Conference agenda

New thinking will be needed on the role of natural gas as an abated bridging fuel, the speed of development surrounding a broader mix of next generation energy sources and adapting new approaches to developing infrastructure to accelerate energy efficiency. How are the energy policymakers responding to the energy supply situation in Europe and globally? What are their views on the short to long term priorities in keeping consumer price points down in the short term, improving energy security in the medium term and reducing carbon emissions in the long term?

Here in Europe could the extreme energy market volatility we have witnessed have ‘positive’ collateral effects on the European Green Deal (carbon neutrality by 2050 and the reduction of carbon emissions by 55% by 2030)?

Audience insights: Understand the priorities of global policy leaders views on the current energy crisis as a lever for increased development of a broader portfolio of next generation energy solutions and infrastructure capabilities allowing for multiple sources of LNG much less reliant on hydrocarbons.

Shri Hardeep Singh Puri

Honourable Minister of Petroleum and Natural Gas & Housing and Urban Affairs

Government of India

His Excellency Tarek El Molla

Minister of Petroleum and Mineral Resources

Egypt

The paper examines the impact of current and future regulatory developments related to Green House Gas (GHG) emissions reduction on the design and operation of a newbuild Liquefied Natural Gas carrier (LNGC). The study further investigates technical and financial feasibility of various options that can be considered for a vessel’s compliance with these regulations ensuring longevity of its operation.

Increasingly stringent regulations on GHG emissions reduction are being adopted by the International Maritime Organisation (IMO) and European Union (EU). The paper explores how, measures such as Energy Efficiency Design Index (EEDI), Carbon Intensity Indicator (CII), extension of EU-ETS to maritime shipping, Fuel-EU maritime regulations and possible future restrictions on methane emissions would impact the design and arrangements of an LNGC design. A 174,000 cbm LNGC with slow speed dual fuel engines is considered as the case vessel and the impact on Main Engine, Boil-off gas management, Air Lubrication System and Shaft Generator were evaluated in the initial phase.

Shipbuilders, shipowners, and charterers are facing the challenge of aligning vessel design for compliance with these requirements. This has prompted measures such as installation of various energy saving devices, optimisation of equipment & components, and proposals for incorporation of technologies for methane emission reduction, onboard carbon capture & storage to vessel design. The study explores these further by focusing on technology readiness, effectiveness of installations towards compliance with regulations and impact on operational aspects. An assessment criteria that includes GHG reduction potential, technology maturity, safety, ease of operation and shipboard installation feasibility was developed to evaluate these technologies.

The financial segment of the paper quantifies the economic benefits of these design considerations in terms of the vessel’s CAPEX and OPEX. A select group of installations and vessel operation on a specific number of routes were considered in this analysis. It is recognised that the installation of energy saving devices and other technologies increases the CAPEX. It was examined whether a corresponding reduction in OPEX, taking also into account of the EU-ETS requirements, was achievable. The financial model considers all of the above and puts into perspective the economic impact of these installations.

Overall, the foreseeable impact on LNGC design and operation due to EEDI, CII, EU-ETS and Fuel-EU maritime regulations were found to be significant. Further, a structured method that can be considered for evaluating the suitability of various technologies into LNGC design was developed. Also, the financial analysis provides an overview of the potential economic impact of the design developments. Essentially, in order for ensuring continued compliance with the evolving GHG reduction regulations, the LNG carriers should be designed to be as efficient as possible at newbuild phase. Careful assessment of various factors should be undertaken prior to choosing the installations for improving technical and operational efficiency. In addition, vessel designs should incorporate a level of flexibility towards integrating newer systems as retrofit installations over the course of its operation. All of this is key in assuring longevity of LNG carriers as we move into the age of decarbonisation.

Sobhith Komalavally Hariharan

Global Shipowner's Newbuild Support Manager and Gas Technology Specialist

Lloyd’s Register

IIn a world striving to balance continuous economic growth with reduction of Green House Gas emissions, LNG is a realistic and reliable energy solution for mitigating CO2 emission. However, the energy loss within the LNG supply chain has been an issue. As the cold energy of LNG is wasted on the conventional LNG regasification system, it is necessary to develop a technology to increase the efficiency of the NG supply chain and thereby reduce the fuel gas usage and the environmental impact.

DSME and MOL have jointly developed a new LNG regasification technology named "Cryo-Powered Regas". It can utilize the LNG cold energy, which used to be disposed, as power generation energy by adopting the Organic Rankine Cycle(ORC) in the regasification process of FSRU. Consequently this technology is expected to reduce fuel consumption and environmental emission of FSRU significantly. Moreover, for the sake of maximizing FSRU asset value, tradability as LNG carrier was also considered. So far FSRU has applied main engine as DFDE to produce required electricity for regasification however due to large size of it, its performance was not so efficient that consumes more fuel.

By applying CPR, DSME & MOL succeeded to save fuel by optimizing DFDE size & configuration for electricity generation for regasification that saves more fuel by 2-stroke main engine application for CPR FSRU. As a result of that, DSME & MOL can provide CPR FSRU that can enjoy fuel saving benefits not only at FSRU mode but also at LNG carrier mode. A pilot-facility of the "Cryo-Powered Regas" system was built in DSME's R&D premises. Through this test, MOL and DSME verified that the system could successfully generate electricity up to its rated capacity. The result show that the performance of CPR pilot plant was consistent with the theoretical expectation within error bounds.

Consequently, the verification was completed through a pilot scale test prior to applying the technology to the commercial project, and the lessons learned through operating the experimental facility were reflected in the standard design.

DuHyeon Cho

Principal Research Engineer

Daewoo Shipbuilding & Marine Engineering Co.,Ltd

Ever since the original version in 1976, the IGC Code has limited cargo tank filling levels to 98%. However, if the tank shape and pressure relief valve arrangements were suitable, Administrations could increase this limit. The 2016 edition of the Code is more specific. Administrations are permitted to increase cargo tank filling limits up to 99.5% - provided that no “isolated vapor pockets” (IVPs) can form at 15° list and 0.015L trim conditions (see 15.4 and 8.2.17). Under emergency conditions, if a loaded gas carrier has an extended time at these list and/or trim conditions, IVPs could form whereby cargo vapor could be trapped and separated by cargo liquid from the pressure relief valves and/or other vapor piping. Under these conditions, the cargo will heat up, and the liquid will expand, thus reducing the vapor space available and increasing the pressure in the IVPs.

As the relief valves cannot relieve the vapor pressure in such circumstances, cargo liquid will back up in the vapor lines or vent mast and could spill onto the deck. This is the reason the 2016 IGC Code requires that Administrations must ensure that no IVPs are formed at the stated list and trim conditions before they can permit filling levels above 98%. Previously, vessels have been permitted increased filling limits without having to prove that IVPs will not form, but under the revised 2016 Code, owner/operators have a few choices. They can choose to fill to the 98% limit, fill to the level at which IVPs begin to form - even if this is suboptimal, modify the arrangement to eliminate IVP formation, or ask their Flag Administration to grant an equivalency. Surprisingly, very little has been written about the IVP formation risk and appropriate mitigation.

This has led to different Administrations permitting widely varied filling limits, even on identical ship designs. The interpretation issue affects a wide range of ships, notably fully-refrigerated LPGCs and membrane-type LNGCs. To clarify this unfortunate situation, information must be provided about the likelihood of IVP formation, critical time after formation, possible outcomes, and mitigation strategies. In the USA, the National Chemical Transportation Safety Advisory Committee (NCTSAC) has been discussing these issues.

In this paper, the authors, who are members of the NCTSAC working group, will give an update on the discussions to date and the possibility that some clarifications will be proposed at IMO CCC to amend the current text to provide greater clarity and ensure that all Administrations are applying the same standards.

Cynthia Woodlock

Lead Chemical Engineer

United States Coast Guard

Decarbonisation currently affects shipping, and will shape the course of the industry for generations to come. The industry has to decide how to best address the upcoming regulations; these decisions will include new technologies, switch to new fuel sources, and/or change operational methods. Shipowners/operators have serious concerns, but some key stakeholders see huge opportunities to transform our maritime industry to environmental sustainability, through zero emission vessels, for international shipping.

MEPC 76 adopted new requirements for EEXI, CII, and enhanced SEEMP effective from January 2023. The EEXI requirement is a technical measure for existing ships similar to the EEDI requirements for newbuilds, whereas the new CII requirement is an operational measure that will get stricter each year from 2023 to 2030 ensuring international shipping follow the decarbonization strategy adopted by IMO.

This is a major step forward in reducing the carbon intensity and eventually fully decarbonize shipping. However, the question remains, what does future shipping looking like and what challenges should be expected? This paper is going to look at the advantages and disadvantages of two potential fuel sources, hydrogen and ammonia; the ways a flag State meets its regulatory obligations to ensuring safe use and transportation of these environmentally friendly fuels. Hydrogen is an attractive fuel source due to its cleanliness. Hydrogen is normally stored and transported as a liquid, where it is reduced to 1/800th of its volume as a gas. As fuel, hydrogen does not release any CO2, and liquefied hydrogen can be used to charge batteries for electrical propulsion via fuel cell technology. The main issue with hydrogen is storage space, liquid hydrogen is about four times larger by volume than conventional diesel, which presents a challenge when considering ship fuel capacity and endurance.

