February 2024
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ISSN 1747-1826
CONTENTS
FEBRUARY 2024
28 A flexible solution for
03 Guest comment 05 LNG news
the future
Mark Krajewski, Director, Technical Services, Aspen Aerogels, USA, discusses the importance of insulation to how LNG plants operate, especially as the world moves towards a more sustainable future.
10 Europe's endeavour for energy security
Rystad Energy provides insight into the role LNG could play in Europe and the Mediterranean’s undertaking for energy security amidst geopolitical tensions throughout the region.
35 Considering the screw compressor
Carlos A. F. Falsiroli, Mayekawa USA, details screw compressor applications for the LNG industry.
41 Turbomachinery in LNG production plants: Part one
In the first part of a two-part article, Brian Pettinato, Manager, Aero & Structural Dynamics, Sterling Scavo-Fulk, Compressor Development Engineer, and Brian Hantz, Advanced Technology Engineer, Elliott Group, USA, examine the use of compressors and pumps in the LNG value chain.
47 Blue and green: the colours of LNG
10 17 Optimising gas treatment
Pedro Ott and Ralph H. Weiland, Optimized Gas Treating, Inc., USA, explore the efficiency and drawbacks of a split-flow configuration in alkanolamine-based acid gas removal processes.
With government policy and financial incentives in place, LNG has a key role to play in the energy transition but societal engagement is essential, says Sebastien Le Moigne, Global Gas Solutions Manager, ABS.
50 The development of dynamic metering systems
Hilko den Hollander, Industry Product Manager, KROHNE, the Netherlands, highlights advancements in dynamic metering systems for LNG and natural gas.
23 Remove the heavy load Justin Ellrich and Emily Galligan, Black & Veatch, outline some guidelines for optimal heavies removal scheme for LNG facilities.
ON THIS MONTH’S COVER With an increased focus on reducing the carbon footprint of LNG facilities, choosing the right energy-saving solutions is key. This month’s cover story comes from Aspen Aerogels, a leader in aerogel insulation, and covers the insulation design considerations to optimise an LNG facility, mitigate performance degradation, and improve efficiency to aid in decarbonisation commitments. Learn more at www.aerogel.com
CBP019982 LNG Industry is audited by the Audit Bureau of Circulations (ABC). An audit certificate is available on request from our sales department.
Copyright © Palladian Publications Ltd 2024. All rights reserved. No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without the prior permission of the copyright owner. All views expressed in this journal are those of the respective contributors and are not necessarily the opinions of the publisher, neither do the publishers endorse any of the claims made in the articles or the advertisements. Printed in the UK.
COMMENT ALEX FROLEY
LNG MARKET ANALYST, ICIS
D
isruptions to Red Sea LNG traffic stepped up in mid-January as Qatar, the biggest single user of the route in 2023, paused a number of vessels due to cross through the Bab al-Mandab strait. The narrow passage, at the bottom of the Red Sea, has become the centre of global attention over recent weeks after Houthi attacks on shipping crossing the strait, followed by US and UK counter-strikes. Qatar supplied Europe with 16% of its LNG imports during 2023, equal to around 15.1 million t of the region’s total 96.2 million t. That made Qatar a key supplier to the region, although significantly lower than the US, which made up almost half of Europe’s LNG supplies in the year at 45.5 million t. Disturbances to Qatari LNG flows to Europe could add time and costs to deliveries, likely lifting spot gas prices. However, Europe is well placed to deal with disruptions, with its gas storage still very high for the time of year, and much better positioned than two years ago when Russia started its war with Ukraine. Europe’s gas stocks are much higher than two years ago, when the Russia-Ukraine war was about to begin. Like Qatar, the US has often used the Suez Canal to deliver cargoes to Asia, sending them east across the Atlantic, then through the Mediterranean, and down through Suez. Routes east from the US to Asia have become more important in recent years as the Panama Canal has grown more congested and suffered from drought, reducing water levels. The number of crossings in December 2023 was fairly in line with normal usage. From 1 – 12 January 2024, however, ICIS tracked only five laden LNG tankers travelling through the Suez Canal, and all were either Qatari or Russian cargoes. Some US spot cargoes started looking for shorter routes to Europe rather than the long route to Asia, while other US cargoes added to the traffic on an increasingly busy route southeast across the Atlantic and around the Cape of Good Hope to Asia.
For US cargoes heading to Asian customers, taking the route via the Cape of Good Hope only adds a couple of days compared with heading via the Suez Canal, although it is significantly longer than heading west via the Panama Canal and across the Pacific. Qatar’s decision to pause LNG traffic through the Red Sea did not pose an immediate threat to Europe’s security of gas supply, as the region is well stocked and has steady inflows of other gas, including Norwegian pipeline gas and US LNG. For much of the first half of winter, the weather has been relatively mild, and industrial demand remains suppressed from pre-crisis levels. Although Europe’s spot prices at the ICIS TTF have fallen hugely from the records broken in 2022 when Russia halted most pipeline supplies to Europe, even now gas prices remain above the long-term averages in the decade before the Russia-Ukraine war, adding to bills for households, leading to factory closures and challenging inflation targets. In the event of long-term disruption, energy companies could attempt to re-arrange global trade flows to make shipping more efficient. For example, a US company that had to deliver a cargo to Japan could do a swap with a Middle East company that wanted to sell into Europe. The US company could deliver its cargo into Europe instead, and the Middle East company could deliver east into Asia. Both customers would receive a cargo and overall shipping times would be cut. In this case, both companies might avoid any need to use the Red Sea at all. Companies already carry out such swaps internally and from time-to-time with other parties. For major LNG traders like Shell or TotalEnergies, the ability to rearrange flows in such a way is one of the benefits of having large global trading portfolios within which they can find cost savings. While it could be a theoretically attractive way to minimise the fallout from any prolonged shipping disruption, in practice, cargo swapping on a very large scale between major companies would require an unprecedented level of trading and co-operation.
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RIDE THE WAVE
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LNGNEWS USA
Seaside LNG announces two milestone first deliveries
S
easide LNG has announced its first delivery to the Carnival Jubilee, an LNG-propelled cruise ship stationed in Galveston, Texas. After entering into a term bunkering agreement with Carnival Corp. & plc, the delivery took place on 30 December 2023, after months of careful co-ordination with all parties involved, including the Port of Galveston. This operation marked the first in-port ship-to-ship LNG bunkering delivery not only in Galveston, but also along the entire US Gulf Coast. Seaside’s barge, the Clean Jacksonville, was moved from Jacksonville, Florida, to operate out of Galveston and serve the Texas Gulf Coast. The Clean Jacksonville has safely completed more than 350 bunkering operations to date. In related news, the Clean Everglades, the newest member of the Seaside LNG fleet, made its first delivery week commencing 15 January 2024. The delivery was made to Isla Bella at TOTE Maritime’s terminal near Jacksonville, Florida. The operation was a regularly scheduled delivery per TOTE’s long-term service contract with Seaside’s maritime transportation company, Polaris New Energy. Seaside took delivery of the Clean Everglades, an articulated tug barge that holds 5500 m3 of LNG, in October 2023. In addition, TOTE Services acts as Seaside’s operating partner for both the Clean Jacksonville and Clean Everglades.
Argentina
Galileo Technologies to help Buquebus expand LNG manufacturing plant in Argentina
B
uquebus has selected Galileo’s technology to help boost production at its LNG plant in Buenos Aires, Argentina. As a result of the Cryobox® technology, developed by Galileo for the liquefaction of natural gas, Buquebus will have a total of nine pieces of equipment in its manufacturing plant, which will result in an increase in production and efficiency in the generation of LNG. Buquebus will incorporate two Cryobox Stations to produce LNG that will fuel Francisco, recognised as the fastest ferry in the world. These units join the project that Buquebus started 10 years ago, thus encompassing a total of nine Cryobox in San Vicente, Province of Buenos Aires. After the generation of energy, Buquebus carries out the transportation of LNG through cryogenic tankers by road through state-of-the-art trucks powered 100% by LNG to the Buquebus facilities in Puerto Madero. This allows LNG to reach the end consumer without relying on conventional gas pipeline networks, providing logistical flexibility that contributes to a more efficient and sustainable distribution. Regarding the consumption of traditional fuels, LNG enables Francisco to achieve a 98% reduction in emissions produced by combustion. Currently, production is 66 tpd of LNG, which is used to fuel its two daily frequencies, resulting in operational savings of 50%. This percentage will increase significantly with the company's recent acquisitions.
India
ADNOC and GAIL sign long-term LNG supply deal into India
G
AIL (India) Ltd has successfully concluded a long-term LNG purchase agreement for purchase of around 0.5 million tpy LNG from Abu Dhabi National Oil Company (ADNOC) Gas. GAIL (India) Ltd, India's largest natural gas company, has successfully concluded a long-term LNG purchase agreement for purchase of around 0.5 million tpy LNG from ADNOC Gas. This is pursuant to a memorandum of understanding dated 30 October 2022 between GAIL and ADNOC P.J.S.C wherein parties agreed that, in potential areas of collaboration both parties shall explore opportunities including purchase of LNG
by GAIL from ADNOC for a tenure ranging from short term to medium and long-term. This significant development between GAIL and ADNOC will reinforce the robust cultural and economic bonds between India and the UAE. Under this agreement, the deliveries will commence from 2026 onwards for a duration of 10 years, across India. This arrangement is believed to further aid in India’s rising energy security requirements and, simultaneously, also fuel GAIL’s strategic growth objectives to cater to its downstream customers in the rapidly evolving natural gas landscape of the country.
February 2024
5
LNGNEWS Kazakhstan
Asia
C
A
Condor receives feed gas allocation for Kazakhstan LNG project ondor Energies Inc., a Canadian based energy transition company, has received a natural gas allocation from the Government of the Republic of Kazakhstan. The gas allocation will be used as feed gas for the company’s first modular LNG production facility. The feed gas will be liquefied to produce up to 350 tpd (210 000 gal./d) of LNG, which can fuel approximately 125 rail locomotives or 215 large mine haul trucks (150 t haul capacity). The carbon emission reductions associated with using this LNG volume to displace diesel fuel equates to removing over 31 000 cars from service annually. The company has also acquired 12 ha. of industrial land where the first modular LNG facility will be constructed. FEED is complete and detailed engineering will commence shortly. Discussions are underway with end-users to confirm LNG volume commitments and the company is reviewing project funding alternatives before proceeding with construction.
Australia
Baker Hughes and McDermott complete subsea infrastructure in northern Australia
B
aker Hughes, an energy technology company, and McDermott, a premier engineering and construction company, have announced the safe completion of the installation of subsea infrastructure at the Ichthys field in northern Australia. Awarded to the Baker Hughes and McDermott consortium in 2019 by INPEX Operations Australia P/L, the subsea infrastructure development project included EPCI of umbilicals, risers, and flowlines (URF), a subsea production system comprised of a new 7-in. (approximately 18 cm) vertical Christmas tree system, all forming a subsea well gathering system (GS4) tied back to the existing Ichthys Explorer central processing facility. The consortium’s scope of work also included an in-fill URF EPCI involving the development of new subsea wells tied in to the existing gathering systems.
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February 2024
Nebula Energy LLC buys majority stake in AG&P LNG G&P LNG (AG&P Terminals & Logistics Pte Ltd), a subsidiary of AG&P Group, has announced that Nebula Energy LLC, a fully-integrated investment, development, and asset management company with a focus on LNG and carbon capture and storage (CCS) sectors, has bought majority stake in the company. With operational headquarters in the UAE, AG&P LNG will now operate as an independent subsidiary of Nebula Energy with key offices in the UAE, Singapore, India, Vietnam, and Indonesia. Peter Gibson has been appointed as Chairman, and Sam Abdalla as Vice Chairman, while Karthik Sathyamoorthy will continue to remain the CEO of AG&P LNG. AG&P LNG accelerates the adoption of downstream LNG infrastructure and logistics networks, bridging the gap between infrastructure/logistics and demand with its advanced proprietary LNG technology and singular leading LNG credentials to develop, own and operate LNG assets in fast-growing markets. AG&P LNG has a substantial growth pipeline with a total of six LNG terminals in development with proposed capacity of 25 million tpy across several international growth projects.
THE LNG ROUNDUP X QatarEnergy and Excelerate Energy sign 15-year SPA X Babcock's LGE business selects Tunable as partner on gas analytics X Tokyo Gas establishes JV for LNG-to-Power project in Vietnam Follow us on LinkedIn to read more about the articles
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LNGNEWS Finland 11 – 12 March 2024
Klaipeda LNG to be supplied to Inkoo LNG terminal
Milan, Italy
A
10th International LNG Congress (LNGCON 2024) 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 www.nistm.org
15 – 16 April 2024
6th Global LNG Forum Madrid, Spain
t the end of January, a transhipment operation occurred at the Klaipeda LNG terminal, operated by the international energy terminal operator, KN Energies. A record amount of 105 000 m3 of LNG was transferred from the FSRU Independence to the conventionally-sized Amur River LNG vessel. Norway’s Equinor will take the LNG from Klaipeda and deliver to the Inkoo LNG terminal in Finland. These volumes of LNG from Equinor are the largest ever reloaded from the FSRU Independence to a conventionally sized vessel the terminal's inception. Until now, commercial LNG transhipments from the Independence storage vessel have been limited to small scale LNG carriers. Typically, less than 10 000 m3 of LNG have been transhipped, with the largest transhipment of just over 17 000 m3 of LNG. The 288 m long Amur River is fit for operation under low temperatures and ice conditions with the ice class 1A FS. The LNG vessel will transport LNG filled in Klaipeda for Equinor to the Inkoo LNG terminal in Finland. Finland's demand for natural gas is being met by imports of LNG since the Balticconnector gas pipeline between Finland and Estonia suffered a rupture and was shut down in early October 2023. The LNG is transported by sea to the Inkoo FSRU Exemplar, and the gas is transported by pipeline from the LNG storage vessel to the shore.
