can
collectively export 12% of all US gas production. Japan purchased 98.3 billion m3 of LNG in 2022, making it the world’s most prominent LNG importer. China fell to second place with 63.44 million t of LNG imported in 2022. Europe is also a net importer of LNG, with 28 large scale LNG import terminals, including non-EU Türkiye.
Figure 1. Artificial intelligence (AI) calculates the arrival, loading, and discharge rate, and storage tank capacity of LNG carriers.
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The continued viability of the LNG market in the US is based upon a complex supply chain involving the most extensive natural gas production, pipeline infrastructure, gathering, processing, and storage systems in the world. The industry is under immense pressure to maximise production and energy efficiency, productivity, safety, and sustainability at existing terminals, requiring significant agility and tight controls between supply chain activities. There is immense pressure on infrastructure and operational procedures for the safe arrival and departure from terminals and, when necessary, safe aborting entry or egress manoeuvres during an on-board or onshore emergency. Risks related to collisions, groundings, contacts, fire, and explosion on board – and, if necessary, the release of gas and any other deleterious consequences – all need measurements and evaluations. Terminal and port authorities require explicit details on the total safety level of LNG shipping operations as it relates to existing infrastructural and surrounding shipping movements. Digital transformation has become a critical strategic priority for LNG infrastructure companies. They have adopted and implemented sensors, analysers, and control and information systems – a network of technologies designed to collect real-time data on various parameters such as temperature, pressure, flow rates, equipment health, and safety conditions – generating massive amounts of data.
LNG terminals are more complicated than ever before, yet time for calculating and estimating terminal behaviour is shorter. The overwhelming abundance of data and the persistence of elusive physical laws to explain the complexity of assets and operations promote a renowned interest in more powerful technologies to extend current model capabilities and decision workflow practices.
The challenge: Too much data
The technology
Digital technologies present unique opportunities for the LNG industry. However, challenges still need to be solved in the massive amounts of data being produced that need to be analysed, leaving massive gaps in optimisation. Most companies engaged in digitisation have lost control of their data – or never had control of it in the first place. They are inadvertently stockpiling massive amounts of data in unstructured and structured repositories, keeping it indefinitely, and bleeding it out through accidental loss, careless but well-intentioned sharing, unfettered collaboration, and insider theft. Without harnessing it, companies are oblivious to what they have, who is using it, how it is being used, or why. Engineers are estimated to spend around 50% of their time looking for data they need and end up using only about 10% of the data being gathered.
Figure 2. AI is a core technology being used by LNG
companies to increase asset utilisation through improved recovery, accelerated production, higher efficiency, and reduced downtime, CAPEX, and regulatory compliance.
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December 2023
The solution to the data problem: Artificial intelligence
To fully capitalise on the digital technologies being adopted by LNG companies and leverage the data that will truly drive the digital transformation, the industry has turned to artificial intelligence (AI). AI can aggregate multi-source data and visualise it all in one area, making it a technological game changer. AI can predict equipment failures, optimise processes, and identify opportunities to improve terminal operations. Companies can then move away from time and tactic-based activities to proactive and predictive management of terminal assets, thus improving safety and reliability. AI removes what was previously limited to the judgment and limits of human cognition and evaluation. It is not to say humans can be removed from the equation. Only subject matter experts (SME) can evaluate whether the definitive correlation found by the data analysis is a possible phenomenon.