Ammonia is twice as energy-rich as liquid hydrogen by weight, has fewer storage issues than hydrogen as it can be stored at ambient temperature under a pressure of 10bar or refrigerated to minus 34°C without pressure. However, it has less than half the energy density of HFO. Another disadvantage is that when combusted, the nitrogen present will produce NOx, itself a GHG. Moreover, it is extremely toxic even at relatively low levels, care is needed in containment systems and ammonia could pose problems for crew and salvors in a damaged situation.

For flag States to approve the use of liquified hydrogen or ammonia as fuel the IGF Code will generally be applied. The IGF Code does not include requirements for the use of liquified hydrogen and ammonia as fuels, however the concept with goals and functional requirements should be applied, often including risk assessments.

Thomas Klenum

Executive Vice President of Innovation and Regulatory Affairs

The Liberian Registry

China has become the largest LNG importer in the world and it has the strongest LNG demand growth in the world in the past four years, up from 38 MMt/y in 2017 to 80 MMt/y in 2021. The increasing energy demand, environmental concerns (e.g. to meet government’s “3060” target) and relatively slow growth from domestic gas production and pipeline gas imports continue to drive up the LNG demand in China.

To meet the LNG demand growth, Chinese players have signed more than 50 MMt/y medium- to long-term contracts commencing by 2020. In 2021, Chinese buyers continue to procure LNG aggressively and signed a total of over 25 MMt/y SPAs, mainly from Qatar, the US and Russia. Especially the second-tier buyers have been actively procuring LNG since 2018, including ENN, Zhejiang Energy, Guanghui Energy, Huaying, etc. With equity LNG from LNG Canada, Arctic LNG 2 and Rovuma LNG, total contracted volume will reach 60 MMt/y by 2025. In addition, many other second-tier buyers are still in negotiation or plan to procure LNG.

There are concerns in the market whether China will continue to see strong growth in LNG demand through to 2025 or 2030. If not, then what will be the impact on Asian LNG market? During 2018-2021, the central government has made several announcements to guide the overall gas market development as well as set the carbon neutral target for 2060. It is crucial to understand how these announcements might affect the overall gas and LNG market in China. In addition, the ramp-up supply of Russia-China pipeline gas import and additional pipeline gas deal are going to bring more uncertainties into the LNG market.

The key purpose of this paper is to discuss prospects of gas market evolution in China, highlighting the opportunities and challenges for LNG buyers and sellers in the market by 2025. It is structured as follows:

- Review the recent major market developments in China, especially the impact of the government’s “3060 target”

- Discuss the overall market outlook and highlight the key uncertainties by 2025

- Investigate where the key potentials for LNG demand growth are by 2025

- Examine the key challenges for LNG market growth in China, from three aspects

o Changes of macro market factors, e.g. economic growth, coal-to-gas policy.

o Changes of market structure, e.g. establishment of National Oil and Gas Pipeline Network Company and third-party access via other existing terminals

o Competition from alternative gas supply, e.g. Russia pipeline gas imports

- Prospects for second-tier LNG buyers competing with NOCs, long-term potential vs. short-term challenge

- Summarize the opportunities and challenges for a variety of LNG buyers in China and implication for suppliers who are targeting China by 2025

- Discuss the overall impact on the Asian LNG market

Ming Cai

LNG Consultant

Poten & Partners

Most of the Gulf states have limited gas resources but regulated gas prices in the region have fueled strong consumption. In the decade to 2019, gas consumption in the GCC states (ex-Bahrain) grew by an average of 5 percent per year. The Gulf states are prioritizing gas exploration and development to shore up supplies, but tight gas and sour gas developments in Oman, the United Arab Emirates (UAE) and Saudi Arabia have higher break-even costs and pose technical challenges for state oil companies. Abu Dhabi National Oil Company (ADNOC) is turning to unconventional gas, sour gas, and offshore gas cap projects in a quest to achieve gas self-sufficiency by 2030. Saudi Aramco has high hopes for the Jafurah Basin megaproject. Kuwait aims to develop its Jurassic gas resources, including some sour gas. And Qatar has embarked on its liquefied natural gas (LNG) mega-expansion and plans to raise its LNG export capacity to 110 million tons/year by 2025-26. These developments vary in complexity, but generally they will be expensive and technically challenging for state oil companies.

Satisfying gas demand in the electricity, household, and industrial sectors was already challenging for economies that are back on a strong growth trajectory. But the Gulf states now have competing priorities for gas. Over the longer term, Saudi Arabia, the UAE and potentially other GCC states are pursuing both blue and green hydrogen. They want to create market demand for hydrogen and ammonia exports and secure a first-mover advantage over other prospective suppliers.

This Gastech presentation will focus on difficult choices the GCC states will have to make on domestic gas use, especially in terms of reserving gas for hydrogen. Some points for discussion include:

• There is limited public information about the cost, difficulty, and technical challenges associated with gas developments like the Jafurah Basin project in Saudi Arabia or Jebel Ali in the UAE. Both will stretch the capacity of NOCs and local service sector companies.

• As Saudi Arabia focuses on satisfying domestic demand and providing gas for blue hydrogen, it may have to re-examine its gas export ambitions.

• Gas availability for blue hydrogen will depend on how quickly Saudi Arabia and the UAE can ramp up renewable energy generation. There is a significant risk that more gas than expected will have to be used in power generation.

• For now, ADNOC and Saudi Aramco are bullish on the prospects for hydrogen, but there is some risk in allocating gas to an export industry whose long-term economic viability is still in question.

Ben Cahill

Senior Fellow

Center for Strategic and International Studies

This paper looks at the developing global hydrogen-based fuel market and opportunities for the maritime sector both for fossil fuel substitution in its operations and for transporting alternative fuels. Hydrogen and hydrogen-based fuels are expected to become an essential part of the climate-neutral maritime fuel mix in the coming decades. But the scale and challenge to supply alternative fuels for the shipping sector to decarbonise is often underestimated. Electricity from renewable sources will need to increase to the equivalent of the current total wind and solar electricity generation of China, just to replace less than 10% of the global demand of shipping fuel. LNG and other net-zero fuels will play a role in the early and mid-term of the decarbonising transition for shipping to reduce its emissions and advance towards the net-zero by 2050 goal. In addition, maritime transport can play an important role to support both LNG trading and a global hydrogen market by transporting hydrogen-based energy carriers from production centres to demand centres as countries shift their priorities to enhance energy security.

More specifically, maritime transport can be a key enabler of a low-carbon future by supplying various customer groups worldwide with (net) zero carbon fuels. There is a clear understanding that (net) zero carbon fuels, including hydrogen-based fuels and biofuels, are needed to decarbonise all sectors including industry, transport, and heating/cooling, although the scale of investments required to supply alternative fuels will need to rise in orders of magnitude. For the maritime sector, a multi-fuel scenario is expected where gas will play a relevant role.

To meet the enormous, expected demand for (net) zero carbon fuels, especially in Europe, North America and Asia, other regions such as Latin America and Africa are expected to operate as supply centres as they would benefit from lower cost of production. Existing energy hubs in the Middle East and North Africa (MENA) region also have excellent export opportunities, which might allow these countries to transform themselves from fossil fuel sellers to (net) zero carbon fuel supply hubs. Trade of (net) zero carbon fuels from these supply hubs to different parts of the world could then be vastly enabled by maritime shipping.

A well-established global trade in (net) zero carbon fuels offers the prospect of lower costs for consumers, since trading enables access to low-cost production in other countries, thus resulting in optimal market prices. Furthermore, trading has benefits for the security of supply: in a mature market, trading facilitates access to multiple producers with substantial production capacity at comparable costs, i.e. (net) zero carbon fuel demand can be satisfied from various sources. Some regions are expected to become net importers, since the local production potential is limited, e. g. roughly half of Europe’s hydrogen demand will be imported by 2050. Similarly, global trading will affect half of the total ammonia production and one third of the total synthetic fuel production worldwide by 2050.

Nelson Mojarro

Head of Innovation and Partnerships

ICS

India is on the path to becoming the world’s fastest-growing economy. With growing energy access, economic development and anticipated population growth, energy demand is expected to increase multifold. The country is the third-largest energy consumer globally after US and China, and India’s energy requirements are primarily fulfilled by coal (~55%) and oil (~28%), with a minor share catered by natural gas (~6.7%) and renewable energy (~4.5%).

In line with the strategy of Energy Transition towards cleaner fuels, among different sources of energy, natural gas is set to play a predominant role in India’s energy basket in this decade. While focusing on the global philosophy of clean air and environmental objectives, India has laid down the blueprint of a gas-based economy, and the industries are working relentlessly towards the milestone.

Over the last five years, gas demand in India has seen a significant increase across various demand centres. Factors such as increased availability of gas, gas related infrastructure development and favourable price economics in a few sectors have helped in ~3% growth in natural gas consumption (from FY2015-16 to FY2020-21). In effect, LNG imports have witnessed a sharp rise of ~9% over the last five years (from FY2015-16 to FY2020-21).