Singapore
www.lng-global.com
30 April – 02 May 2024
Seatrium delivers Singapore’s first membrane LNG bunker vessel
Washington, USA
S
2024 AGA Operations Conference
www.aga.org/events/2024-aga-operationsconference-spring-committee-meetings/
07 – 08 May 2024
ITLA 2024 Annual International Operating Conference & Trade Show Texas, USA https://ilta2024.ilta.org
07 – 09 May 2024
Canada Gas Exhibition & Conference Vancouver, Canada www.canadagaslng.com
8
February 2024
eatrium Limited has announced the delivery of Brassavola, Singapore’s first membrane LNG bunker vessel, built locally by the group, to owner Indah Singa Maritime Pte. Ltd, a wholly-owned subsidiary of Mitsui O.S.K Lines (MOL). Following delivery, Brassavola will be chartered by Pavilion Energy to supply LNG bunkering in the Port of Singapore. The vessel, which is expected to commence operations in February 2024, will also be deployed by TotalEnergies Marine Fuels to serve its customers under a long-term agreement with Pavilion Energy. Brassavola, constructed based on a proprietary design by LMG Marin, a wholly-owned subsidiary of Seatrium, adds to the group’s portfolio of proven LNG bunker vessel designs of various capacities. Measuring 116.5 m in length and 22 m in width, the vessel incorporates state-of-the-art technology, including superior loading and faster bunkering rate of up to 2000 m3/h, mass flow metering and online gas chromatograph systems, for improved bunkering turnover and enhanced operational efficiency. Brassavola utilises dual-fuel engines, allowing the vessel to run on marine LNG for cleaner and lower-carbon operation. The vessel’s advanced reliquefaction technology also enables more efficient boil-off gas management, which reduces carbon emissions. The LNG bunker vessel also features two GTT Mark III Flex membrane tanks with characteristics which include lower internal pressure, temperature, and boil-off rate, enabling greater tank durability, safer fuel transfer operations, and reduced cargo loss through evaporation. The twin membrane tanks are optimised to be lighter and space-saving to allow for a larger cargo carrying capacity and greater fuel efficiency during transportation.
EUROPE’S ENDEAVOUR
Rystad Energy provides insight into the role LNG could play in Europe and the Mediterranean’s undertaking for energy security amidst geopolitical tensions throughout the region. 10
urope has been pushing for increased energy security with the region trying to reduce its dependence on Russian gas since the onset of the Russia-Ukraine war in early 2022. It has been successful in overcoming a potential gas shortage even with the halt of Russian supplies, which was mainly caused by a decline in gas demand due to milder winter conditions. This decline was driven by the use of lower quantities of gas for power generation, which was substituted by increased output from other renewable
FOR ENERGY SECURITY
energy sources such as solar, wind, and hydro. But letting go of Russian supplies has caused a spike in European LNG imports, mainly from the US. The increasing trend is expected to continue due to the decline in production of domestic gas fields and reduced pipeline supplies, even with falling European demand. European LNG imports are expected to double from 70 million tpy in 2021 to 140 million tpy in 2030, before declining to 117 million tpy in 2040. The spike in LNG demand will result in a large volume of uncontracted LNG
of about 75 million tpy from 2022 – 2030. To fix this deficit, long-term sale and purchase agreements (SPA) must be signed to secure volumes for European markets. A couple have recently been signed, but more effort needs to be put into establishing long-term relationships if the continent wants to avoid being short on supplies during harsh winters and a tight market. Exploring partnerships in the Middle East and Eastern Mediterranean could emerge as a promising avenue as the regions have recently been increasing gas investments and portfolios.
11
ADNOC’s strategic focus on gas developments
The UAE has been putting an increased focus on gas developments in recent years, with Abu Dhabi National Oil Company (ADNOC) taking the lead. The state giant recently went public with its gas division, ADNOC Gas, to raise capital for its upcoming projects. The most anticipated of these is the Al-Ruwais LNG project, which is expected to add 9.6 million tpy of LNG capacity in the UAE. The plant is expected to be fed by gas produced from the Bab, Bu Hasa, and Asab fields. The project was initially planned to be built in Fujairah but was shifted to Al Ruwais Industrial City due to its proximity to ADNOC’s current operations and, therefore, access to its current facilities and the
presence of an existing supplier base. ADNOC is believed to be rapidly advancing towards a final investment decision (FID) on the development. With the Al-Ruwais LNG trains coming online, the country will increase its LNG capacity more than twofold. Currently, ADNOC Gas has an ownership stake of 70% in its LNG division, with the joint partners being Mitsui, BP, and TotalEnergies. Its operations began in the 1970s on Das Island, and the company has capacity of 6 million tpy of LNG and 2 million tpy of non-LNG liquids. In 2019, it ended a 27-year long contract with Japanese utility, TEPCO, with contracted volumes of 4.3 million tpy. Since its conclusion, ADNOC has been looking at potential customers for the uncontracted volumes. While a series of agreements have been concluded with Asian players, the national oil company (NOC) is yet to sign any long-term SPAs with a European nation. Even so, the UAE is trying to broaden its reach with its first ever LNG shipment to Germany in January 2023. The shipment comes as part of the UAE-Germany Energy Security and Industry Accelerator (ESIA) Agreement signed in September 2022, focusing on energy security.
Figure 1. EU27 + UK gas supply mix by source and demand scenarios – RE 1.9˚ Scenario.
Source: Rystad Energy GasMarketCube.
Figure 2. European LNG demand vs contracted LNG imports. Source: Rystad Energy GasMarketCube.
Figure 3. Al-Ruwais LNG production and economic profile. Source: Rystad Energy UCube. 12
February 2024
Lifting Qatar’s LNG dominance: North Field Expansion
Qatar is the unmatched powerhouse of LNG in the Middle East, accounting for over 80% of the LNG produced in the region. The country will account for three-quarters of the expected additional output growth in the region between 2010 – 2040. This will be attributable to the two-phase North Field Expansion project, involving six new LNG trains. Both the phases have been sanctioned and are undergoing development works. The US$50 billion expansion project is expected to increase Qatar’s LNG capacity from a current 77 million tpy to 126 tpy by 2027. The project has attracted significant traction from major international oil companies such as ExxonMobil, Shell, Eni, TotalEnergies, and ConocoPhillips, all of which have taken stakes. Qatar is competing with the US to replace Russian volumes, with state giant QatarEnergy having signed multiple long-term supply agreements involving European nations. The agreements have been signed for a period of 27 years, with the supply expected to begin
related obligations are honoured could reach 17 billion m3 by 2030. Currently, produced gas is supplied to the neighbouring nations of Jordan and Egypt. Israel currently does not possess the infrastructure required for an LNG ecosystem and leverages Egyptian infrastructure. In February 2023, the Leviathan partners approved a budget of US$50 million for the pre-FEED stage for construction of a Figure 4. Qatar LNG production by project (million tpy). Source: Rystad Energy Ucube. 4.6 million-tpy floating LNG facility, but the FEED studies indicated an increase in the overall estimated costs of building the unit. The decision on the FEED stage has been put on review and it is believed that the project will be stalled for now. Going forward the project partners are reviewing building additional pipelines to export the increased volumes produced. As of now, Egypt leverages Israeli gas imports mainly coming from Chevron’s operated fields and uses the same to feed its LNG plants. However, in recent times and with the rising demand for gas in Egyptian markets and the declining trend of production from its major fields, Egypt is tending towards being restricted to a mere seasonal exporter and will have to rely on additional imports from Israel even for meeting domestic demand. This will free up capacities at the Figure 5. North Field Expansion’s gas sale and purchase Idku and Damietta LNG plants for use by Israeli and agreements split by country. Source: Rystad Energy research Cypriot gas producers for processing and export of their and analysis. own gas in the international market. It is worth noting that Idku LNG T1-T2 has capacity of 7.2 million tpy and from 2026. The SPA signed with Eni involves the supply of Damietta LNG has capacity of 5.5 million tpy, putting 1 million tpy LNG to Italy, while the SPAs signed with Egypt’s LNG capacity at 12.7 million tpy. Shell and TotalEnergies both involve a supply of 3.5 million tpy to the Netherlands and France, respectively. The contracted volumes will be sourced from the The evolution of Cyprus’ Aphrodite two-phased North Field Expansion project. Out of the gas field development 49 million tpy capacity addition, about 47% of the volumes The Aphrodite field off Cyprus could be a game changer for have been pledged under long-term SPAs, with around 60% the country. The field is owned by Chevron (35% operator), of the signed volumes being contracted to the Asian Shell (35%), and Delek Group (30%); the partnership market. It is estimated that half of the production from the submitted a development plan to the government in project will be supplied to Europe, while the other half will 2019. The proposed US$3.6 billion scheme involved a go to Asia. EU countries’ climate targets, which are mainly floating production facility and a five-well system capable based for the next decade, may, however, pose a challenge of producing 800 000 ft3/d of gas. The revised proposal in signing long-term agreements, as these nations move submitted in 2023 presented a better scenario for partners, towards an increased participation of renewables in the with a reduction of US$1 billion in costs. The plan involved energy mix. a 600 000 ft3/d capacity, three-well system feeding gas directly to Egyptian subsea facilities – potentially to Shell’s West Delta Deep Marine (WDDM) – via an approximately Israel’s gas transition and 300 – 350 km pipeline. The gas will be then piped to the infrastructure dynamics in the Shell-operated Idku LNG export terminal in Egypt. The Eastern Mediterranean partnership and Cyprus are believed to be at odds with the Israel went from being a net importer of hydrocarbons new development plan due to conflicting views for now as in the early 2000s to becoming self-sufficient and a net the government encourages the former development plan exporter in recent years, driven mainly by production from as it expects to have greater control as well as production. the large Tamar, Leviathan, and Karish fields. Domestic Israel and Cyprus are discussing a potential pipeline demand is expected to increase as the country aims that would connect both their gas fields before finally to move towards a gas-based energy system and away reaching the LNG export terminal in Cyprus. The project is from sources such as coal – but even then, surplus gas estimated to cost between US$1.5 – US$2 billion for the production is expected to remain to meet exports. Israel’s pipeline and LNG plant and the delivered breakeven price spare upstream capacity after domestic and export
14
February 2024
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1400 km offshore and 600 km onshore pipeline meant to connect offshore gas reserves from the Leviathan field to Greece via Cyprus, and further to south-eastern European countries. The pipeline is proposed to have capacity of 10 billion m3/y of gas, with potential expansion to 20 billion m3/y. Edison Group plans to take FID on the pipeline. Rystad estimates a transport tariff range of US$1.25 – US$1.75/thousand ft3 for the pipeline. Israeli supply would break even at an average gas price of US$2.50/thousand ft3, whereas Cypriot supply would require an average price of about US$4.50/thousand ft3 to break even. These prices indicate that, considering Rystad’s Title Transfer Facility (TTF) price strip estimates, gas exported via the EastMed pipeline will be a commercial endeavour. The pipeline can expedite several discoveries in the region, but it faces geopolitical challenges as it passes through Turkish-claimed maritime areas. Also, Türkiye’s ambitions to become the regional gas hub would mean a stronger geopolitical resistance in their claims of maritime boundaries. The gas fields of the Eastern Mediterranean have recently emerged as a feasible option for Europe, considering how large they are and their proximity to markets. But uncertainties have always prevailed in the region, as evidenced by the ongoing Israel-Hamas conflict. Figure 6. Israel’s natural gas balance – RE 1.9˚ Scenario. Source: Rystad Energy One of Israel’s largest gas field, GasMarketCube. Tamar, had to completely shut for some time due to its proximity to the Gaza Strip. The field is one of the major suppliers of gas to the markets of Jordan and Egypt, with imports totalling between 6 – 7 billion m3/y in Egypt. Production from Leviathan also dipped, albeit only for a short period. All this highlights the region’s challenges despite its huge potential.
is estimated to range between US$7 – US$7.40/thousand ft3 of gas. Additionally, as per Rystad Energy’s estimates, the current proposed plan may put Aphrodite’s gas breakeven just short of US$4/thousand ft3. If, therefore, the proposed Israel-Cyprus pipeline to an LNG plant is to reach fruition, it would require the fast-tracking of all the other Cypriot discoveries. Apart from exporting gas through the Egyptian route, there remains another possibility open with the much-delayed EastMed pipeline. The US$6.5 billion pipeline was considered too costly to compete given Russian gas supplies to Europe. However, Russia’s invasion of Ukraine has again stirred the discussion around the pipeline as Europe pushes for diversification from Russian energy. The initially proposed project was a
Conclusion Figure 7. East Mediterranean gas infrastructure. Source: Rystad Energy UCube;
Rystad Energy research and analysis.
Figure 8. Breakeven price of Israel and Cyprus supply vs TTF gas price forecast. Source: Rystad Energy UCube. 16
February 2024
As Europe endeavours to secure its energy future and reduce dependence on Russian gas, the Eastern Mediterranean emerges as a pivotal player. With significant developments in Qatar, the UAE, Cyprus, Israel, and potential projects such as the EastMed pipeline, the region holds significant promise. However, geopolitical challenges, ongoing conflicts and uncertainties underline the complexity of relying on Eastern Mediterranean gas fields as an alternative to Russian supplies. As these nations navigate intricate energy dynamics, the pursuit of diversified sources remains crucial for Europe’s energy security.
OPTIMISING GAS TREATMENT Pedro Ott and Ralph H. Weiland, Optimized Gas Treating, Inc., USA, explore the efficiency and drawbacks of a split-flow configuration in alkanolamine-based acid gas removal processes.