SparkCognition’s Industrial AI Suite (IAS) uses advanced model-building techniques to reduce AI predictive maintenance deployment times to just weeks or days. With a wide range of its capacity to ingest and analyse new data, IAS scales to suit increasing workloads and changing business requirements. The continual learning and adaptive algorithms capture SME knowledge with natural language processing (NLP) technology that extracts insights from unstructured data – even sparse, unlabelled, and dirty data. AI can discover patterns, improve models, and reduce time to resolution with faster root-cause analysis, avoiding model drift with normal behaviour modelling (NBM) techniques. Normal behaviour modelling is an automated AI/machine learning (ML)-enabled anomaly detection methodology for evaluating and describing the behaviour of a system or piece of equipment under normal operational and environmental conditions. NBM models ingest large volumes of quantitative time-series data (temperature, pressure, flow rate, etc.) from multiple sensors, both initially for training purposes and continually thereafter for ongoing monitoring and periodic system retraining. Once trained to understand the quantitative characteristics that define ‘normal’ for the system being monitored, the model continues to evaluate the incoming sensor-provided data stream and generates alerts whenever an out-of-normal condition is detected. Managers and technicians can then use these alerts to undertake maintenance and repairs of the system more proactively than doing so only upon system failure. As a result, an organisation saves time and money and improves the overall productivity and safety of the system, the facility in which it operates, and the workers who interact with it. NBM models are used in a wide variety of capacities, but their applicability falls primarily into the predictive
maintenance field. They are used to monitor and maintain complex physical or virtual systems more effectively and efficiently. To employ NBM modelling, the only requirements are a continuously operating system comprised of multiple components, status, and performance data from sensors attached to those components, and one or more quantifiable outputs from the system. An important distinction between NBM and other forms of system monitoring is asset agnosticism. An NBM model is unconcerned with what kind of equipment it monitors, whether an LNG terminal or a nuclear reactor. The model evaluates an input data stream, develops its understanding of normality, and triggers alerts whenever it perceives that normality has been violated.
Case study: National Grid Grain LNG Terminal
As an example of the efficacy of AI for terminal assets, National Grid Grain (Grain LNG) Terminal is the UK’s leading gateway connecting global LNG to the European energy market. Located on the UK’s Isle of Grain, it is currently the largest terminal in Europe and the eighth largest in the world by tank capacity, with a site that spans over 600 acres in total. Grain LNG Terminal currently has an LNG storage capacity of 1 million m3 and a throughput capability of 15 million tpy, equivalent to 20% of UK gas demand. Recently, Grain LNG integrated SparkCognition’s Industrial AI Suite into its system. This AI solution tackles the most critical production, reliability, and process optimisation challenges facing the LNG industry, digesting large amounts
of data and transforming them into actionable insights that integrate easily and intuitively with existing workflows. It helps identify impending failures in critical assets and processes with enough lead time to schedule timely, optimised maintenance. IAS also addresses suboptimal operations with actionable prescriptive insights to increase production throughput across an entire operation. Grain LNG found that IAS successfully identified over 90% of production-impacting issues an average of eight days in advance. As a result, Grain LNG is taking advantage of unplanned downtime, reduced costs, and the potential increase of the useful life of its LNG terminal assets.
A continuous loop of improvement
LNG is an essential fuel source for reliable, dispatchable power, especially when intermittent renewable sources aren’t available. A strong supply chain that supports an uninterrupted flow of LNG to and from terminals is critical. Traditional projects, engineering, and operations need to be in line with the evolution of the current LNG landscape. The accelerated advancement of digital technologies, combined with AI, leverages their potential for what has become unmanageable for human power alone. AI has stepped in to enable further digitalisation by advancing project planning, reducing capital costs and scheduled maintenance, and minimising risks to personnel and assets. When fully embraced across the LNG value chain and with greater collaboration within and outside the industry, a step change can be made in how LNG terminals are developed, executed, and operated.
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15FACTS
...ON AFRICA
Africa became the first continent to export LNG in 1964
Nigeria has the highest number of twins born in the world
Between 201w0 – 2020, approximately 40% of all natural gas discovered worldwide was in Africa
Some houses in Tunisia use fish bones in the construction of their homes
There are 54 countries in Africa
Madagascar is the fourth-largest island in the world
Africa covers approximately one-fifth of Earth’s total land surface
In 2021, African LNG accounted for approximately 10% of Europe’s gas imports
The first cargo of LNG produced from the Coral gas field was shipped from Mozambique’s Coral South FLNG in 2022
Over one-third of the African continent is covered by desert
Nigeria was Arabic is the most widely spoken language Europe’s African LNG exports In 2022, Africa exported fifth-largest rose by over 7% in approximately the wake of Russia’s LNG supplier 42 million t of LNG invasion of Ukraine (around 5.7% of global in 2022 LNG exports)
Africa is home to the world’s longest river, the Nile
December 2023
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With more than 100 ecoSMRT® ordered and more than 50 in service, ecoSMRT® is the world-leading LNG marine reliquefaction technology. ecoSMRT® can support shipowners to lower their carbon footprint, helping the industry transition to zero carbon. For more information contact us: lge.sales@babcockinternational.com
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