The total gas consumption in January 2022 was 169 MMSCMD; out of which 92 MMSCMD was from domestic production and 77 MMSCMD, representing a significant component from LNG imports. As India aims to move towards a gas-based economy by increasing its share of gas from 6.7% to 15% energy mix by 2030, achieving the 15% target would imply a consumption target of ~500 MMSCMD by 2030.

This paper aims to provide a detailed insight into the outlook of Gas and LNG demand in the era of clean fuels from Indian perspective.

I. India aims to achieve ~15% share of natural gas (~ 500 MMSCMD) in the primary energy mix by 2030

II. Development of conventional sectors to drive the gas demand growth (~ 400- 430 MMSCMD)

· Power Sector · Fertilizer sector

· Refinery & petrochemical and

· City Gas Distribution (CGD) sectors

III. Additional gas demand creation from “New Avenues- Transitional Change” (~ 100 MMSCMD)

· Natural gas for Trigeneration

· LNG as a long haul and Marine Fuel

· Natural gas for balancing for renewable energy generation

· Natural gas as a sustainable energy source in small scale industries

This paper will particularly highlight the following points which will help to boost the Gas and LNG demand in the country:

• Increasing share of domestic gas & LNG through investor-friendly policies

• Gas-based infrastructure development across the country

• Policy/ Regulatory support for developing the gas market

• Climate change and India’s commitment in Glasgow Climate conference (COP 26)

To meet this ambitious consumption target of ~500 MMSCMD by 2030 and to create a truly mature gas market, India would require support in terms of Technology, Investment and Skilled development from the Global Gas community.

Tapas Kumar Sengupta

Director of Exploration and Production

Federation of Petroleum Industry (FIPI)

The demand for LNG is expected to increase due to a growing demand for global energy supplies and the need to address environmental concerns. At the same time, investments in LNG plants, have faced obstacles in recent years. The demand for early payouts has led to a reduction in initial investments.

Investors expect EPC contractors to complete projects faster, more cost effectively and more systematically. It is getting increasingly harder to fulfill all the requirements, only by following the current EPC project schemes. This could potentially jeopardize the plant engineering business as a whole as very high risks are taken on the client side. Yet there are various aspects of the entire design process that could offer valuable opportunities.

One of those solutions is to accurately estimate the amount of construction materials and work-volumes in the earlier project stage. “Auto-Routing System” with its “Data-Centric Engineering” is a critical part of the solution, and we believe it will be a major contributor to the project's success.

In Gastech 2020, Chiyoda Corporation introduced the Auto-Routing System which has the following three key features.

● Superfast Auto Routing

● Block Pattern Arrangement

● Easy 3D Plot Plan Layout

Subsequently, we found it can eliminate a huge amount of the initial 3D modelling steps. For example, this system has been proven to realize an 80% reduction of work volume for plant 3D engineering of basic design and at a speed up to 5 times faster than before. However, it's not enough to achieve full optimization of the entire engineering workflow, we need to incorporate all of the engineering activities.

The issue with the current engineering workflow includes multiple design data and complicated steps. For example, while PDF and drawing files are used to exchange data among different departments, the overall process remains an analog one that is prone to human error. There is a huge amount of rework in the creation of 3D models from 2D drawings. Each step is time-consuming and requires a human interface. The system is far from being fully digital.

Auto-Routing System and single database enables the creation of 3D models from the early design phase based on digital data rather than on 2D analog information. This is what we call “Data-Centric Engineering”, which will enable the following changes.

● Eliminating complicated multiple steps, the human interface.

● Engineers can focus on creative areas, such as layout case studies.

● Enables the creation of 3D models and precisely calculates the quantity of materials and construction work volumes.

Single engineering database concept with Auto-Routing System is enable to achieve full optimization of the entire engineering workflow and the Data-Centric Engineering. And this is a true technology revolution in a digital era. In this presentation, we will focus on:

● How seamless design work has become thanks to the data export feature

● How we approach the integration of engineering organization

● How we have improved the automated routing algorithms

Seitaro Narue

Chief Executive Officer

PlantStream Inc.

Plant engineering projects nowadays are required to accelerate their schedule and to reduce costs. At the same time, it is also a major challenge how to integrate digital technology with the accumulated senior engineer’s tacit knowledge so that it can add value to plant design and enhance customer satisfaction,

Plot plan design is one of the key areas of such challenges. Plot plan conveys a wide range of design parameters such as CAPEX, OPEX, safety, maintainability, and scalability. Its design process requires sophisticated technologies aspects such as piping and equipment design, process performance, HSE, and constructability evaluation, based on experiences and customer’s design prioritization.

For this purpose, JGC has developed a plot plan automated design system "Auto Plot PATHFINDERTM" to be used feasibility study, FEED and early EPC phases.

This epoch-making system combines the senior engineer’s tacit knowledge and multiple objective optimization technology. It can propose several arrangement patterns of equipment / units at very high speed, together with numerical scores of multiple evaluation axes such as piping volume, area efficiency, etc.

The system can save a considerable engineering time and enables us to compare multiple proposed plot plans. It will greatly contribute to customer satisfaction and project schedule reduction.

In this presentation, we outline "Auto Plot PATHFINDERTM" system with the following features.

(1) DSM(Design Structure Matrix) method has been used to derive and formulate the senior engineer’s equipment placement tacit knowledge with more than 250 steps.

(2) Preparation of several arrangement patterns for a plot plan, which usually needs half a month or one month, can be carried out in one day by using a multiple objective optimization method. (more than 1,000 proposals)

(3) Plot plan are presented visually with 6 evaluation axes (piping length, cable length, underground work volume, occupied area, maintainability and constructability) and expressing it on 3D model.

Hiroyuki Koito

Design Innovation Unit Leader

JGC

o Summary/Conclusions

Electro-intensive industries are under constant pressure to reduce total expenditures, optimize their operations and reduce their carbon footprint. Unifying energy and process automation data, and design is a catalyst for increased operational resilience, efficiency, sustainability, and responsible profitability across the full lifecycle of the operations.

o Background

The confluence of digital transformation and the constant pressure to improve sustainability, reduce CAPEX and OPEX, are driving an initiative to rethink the separation between process automation and power management. Electrification is forecasted to increase by two-fold in 2050 as more companies intensifying their decarbonization efforts. These increased electrical and power asset data should be integrated with process data to improve operational and maintenance performance. Some of the key technology enablers to be discussed include IIOT, Big Data Analytics, Digital Twin, Process Automation, Power Systems, Asset Management, Project Execution Strategies, Unified Simulation, Augmented Reality, Process and Energy Optimization, etc.

o Aims

Digital transformation should not be the goal but rather be the enabler to achieve the business objectives. In oil & gas, and petrochemical enterprises, the two most important digital elements are power management and process automation. This paper will present solutions that are available through the unification of these two historically separate disciplines and describe a logical path for digital transformation that applies eight key strategies.

o Methods

The eight Unified Power and Process Digital Transformation strategies are described below:

1. Unified engineering and asset data information.

2. Power and Process system design optimization.

3. Unified Power and Process simulation.

4. Unified project execution.

5. Power and process systems integration.

6. Integrated asset performance management.

7. Process energy optimization.

8. Value Chain Optimization.

o Results

The combined view and management of energy and automation can help to:

• Decrease Electrical Instrumentation and Control Engineering (EI&C) CAPEX by up to 20%

• Decrease the unplanned downtime by up to 15% with improved design, planning, scheduling, operation, and maintenance

• Improve process energy usage by up to 10%, reducing both energy cost and carbon intensity, and lower emissions through optimized energy and automation efficiency

• Improve the profitability by up to 3 EBITDA pts, with Uptime improvement / maintenance cost reduction and Value chain optimization

Use case:

An LNG producer suffered from multiple unplanned plant trips in a year, which resulted in significant production revenue loss of more than $10M. By digitally unifying their power and process information, they were able to reduce the number of unplanned outages by approximately 30% and shorten the investigation time by approximately 18%, which resulted in $5M recovered production revenue loss.

Lucas Pellegrin

Vice President EcoStruxure Power and Process

Schneider Electric

Exploration and Production companies are global companies that operate worldwide, often in remote areas where logistics present challenges. Replace a component after a failure may have a long lead time and then can generate even millions of dollars of losses. The key interest for these companies is to customize, manufacture and receive a component in a short time, regionalize the supply chain, and then reduce the costs of the warehousing of spares.

The solution is for the E&P companies to digitalize their supply chain, together with the main manufacturers, to develop a strong network of small 3D metal printing shops and implement a distributed additive manufacturing model. The overall concept is to enable a build job to be created centrally (at HQ level) and distributed securely through the Internet (for IP protection purpose) as and when needed to the relevant printing shop, so that the component can be produced locally on spot. Large manufacturers are looking for creation of such reliable local network, controlling/securing their end-to-end supply chain, while protecting the design of their components. E&P companies enjoy the short lead time and the ability to effectively create a digital warehouse that saves them a large amount of money.

This paper intends to discuss these strategic topics, specifically the digital technology innovations that are synergic to the manufacturing process of the components addressed to the oil and gas sector, via laser powder bed fusion process.