U
sing alkanolamines to removal acid gases is 1930s vintage technology, nearly a century old. Still in wide use today, it is applied primarily to pipeline gas conditioning and treating refinery sour gases. The basic process (Figure 1) centres on a closed, solvent-circulation loop where the acid feed gas contacts lean solvent in an absorber column chemically removes hydrogen sulfide (H2S), carbon dioxide (CO2) and other acid species according to their concentrations, solubilities, and reactivity. The rich solvent is regenerated by applying heat to a reboiler at the base of the stripping column where chemical reactions reverse and the acid gas desorbs from loaded (rich) solvent. System energy demands and solvent flow requirements quickly rise as the acid gas content in the feed gas increases. Over the years, this basic process has been improved, implementing new and better performance solvents and blends that maximise acid gas removal while reducing energy requirements. As the energy and solvent circulation requirements grow from processing larger feedstocks with higher acid gas content,
designers, and technologists have devised modifications to the basic process to reduce energy consumption. One of these process scheme variations has been described by Mohebbi and Moshfeghian.1 There, a split-flow process configuration (Figure 2) is outlined for sour gas sweetening applications. It showed 39% reboiler duty savings with a split configuration (897 m3/h total circulation, 390 m3/h lean, 507 m3/h semi-lean, 54.5 MW reboiler duty) vs a conventional scheme (790 m3/h, 90 MW), respectively. Conceptually, the split-flow configuration takes a large flow of partially regenerated (semi-lean) solvent from the stripping column and introduces it toward the absorber’s midpoint. The semi-lean loop is intended to absorb the bulk of the acid gas within the absorber’s lower section, with the smaller lean flow now requiring much less duty to regenerate it to the solvent loading required to meet the treated gas specification. However, there are numerous potential drawbacks to split-flow processing. Before proceeding, it is worth making a critical, qualitative comparison between single-recycle and split-flow processing.
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the solvent has such a high net loading value; the semi-lean portion has a much lower value because it is not regenerated to nearly the same extent. Solvent capacity depends on solvent flow rate and amine strength, as well as net loading:
One of the most pressing concerns in any gas treating facility is acidic corrosion. The general rule-of-thumb is not to allow rich solvent loading to exceed 0.4 – 0.45 (moles CO2 per mole of total amine). Lean amine loading is set by the treated gas CO2 specification on the assumption that these will be in close equilibrium at the top of the absorber. In LNG production, treating to <50 ppmv CO2 is generally required and this sets the lean solvent loading at roughly 0.02 or better. This sets 0.38 – 0.43 as the maximum net2 CO2 loading. In a single-recycle process, this is the maximum net loading of the entire solvent stream. In a split-flow process, however, only the lean portion of
In a split-flow process, capacity can be increased by using higher strength amine, but the resulting higher boiling points and consequent amine degradation rates make that approach ill-advised (if it is even possible at all). Solvent flow rate can be increased; however, the objective is to reduce reboiler heat duty whereas higher solvent flow rate tends to increase it (Table 1). The remaining option is to permit higher net loadings by relaxing the limit on solvent rich-loading limit. This will necessitate mitigating corrosion issues, perhaps by cladding portions of the process equipment exposed to hot, highly-loaded solvent and by using upgraded metallurgy piping in some areas. Even if split-flow processing can provide substantially reduced energy consumption, potential savings must recognise the following drawbacks and additional costs: z Larger capital cost for installing additional equipment such as semi-lean/rich anime exchanger, semi-lean cooler, semi-lean pump.
Figure 1. Conventional amine flowsheet.
z Increased capital cost for installing a taller absorber to achieve adequate mass transfer. This also results in the additional cost for loading additional packing and additional internals for the semi-lean draw, and possibly column diameter transitions to optimise tower diameters. z Greater operating costs resulting from possible amine flow. This also results in increased column diameter. z Higher lean and semi-lean solvent acid gas loadings and, depending on solvent circulation rate, rich
Figure 2. Split-flow amine flowsheet. Table 1. Overall circulation (1X, 1.25X, 1.50X) Circulation 1X
18
Circulation 1.25X
Circulation 1.5X
Duty ratio Btu/gallon
900
1100
1250
1400
1550
1700
900
1100
1250
1400
1550
1700
900
1100
1250
1400
1550
1700
Reboiler duty (million Btu/h)
49.122
49.071
49.919
50.49
52.153
53.171
52.384
52.251
52.282
52.221
52.734
52.913
53.903
54.706
54.584
54.668
55.089
55.278
Absorber outlet (CO2 ppmy)
2
2
1.8
1.9
1.9
1.9
1.9
1.9
1.9
1.9
1.9
1.8
1.8
1.9
1.8
1.9
1.9
1.9
Absorber semi-lean draw faction
0.21
0.34
0.4
0.45
0.48
0.51
0.324
0.436
0.495
0.540
0.576
0.606
0.42
0.513
0.56
0.6
0.63
0.656
Absorber rich loading
0.4564
0.4591
0.4564
0.4559
0.4542
0.4535
0.4088
0.4135
0.4143
0.4121
0.4101
0.4079
0.3892
0.3925
0.3897
0.3906
0.3877
0.3874
Absorber lean loading
0.0075
0.0057
0.0047
0.0040
0.0025
0.0032
0.0098
0.0074
0.0063
0.0054
0.0047
0.0042
0.0108
0.0082
0.0068
0.0060
0.0052
0.0047
Absorber semi-lean loading
0.0696
0.0566
0.0431
0.0387
0.0333
0.0312
0.1664
0.1387
0.1256
0.1125
0.1027
0.0949
0.2189
0.1904
0.1709
0.1628
0.1507
0.1442
Semi-lean % CO2 removal
98.269
98.143
98.350
98.361
98.457
98.326
98.225
98.248
98.416
98.540
98.656
98.194
98.179
98.391
98.370
98.555
98.592
Lean % CO2 removal
1.721
1.848
1.641
1.630
1.534
1.665
1.765
1.742
1.574
1.450
1.335
1.797
1.182
1.600
1.621
1.436
1.398
February 2024
1.495
solvent could also reach high enough acid gas loading to exceed the maximum limits for metallurgical integrity. z Controls become more complex to balance duty on lean/rich and semi-lean/rich exchangers to maintain rich amine temperature fed to the regenerator. z Requires tight flow control in the semi-lean loop to achieve minimum reboiler duty, excessive semi-lean draw starves lean amine flow to the absorber top, which results in sudden increases on absorber outlet acid gas content. By contrast, insufficient semi-lean draw results in higher reboiler energy demand above the targeted minimum. Energy savings must be balanced against design and operational constraints. A detailed techno-economic analysis with favourable NPV and payout years outcomes will then determine in which cases (if any) the split-flow configuration should be considered.
Figure 3. Effect of reboiler duty on treating, Table 2. Single recycle loop configuration (base case). Key variables include: Absorber CO2 outlet ppmv
1.8
CO2 removed (%)
99.99
CO2 removed (%) at absorber mid-section
99.17
Lean loading (mol/mol)
0.0078
Rich loading (mol/mol)
0.445
z 500 million ft3/d feed gas at 760 psig, 100˚F; feed gas contains 2 mol% CO2 (typical feedstock).
Solvent circulation (lbmol/h)
20 980
Regenerator feed temperate (˚F)
220.8
z Lean loading as needed to achieve less than 50 ppmv CO2 (99.7% CO2 removal or higher).
Regenerator reboiler duty (million Btu/h)
52.86
Absorber/regenerator bed height (ft)
40
Case study
Using example results from ProTreat® simulation, the performance of a conventional, single-recycle loop is compared to the split-flow configuration based on the following treating premises:
z Rich solvent loading allowed leaving the absorber is 0.45 maximum due to corrosion and equipment material selection considerations. z Solvent circulation rate fixed to 20 980 lbmol/h (CO2 free), strength 45 wt% MDEA blended with activator. z Lean/rich exchanger approach of 20˚F to maximise regenerator rich amine feed preheat. z 40 ft beds of 2 in. random packing for both absorber and regenerator columns. z Reboiler duty is adjusted to meet these process parameters. Additionally, for the split-flow configuration, there are further considerations: z Overall solvent circulation rate (lean + semi-lean) fixed to 1.0X, 1.25X, and 1.5X the 20 980 lbmol/h base solvent circulation rate set for the single recycle loop. z Regenerator semi-lean solvent draw is maximised to meet a 1.8 ppmv CO2 specification adopted for the single recycle loop case.
Figure 4. Absorber temperature profile. z Absorber and regenerator bed heights are increased to 80 ft to maximise mass transfer as allowed by CO2 solvent equilibrium. z Optimum split for the rich amine stream feeding lean/rich and semi-lean/rich exchangers to maximise heat recovery for achieving maximum regenerator feed preheating.
February 2024
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Single recycle loop results
operating condition – the regenerator temperature profile is collapsed indicating insufficient solvent regeneration. Lean loading is extremely sensitive to reboiler duty and only a small duty reduction will cause the lean loading to increase precipitously. This quickly raises the absorber CO 2 content beyond the intended CO2 target specified. For better and more stable unit control, the regenerator is purposely driven at higher duty (52.86 million Btu/h) which achieves a much lower but stable 1.8 ppmv CO2 at the absorber outlet. Key operating variables are summarised in Table 2. Figures 4 – 6 show respective profiles for absorber temperature, percent CO2 recovery and CO2 actual vs equilibrium partial pressure. The absorber temperature bulge is at the column mid-way point, the bottom half (20 ft) absorbs 98.5% of the CO2 fed while the top 20 ft serves as polishing section absorbing the remaining 1.49% for 1.8 ppmv CO2 content at the absorber outlet. The regenerator temperature profile shows a well regenerated system with most of the stripping occurring within the top 15 ft and the remaining 25 ft achieving low loadings 0.013 at the bottom of the column and 0.0078 at the reboiler outlet. The absorber operates under a mass transfer limited regime so a taller bed would further lower the treated gas CO 2 content, helping to further reduce either solvent circulation or reboiler duty; however, in such a case, the rich loading leaving the absorber increases beyond the recommended 0.45 max limit for carbon steel metallurgy.
Figure 3 shows absorber outlet CO2 content and solvent lean loading for ProTreat simulations at constant 21 980 lbmol/h circulation with varying reboiler duty. The regenerator requires about 46 million Btu/h reboiler duty to meet the maximum 50 ppmv CO2 at the absorber outlet. Note however that this is a very sensitive
Figure 5. CO2 recovered vs depth into bed.
Split flow with semi-lean loop results
With split configurations, key performance variables are difficult to analyse to get an optimum unit design with pre-specified packed tower heights because the semi-lean draw rate simultaneously affects all variables considered, which makes it difficult to isolate the effect of any particular variable. The procedure to optimise this process and to successfully converge the simulation model is as follows:
Figure 6. CO2 partial pressure profile. Table 3. Split-flow configuration results with taller beds – key variables
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Simulation run
Case A
Case B
Case C
Overall circulation
1.5X base
1.5 X base
1.0X base
Regenerator semi-lean draw fraction
0.585
0.632
0.525
Absorber CO2 outlet (ppmv)
0.1
1.8
1.7
CO2 removed (% overall)
99.999
99.991
99.992
CO2 removed semi-lean section
91.031
76.92
57.73
CO2 removed lean section
8.97
23.07
42.26
Lean solvent loading
0.0036
0.0031
0.0029
Semi-lean solvent loading
0.272
0.324
0.323
Rich loading
0.449
0.491
0.597
Regenerator reboiler duty (million Btu/h)
52.25
46.71
40.33
Reboiler energy savings vs base case (%)
1.13
13.16
23.70
February 2024
1. Modify the single recycle model to include in the simulation the regenerator semi-lean draw stream, semi-lean/rich solvent exchanger, semi-lean solvent cooler and pumps, to configure the split flow scheme. Start with column semi-lean regenerator draw and absorber injection located at column mid-section, splitting 50% rich amine between the lean/rich and semi-lean/rich exchangers for regenerator feed preheating. Set the reboiler regenerator energy requirements as a duty/flow ratio specification so the duty is scaled proportionally as the semi-lean stream draw varies. 2. Select desired acid gas treating specification. 3. Select desired overall solvent circulation. 4. Maximise column bed heights as allowed by equilibrium pinch constraints.
5. Increase the regenerator semi-lean draw fraction until meeting the absorber target acid gas specification. 6. Adjust the rich amine split fed to the lean/rich and semi-lean/rich exchangers for achieving maximum regenerator rich solvent temperature. 7. Repeat steps 5 and 6 to minimise reboiler duty needed while obtaining a balanced performance for absorber treated acid gas outlet, rich amine loading, semi-lean draw ratio and maximum rich amine preheat. 8. Move absorber semi-lean injection and regenerator semi-lean draw locations and repeat steps 5 and 6 as required to arrive to the optimum design. Table 1 summarises the system performance when including the semi-lean loop for the split-flow configuration at 1.0, 1.25, and 1.5 times the overall solvent circulation with same 40 ft columns bed heights and exchangers heat recovery approach temperatures used for the simple recycle loop case These tables show that higher semi-lean draw rates and higher overall solvent circulation hardly reduce the reboiler duty at all, the best case achieves a marginal 7% energy reduction (from 52.85 to 49.12 million Btu/h) for a maximum 0.21 semi-lean draw ratio fraction at 1.0X overall circulation case. In all cases evaluated, increasing the semi-lean draw fraction above the maximum possible for meeting the absorber CO2 specification, results in higher rich amine loading beyond 0.45 limit and much larger reboiler duties exceeding the 52.86 million Btu/h base case. Further evaluation of regenerator semi-lean stream draw location and absorber semi-lean stream injection at various column heights above and below the column middle did not show any significant advantage for reboiler energy reduction. Increasing absorber and regenerator bed height achieves lower absorber outlet CO2 content which allows for larger regeneration semi-lean draw fraction. Taller beds, while beneficial, may reach pinch conditions where additional bed height does not achieve any additional absorption/stripping, limiting the maximum CO2 removal effectiveness. Table 3 summarises the split configuration performance equipped with taller (80 ft) packed beds for both absorber and regenerator columns; evaluated at two solvent overall circulation rates 1.0 and 1.5X, respectively. Case A shows that 0.45 maximum rich amine load constrains the 0.585 maximum feasible semi-lean draw ratio without gain in reboiler duty savings, despite the fact that the CO2 in the treated gas is much lower than the targeted 1.8 ppmv. Case B has a larger semi-lean draw rate while Case C has a lower overall solvent circulation rate. These cases have noticeable reboiler energy savings but at the expense of much larger rich loadings, exceeding the maximum 0.45 limit. They also shift the absorber CO2 recovery profile, showing a substantially lower CO2 recovery in the absorber’s semi-lean section. Figures 7 and 8 show respectively profiles of absorber temperature, percent CO2 recovery and actual vs
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equilibrium CO2 partial pressure; Figure 9 shows the regenerator temperature profile, all for Case A. The absorber temperature profile shifts when injecting semi-lean stream quenching the temperature rise associated with heat release by the CO2 reaction. The maximum temperature obtained is smaller and the temperature bulge location moves further down the column into the semi-lean section. The CO2 removal is not completely depleted within the semi-lean section, thus the
remaining CO2 travels up the absorber and continues to react with lean solvent, forming a smaller second bulge in the absorber lean section. Percentage CO2 removal also degrades; the absorber bottom half achieves only 93.03% compared to 99.17% with conventional single recycle loop configuration. This percentage removal quickly degrades as the semi-lean fraction draw increases or the overall solvent circulation decreases. Plotting the absorber equilibrium vs actual CO2 partial pressure shows that there is a 10 ft section in equilibrium for the semi-lean zone not performing any CO2 removal. This explains the shift in absorber CO2 removal between the lean and semi-lean sections. Regenerator temperature and solvent loading profile also shift accordingly to the semi-lean draw rate. CO2 stripping occurs towards the regenerator bottom and is accompanied by a big loading jump at the reboiler. Semi-lean solvent loading also increases as the semi-lean draw fraction goes up.
Take away conclusions
Figure 7. Absorber temperature profile.
Figure 8. CO2 partial pressure profile.
The single recycle loop classic configuration is the most efficient design applicable for most design cases since acid gas is contacted throughout the whole column with a well regenerated solvent. The system could have stable operating controls to cope with variability changes. The case study shows that for a typical LNG feed pretreatment, the reboiler energy benefits are none-to-marginal at best for the additional equipment and metallurgical considerations. Split-flow configuration could be an advantage in certain cases. A large reboiler energy reduction can be achieved with larger semi-lean solvent draw rates, but at the expense of: 1. Rich amine loadings exceeding maximum threshold limit. However, if the economics warrants the use of stainless-steel metallurgy for rich amine piping and cladding in the upper section of the regenerator, substantially reduced reboiler energy consumption can result. This is a trade-off between operating and capital costs. 2. Lower CO2 percentage recovery along the absorber column. 3. CO2 absorption becomes highly-dependent on semi-lean draw fraction setpoint control, which causes wide variations in the purified gas CO2 content. 4. Additional equipment for the semi-lean loop circuit. An economic analysis will inform the choice between the single-loop, classic case and the split-flow configurations.
References
Figure 9. Regenerator temperature profile.
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February 2024
1.
MOHEBBI, V., and MOSHFEGHIAN, M., ‘Method Calculates Lean, Semi-Lean Streams in Split Flow Sweetening’, Oil & Gas Journal, (23 July 2007).
2.
Net loading is the increase in loading between the top and bottom of the absorber. It is a measure of solvent capacity.
Justin Ellrich and Emily Galligan, Black & Veatch, outline some guidelines for optimal heavies removal scheme for LNG facilities.
T
he LNG industry has practiced the removal of potentially freezing heavy hydrocarbon components from natural gas since its inception. The impact of inadequate design of a heavies removal system is clear – freezing at LNG temperature causes downtime and lost revenue. But even with extensive experience across decades of operation, there is not a simple and clear-cut answer as to the desired design required to meet LNG specification. This is because there are significant ramifications to capital and operating expenses depending on the configuration employed. Differences in gas composition,
liquefaction technology, plant/train size, and other pertinent factors necessitate different process solutions.
Feed gas analysis and decision factors The analysis starts with a study of the feed gas composition and determination of the lean-to-rich range of the design. The amount of natural gas liquids (NGL) and potentially freezing components, typically marked by benzene concentration, are primary factors. But even for a set composition, other factors, such as the ability to sell NGL product(s) if there is a fuel sink to
23
blend in the removed heavies and the pipeline pressure, favour different configurations. The range of compositions to consider is key to making design decisions. Gas from a single production source may vary but is typically more consistent in composition and can have a narrower, targeted process. LNG plants on a large pipeline system – like the US Gulf Coast with many different producers – can see significant variations, so flexibility to meet removal specifications is warranted but comes at a higher cost. For these systems, feed gas analysis should be conducted throughout the project lifetime to account for changes that may alter feed gas composition by the time the plant starts up. Feed gas pressure is also key to design selections. Lower pressure directly results in lower liquefaction efficiency, so options that feed the main heat exchanger at higher, super-critical pressures exhibit higher efficiencies. However, many LNG plants do not receive gas at super-critical pressure, particularly those on pipeline systems and small scale units, and therefore may be less restricted by configurations that favour lower pressure for separation. Regardless of the configuration chosen, a use or disposal method for the heavy hydrocarbons must be found as this can be a constraining factor. The heavies stream can be blended to fuel with a turbine drive system if it meets the quality and volume needed. However, sometimes the blend exceeds the consumption rate (particularly when the facilitity is motor driven) or specification and requires further processing to remove the light ends. This results in an LPG/NGL/condensate product that needs to be stored and moved offsite.
Heavies removal configurations
Sorting through available heavy hydrocarbon removal options from those proven in the LNG industry can be a daunting task. Gas Treating
Feed Gas
Refrigerant Loop
Main Exchanger
Heavies Fractionation/ Storage LNG Storage
Gas Treating
Refrigerant Loop
Main Exchanger Feed Gas or Refrigerant Liquid
Heavies Fractionation/ Storage
LNG Storage
Figure 2. Scrub column configuration. 24
February 2024
Partial condensation
Partial condensation configurations are the simplest in both flowsheet and operation. However, phase separation cannot be achieved unless the stream is below the critical pressure, and sometimes considerably so in the case of a simple flash to ensure freezing components are adequately removed. Therefore, partial condensation configurations are most favourable at lower feed gas pressures since the gas is already below the critical point. High feed gas pressures require significant pressure reduction for partial condensation to be effective, reducing overall efficiency.
Simple flash A stalwart for small scale applications, the simple flash has a proven history and is still a fit for many applications. The separation temperature can be customised to the feed gas conditions to properly balance efficiency and product retention with the need to ‘over-condense’ a significant portion of methane to ensure heavy components stay with the liquid phase. The heavies liquid stream is usually vaporised, either through a separate heater or as another pass in the main exchanger, and can be used for fuel or re-injected back to the feed pipeline. A variation by Black & Veatch uses a simple flash as the first removal step then fractionates the heavies stream to effectively recover C4 and lighter components for reliquefaction in a separate pass of the main exchanger, while also producing a stabilised condensate product or a blend into fuel. While the simplicity and low cost is advantageous, this configuration carries the lowest efficiency of all options and could be limited by heavies product disposition. Being reliant on just a single-stage flash renders application to lean feed gas difficult as not enough liquid can condense to be effective in removing freezing components. It also lacks flexibility to significant changes in feed gas composition as there is limited control over the separation conditions. These disadvantages can typically be overcome for small scale and intermittent applications which favour a low CAPEX approach, but larger baseload units may take a more sophisticated approach for better overall economics.
Scrub column
Figure 1. Simple flash configuration. Feed Gas
This article will discuss the merits and drawbacks for the three most common general flowsheets: partial condensation integrated with the liquefaction process, expander-driven units either integrated with or upstream of liquefaction, and adsorption technology.
Applying a scrub column with reflux enables heavies removal at higher pressure, usually with less loss to the liquid stream compared to a simple flash. Reflux can be sourced from multiple locations depending on simplicity and efficiency desired; an intermediate pass in the main exchanger could be employed to limit the refrigerant duty consumed or it can be pulled directly from the LNG product stream. Higher flexibility is also gained from reflux, though it is still limited by the liquids which can be produced and may struggle on leaner feed gas. While better heavies removal certainty is achieved with this design, the need for sub-critical pressure and lack of gas machinery still leaves this configuration on the lower end of efficiency. Another variation on this concept where reflux is not required is to strip the liquid flowing down through the column to manage product loss.
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Expander processes
Larger scale applications reap greater benefit from increased cost and complexity when employing gas expanders and compressors. Some form of expander process has become commonplace across many newer facilities. Expanders provide supplemental refrigeration by the mechanical removal/transfer of work and achieve separation at lower pressures while an integral and/or separate booster compressor recovers that pressure loss to keep liquefaction efficiency high. Therefore, the expander processes prove favourable for facilities with a high feed gas pressure, as they can capitalise on the pressure reduction in the overall efficiency of the refrigeration process. There are many process configurations available, both open-art and licensed, with variations on C2 and heavier recovery and machinery/tower lineup that were primarily developed for gas processing applications. Though it should be noted in many instances,
Gas Treating
Feed Gas
Refrigerant Loop
LNG Storage
Figure 3. Expander/scrub column hybrid configuration.
maximum recovery of C2-C4 to LNG is the desired result and some modifications to typical schemes or operating conditions used in the gas processing arena should be considered. An intermediate option exists before jumping straight to an independent, up-front heavies removal system. A hybrid of the flash or scrub column along with an expander/compressor integrated within the liquefaction unit can be an ideal balance of cost and efficiency, as well as footprint which is essential for floating applications. More applicable to mid scale units and those using brazed aluminium heat exchangers, an expander at some mid-point of the process can be optimised as much of the refrigeration is from the main loop which brings great flexibility. Reflux can still be incorporated if necessary. Depending on the feed gas conditions, approximately 4 – 8% efficiency increase is expected with this integrated expander configuration. For large scale trains or where many mid scale trains are in parallel, the independent up-front expander process holds a lot of merit. The key is not the expander itself, but additional booster compression to maximise the liquefaction efficiency at super-critical pressure. The efficiency increase over non-machinery options is expected to be 10 – 14%, more than enough to justify additional cost and complexity when it results in increased LNG production for baseload export facilities. While there are many flow schemes to Feed Gas or Refrigerant choose from within this subset of processes Liquid Heavies Fractionation/ with cost and efficiency sensitivities with Storage preferred applications for richer or leaner gases, there is considerable history for many of them in gas processing plants.
Adsorption
Refrigerant Loop
Main Exchanger
Feed Gas
Gas Treating
LNG Storage Feed Gas or Refrigerant Liquid
Heavies Fractionation/ Storage
Figure 4. Independent upfront expander process. Table 1. Major aspects of heavy hydrocarbon removal systems Simple flash
Scrub column
Expander, integrated
Expander, up-front
Adsorption
Cost
1
2
3 – 4**
5
3 – 4**
Efficiency
5
4
3
1 – 2**
1 – 2**
Footprint
1
2
3
4 – 5**
4 – 5**
Lean gas effectivenss
5
4
2
3
1
* Scale from 1 – 5, with 1 being best (lowest cost, highest efficiency, lowest footprint, best effectiveness). ** Advantage is dependent on feed gas composition and pressure for specific applications.
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February 2024
The previous heavies removal applications discussed are based on vapour-liquid equilibrium and phase separation. They are ultimately hampered by the need for equipment and power to refrigerate the gas stream to achieve the necessary operating conditions for effective freezing component removal. A relatively newer technology segment of molecular sieve based regenerable adsorbents can bring significant advantages to the right applications. The adsorbent system closely resembles a dehydration unit (which is standard in nearly all LNG plants) and, in some cases, can even be combined with the dehydration beds for a single system for water and heavy hydrocarbon removal. Achievement of non-freezing levels of heavy hydrocarbons in the gas to be liquefied is insensitive to pressure, meaning expander/compressors are not needed and super-critical incoming feed pressure does not need to be reduced like in phase separation designs, maintaining liquefaction efficiency. There is still a need to manage the disposition of heavy hydrocarbons concentrated in the regeneration
gas stream. Fuel blending of all regeneration gas is ideal but may not always balance with the fuel consumption, particularly for motor drive facilities, so a phase separation may still be needed. But such separation will be applied on a smaller stream than the main feed gas and with potentially more concentrated heavy hydrocarbons enabling a less complex system. This highlights the main advantage for an adsorbent system – lean feed gas. Richer gases with higher NGL content are easier to do traditional separation processes on and could also render a design infeasible in terms of bed size or cycle times, but lean feed gas with low levels of heavy hydrocarbons fit reasonable parameters for adsorbent system design.
Options comparison
A relative ranking of the major aspects of heavy hydrocarbon removal systems is provided in Table 1, but it is not intended to unilaterally pick a winning configuration. Evaluation of the options comparison to best fit project goals will be specific to every application (dependent on gas conditions, drive technology, scale, etc.) and likely results in a different decision even if many other parameters are equal.