SLM Solutions is an integrated solutions provider and metal additive manufacturing partner. Robust Selective Laser Melting machines optimize fast, reliable, and cost-efficient part production, and SLM Solutions' experts work with customers at each stage of the process to provide the support that elevates the use of the technology and ensures their return on investment is maximized. A publicly traded company, SLM Solutions Group AG is headquartered in Germany, with offices in Canada, China, France, India, Italy, Japan, Singapore, South Korea, and the United States.

We have recently announced the successful integration of Assembrix and of Viaccess Orca software with our SLM machines, paving the way for a remote printing reality. This will enable our customers to benefit from highly secured end-to-end manufacturing solution worldwide, while keeping full ownership of the automated printing process worldwide. This is part of our value proposition to integrate such digitalization services into AM thanks to our broad ecosystem of software partners.

Our AM technology is able to support this goal, for new parts but also for repair of parts. Due to the high detail resolution of the SLM process, high complex parts with inner cavities could be repaired. This spurs the creation of a data model of the reality that connects to predict maintenance artificial intelligence software and operation models.

This paper will describe the ecosystem of the many software that we are implementing around the additive manufacturing process, in order to make this strategic digitalization model a reality in this industry.

Fabrizio Ragusa

Global Business Development Director, Energy

SLM Solutions

Russia's invasion of Ukraine has triggered a re-examination of European, and indeed, worldwide energy priorities. While no one questions the need for ambitious progress towards a dramatically lower carbon economy, immediate concerns about energy security compete for attention in both the short and medium term. The EU has published a 10-Point Plan to reduce dependence on Russian natural gas by 2/3 by year-end, and Russia has countered with threats to terminate supplies completely. But from where will Europe get its replacement energy? Many of the proposals in the 10-Point Plan (including large scale renewable as well as fossil fuel and nuclear projects) will take many years to implement. One renewables expert recently estimated it would take 7-8 years to permit a large new wind project in Europe. Even Germany's two announced new LNG terminals will take at least 2 years to build. Some commentators -- even environmental advocates -- suggest turning back to burning more coal until these projects are completed. LNG is one option, of course. But its supply is currently constrained. Every cargo diverted to Europe is coming from somewhere else -- often Asia. It is therefore not surprising that Japan is also discussing the possibility of contracting for coal and China is using more coal. Must energy security be a zero sum game where the climate and the future must lose?

The author has examined these and related issues and has concluded that both goals can be pursued simultaneously. For example, Europe can insist that LNG suppliers meet the "30% Methane Reduction Pledge" agreed by the US, UK and EU in Glasgow. On the other hand, those same three governments may want to consider relaxing their prohibition against financing foreign LNG export projects that would grow the pool of LNG and reduce the need for more coal. Other steps, such as promoting floating LNG storage and regas vessels near Lubmin, Groningen and other gas hubs in Europe would offer flexibility for short-term energy solutions that offer energy security while not locking Europe into long-term infrastructure that may not accord with the EU's Carbon Taxonomy.

The author will bring a unique perspective to this important issue in having spent three years analyzing both low-carbon solutions for natural gas and LNG as a Fellow for Global Natural Gas & Energy Transitions at the Baker Institute at Rice University, and prior to that spending 35 years as an attorney working on over 100 LNG and natural gas projects around the world.

Steven Miles

Senior Counsel, Fellow, Global Natural Gas & Energy Transitions

Baker Botts, LLP

There is growing acceptance of the need to decarbonise our energy and awareness of the key role that the gas industry plays in the transition to zero GHG emissions. IRENA has a membership of 167 national governments and partners with many global organisations to produce impartial scientific data on global renewable energy trends, and make policy recommendations to its Members.

In 2021 IRENA issued its World Energy Transition Outlook that described an ambitious scenario for the transformation of energy to limit the global temperature rise to 1.5C and bring CO2 emissions closer to net-zero by 2050. This includes the implications of countries’ net-zero energy policies and hydrogen strategies. It indicates that by 2050, electricity will account for half of final energy, biofuels will be five-fold and that natural gas demand will decline by over 40%.

The paper will present the Outlook and the role of gases in the energy transition to 2050. It will also an update of findings from 2nd edition of the Outlook to be released in June 2022. It will also highlight the opportunities and challenges for the natural gas industry, outline the work IRENA is undertaking with public and private industry and invite participants to collaborate with IRENA. Although the supply of natural gas is essential to substitute coal, oil and other more polluting fuels, the production and use of natural gas emits significant quantities of greenhouse gases that is incompatible with the Paris Targets.

A new industry must be developed to supply decarbonised gases (green hydrogen, biomethane and synthetic methane) and also target the energy-intensive and hard-to-electrify sectors of aviation, heavy transport and shipping and, the largest part sector, heavy industry. The Outlook indicates the demand for green hydrogen (from renewable sources) will be double that of blue hydrogen (fossil sources with CCS).

This has profound implications for the gas business to adapt its production, supply chain and customer base and requires strategic investment to avoid stranded assets. However there are also large opportunities for the industry to address the challenges.

Opportunities include:

- Delivery of green gases through the existing midstream and downstream infrastructure to targeted high-value consumers – at minimal additional cost to the networks.

- Producing green gases at competitive prices – locations around the world will deliver green hydrogen at competitive prices.

- Large-scale gas storage to provide flexibility to electricity networks that become stressed as variable renewable electricity production is accelerated.

- Ability to produce and develop international trade in green gases. Challenges include:

- Increasing urgency and time pressure to reduce emissions and prove undeveloped technology and processes, including CCS and green gas trading.

- Creating demand and supply chains for decarbonised gases. - Showing the role and cost effectiveness of natural gas in a decarbonised energy future.

- Policy and regulation to enable green gas ramp-up and trading, including an internationally-recognised certification system for the origin and carbon footprint of green gases.

- Updating technical and safety standards.

- Avoiding stranded gas assets.

Barbara Jinks

Programme Officer - Green Gases

IRENA

Since spring 2021, global gas and spot LNG prices have increased due to low inventories of European underground gas storage and reduced Russian pipeline gas exports. After Russia's invasion of Ukraine on February 24, prices reached uncharted territory, with JKM and TTF hitting all-time highs of $84.8/MMBtu and $72.3/MMBtu, respectively, on March 7. Volatility has also widened, with frequent reversals in the JKM and TTF spreads.

So far, we have observed rising electricity and gas prices, rising majors' profits, bankruptcies of energy marketing companies, declining gas demand in emerging markets, and an acceleration of long-term contract signings, but new developments include the disappearance of the Japan premium (emergence of the Japan discount), the diversion of US LNG from Asian to European markets, and a drop in LNG carrier freight, and the exposure of the utilization caps of European LNG regasification terminals occurred.

Although gradual sanctions have been implemented by various countries and companies are moving away from Russia, Europe's dependence on Russian pipeline gas is so high (31% of gas consumption in 2020) that the boomerang effect is higher, and European countries are unable to embark on an embargo.

In March 2022, the EC presented a new energy security proposal (REPowerEU). The proposal calls for a 7% reduction in gas consumption through energy efficiency upgrades and other measures, as well as the procurement of additional LNG and pipeline gas (equivalent to 47 million tons of LNG), which would enable a two-thirds reduction in Russian pipeline gas within 2022. However, the world supply allowance of LNG and pipeline gas in 2022 is only equivalent to 11 million tons of LNG.

Gazprom has repeatedly stated that it will comply with its long-term pipeline gas supply contracts. If Russian pipeline gas supplies are reduced to one-third of the total exports corresponding to the long-term contracts, even if all of the world's LNG and pipeline gas supply allowance, equivalent to 11 million tons of LNG, is additionally supplied to Europe, European underground gas storage stocks will reach zero by the end of January. It was estimated that an additional 44 million tons of LNG would be needed to restore these inventories to normal levels.

Regardless of how much subsidies and other incentives are used to incentivize underground gas storage, there is no extra LNG or pipeline gas in the world to begin with. Furthermore, it is clear that the world's LNG supply allowance will decline to record lows by 2025.

In the short term, there will be no choice but to slow the pace of decarbonization and return to coal-fired and nuclear power generation. In the long term, it is important to change the rush decarbonization policy in Europe, which was aimed at gaining hegemony, to restore upstream investment, and to diversify the sources of LNG supply for a de-Russia.

Japan's new LNG strategy announced in May 2022 and Japan's energy mix, as well as the Japanese government's policy to support new LNG supply in the future, will also be explained.

Yutaka Shirakawa

Project Director

Japan Oil, Gas and Metals National Corporation (JOGMEC)

Introduction

Co-authored by Dr. Laura K. Huomo and LL.M Cea Mittler.

On 8 March 2022, in light of Russia's invasion of Ukraine, the European Commission proposed the REPowerEU plan to make Europe independent from Russian fossil fuels well before 2030. As for all the ambitious climate policies presented, this one feels more personal. Why? Because it reveals our vulnerabilities and heightens our necessity for independence. The ongoing turmoil has been testimonial to the way we consider change - after the initial shock we already have the capability to see the promise of the new. The window for change is more open than ever, but is the hope of energy independence just a new narrative to delicate to have an impact or will it boldly form our perception of a greener tomorrow?