Conclusion
Higher efficiency processes like expander units and booster compressors upstream of the liquefaction process can add 10% or more LNG capacity when refrigeration power is fixed. Adsorption is an emerging technology that can maintain high pressure and efficiency for lean gases where phase separation is difficult. The added cost and complexity are economically favourable for large scale plants but the efficiency/production
gains on a small scale unit are usually not enough to justify. Motor-driven refrigeration, which is not constrained to a set power like a turbine, may also not warrant added complexity if increase in refrigeration loop cost is lower. Liquefaction technology also plays a role in the decision if not removing heavies upstream as the flexibility in separation temperatures and integration with the main cryogenic heat exchanger is simpler in single loop processes compared to multi-loop refrigeration. There is no blanket solution for all LNG facilities or even sub-segments of similar facilities because influences of feed gas, economics, and operating philosophy warrant different strategies. But once the feed gas is properly characterised and the project parameters and goals are clear, the ideal heavies removal scheme can be selected by applying the framework for decision-making provided herein paired with economic analysis.
Bibliography 1.
BRUSSOL, L., and GADELLE, D., ‘Lean LNG Plants – Heavy Ends Removal and Optimum Recovery of Liquid Hydrocarbons for Refrigerant Make-up,’ LNG2017, (2013).
2.
CHEN, F., and OTT, C., ‘Lean Gas’, LNG Industry, (January/February 2013).
3.
GASKIN, T., and DAVIS, K., ‘LNG Freeze Component Removal Technology Application Map,’ GPA Midstream Convention, (2017).
4.
KRISHNAMURTHY, G., and LIU, Y., ‘Removal of Heavy Hydrocarbons from Lean Natural Gas,’ AIChE Spring Meeting, (2013).
5.
‘Liquefied Natural Gas Solutions,’ Honeywell UOP Brochure, (2019).
A flexible solution
cover story Mark Krajewski, Director, Technical Services, Aspen Aerogels, USA, discusses the importance of insulation to how LNG plants operate, especially as the world moves towards a more sustainable future. 28
for the future
L
NG is broadly recognised as the primary fuel that will bridge the power needs of the world as the energy economy transitions from fossil-based fuels to renewable sources. Liquefaction and receiving plants that produce, receive, and distribute this vital commodity are unlike most other types of hydrocarbon fuel production facilities because LNG is produced, stored, and transported at the deep cryogenic temperature of -160˚C (-256˚F). This fact makes the design and performance of the insulation system selected to protect the cryogenic liquid from heat gain critical to how these plants operate. The insulation system also heavily influences a plant’s actual carbon footprint, and can either assist or hamper the decarbonisation efforts many oil and gas majors are looking to implement in future liquefaction facilities.
LNG facility insulation thermal design
From a thermal design standpoint, cryogenic insulation systems are charged with two main tasks: the first is to limit heat gain to the LNG and the second is to control condensation on the insulation surface. It is evident why minimising heat gain is important to the efficient and safe operation of liquefaction and import facilities. In most every case, the LNG contained by the piping and vessels of the facility is at its boiling point given its operating pressure. Every W/Btu of heat that leaks through the insulation converts directly into the formation of boil-off gas (BOG). Certainly, facilities are designed to handle a defined amount of BOG, but what happens if that becomes too much? What are the consequences of a facility facing higher-than-designed-for BOG?
29
A secondary thermal design criteria is to control or reduce condensation that can form on the outer surface of the insulation jacket when its temperature falls below the ambient dewpoint. While this may appear to be a secondary design consideration, excessive surface condensation can cause significant operational problems at start up and as facilities age. Continued excessive condensation can run off the insulated surfaces and create slipping hazards. Consistent and excessive surface condensation can also cause mould and other bio growth
on the insulation jacket, giving the appearance of an ill-maintained facility (Figure 1). Over time, that same consistent condensation run off can cause significant corrosion to supporting structures and decking, giving rise to repair and reliability concerns. Appropriate thickness tables are based on the operating temperature of the asset and, more importantly, should be an accurate representation of the ambient weather conditions where the facility is located. Typical insulation specifications may contain separate design thickness tables prescribing thickness of insulation by pipe size and process temperature for each criterion. It is also common to have a single table for thermal insulation that is a combination of the greater calculated thickness for any given pipe size and process temperature of the two design criteria. These combination thickness tables are often referred to as condensation control tables with a heat gain backstop. When the facility exists in a low relative humidity environment, a combination table is dominated by heat gain criteria; in high relative humidity environments, insulation thickness is dominated by condensation control criteria.
Industry trends in design
Figure 1. Bio growth on jacketing exterior.
Figure 2. Relative thermal resistance design of LNG facilities.
As a trend, insulation design criteria are becoming increasingly more stringent. This trend is being driven by several macro-economic factors. For one, countries or groups of countries are adopting stricter energy codes, as is the case with the Mexican NOMs that are now being integrated into upcoming project specifications. Since heat gain calculations are essentially an economic thickness calculation, some owners and EPCs are betting the cost of energy will continue to increase in the future and more stringent design will offset higher initial capital costs. The last element factoring into increasing thickness designs is the consideration around lowering LNG production carbon intensity. This can take the form of straightforward reduction in carbon emissions due to less heat gain and the carbon cost thereof, and the possible need for super-insulating designs which enable deep decarbonisation of the liquefaction process – more will be discussed later in the article. A recent example: a major gas importer in Southeast Asia completed a new LNG import facility. The specified insulation resistances on the new facility were, in some cases, 28% greater than the design used for a sister facility that was commissioned 12 years earlier (Figure 2).
Real-life performance and insulation system degradation
Figure 3. Frost on jacketing surface above a failed contraction joint.
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February 2024
As the key transitional fuel source, there is high interest and public pressure to reduce the carbon intensity of LNG production, shipping, and distribution, by as much as is practical. When considering insulation’s role in this effort, one should consider the performance of the insulation system as designed (on day one of plant operations) and also how that insulation system’s performance may degrade over time. Performance degradation in cold insulation systems is well documented and, like hot systems, is by and
large caused by water ingress. For cryogenic insulation, the failure cycle begins with a breach of the all-important vapour barrier system. Once the vapour barrier is breached, the differential in relative humidity between atmosphere at cryogenic and ambient temperatures literally pulls the water vapour into the system. That vapour draw will not stop until every void is filled with ice or water. Many of these failures occur in locations where mechanical stresses in a system build up, or in features meant to absorb the differential thermal expansion between the cryogenic piping and the relatively warm outer layers of insulation (i.e. contraction joints) (Figure 3). Additionally, many of these vapour barrier failures can be attributed directly to using insulation materials that are ridged in nature. When a failure is gross it is easy to see (Figure 4), but often this vapour ingress can be subtle, i.e. jacketing that sweats more than it did at start up, or greater usage of the BOG compressors.
Even subtle changes like these can cause significant reduction in the insulation system performance (Figure 5).
Effects of insulation design and performance on efficiency and carbon emissions
What impact does insulation design and possible degradation have on plant efficiency and carbon emissions? To answer this, the article will look at a 15 million tpy liquefaction facility with a base line heat gain thermal design of 25 W/m2 (Table 1). What are the impacts of making that design more stringent? Shifting design criteria from the 25 W/m2 industry rule of thumb to more stringent values results in both cost and emissions reduction benefits – as one would expect. There would also be a commensurate reduction in BOG, which would yield operational benefits. More interesting are the effects of insulation degradation on a plant’s operation and emissions profile (Table 2). Table 2 shows that with degradation factors often seen in real world insulation systems, substantial negative effects on both cost and efficiency are observed. It is important to keep in mind that while these numbers detail carbon dioxide (CO2) emissions and cost, the other side of the coin is vastly increased BOG. With just a 4x degradation factor, BOG jumps from a baseline 33 897 to 135 588 tpy.
Deep decarbonisation
Figure 4. Infrared image of failure (left) and close-up photographic images of failure (right).
With the drive to the lowest carbon intensity LNG possible, one has to think outside the box in all aspects of LNG production and storage. All of the systems in a plant are interdependent. If a new super-low CO2 liquefaction facility is using an electric drive liquefaction train, what does it do with its BOG? It cannot be used to power the gas drive turbine. It would have to be reliquefied and shipped out in product. What if that same plant now sees a 4x degradation in performance and it overwhelms that system? Furthermore, how will site leaders navigate demonstrating improvements to their facility operations, should third party CO2 audits become mandated? All these eventualities point to the necessity of specifying a cryogenic insulation system that can allow for any level of performance in a reasonable thickness envelope and that is not subject to the failure mechanisms that bedevil traditional rigid insulation systems.
What can be done?
For cold insulation, flexible aerogel blanket materials, such as Cryogel®, bring a unique set of material and system-level properties to the problem of insulation surface temperature. degradation from water ingress. Cryogel’s Table 1. Heat gain design sensitivity analysis: influence on CO2 generation and cost multi-layer designs Heat gain design value (W/m2) bring six, nine, even 12 redundant sheets of 25 22.5 20 17.5 vapour-retarder material 2899 2609 2319 2029 CO2 emitted due to insulation heat gain at design (tpy) to cryogenic systems. Even without any Energy cost due to heat gain through insulation at design (US$/y) 228 000 206 000 183 000 160 000 vapour barriers, Cryogel’s 372 950 336 450 298 950 261 450 Total energy cost with a US$50/t CO2 charge (US$/y) nanoporous structure
Figure 5. Heat gain deviation, design vs actual insulation
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is simply too fine-scaled to allow the internal formation of ice when tested down to -196˚C (-320˚F).1 And, most importantly, the fact that Cryogel is flexible even down to LNG temperatures means that it does not require contraction joints or build stress at typical areas like pipe supports. Simply put, flexible blanket insulation is the best form factor for cryogenic services.
Table 2. Insulation degradation sensitivity analysis: effects on CO2 generation and cost (cold work 25 W/m2 baseline) Degradation factor 4
6
8
CO2 emitted due to insulation heat gain (tpy)
11 595
17 392
23 190
Energy cost due to heat gain through insulation (US$/y)
914 000
1 370 000
1 828 000
Total energy cost with a US$50/t CO2 charge (US$/y)
1 493 750
2 239 600
2 987 500
8696
14 783
20 871
Energy cost above baseline design heat gain (US$/y)
686 000
1 142 000
1 600 000
Total cost above baseline with a US$50/t CO2 charge (US$/y)
1 120 800
1 881 150
2 643 550
CO2 emitted above baseline (penalty) (tpy)
Why flexibility matters and is the solution
If one considers the benefits afforded by a flexible cryogenic insulation system, the choice becomes clear. Flexible aerogel blanket systems offer a significant reduction in installation time, simplified dual-purpose systems, a multitude of logistical benefits, and redundancy of vapour barriers throughout, and those are just the construction benefits. Operationally speaking, flexible aerogel blanket systems offer thermal performance that can reduce the amount of BOG a system produces, and they are reusable, meaning lower CAPEX costs when maintenance requires removal of insulation. In short, most everyone prefers some flexibility over rigidity, especially if it leads to savings and a more carbon-neutral facility.
As the world strives towards a cleaner and more sustainable future, and the LNG industry takes a closer look at the construction and operation of the plants that produce the fuel required to meet the ever-increasing energy demands, simple decisions around insulation systems are the easiest and most obvious levers to pull. Adding flexibility to LNG insulation systems is an opportunity to prove the industry’s commitment to long-lasting operational performance, energy savings, and CO2 reduction overall.
References 1.
WILLIAMS, J., ‘Cracking the Code: Thermal Insulation in Ethylene Plants’, Hydrocarbon Engineering , (July 2023).
MICRO SCALE LNG PRODUCTION Integrated purification & liquefaction up to 30 ton/day
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In cooperation with:
Carlos A. F. Falsiroli, Mayekawa USA, details screw compressor applications for the LNG industry.
C
entrifugal compressors are continuous flow machines in which one or more rotating impellers accelerate the gas as it passes through the impellers, which are shrouded on the sides. The resultant velocity head is then converted into pressure. This occurs partially in the rotating element and partially in the stationary diffuser. Reciprocating compressors are positive displacement machines with a piston compressing the gas in a cylinder. As the piston moves forward, it compresses the gas into a smaller space, thus raising its pressure. There are two types of reciprocating compressors: a ‘lube’ type with oil injection, and ‘non-lube’ as oil-free. Screw compressors are also
positive displacement machines, but rotating twin rotors act as pistons that compress the gas in a rotor chamber (casing). Compression is done continuously by the rotation of the twin rotors. There are also two types of screw compressors: the ‘oil flooded’ type with oil injection, and ‘oil-free’ with no oil injection.
Screw compressor compression process
The term rotary describes a class of compressors that operate on the positive-displacement principle and employ rotary motion to transfer energy, that is, to compress gas.
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The screw compressors use a twin-shaft rotary piston to combine positive displacement with internal compression. The gas that is entering at the suction side is conveyed to the discharge side through the intermeshing spaces between the male and female rotor where the volume is reduced continuously until the point the gas reaches the discharge port. The result is the compression of the gas to the internal discharge pressure before it is released through the discharge nozzle. The compression process in a screw compressor occurs in four phases: 1. Suction: The rotors with different tooth profiles are engaged. As the rotors turn, the volume between the male and female rotor tooth profiles and the compressor casing gradually increases starting from the suction side. 2. Transfer: As the rotation continues, at a certain point when the volume reaches its maximum, the rotors isolate the gas (volume), which is enclosed by the rotors and the compressor casing, from the suction port and then continue rotation. 3. Compression: As the rotors rotate further, the volume between the rotor lobes and grooves decreases while the sealing line moves toward the discharge side, which compresses the trapped refrigerant gas. 4. Discharge: The volume between the rotor lobes and grooves decreases to a level predetermined by the discharge port. With the rotations of the rotors, the compressed refrigerant gas is pushed out to the discharge port. Regardless of whether the screw compressor is executed for dry screw compression or oil-injected compression, the gas is compressed in chambers. This progressively decreases the size that is formed by the intermeshing actions of the helical rotors and by the housing wall. Oil-free screw compressors have a set of timing gears in their design to avoid contact between rotors and casing. In the case of the oil-injected screw compressors (oil-flooded), there are no timing gears incorporated in the design, meaning the driven male rotor interacts directly with the female rotor. Oil injected into the compressor cavity provides intensive
lubrication, and a large portion of the compression heat is absorbed.