This abstract discusses key legal and policy developments that are shaping EU’s energy future. It explores the possibilities to speed up the energy transition. To adequately fight the greenhouse gasses and provide a structured approach to security of supply issues.

Out with the old and in with the new?

Following the recent state of affairs in Europe, market actors have had to deepen their contemplations and take new factors into consideration as to achieving the goals of the EU’s Fit for 55 package. Governments and companies need to put security of supply to the forefront. Decarbonising gas to gain freedom from fossil gas well in advance of the previously contemplated schedule is on top of the agenda. Companies need to change their energy systems to be ready to utilise new green cases, this will have a massive economic effect on the companies and the economies as a whole. Preparing for the coming regulatory development adds layers of complexity to the already highly regulated sector.

The subject of gas market decarbonisation combined with security of supply issues is challenging. Energy sources which were “definitively” put out of use, like peat and coal, might temporarily be taken back in the energy source arsenal just to cope with security of supply issues. How can countries go back in their political agenda and facilitate this hopefully temporary need to utilise its old arsenal?

It's all about possibilities

Europe needs to diversify its energy sources, create more opportunities to utilise LNG terminals, get the volumes of biomethane into the transmission infrastructure and support renewable hydrogen production and imports. All of this needs to be boosted by energy efficiency measures, by increasing renewables in the energy mix, by applying electrification to the largest extent possible, and use hydrogen in areas that are hard to abate.

Conclusion

There are many ways to change the story that is being written. By using policy and regulation combined with needed technology and public perception we can establish an interplay between the old and the new without necessarily having to choose either or. We can use this new opportunity to speed up the energy transition and turn this sudden change to the benefit of us and the whole energy future.

Laura Huomo

Partner

Bird & Bird Attorneys Ltd

Floating LNG terminals, whether for liquefaction and export of LNG (FLNGs), or for import and regassification of LNG (FSRUs, FSUs, FRUs), often require an offtake or import LNG carrier (LNGC) to be moored alongside the floating terminal in a side-by-side / ship-to-ship (STS) arrangement. This involves the LNGC being manoeuvred and berthed alongside another floating structure, which itself may be moving. So the manoeuvring operation requires great care and skill from the marine operations personnel and will need to be assisted by two or more tugs.

The marine operations personnel involved include the local marine pilots and/or mooring masters, ship masters and the masters of the tugs that will be needed to assist the operation. With the increasing demand for gas in many locations around the world, there is a consequential increase in the numbers of floating LNG terminals being planned and installed.

These facilities can often be positioned offshore in open water locations, so can be turret moored, yoke moored, or use another type of single point mooring, or can be spread-moored where the conditions allow. Although they can also be located in or close to existing port facilities, and could be moored alongside a fixed jetty. Some of the facilities may have no fixed structures (other than subsea pipeline) and others will have fixed infrastructure, which can have an impact on the LNGC approach and berthing manoeuvres. Also, they can be located in shallow or deep water area, which will affect the local metocean conditions, along with having an influence on vessel response.

As many facilities are located in relatively unsheltered waters, there is the potential for adverse conditions, especially if offshore. These can include high wave heights, long wave periods and constant swell, affecting both the floating facility and the approaching or departing LNG. In addition there may be multiple directions and components of waves, wind and currents, affecting the orientation of the facility (if weathervaning), and hence the approach direction and manoeuvring strategy of the LNGC. This presentation will provide some details on the ship manoeuvring criteria for floating LNG terminals covering:

• The impact of location, water depth and local metocean conditions on safe ship manoeuvring
• The potential operational issues and limiting factors that can affect facility availability and uptime
• Manoeuvring criteria for offshore floating terminals • Manoeuvring criteria for inshore floating terminals
• Tug performance in waves
• Spread moored FSRUs and how their design can affect safe ship manoeuvring
• Methods for assessment and evaluation of ship manoeuvring.

Dr Mark McBride

Group Manager, Ships and Dredging

HR Wallingford Ltd

The energy transition requires new solutions to transfer cold or even cryogenic liquids. The vacuum insulated corrugated stainless steel pipe reinforced by layers of tensile armouring and extruded thick walled polymer sheath makes floating or water submerged connection between floating storage units and offshore production facilities possible. The pipe can be produced in section lengths of 200m without intermediate connectors. All strength layers and the corrugated pipe itself can be simulated in it's strength and fatigue properties with conventional computer models. In any project, the motion of the pipec is caculated from the sea conditions and transferred into an expected life time of the pipe. The two concentric corrugated pipes provide best possible thermal insulation by the vacuum between the pipes, and secures with the double containment best possible safety features. Such pipe is type tested according to EN1474, and can be used within any offshore or costal LNG, LH2 or Amonia project. In this paper the pipe technology ist presented and examples are given, where such pipe makes innovative new energy projects possible.

Dr. Jürgen Essler

Sales Cryogenic Systems

BRUGG Rohrsysteme GmbH

It has been known for a long time that mooring failure in ship-to-ship transfer is the most prevalent incident in operations and mooring incidents are reported to represent 70% to 80% of all STS incidents globally. The most immediate impact of a mooring incident to an individual, is Snapback. Being hit by a parted rope at 50 tonnes,is like being hit by a car traveling at 90 KM/H with a 14% chance of being killed. The rope travels at the speed of a bullet and the chances of getting out of the way are zero for anyone in the line of the rope trajectory.

Industry lays down guidelines on the working load limits for 50% for ropes and 55% for wires. These limits are mandated as maximum limits but with a caveat of a recommended working limit of 22% of the original MBL.

Our presentation will introduce a totally new cost-effective product that can be incorporated into any mooring system to control the tension within defined limits. The Mooring Protection is provided by a rope grommet that is two metres long, which can be inserted into the eye of the mooring rope by a COW hitch.

The fuse solution for STS is designed with 3 elements encapsulated in a protective chafe protection jacket.

Trigger

The fuse has a trigger made of Dynema that is designed to break at a pre-defined tension which will activate the fuse. (For example on an LNGC, it would be set at 50 Tonnes in line with OCIMF guidance on WLL)

Fuse

The fuse is made of a fibre that elongates under tension at a set level for 150% of its original length. The fuse setting will depend on the strength of the rope and is set between 20% to 30% MBL.(For example on an LNGC we would use 25 tonne fuses in line with OCIMF recommended working load of 22% MBL) The fuse will break at a predefined level of 2.6 x fuse setting so for a 25 tonne fuse this would be 67 tonnes. (Using a 25-tonne fuse that breaks at 67 tonnes considers OCIMF recommendations and at a level above mooring brake render but below retiring ropes at 75% original MBL)

Attenuator

The Attenuator is made of a fibre that elongates under tension at a set level for 300% of its original length. The Attenuator is much smaller than the fuse and designed to fail at 6 tonnes, eliminating snapback (Due to the exceptional stretch characteristics, the attenuator would not actually break, and the rope would remain attached to both vessels allowing a rapid reinstatement of mooring integrity)

The characteristics of this new rope material provide an opportunity to create custom protection for specific mooring hazards. Correct management of the maximum tension using our custom fuses will ensure that over-tension is avoided through the working life of the rope. This will ensure that mooring strength is maintained at an optimum level and help to protect the lives of seafarers from snapback.

Robert Gilchrist

Marine Director

SafeSTS Ltd

An innovative BOG management system has been offered for an important ssLNG terminal initiative in North Italy with design capacity to distribute 900,000 cbm of LNG per year.

During the FEED stage the terminal was designed according to a traditional configuration including compressors, high pressure pumps, and a send out line to interconnect the terminal with the national natural gas grid.

TGE has instead proposed an alternative configuration which reduces complexity of the installation and at the same token improves the reliability. The BOG is managed by a subcooling unit which is able to control the tank pressure by spraying subcooled LNG into the vapour space. In fact the systems offers the benefits of an “in-tank” re-liquefaction.

TGE has achieved a lower yet comparable level of CAPEX for the implementation of the project, which is anyway offsetted by the improved profitability of the plant operation along with a shorter investment pay-back. Under the Authorisation permits point of view, the configuration has the undeniable benefit of a massively reduced complexity, lower pressure level (all portion of plant are at atmospheric pressure level), as well as risk scenarios are accordingly reduced.

The improved marginality of higher added value LNG sold rather than the low profit generated by the natural gas prices well compensates the slightly increased terminal operational cost. Furthermore the personnel required to operate and maintain the terminal is also less than the required team employed in similar capacity terminal implemented with a traditional configuration.

Paolo Ferrarese

Sales & Business Development Manager

TGE Gas Engineering

With the drive to continually reduce the cost of hooking up new coal seam gas wells, Worley developed a GIS based system which automates engineering and improves operational efficiency for pipelines and gathering systems. One of the recent developments has focused on data driven execution of process engineering design resulting in an automated and data driven approach to flow assurance and production of process deliverables in the form of Gathering Network Diagrams (GNDs), an alternative to conventional Piping & Instrumentation Diagrams (P&IDs).

On a recent project, Worley implemented a GND workflow capable of showing ~40 wells per A3 deliverable in conformance with intelligent drafting standards.

This reduced ~2,000 as-built P&IDs to ~200 GNDs (and associated standard details) with a significant improvement in quality and usability. The transition to the new style of deliverable was achieved through the creation of standard drawings for common equipment such as well skids which remove the need to show the detail on the GND allowing more of the network to be represented on a single page. To capture the well site equipment tagging, the standard drawings are accompanied by a tag list which is revised as new wells are designed and subsequently as-built.

Prior to generation of the GNDs, a site walkdown was conducted to address mismatches between as-built P&IDs, GIS, and what was actually installed at site. Our customer now has a suite of GNDs and associated standard drawings and tag lists which match the installed asset and are produced from the corporate GIS database, essentially their digital twin.

This data driven methodology utilises a GIS running over a spatially enabled enterprise database to provide a single point of truth for design information. From the database, the team leveraged a combination of custom developed code (SQL, C#) to compile pre-requisite data for GND production and a GIS-based schematic extension to produce the schematic representation of the design. This is subsequently converted CAD format and converted into process design symbology using AutoLISP before a subsequent conversion is applied to convert the drawing to the necessary intelligent native file required by the customer.

Having helped our customer develop a quality digital as-built GIS database and associated intelligent master GNDs, Worley then focused on integrating flow assurance software with GIS to allow for data driven execution of future design packages needing to be incorporated into the master GNDs. We successfully integrated with two market leading flow assurance packages and have a pattern which can extend to other packages as required by our customers. Through the integration, linear pipeline routes and associated wells are transferred to the modelling software via easy to use, Worley developed web applications. An engineer can now sync the confirmed process design back to GIS without producing red-lined and/or CAD drafted deliverables which improves efficiency and reduces human error.

This presentation demonstrates how digital automation can be applied to the gas industry to significantly reduce cost and schedule whilst enabling data driven operational efficiencies and reducing project risk throughout design and operational project phases.

Andy Cole

Senior Vice President Sales, Global Partnerships

Worley

In the construction industry, design automation programs for various structures have been developed, but in relation to LNG tanks there have been difficulties in improving the design efficiency due to specific challenges, including the need to combine results from thermal and structural analyses, model staged construction and include creep and shrinkage effects.

The analysis of such tanks seems to require a 3D solid continuum FE model to properly represent the conduction of heat through walls, slabs and insulation layers, along with the effects of the structural loads such as wind and seismic. However, extraction of load effects for design purposes (e.g. bending moments and shears forces) from such models is not straightforward - for this reason 3D shell models are favoured. Shell models, on the other hand, generally lack the ability to model the conduction of heat through-thickness. The use of a cartesian reinforcement arrangement in some areas of the roof and base slab, and circumferential/radial arrangement in other areas presents a further challenge when obtaining suitable design effects. Computing the section capacity with consideration of prestress changes at different stages is also required.

An efficient design approach, adopting a 2D axisymmetric model for the thermal analysis, a 3D shell model for structural loads and furthermore considering seismic effects, demands an integrated methodology extending to the combination of results and design checking, with detailed attention to the varying reinforcement orientation.

Methods have been developed that include converting thermal results into loadings for 3D shell model, based on the requirements of ongoing LNG tank projects for various companies including KOGAS (Korea Gas Corporation) and KGT (Korea Gas Technology Corporation). These enable all the required design checks to be done in a single 3D shell model bringing together results from thermal, seismic, and staged construction analyses with design checks performed to the various international standards. Results output by way of summary reports, graphs and contours in consideration of the mixed reinforcement directions is also provided.

The London University Structural Analysis System (LUSAS) software was used to develop the required tools, applying the latest FE technology to automate the modelling and design of LNG storage tanks. Customisation and automation through an open API enables users with basic programming knowledge to create the various user defined features required, extract results and combine them with speed and accuracy in the desired format.

Solutions to the challenges encountered have enabled improvements in the efficiency of the analysis and design process for LNG storage tanks to reduce the engineers time and time to market by an estimated 20-30%. With less time spent on simulation and design checking, engineers will be able to produce accurate and reliable analyses of LNG tanks while optimising designs and reducing projects costs.

Jesus Rodriguez Rodriguez

Consultancy Manager

LUSAS

The Shale Gas Revolution created abundance of Ethane and Propane feedstock for hydrocracking and Propane De-hydrogenation. In the light of this development the trend for new built steam crackers is clearly leaning towards light hydrocarbon feedstock. Currently major investments for gas crackers and PDH plants are ongoing or planned worldwide.

TGE has pioneered the development of Multi Product Storage Terminals during the last decade and can demonstrate with a practical example how terminal operators can benefit of the built in flexibility.

In the light of a VUCA world, many investors are interested in having assets which are flexible in terms of stored liquid gas (from LNG, LEG, LPG to NH3). As TGE has already plenty of experience in designing and building multi product terminals and has been recently awarded with a study for conversion from LNG to NH3 storage, we would like to share the developments with the business community.

Picture 1 below shows one of the biggest Ethane/ Propane Terminals worldwide designed built under the lead of TGE. The plant has been commissioned back in 2018. Initially the plant operated in a way that 2 x 120.000 m³ Full Containment Tanks were under Propane Service and 1 x 120.000 m³ Full Containment Tank was receiving Ethane via VLEC from the USA.

Just recently our customer made use of the built in flexibility and executed with our supervision a product change from Propane to Ethane for the second tank in the picture below. The presentation will give an impression of the unique design features of TGE’s Multi Product Storage Gas Terminal, the additional CAPEX required, the related steps and the timeline required to execute such product change.

The long term advantage of the flexible asset clearly outweighs the additional CAPEX to be spent.

Markus Ecker

Senior Head of Research and Development

TGE Gas Engineering GmbH

Big data surrounds every activity in modern society, but how can it be harnessed in the world of gas turbine power generation to allow data-led engineering and operation decisions.

Today’s electric power grid is complex, dynamic and in a state of source transformation. Whether the sun is shining or the wind is blowing, renewable sources must be balanced with reliable, responsive, dispatchable firming capacity .gas turbine power plants operators must then make business choices; stand idle, in a mode of spinning reserve or operate below their design-intended optimum efficiency ratings, waiting to fill in the often rapid and volatile swings in load from this renewable power output.

To support these business decisions, significant development has taken place to create “Digital Twins” of Gas Turbines to bring together operational data and theoretical performance calculation tools. Using artificial intelligence and significant domain expertise we enable a better understanding of the real world operations and create actionable data insights. Features include:

• Combined cycle power plant (CCPP) Start-up optimization: faster, slower, lower emissions, purge credit, automation;

• Turbine AutoTune for improved emissions and combustor stability;

• CCPP Cycling optimization – fast ramp, lower low load points, peak power increase;

• Virtual Instrumentation

The power of the digital twins can be harnessed centrally for fleet comparisons and plant specific KPI’s, as well as locally in edge-based system optimization packages. Delivering faster startups, higher ramp rates – significant improvements with more intelligent operational limits, while not going beyond the proscribed plant equipment limits.

Case studies of recent commercially implemented plant optimization projects and examples will be used to illustrate what is possible operationally that can support improved profitability.

Ian Summerside

Global Product Manager

PSM (A Hanwha Company)

In response to the ongoing drive towards a carbon-free future, the maritime industry has been reconsidering the utilisation of traditional fuels such as Heavy Fuel Oil (HFO), in favour of lower emission fuels. Initially concentrating on reducing SOx and NOx emissions, the industry has more recently been focused on developing fuels which emit less carbon dioxide (CO2), which will support emission reduction commitments made by world leaders and reinforced at COP26 in 2021.

While the utopia is a solution based on hydrogen produced from renewable energy sources that can be classed as truly a green fuel, it will take some time to reach this goal. LNG has been widely recognised as the first ‘bridging fuel’ to the zero carbon goal, offering reduced CO2 emissions and being readily available across the globe, but more recently, LPG has also been adopted as a ‘stepping stone’. LPG offers reduced CO2 emissions compared to conventional fuels, is an easier fuel to handle than LNG and is equally available across the globe, being among the most traded commodities on the planet. Particularly for LPG carriers, the use of LPG as a fuel, whether from the cargo or loaded specifically as fuel, gives an attainable solution and LGE’s ecoFGSS® was developed to satisfy this need. Covering the full range of LPG carrier sizes, ecoFGSS® is as at the end of 2021 installed and operating on 8 mid-size and very large gas carriers with a further 17 on order due to be delivered within the next 2 years. As the industry’s focus switches to zero carbon fuels, ammonia has come to the forefront of discussions, offering a carbon-free, hydrogen based fuel which is truly ‘green’ when produced from renewables. For many years, the main issue associated with ammonia was its toxicity and it was assumed, for practical intents and purposes, to be non-flammable. However, for many projects it is now the transition fuel of choice, with a number of engine manufacturers working on delivering ammonia ready engines in the next few years. Compared to LPG, ammonia has to be supplied at higher pressure to the engine and due to the reduced energy density, has to be supplied at higher flowrates to provide the same power output and therefore systems designed solely for LPG will not be suitable for ammonia. This led to the development of ecoFGSS-FLEX®, a fuel gas supply system that is suitable for both ammonia and LPG and addresses the more stringent venting restrictions associated with ammonia. With minor add-ons, ecoFGSS-FLEX can also be used for methanol or dimethyl ether (DME).