The internal volume ratio
In the case of reciprocating compressors, the refrigerant compression capacity is controlled by setting the pressure attained by piston displacement to an optimum level for the intended application. With screw compressors, on the other hand, the compression capacity is controlled by setting the extent to which the volume of the sucked refrigerant gas is to be reduced. In other words, the compression capacity control applied to the screw compressor is a volumetric ratio control. The position of the edge of the discharge port determines the built-in volume ratio. The built-in volume ratio is a relationship between the suction and discharge volumes at the respective ports of a given mass of gas that is being conveyed:
The built-in compression ratio is calculated according to the following formula:
Where k is the adiabatic coefficient, that means the ratio of the specific heats of the gas at constant pressure and volume respectively. Screw compressors are designed for a determined compression ratio. If the compressor discharges into a system with a compression ratio in excess of, the compressor end will face such pressure. On the other hand, if a screw compressor works with a higher built-in compression ratio than the system, some efficiency will be sacrificed.
Oil-flooded screw compressor description
In the case of the oil-flooded compressors, the are two rotors inside the casing where they contact each other at the lobe surface through an oil film. Oil is supplied not only to the bearing and seal, but also to the rotor chamber
Figure 1. Properly adapted Vi to load condition (left) and improperly adapted Vi to load condition (right). 36
February 2024
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directly, e.g. in case there is a need to control the discharge temperature. The oil acts as lubricant, coolant, and sealant in the rotor chamber. Typically, the male rotor is driven by a directly coupled electric motor and drives the female rotor. An external gear unit is typically not used since the tip speed of the oil-flooded screw compressor is in the proper design range when driven at motor speed. There is one mechanical seal located at the drive shaft end. There are typically sleeve-type journal bearings on either end of the rotor lobes. Thrust bearings are typically tilting-pad type and are located on the outer side of the journal bearings. The oil and gas mixture are discharged through the compressor discharge nozzle into an oil separation system located downstream of the compressor. Oil separated in the oil separation system is circulated in the compressor lube system. An unloaded slide valve is located in the compressor just beneath the twin rotors and is used to adjust the inlet volume. The inlet volume of the compressed gas can be adjusted by moving the slide valve, which is actuated by a hydraulic cylinder. Oil also is necessary for capacity control, which is hydraulically operated. The unloader slide valve, which is activated hydraulically via the unloader cylinder and the unloader piston, automatically carries out capacity control (suction gas amount control). The unloader indicator assembly is connected to the unloader cylinder via the indicator cam, allowing the indicator to indicate the positions of the unloader slide valve. The indicator cam has a spiral groove, in which the guide pin implanted in the unloader slide valve push rod is movably inserted. As this pin and cam combination convert a linear displacement of the unloader slide valve into an angular displacement, the pointer of the indicator indicates the position of the slide valve.
In addition to the visual reading of the position of the unloader slide valve, the unloader indicator assembly can also provide the following electric signals for output to external devices: ON/OFF signals produced by the cam mechanism contacts and resistance signals produced by a potentiometer mechanism.
Major characteristics of screw compressors z High compression ratios: Since the lubricant (oil) acts as a coolant and sealant, oil-flooded screw compressors bear high compression ratios. The discharge effect caused by the high compression ratio can be offset by injecting oil in the rotors chamber to absorb the heat. In the case of very high compression ratio, a tandem arrangement in a two-stage system combined in just one frame is possible. When the pressure ratios are higher than 10:1 tandem design can support compression ratios up to 60:1. Figure 5 shows a typical tandem (compound) oil-flooded screw compressor configuration. z Simpler skid arrangement: The compressor and lube oil system can be integrated into just one single skid, reducing the installation costs. z Low maintenance cost: As the oil system is inserted into the rotors, bearings and other parts forming an oil film, the life span of the components, and the compressor itself is increased. z Lubricant selection: Once the oil mixes with the process gas during the compression process, a compatible oil must be selected. Mineral and synthetic oils are used to expand the range of applications of oil-injected screw compressors. There are two types of synthetic oil: polyalphaolefin (PAO) and polyalkalyne glycol (PAG). When the process has heavy hydrocarbons content, mineral and PAO oils are subject to dilution. The PAG has less dilution.
Screw compressor application in LNG plants
There are numerous processes in the LNG facilities which require compressors being screw compressors suitable for most of them depending on the project scale.
Figure 2. Lubricating oil flow inside the compressor.
LNG pre-treatment plant
Prior to the liquefaction of the natural gas, the feedstock is treated to remove mercury, water, and carbon dioxide (CO2) (CO2 and water would otherwise freeze and cause clogging in the downstream liquefaction equipment). The plant may also have a sulfur recovery unit (SRU) to remove sulfur. Fractionation is also carried out to recover liquids (NGLs) and potentially LPG.
Liquefaction plant
Figure 3. Double stage compound compressor. 38
February 2024
Liquefaction is carried out on the treated gas stream through a refrigeration process. There as a number of different processes provided by technology licensors, with Air Products being the most prominent. Others include ConocoPhillips, Shell, Black & Veatch, and Linde.
Once the gas is in LNG form, it is stored in special tanks prior to distribution to markets. The liquefaction process can be carried out in land-based plants of varied capacities and also on-board floating LNG production vessels. In some plants, there may also be a helium plant to extract helium from the final stages of the cooling process (the off/flash gas).
LNG transportation
LNG can be transported via land-based networks, but a major route to market is via specialised LNG carriers. As some of the LNG will vaporise during storage there are systems to recover the vapours (boil-off gas [BOG]) and either feed the ship engines or return to storage through a reliquefaction process.
LNG regasification plant
Once shipped, the LNG will arrive at a receiving terminal where LNG will be offloaded into storage tanks before passing through a regasification process. Once returned to a gas, the gas will be fed into the distribution pipeline. The storage tanks where the LNG is stored pre-regasification will continue to emit BOG and so will have systems in place for recovery with gas going to power turbines, the pipeline feed, or reliquefaction. Storage of LNG and regasification can also be carried out on-board specialised vessels (FSUs/FSRUs).
Stabilised liquids collect in the bottom of the tower and are cooled prior to flowing to storage tanks. The gas is compressed using the off-gas compressor to the required pressure for the acid gas removal processes.
NGL recovery (refrigerant/ overhead)
After a gas stream has been dehydrated, the gas will still contain natural gas liquids (ethane, butane, propane, gasoline condensate). These need to be removed prior to liquefaction. Refrigeration is most common from gas streams and absorption within gas plants and refineries. Within refrigeration, the refrigerant (e.g. propane or ammonia) would be compressed. After cooling, the gas would pass through a fractionation tower consisting of three columns: demethaniser, depropaniser, and debutaniser. Compressors are used to process the overhead gases (mainly the ethane from the de-ethaniser).
CO2 (boost/recycle/injection)
CO2 is removed from the feed gas using solvents (chemical absorption, physical absorption, or mixed) in an acid gas removal unit (AGRU) along with hydrogen sulfide (H2S).
Application overview
As a rule of thumb, screw compressors will be suitable in volume flows ranging from 500 – 12 000 ft3/min. and with compression ratios within 2:1 to 50:1.
Separation (flash gas)
Flash gas occurs within the separation process (pre-treatment – sometimes described as inlet facilities). Particles and residual condensate are removed in a gas separator. The high-pressure separator is likely to have gas drawn off without the need to boost the pressure. The low-pressure separator though will require gas compression (assuming it is to be utilised – likely based on cost and environmental restrictions). The compressor is therefore fed from the low-pressure (LP) separator and recycles the recovered gas to the process.
Figure 4. Typical LNG processes.
Stabilisation unit (off gas)
Condensate stabilisation occurs after primary separation where the condensate stream enters the unit and is preheated in the inlet heat exchanger prior to flowing into the stabiliser tower. Inside the tower, the light components – typically methane, ethane, propane, and butane – rise and exit the overhead vapour outlet. The heavier liquid components descend and pass through the indirect heater to cause additional vapour to flash off, rise, and exit the tower.
Figure 5. LNG application map.
February 2024
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In a solvent-based system (UOP/Fluor), the H2S is removed using a CO2 saturated lean solvent from the CO2 section. The CO2 is stripped off, compressed, and recycled to the H2S absorber. The remaining CO2 in the sulfur-free gas is then removed in an absorber within the CO2 removal section, which will also contain a recycle compressor and final process compressor. If CO2 storage is also carried out, there may be an injection compressor (likely high pressure).
BOG
Due to heat absorption by piping, tanks, and equipment, a part of the LNG is continuously turned into vapour. The amount and composition of BOG varies over time. Vaporised LNG is mainly methane (CH4) and nitrogen and is recovered for environmental reasons (to minimise hydrocarbon loss and flaring) and also for economic reasons (to retain valuable fuel). The BOG is compressed and, depending on the plant requirements, can be sent for reliquefaction and returned to storage, sent for fuel gas, flared, or degasified for send-out into the pipeline.
Helium extraction (feed, helium)
Helium is contained within natural gas and is extracted through a low-temperature condensation process to produce a concentrate. It is then purified. By virtue of the LNG process, the feed gas will already be purified (water/acid gas removal) and separated
from hydrocarbons. This is then fed through a cryogenic process (via a feed gas compression unit – end flash compressors possibly) to remove remaining methane and produce crude helium. The crude helium then goes through a final purification, typically a PSA unit – tail gas routed back through feed compressors. Once purified, the crude helium is compressed typically to 15 – 25 bar (217.6 – 362.6 psi) for liquefaction. This is normally from approximately 1.9 – 5.1 bar (27.6 – 74 psi).1 Therefore, two-stage compression is common. Air Products, Air Liquide, Linde, Technip, and ExxonMobil have helium technology processes.
Power plant (turbine inlet cooling – refrigerant)
Gas turbines are typically used as for power and compressor drivers in LNG liquefaction plants. As ambient temperatures increase, they can suffer from decreased power output with potential reductions in LNG production and process instability. Gas turbine inlet cooling/chilling (TIC) can alleviate this and is a widely accepted technology by gas turbine original equipment manufacturers (OEMs). A mechanical vapour compression refrigeration cycle can be used to cool the inlet air down to a desired temperature using latent heat of vaporisation of a working fluid or refrigerant to chill water or an anti-freeze solution, such as water/propylene glycol. The liquid refrigerant is expanded at low pressure in an evaporator and the vapour is then compressed. Heat from the compressed refrigerant is then transferred in a condenser, which in turn is rejected to the atmosphere. Air-cooled condensers will condense the refrigerant in a heat exchanger which allows the refrigerant to drain back to a refrigerant receiver or directly to the evaporator where the cycle continues. Common refrigerants used include R123 or R134a, R717 (anhydrous ammonia), or hydrocarbons such as propane (commonly available within LNG plants).
Conclusion Figure 6. BOG process.
Oil-flooded screw compressors can be applied in many applications. Some reasons for considering the screw compressor are changes in process conditions, recent progress in compressor technologies, and the application range of screw compressors. There are many benefits for the customer such as high reliability, low initial cost, less maintenance cost, and power savings.
Bibliography
Figure 7. Turbine inlet cooling process.
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1.
‘API Standard 619: Rotary Type Positive Displacement Compressors for Petroleum, Petrochemical, and Natural Gas Industries,’ American Petroleum Institute, (2010), 5th edn.
2.
‘2201X2JE-MY-S2-N_2020.12’, Mayekawa USA Oil & Gas, Chemical Division.
3.
MOKHATAB, S., MAK, J. Y., VALAPPIL, J. V., and WOOD, D., Handbook of Liquified Natural Gas, (2014).
TURBOMACHINERY
IN LNG PRODUCTION PLANTS – PART ONE
In the first part of a two-part article, Brian Pettinato, Manager, Aero & Structural Dynamics, Sterling Scavo-Fulk, Compressor Development Engineer, and Brian Hantz, Advanced Technology Engineer, Elliott Group, USA, examine the use of compressors and pumps in the LNG value chain.
O
ver the past 20 years, global consumption of natural gas linked to population growth and motivation for cleaner power sources has been steadily rising. LNG offers the capability to convert natural gas to higher energy concentration and transport its value to higher-demand markets where it can be stored and regasified for power generation, direct heating, industrial processes, and as a supplement to renewable power worldwide. In 2019, LNG represented 9.8% of the global gas supply. This percentage will increase as the primary gas-producing areas develop greater LNG production capacity in order to capture higher market value for natural gas as a primary and supplemental means of power generation.
Converting natural gas to a liquid allows for the transport of greater energy content since LNG takes up about 1/600th the volume of natural gas. It can be pumped and transported using maritime vessels, highway trucks, and short liquid pipelines. For commercial use, LNG must be converted back into gaseous form at regasification plants at the receiving terminal where the LNG is delivered. LNG production plants use a wide range of turbomachines including centrifugal compressors, gas and steam turbines, turboexpanders, and cryogenic pumps and expanders. Historically, LNG producers have adapted to advances in turbomachinery to maximise output. Additionally, producers have continued to gain efficiencies and cost improvements by
41
considering variations to the refrigerant mixtures and cycle adaptations to convert natural gas to its liquefied form. This article, based on a short course given at the 2023 Turbomachinery Symposium, reviews the LNG value chain, focusing on how compressors and pumps fit into the various LNG plant cycles. Part 1 includes production processes and compressor applications. Part 2 (coming in September 2024) will cover LNG pumping applications and equipment.