This presentation covers the development of ecoFGSS® and how the operational feedback from units in service supported not only the improvement of ecoFGSS® but the development of ecoFGSS-FLEX® and its application for both new-builds and retrofits and satisfying the requirements of both the IGC Code (for gas carriers) and the IGF Code (for gas-fuelled vessels).

Andrew Scott

Business Development Director

Babcock LGE

As part of demand for eco-friendly vessels, market of LNG fueled vessels (LFV) is growing fast. It is because LNG is economically valuable and relatively greener energy as a “bridge” fuel to the zero emission energy resources. LNG fueled system can reduce air pollutants such as SOx, NOx and even CO2, a major contributor to global warming, comparing to conventional oil system. Since LNG is cryogenic and volatile, a special system called fuel gas supply system (FGSS) is applied on an LNG fueled vessel. Due to the nature of LNG, FGSS must consider safe handling of LNG from fuel supply as well as fuel tank operation. The tank condition must be kept in normal operation range for the safety of the entire vessel. Therefore, the most of FGSS have a function to use boil-off gas (BOG) as fuel to keep the safe tank pressure. In general, compressors are installed to compress BOG up to required fuel gas pressure. To handle BOG in any voyage condition, it is preferred to have BOG compressors that fit the required pressure of the main engine by ship owners, so high pressure (HP) compressors have been applied. Although HP compressor has advantage on its ability to supply BOG over 300 barg for main engine, it has clear disadvantage on CAPEX and large footprint of it. HP compressor also consumes significant power with relatively lower efficiency even at low pressure (LP) discharge mode. However, considering whole voyages, there are not much conditions that BOG actually has to be compressed up to 300 barg. During the most of voyage or vessel operation, generated BOG can be used in low pressure consumers, e.g. generator engines or auxiliary boilers. Samsung Heavy Industries (SHI) focused on actual fuel gas consumptions of various vessels and developed a novel BOG handling system called BReS (BOG Recovery System). BReS is a system to liquefy and recover excessive BOG over LP fuel consumption at low pressure under 10 barg by utilizing maximum cold energy extraction from fuel LNG and BOG itself. Since BReS requires LP BOG and can liquefy nearly doubled amount of normal BOG, FGSS can be much simpler and safer with BReS. BReS consists of only one heat exchanger and related piping while utilizing existing FGSS equipment to maximize its simplicity. The first advantage of BReS is its impact on improving EEDI. Unnecessary CO2 emission is reduced with BReS by recovering BOG without low efficiency compressor. The second is its fuel tank cooling-off ability. It is important to cool vapor area in fuel tank to suppress additional BOG generation. Thermodynamic simulations of BReS in connection with FGSS and fuel tank were carried out to confirm the effect of controlling tank pressure. Finally, BReS is economically competitive by a result of its simplicity and compactness. Actual scale of BReS for 15,000 TEU container carrier is planned to be tested in full scale with actual LNG and NG in 2022 at SHI’s LNG pilot test facility to verify its BOG recovering capability.

Ahmin Park

Engineer

Samsung Heavy Industries

With the rapid growing LNG market, there is clearly a strong need for new innovative and cost-effective LNG terminal solutions. This includes LNG regas terminals and LNG bunkering facilities. Such solutions will be a key factor for unlocking LNG deliveries to new markets and new countries seeking clean energy.

This paper will provide an overview of the new Jettyless LNG terminal solutions that the been developed by the company over the last five years. The target has been to a obtain robust, safe and cost-effective LNG receiving and regas terminal without the need for construction of expensive and environmental sensitive jetty or other fixed infrastructure.

The Jettyless solution consists of a spread moored FSU used in combination with a jack-up based Self-Installing Regas Platform and a Floating LNG Transfer System enabling the LNGC to be safely independently moored 150 m from the FSU. The jack-up regas platform is elevated at a safe height well above the 100-year wave to ensure that the regas facilities are not be exposed to wave loads and motions that as is a typical challenge for other regas solutions. A patent for the Jettyless solution was granted by the United States Patent Authorities in 2018. The paper will describe the typical challenges involved with design and construction of a new LNG regas terminal and how these challenges has been solved during the development of the Jettyless alternative. This includes analysis, safety assessments and technical and operational considerations.

In conclusion, the Jettyless solutions that will be presented in the paper may provide the LNG industry with a new and innovative way of delivering LNG to countries and new locations seeking clean energy. The significant cost savings and less environmental impact obtained with the Jettyless solutions may be a key enabler to unlock new LNG markets in 2022 and onwards.

Emil Aasland Pedersen

Project Development Engineer

Stena Power & LNG Solutions

“Just throw the cable over!”

In its simplest form and to the understanding to most operators, the ship to shore link systems have been used for 40 years and are expected to be plug and play.

More commonly nowadays of course are the floating LNG projects which are leveraging off the base operational philosophies of existing infrastructure but have developed rapidly from their initial ‘make it work’ concepts to now demand more and more integration of the various assets in whatever layout is in operation, and their common conduit between all applications is the ship to shore link.

The recently updated SIGTTO ESD guidelines have incorporated for the first time the required basic safety connectivity, and these safety signals are fully isolated from any process signalling, however the level of process integration being demanded varies from operator to operator, yet everybody demands the most flexible asset, and although not a requirement for a specific project build, operators are looking to the 2nd and 3rd contracts where the ship may be re-deployed and want as much inherent compatibility built in from delivery.

As presented in 2017, these applications have continued to increase in complexity and add significant overhead to the ship to shore link infrastructure which has to date developed piecemeal for application to application and has recently reached the point of potentially not being suitable to support the required functionality by the latest generations of FSRU vessels which are now expecting 100% functionality as both an LNGC and FSRU at ANY terminal globally whatever interface the terminal project may have specified. This has not only increased the various connection options significantly, but with the added enhanced functionality forced the core functionality of the ship to shore link to be re-addressed with new novel solutions allowing this functionality whilst retaining the legacy interfaces.

Whereas we’d previously discussed the addition of the SONET digital fibre SSL as the conduit to carry enhanced functionality forwards with the ship to shore link, applications are now expecting ‘double digital’ systems to offer the enhanced functionality on both sides of the vessel, including provision for LNG bunkering, previously not a concern, but now to multiple operators seen as a requirement of their operating philosophies.

This paper will review the development and deployment of these applications, the options and solutions that have been developed to overcome the limits of the legacy interfaces, and hopefully leading to a roadmap taking ship to shore link systems forward to provide the interfaces demanded by operators in the near and distant future.

The author has been working with LNG ESD systems for over 17 years and has been involved in working groups and technical committees of SIGTTO, SGMF and OCIMF.

Andrew Stafford

Technical Director

Trelleborg Marine Systems UK Ltd

The Russian invasion of Ukraine has sent shockwaves across Europe and further afield, particularly in global energy markets. Fears of disruptions to gas flows sent European gas prices to record levels. The Nord Stream 2 pipeline has been suspended indefinitely. The increasing scope and depth of sanctions being placed on Russian interests do not yet cover natural gas imports, but there is great uncertainty whether gas flows will be sustained, reduced or even suspended.

Europe is scrambling to find alternatives to Russian gas, but there is no realistic way to substantially replace it in the short term. Imports from Russia (pipeline gas and LNG) in 2021 totalled 155 Bcm, accounting for around 45% of the EU’s gas imports and almost 40% of its total gas consumption. The EU has proposed an outline plan “REPowerEU” to make Europe independent of Russian imports before 2030. The plan envisions diversifying gas supplies, via increased LNG and pipeline gas imports from other (non-Russian) suppliers, and addressing infrastructure bottlenecks. The IEA also laid out a 10-point plan to reduce Europe’s reliance on Russian natural gas.

In line with the initial plans laid out, pathways to reduce the level of Russian gas imports will require a combination of reductions in gas use, switching to alternative energy sources, and finding alternative supplies of natural gas. LNG is the most obvious alternative supply to bring to Europe, given the range of new LNG supply projects seeking to reach FID, although any solution will be constrained by the ~4-year construction schedule for new plants. The European market has already developed into the global balancing market for LNG due to the flexibility and liquidity of its gas markets, although this role may now evolve in light of increased security of supply concerns.

The paper will examine how the LNG industry is placed to react to the current situation. We have already seen a raft of new and resurrected LNG import infrastructure projects come to the fore while LNG cargos are diverted away from other markets. January 2022 saw an all-time record for LNG imports into Europe, attracted by sky-rocketing European prices and imports are set to continue to beat previous pre-pandemic levels.

The LNG industry can rise to the challenges and opportunities that the tragic situation presents. The paper will examine some of the ways that can happen, including:

*Optimising European LNG import infrastructure to deliver gas to Europe

-Utilisation of existing terminals and constraints in the system.

-Where new infrastructure is planned and where it is most needed.