The LNG value chain
The LNG value chain includes the production, processing, and conversion of natural gas to LNG, transportation of the liquefied gas, and regasification as it travels from extraction to final delivery to end-users. The value chain includes: z Production – extraction and separation of natural gas from condensate and/or crude oil; transport of the raw gas to processing facilities for contaminant removal.
z Gas processing – cleaning and treating the natural gas before liquefaction. z Liquefaction – clean, dry natural gas is liquefied by dropping its temperature below its boiling point through a cryogenic process. z Transportation – LNG is transported to regasification facilities by specialised ships or by truck in smaller quantities. z Receiving and regasification terminal – unloading, storage, and regasification at import terminals, which are typically located near a port. z Gas utilities/pipeline – the natural gas in its gaseous phase enters the local distribution system. z LNG peak shaving – if the LNG is delivered to a utility-operated peak-shaving facility, it is stored until needed at peak demand. The LNG value chain is relatively complex and requires many different types of turbomachinery to complete the thermodynamic processes required. It is fairly efficient, with most of the energy consumed by the liquefaction and transportation steps. Optimising the liquefaction process and employing energy recovery systems throughout the chain is important to maximising return on investment (ROI). A typical breakdown of costs is shown in Figure 1.
Refrigeration and liquefaction
Figure 1. Approximate breakdown of LNG project costs.
Figure 2. Simplified single-stage compression expansion refrigeration cycle. 42
February 2024
Refrigeration is integral to the natural gas liquefaction process. Refrigeration cools the feed gas by heat exchangers between the warm feed gas and colder refrigerants. To generate the cold temperatures required for LNG production, work must be put into the cycle through compression, and heat must be rejected from the cycle via a heat exchanger. There are different types of proprietary refrigeration processes (cycles); the most common include reverse Brayton, interlinked single refrigerant cycle, mixed refrigerant, single mixed refrigerant, and dual mixed refrigerant. The operator selects the licensed process during the design and development of the LNG facility. A typical refrigeration cycle is shown in Figure 2. Nitrogen is typically used as the refrigerant in the reverse Brayton process, but methane may also be used in this cycle. Propane, ethylene, or methane are the common choices of pure refrigerants. Mixed refrigerants are often a blend of hydrocarbons with nitrogen (Figure 3). The basic principle of using mixed refrigerants is to match as closely as possible the cooling/heating curves of the feed gas and the refrigerant, which results in a more efficient liquefaction process, requiring a lower power consumption per unit of LNG produced. Liquefaction is one of the most expensive parts of the LNG value chain, and the turbomachinery that supports liquefaction is process critical. Capital investment and OPEX are the areas over which LNG
operators have the most control, and they can optimise their development costs through process selection and capital equipment.
and water vapour. H2S may also be present. Materials need to be selected to resist corrosion from acid gases H2S and wet CO2.
Compressors for LNG applications
Flash gas compressor/off gas compressor
Natural gas processing compression applications
Raw natural gas varies in composition and contains contaminants such as water, carbon dioxide (CO2), and hydrogen sulfide (H2S). Processing removes the contaminants and adjusts the composition to meet specifications. If the gas is not transported via pipeline, it is typically liquefied for easy transportation and storage. Processing and the liquefaction process, as well as storage of natural gas, requires compressors. These compression services require different design features specific to the compressed fluid and operating conditions. Whether raw gas is delivered to a pipeline or liquefied for transport or storage, some processing is required. Some common applications for compressors in a gas processing plant are shown in Figure 4.
Feed gas or booster compressor
If the pressure in the gas reservoir or pipeline is too low to pass through the processing plant, a feed gas or booster compressor is used to increase the pressure. Raw gas composition can vary greatly. Major constituents would be 68 – 99% methane, 0.2 – 14% ethane, 0 – 9% propane and butane, 0.5 – 18% nitrogen, 0.1 – 2% CO2,
The first processing step is to remove liquid oil and water from the raw gas. Gas is ‘flashed’ from a hydrocarbon liquid when the liquid flows from a higher pressure to a lower pressure separator or to a stabiliser column where the light ends (methane, ethane, some propane, and butane) are removed. The gas from the column overhead is compressed and returned to the feed stream. Flash gas compressors typically handle low flow rates and produce high compression ratios. These may be reciprocating, screw-type, or barrel-type centrifugal compressors. For centrifugal compressors, the variable mole weight of the feed gas and variable flow rates require variable speed control and/or a need to recycle flow around the unit.
Regeneration gas compressor
The next step is ‘sweetening’ or the removal of acid gases, followed by dehydration. The acid gases are removed by either amine treatment (scrubbing) or membrane separation. The membrane process may require gas recompression due to large pressure drops. A solid desiccant dehydrator or molecular sieve typically uses a slipstream of the dried gas to drive off the adsorbed water and regenerate the desiccant. This may be a small, barrel-type centrifugal compressor or a single-stage, integrally geared design.
CO2 injection compressor
CO2 removed from natural gas can be reinjected into the well for enhanced oil recovery (EOR) or enhanced gas recovery (EGR), as well as carbon capture and storage (CCS). The elevated injection pressure is governed by the reservoir formation pressure and depth of the well, and can be 2500 psi or more. These pressures can be achieved with integrally geared compressors or barrel-type centrifugals, or a compressor in series with a dense-phase.
Turboexpander
Turboexpanders are used along with a low temperature distillation column (demethaniser) to remove heavier hydrocarbons from the gas. More than 90% of the propane and 80% of the ethane can be removed in this manner.
Lean gas compressor
Lean gas compressors raise the pipeline quality natural gas pressure to a level suitable for the liquefaction plant.
Liquefaction plant compression applications A general view of a liquefaction plant and LNG tanker with common compressor applications is shown in Figure 5.
Refrigeration compressors
Different proprietary processes use different gases for refrigeration. Propane, ethylene, methane, nitrogen, and mixed refrigerants are common.
End flash gas compressor
Figure 3. Simplified precooled MR refrigeration process for natural gas liquefaction.
End flash gas compressors compress the lowpressure vapour that comes off the vapour liquid separator at the end of the liquefaction process. This gas is used as fuel gas for the plant. The compressor inlet temperature will be near -157˚C (-250˚F), so low temperature materials and design considerations are needed.
Boil-off gas compressors
Boil-off gas (BOG) compressors compress the low-pressure vapour that comes off the LNG storage tanks. This gas is also used as fuel gas for plant consumption. Some ships also burn BOG from the cargo tanks as fuel for their engines, or recompress and reliquefy the gas. Like the end flash gas compressors, boil-off compressors have a low inlet temperature and require special materials and designs.
Fuel gas compressors
Fuel gas compressors raise the pressure of the supply line to the fuel inlet pressure required for plant consumption.
Figure 4. Gas processing plant.
Figure 5. Liquefaction plant compressors. 44
February 2024
LNG compressor technologies
Regardless of the driver, each compressor is designed to attain the best performance in terms of efficiency, reliability, and dependability. In addition to performance requirements, these design elements and components must be considered when selecting the compressor. z Aerodynamic components: The selection of aerodynamic components is based on specific performance requirements. Compressor configuration (straight through, side-load, iso-cooled, etc.) is determined by the process. Operating speed, off-design running conditions, and dynamic behaviour should also be considered.
z Shaft support configuration: The main shaft support elements are oil lubricated, tilting pad journal bearings. Labyrinth-style seals made of aluminium or polymer material are installed between each stage to minimise parasitic leakage. Self-equalising tilting pad thrust bearings are used to absorb excess axial loading. z Shaft end seals: Dry gas seals are used in newer compressors. Separation seals keep the lubricating oil away from the gas seal cavity. They can be labyrinth or carbon ring type seals. Buffer gas systems condition the process gas as the main seal gas and inert gas for the separation seals. z Thrust equalising mechanism: Balance pistons are used to overcome the axial load. The chamber behind the balance piston is normally equalised back to the inlet of the compressor. z Construction materials: Design considerations for compressor casings and components must include material ductility and yield strength at low temperatures.
Summary
The compressor value solution for LNG liquefaction is determined by operational and market realities that affect plant size and LNG train arrangements. Original equipment manufacturers (OEMs) provide customised solutions that balance range, efficiency, price, and experience in accordance with the customer’s requirements. Technology also plays an important role. Improvements in aerodynamic technology have led to the development of high-flow staging that pushes well beyond previous flow coefficients. New staging that achieves modest efficiency gains with significant space reduction has also been developed, enabling use of smaller compressors with better results. In some cases, a single compressor body can be offered where two were required before. In other cases, parallel compressor arrangements are required for greater operational flexibility. These technology improvements are the result of ongoing development by OEMs and process licensors, adding up to significant gains over time.
Note This article is based on a tutorial that Elliott Group gave at the 2023 Turbomachinery Symposium: Turbomachinery in
Liquified Natural Gas Production Plants. The other authors are: Klaus Brun, Director R&D; Marybeth McBain, Product Line
z Control system, condition monitoring and safe operation: Bearing temperature monitoring, vibration monitoring, and an anti-surge system are typically supplied.
Manager; Todd Omatick, New Product Introduction Manager; Brian Setzenfand, Senior Manager, Corporate Strategic Planning; Enver Karakas, Fellow Engineer; and Sterling Scavo-Fulk, Compressor Development Engineer, Elliott Group.
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With government policy and financial incentives in place, LNG has a key role to play in the energy transition but societal engagement is essential, says Sebastien Le Moigne, Global Gas Solutions Manager, ABS.
L
NG has emerged as a transformative force in the global energy landscape, offering a cleaner and more sustainable alternative to conventional fossil fuels. A White Paper produced by ABS delves into the LNG value chain and explores the upstream processes
of exploration, production, and processing.1 Furthermore, it addresses the new trends and innovations that have revolutionised the industry. The midstream sector — encompassing liquefaction, transportation via pipelines, specialised LNG carriers and
small scale LNG distribution — plays a crucial role in ensuring the efficient and reliable movement of LNG from production centres to end-users across the globe. Downstream operations, including storage, regasification, and distribution, facilitate the utilisation of LNG in
47
various sectors such as power generation, heating, chemical plants, and gas-to-liquid (GTL) conversion. In the White Paper, ABS also discusses the environmental aspects, regulatory frameworks and efforts to eliminate or mitigate methane emissions, thereby reducing the industry’s environmental impact. Additionally, the market realities, with a growing LNG carrier fleet, expanding orderbook and contracts shaping the market, are also analysed. ABS also considers the societal perspective and acknowledges how the LNG value chain influences livelihoods and economies worldwide. As the report navigates this ever-evolving industry, exploring new technology trends and the ‘grey/blue/green’ categorisation of LNG, it aims to shed light on the significance of LNG as a vital pillar of the global energy transition.
Understanding the colours of LNG
Blue LNG refers to conventional LNG produced using the traditional method of extracting natural gas from underground reserves, liquefying it and transporting it via LNG carriers. In this context, the term ‘blue’ represents the efforts to reduce or offset carbon emissions through carbon capture and storage (CCS) technologies. These technologies capture the carbon dioxide (CO2) emissions generated during the LNG production process and store them in geological formations deep underground, preventing them from being released into the atmosphere. By doing so, blue LNG aims to reduce the overall carbon footprint and environmental impact associated with traditional fossil fuel-based LNG production and transportation. However, the environmental impact of blue LNG is still a point of concern as it involves the release of CO2 and other greenhouse gases (GHG) during the extraction and liquefaction processes. The term ‘green’ is often used to symbolise environmentally-friendly or sustainable practices. In the context of LNG, green LNG refers to LNG that has been produced using low-carbon or zero-carbon sources. This might include LNG derived from renewable energy sources like biomethane or synthetic methane (e-methane) produced using a low emission hydrogen and carbon component from CCS technologies. Green LNG is seen as a cleaner alternative to traditional LNG as it has a reduced carbon footprint. Grey LNG is not a type of LNG with environmental benefits. Instead, it refers to conventional LNG produced from fossil fuels without any efforts to reduce GHG emissions or carbon footprint. Grey LNG is the most polluting and environmentally detrimental type as it releases significant amounts of CO2 and other GHGs during its entire production and transportation process. For this reason, it lacks the efforts towards sustainability and emission reduction found in green LNG options which prioritise renewable and low-carbon sources. It also lacks efforts found in conventional blue LNG which often implements CCS technologies to mitigate environmental impact. It is important to note that the specific meanings associated with colours in the LNG industry may vary depending on industry practices, regulations, or specific initiatives. Green and blue LNG are terms often used to describe more environmentally-friendly options in the LNG industry. However, there are several potential regulatory incentives for using green or blue LNG.
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January 2024
Regulatory incentives
The EU has been actively promoting the use of cleaner and more sustainable energy sources, including LNG. It has implemented regulations and initiatives such as the European Green Deal and the EU Gas Market Directive which is aimed at decarbonising the energy sector and reducing GHG emissions. These policies provide incentives and support for the development and utilisation of blue and green LNG, encouraging investments and regulatory backing for environmentally-friendly projects. In the US, regulatory incentives for blue and green LNG vary at federal, state, and local levels. While the federal government provides oversight and regulations for LNG exports, states like California have implemented policies and incentives to promote cleaner and lower-carbon energy sources. Additionally, incentives such as tax credits and grants for clean energy projects may indirectly support blue and green LNG development. Given Japan’s heavy reliance on imported LNG, there is a strong incentive to promote the use of cleaner and more sustainable LNG. The Japanese government has implemented various policies and regulations to support green and blue LNG, including financial incentives and subsidies for low-carbon projects. Japanese institutions like the Japanese Bank for International Cooperation (JBIC) and Nippon Export and Investment Insurance also play a significant role in providing financial support to LNG projects.
Financial incentives
Financial institutions are increasingly interested in supporting environmentally sustainable projects, including green and blue LNG. They provide financial incentives in the form of green bonds, green loans, or sustainability-linked loans. These financial products offer favourable terms, lower interest rates, or longer repayment periods to projects that meet specific environmental criteria, encouraging the development of green and blue infrastructure. Development banks like the World Bank, European Bank for Reconstruction and Development, and Asian Development Bank, actively support sustainable energy projects, including blue and green LNG. They provide funding, grants or guarantees to mitigate risks and incentivise investments in environmentally-friendly initiatives. Export Credit Agencies, such as the Export-Import Bank of China (China Exim) and JBIC, can provide financial support to LNG projects. They offer loans, credit guarantees and insurance to mitigate financial risks and promote investment in clean energy projects.
The societal perspective
LNG projects have the potential to significantly impact — both positively and negatively — livelihoods in communities where they are located. The impact can vary depending on the type of LNG project and its approach to environmental and social responsibility. The development of green and blue LNG, which prioritise reduced emissions and sustainable practices, can have several positive effects on livelihoods. Green LNG produced from renewable energy sources such as solar, wind, or hydropower significantly reduces greenhouse gas emissions compared to conventional LNG. The impact of green LNG on livelihoods can be beneficial in several ways. The development and operation of green LNG projects can create employment opportunities for local communities.
This includes jobs in renewable energy infrastructure such as solar or wind farms, as well as in the LNG production and supply chain. These job opportunities can contribute to the economic development and prosperity of the communities. Green LNG projects promote sustainable economic growth by supporting the transition to a low-carbon economy. By embracing renewable energy sources, these projects contribute to energy diversification, reduce dependence on fossil fuels and foster the growth of sustainable industries. This can lead to long-term economic stability and improved livelihoods for local communities. Green LNG projects help mitigate climate change by reducing carbon emissions. This has positive implications for the environment and the health of communities. The improved air quality and reduced environmental pollution associated with green LNG can have direct benefits on the health and well-being of individuals, thereby positively impacting their livelihoods. Blue LNG refers to LNG produced from conventional natural gas sources, with CCS or carbon offset measures to mitigate emissions. While blue LNG may not have the same level of immediate environmental benefits as green LNG, it still offers potential positive impacts on livelihoods. Blue LNG projects require skilled labour and expertise in natural gas extraction, processing and CCS technologies. This can create employment opportunities in the local communities, providing income and livelihood support for individuals and their families.
Blue LNG projects contribute to the availability of clean and affordable energy sources. This can improve access to reliable electricity and clean cooking fuels in remote and underserved areas, enhancing the quality of life and economic opportunities for communities. The establishment of blue LNG projects often involves the development of infrastructure such as pipelines, LNG terminals, and storage facilities. This infrastructure can facilitate economic development, attract investments, and provide opportunities for local businesses and services, thereby positively impacting livelihoods. It is important to note that while green and blue LNG projects have the potential for positive impacts on livelihoods, there should also be a focus on addressing potential negative effects. This includes ensuring that proper safeguards are in place to protect the environment, local communities and biodiversity.
Conclusion
It is crucial to engage with stakeholders and local communities in the planning and implementation of LNG projects to ensure their voices are heard and their concerns addressed. This collaborative approach can help maximise the positive impacts of LNG on livelihoods and create a sustainable and inclusive energy future.
References 1.
‘Examining the LNG Value Chain’, ABS, (September 2023), http://www.eagle.org/LNGValueChain
The
Hilko den Hollander, Industry Product Manager, KROHNE, the Netherlands, highlights advancements in dynamic metering systems for LNG and natural gas.
development
of DYNAMIC METERING SYSTEMS _____ 50
I
n recent years, the LNG and natural gas industry has navigated through a dynamic landscape marked by fluctuating prices, heightened awareness of carbon dioxide (CO2) emissions, and the increasing significance of hydrogen as a potential future energy carrier. Amidst these challenges, accurate measurement has emerged as a linchpin for operational success. This article delves into the intricate details of dynamic measurement systems, particularly focusing on the role of LNG flow meters, shedding light on the underlying technologies, and emphasising the substantial benefits these systems bring to the forefront.
Flowmeters at the core of metering systems The crux of any modern metering system lies in its flowmeters. For LNG and natural gas applications, ultrasonic or Coriolis
51
flowmeters are predominant, with turbine flowmeters finding their place in natural gas measurement. What sets ultrasonic and Coriolis flowmeters apart is their capability to maintain measurement accuracy independently of the medium being measured, making them the preferred choices in dynamic metering systems.
Ultrasonic flowmeter principle
Ultrasonic flowmeters operate on the transit time principle, calculating the flow velocity of the liquid or gas within the meter. One notable feature is the independence of the flow velocity calculation from the speed of sound in the medium inside the meter (Figure 1). This characteristic allows for consistent accuracy even when the velocity of sound differs during calibration and operation. It is important to note that this holds true for inline flowmeters with ‘wetted’ transducers, while clamp-on flowmeters necessitate manual entry of the velocity of sound.
Reynolds-based flow calibration
Figure 1. Transit time principle.
Figure 2. Turbulent (green) and laminar (red) flow profile.
Figure 3. Coriolis principle.
The next step in the process involves converting flow velocity into flow rate, a critical aspect where the flow profile comes into play. Figure 2 exemplifies how flow inside a pipeline exhibits varying velocities, with the highest flow in the centre and the lowest near the pipe wall due to wall friction. The Reynolds number determines the ‘pointiness’ of the flow. Given the unavailability of large scale LNG calibration, flowmeters are typically calibrated on water, leveraging the Reynolds principle. By selecting a clever calibration flow velocity, such as a 1 m/sec. flow of 0.2 cSt LNG, mirroring the flow profile of a 1 cSt water flow at 5 m/sec., calibration accuracy is maintained. Figure 2 demonstrates how an ultrasonic flowmeter, equipped with five chordal paths, detects the flow profile inside the meter. This Reynolds-based calibration principle is fully NMi-approved and has been validated by calibrating a small diameter five-path ultrasonic flowmeter on the VSL LNG calibration facility. It is worth noting that multipath clamp-on flowmeters cannot utilise this flow profile detection mechanism due to all acoustic paths passing through the centre of the pipe, providing insufficient information about off-centre flows. A final correction factor addresses body expansion/contraction resulting from differences in pressure and temperature between calibration and actual service. With well-known material properties and formulas, the contribution to overall measurement uncertainty is minimal.
Coriolis measurement principle
Figure 4. Custody transfer metering system for the LNG process. Source: Bahía Bizkaia Gas. 52
February 2024
Coriolis flowmeters operate based on Coriolis forces generated in oscillating systems when a liquid or gas moves toward or away from the axis of oscillation. The symmetrical design comprises one or more measuring tubes, straight or curved. The driver induces a uniform fundamental oscillation mode in the measuring tube(s). At zero flow velocity, the Coriolis force is nil, but in flowing conditions, the fluid’s acceleration and deceleration generate the Coriolis force, proportional to the mass flow rate. This force causes a slight distortion in the measuring tube, superimposed on the fundamental component and directly proportional to the mass flow rate. Sensors detect this distortion. Continuous measurement of temperature is essential, as the
oscillatory characteristics of the measuring tube depend on it. Additionally, Coriolis flowmeters directly measure density by tracking the resonance frequency of the measuring tubes, following Hooke’s law. Lower-density fluids exhibit higher resonance frequencies, providing a direct indication of density differences.
LNG meters in situ
The measurement of LNG at extreme conditions, such as -170˚C and up to 186 tph accuracy and accounting for the resulting boil-off gas (BOG), poses unique challenges. To address these challenges, BBG collaborated with KROHNE to develop a certified cryogenic custody transfer system under the EU Measuring Instruments Directive 2014/32/EU to MID-005 (measuring systems for liquids other than water) with full ATEX hazardous area approval. Central to this system are KROHNE’s twin bent tube 316L stainless steel OPTIMASS 6400 high-capacity Coriolis flowmeters with a minimum allowable operating temperature of -200˚C. Two DN200 flowmeters are installed in series on the LNG line, serving as the duty measurement flowmeter and master meter to ensure accuracy. The entrained gas management function of the flowmeters is employed to control the transfer process, identifying the presence of BOG during start-up. A dedicated OPTIMASS 6400 DN100 flowmeter certified to MI-002 (gas meters) accurately measures BOG on a bypass line routed to a reliquefication unit, returning it into the system as LNG.
Water-based flow calibration for Coriolis meters
Coriolis meters undergo wet calibration at the factory using water, eliminating the need for calibrations using a fluid similar to the final application, even for cryogenic fluids. This industry-accepted method ensures calibration accuracy, with large new mass flow calibration rigs accredited by UKAS, the UK’s metrology agency, to an uncertainty of less than 0.017%.
Metering system design
A comprehensive metering system typically comprises multiple meter runs, allowing for accurate measurement of low flows by directing all flow through one meter run. This approach facilitates the isolation of a meter run for repair or inspection while ensuring uninterrupted flow measurement through the other runs. In natural gas and LNG, one of the meter runs is often designated as the master meter run. The primary objective is to utilise the master meter for periodic verification of duty meters, ensuring any potential contamination in the duty meters manifests as a difference from the master meter, which is only used periodically. Figures 5 and 6 illustrate a concept with three duty meters and one master meter, emphasising the periodic verification process.
Flowmeters for high accuracy measurement
For achieving high accuracy in the measurement of natural gas and LNG, custody transfer ultrasonic and
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Coriolis meters are the preferred choices. It is crucial to install ultrasonic meters with sufficient inlet piping in order to eliminate measurement errors resulting from installation effects. In cases where space is limited, flow conditioners can be considered for natural gas applications to optimise the flow profile.
Analyser house and flow computer cabinets
Larger metering systems are typically equipped with an analyser house housing instrumentation, such as
gas chromatographs, dew point, sulfur, mercury, density, and trace oxygen analysers. The analysis of gas or LNG samples is contingent on the sample lines’ representative nature, emphasising the importance of the take-off probe’s location and design, sample line routing, and sample conditioning system. These factors play a crucial role in minimising lag times and maintaining the sample’s properties. The exact volume and calorific value calculations are executed by a flow computer, often requiring third-party certification from entities such as NMi or PTB to guarantee accuracy. Integrated into flow computer cabinets alongside the supervisory computer, uninterruptable power supply, and programmable logic controller, the flow computer allows operators to control the metering system from the supervisory screen in the control room.
Alternative for LNG sampling
Figure 5. Schematic overview of the metering system with three duty and one master meter run.
Traditionally, LNG quality readings have been reliant on laboratory analysis of samples obtained during the loading process. However, this approach poses challenges, including manual handling of cryogenic sample cans and delays in obtaining quality certification after the ship has left. To overcome these issues, KROHNE developed a solution to measure LNG quality directly during loading. The LNG-Quality Release System (L-QRS) ensures immediate availability of a certificate of quality and bill of lading upon completion of loading. This capability mitigates costly disputes post-departure and eliminates human errors in data processing, as the information flows are fully automated.
Based upon certified statistical calculations
Figure 6. Metering system with three duty and a master meter run.
Figure 7. Analyser house (left) and flow computer cabinet (right). 54
February 2024
KROHNE’s L-QRS represents progress in quality measurement, offering a real-time product release of LNG loading through online measurements and certified statistical calculations. Samples are fed directly into a gas chromatograph during the loading process. The system combines analyser management and data acquisition (AMADAS) functionality, leveraging control charting techniques and statistical process control to ascertain the performance, availability, and maintainability of the process analysers, ensuring optimal results.
Certified by NMi, an independent and internationally accredited metrology institute, the L-QRS is compliant with ISO 8943, GPA 2172, ASTM 4784, and GIIGNL. Additional standards can be incorporated upon request. The integration of CalSys, the AMADAS of KROHNE, results in a 25% reduction in maintenance costs, with critical instruments achieving an availability rate exceeding 95%. The structured and consistent validation of analysers and instruments ensures traceability and auditability, with L-QRS data securely stored and fully auditable, coupled with the certified calculation.
Case study: Australia
To illustrate the practical application of these advancements, consider a natural gas hub in Australia with a production capacity of 8.9 million tpy of LNG. Faced with the need for live information on gas quality and quantity, the operator initially relied on traditional offline laboratory analysis combined with dynamic flow measurement. Implementing the L-QRS solution revolutionised the operations, providing instant availability of the bill-of-lading and quality certificates. The L-QRS software seamlessly integrated with existing infrastructure, including gas chromatographs, running on a SUMMIT 8800 Custody Transfer flow computer, with the operator interface integrated into the central HMI. Beyond the immediate benefits of real-time certification, the system offered trend insight, alarm management,
and integration with plant management and control systems (DCS, PI, LIMS, ERP, etc.).
Conclusion
In conclusion, the development of dynamic metering systems has brought about enhanced precision and efficiency for the LNG and natural gas sector. The integration of advanced flow measurement technologies, such as ultrasonic and Coriolis flowmeters, coupled with innovative solutions like the L-QRS, not only ensures unparalleled accuracy but also contributes significantly to the overall efficiency and competitiveness of the industry. As the global demand for LNG continues its upward trajectory, effective management by suppliers becomes crucial for maximising competitiveness and profits. Given the potential cost implications of product giveaways to compensate for problems, KROHNE’s L-QRS system is positioned not only as a technological advancement but as a strategic investment that can potentially pay for itself by avoiding LNG-quality disputes. The adoption of state-of-the-art metering systems becomes imperative for maximising profitability and meeting contractual obligations. By embracing these technological advancements, industry players can navigate the complex landscape with confidence, ensuring not only compliance with regulatory standards but also establishing themselves as leaders in the evolving LNG and natural gas sector.
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