*Adjusting global LNG trade flows to meet the new market realities

-LNG availability will depend on the Asian market, particularly Northeast Asia and China, which determines the amount of supply that might be available for Europe, and crucially where prices may be heading.

*Fast tracking and financing new LNG supply projects

-Identify regions at the head of the queue to bring new LNG supply to the market

Jan Bruil

Senior Consultant

Poten & Partners

Global gas markets have been in turmoil in recent times undergoing significant changes in the wake of the Ukraine-Russia conflict. LNG is set to strengthen its role in Europe replacing Russian gas as a primary fuel supplier. We analyse scenarios of market changes and give an outlook on implications for market prices, gas flows and security of supply. The analysis draws on a European gas market optimization model with daily resolution looking two years ahead. The model optimizes European LNG versus pipeline imports and it considers weather effects on demand, infrastructure capacity constraints, storage obligations, long-term contracts, capacity bookings as well as supply cost. The base scenario is represented by Russian supplies limited to contractual obligations while a second scenario studies the impact of a complete halt in Russian supplies. The analysis takes into consideration different weather forecasts as well as demand response. Our findings point to the limited displacement potential of Russian gas imports. If Russian gas is replaced by LNG, it will come at an additional cost. Also, we find that the new EU storage regime is feasible and ensures the security of supply in a cold winter scenario.

Andreas Schroeder

Head of Energy Analytics

Independent Commodity Intelligence Services (ICIS)

EU Comission published REPowerEU that aims reducing the Europe’s dependency on Russian gas well before 2030. This joint European action proposed after Russia’s invasion of Ukraine. The action plan includes a series of measures, which are diversifying gas supplies, dealing with energy prices, filling gas stocks up, and replacing the gas in heating and power generation. In this study, the reasons behind why today's conditions are not enough to get rid of Russian gas will be explained.

Energy prices have been surging in the EU’s states due to combination of factors on both demand and supply side. The first factor is lacking of renewable energy production because of its intermittent nature. In 2021, wind was low and water levels hit the lowest. The other factor is that changing precipitation patterns led to the colder winter and more energy used for heating than expected. As for the supply side, although Gazprom fulfilled its contract obligations, it did not supply extra gas to the EU and this action was interpreted by the market experts as Russia squeezed the gas supply to the markets due to political reasons (e.g., the Nord Stream). Finally, all these combination factors led to increase in the energy bills.

Besides the REPowerEU offering a big potential for avoiding the gas use imported from Russia, it will unfortunately have come to standstill in the short-term. If the EU will aim at limiting the natural gas consumption supplied by Russia through the Europe, the gap left from the gas in the energy mix must be quickly replaced with other alternative source of energy. However, to be able to substitute the gas’ capacity in the energy mix means that three or four times of the current renewable energy installed capacity are needed.

Diversifying the gas supply routes to fill the storages are also neither in line with the European Green Deal goals, nor delivering the other goals lied in the Climate Law. Under the current circumstances, the EU needs to import more LNG to be able to diversify the source of energy and needs also more gas from other pipelines (e.g., TANAP), but this is not a permanent solution for the security of gas supply. Even if the EU takes the emergency steps mentioned above, the more LNG imports to the EU means to compete with Asian market and it also means paying more than the others. As for the TANAP constraints, the initial capacity of the project 16 bcm, 10 bcm to the Europe via TAP. TANAP’s capacity can increase up to 32 bcm, however there is a need more time and budget to be effective implementation of the project. For this reason, the capacity expansion of the TANAP is not foreseen in the short term.

All in all, giving up Russian gas in the energy mix, at least for 4-5 years term, by may not have foreseen in the EU’s states since shifting gas is not an easy task and all the given constrains above in the short-term.

Ethem Uğur

Commercial Operations Engineer

TANAP Natural Gas Transmission

European energy policy has for decades been based on the assumption that Gazprom will always deliver because Russia needs the income as much as Europe needs secure supplies of gas – and that this would always be a desirable situation.

For decades, this was true. Even through the regulatory tumult of the third energy package and the decoupling of upstream and infrastructure, Gazprom retained and strengthened its position as the key supplier of natural gas to the European market. Despite multiple warnings of geopolitical risk, and a decade of regulatory campaigns waged in Brussels against Gazprom’s previous oil linked long term contractual model, Gazprom has enhanced it’s moving from 25-40% of EU natural gas supply.

How has this happened? The past 20 years + have a multiple interlinked set of constant factors that had previously strengthened Gazprom’s position as the dominant gas supplier to Europe:

• Demand – natural gas remains a vital component of European energy systems, being included in the recent taxonomy.

• Geography & capital – Russia has multiple massive gas fields within pipeline distance of Europe and Gazprom is a capital raising and churning machine. It is the easiest option

• Decline of EU / UK domestic production due to field depletion.

• Increasing competition in global markets – APAC a core market for natural gas

• Adjacent import partners such as Norway and Algeria are limited in additional production due to maintenance / infrastructure /

• A very tight global LNG market

There is a vital additional factor that should be considered. That of the choice to outsource carbon cost of energy to external gas suppliers – primarily Gazprom – and minimize EU “domestic” hydrocarbons production and exploration. Europe could state that it was getting greener and greener.

This point has been made by multiple stakeholders, such as Roberto Cingolani, Italian Minister for Energy Transition, “We did reduce our domestic gas production but we increased imports. The environmental impact was constant, and we self-damaged the economy.” (https://www.ft.com/content/b32bf4fc-608c-46fa-944b-0b3fe8642919?shareType=nongift)

All of the above has been thrown into stark consideration by the horrific Russian invasion of Ukraine.

If Europe is serious about reducing its reliance on Russian gas there must be a series of marginal changes, all encouraged by supportive policy and regulation. There is no way there can be a like for like switch. There is no “Gazprom 2.0”. Policy and regulation must be devised to encourage:

• Swift investment in renewable energy capacity & nuclear to cut demand for gas

• Engage mature global LNG & pipeline importers – but be aware how tight the global gas market has become

• Encourage domestic in infrastructure to support H2 and natural gas – pipes AND storage

• Encourage domestic E&P – particularly in Italy & Greece, and reverse the Netherlands shut ins

• Engage positively with new energy provinces eg E Mediterranean to make case to “share the wealth”

Nick Witney

Commercial Director

Energean plc

THIS ABSTRACT WAS PREVIOUSLY SUBMITTED, APPROVED, AND FULLY WRITTEN FOR GASTECH 2021 BUT THE CONTENT WAS NEITHER PRESENTED NOR PUBLISHED IN THE PROCEEDINGS DUE TO TRAVEL RESTRICTIONS FACED BY THE AUTHOR(S). IT IS RESUBMITTED FOR USE IN 2022.

Pipeline-quality feed gas for US LNG projects poses a unique challenge: heavy hydrocarbon removal. Most of the feed gas from a pipeline network has been pre-processed to extract valuable NGLs, so it typically is lean. However, this gas still can contain small amounts of heavy hydrocarbons and BTEX that will freeze out during the liquefaction process and must be removed. For such lean feed gas, traditional hydrocarbon removal methods such as a scrub column or an expansion and condensation scheme may not meet all required liquefaction specifications because there is only a small quantity of C2-C5 components present (which are typically used to absorb the heavy components). When actual natural gas compositions to liquefaction plants are even leaner than previously estimated and designed for, these treatment units are further stressed to meet the target specifications. Consequently, increased pressure drop/freezing in cryogenic exchangers has been observed in multiple North American LNG projects.

For North American LNG projects early in the development cycle, most attention is placed on the liquefaction unit and familiar choices are made for gas treatment that are common for large-scale LNG trains that have been built over the last several decades. Conventional heavies removal designs are often considered for North American projects due to their perceived process simplicity and low capital cost (CAPEX). However, conventional designs come with their own set of operational limitations -- particularly due to their inability to generate sufficient reflux, resulting in unstable distillation column operation when feed gas is lean. Technology selection that does not best fit the feed gas composition, and the operational/turndown requirements, can lead to freezing issues that result in higher operational costs and reduced availability.

This paper reviews proven technologies that show benefits for heavy hydrocarbons removal systems for lean feed compositions. The discussion includes an analysis among heavy hydrocarbons removal technologies using a case study approach which considers different ranges of feed gas compositions and delineates an optimal selection for each composition. The paper also highlights relative CAPEX and OPEX estimations among different technologies and the significant impacts to liquefaction process efficiency. Qualitative review of reliability and flexibility of the heavy hydrocarbons removal unit operation also is provided. The paper also addresses considerations for the integration of heavy hydrocarbons removal in large scale and multi-train small scale LNG units.

Dipanjan Bhattacharya

Technology Manager, LNG and Gas Processing

Kiewit

Bhargav Sharma

Global Senior Business Leader, Gas Processing and LNG

Honeywell UOP

To achieve efficient production of LNG, natural gas must be dehydrated to cryogenic dew points. For decades, molecular sieves have been used to accomplish this very important task. However, standard molecular sieve dehydration can cause significant challenges to operations, including increased pressure drop and short lifetimes; both of which have a negative impact on the profitability of the plant by reducing throughput and increasing plant downtime.

BASF has taken an innovative approach to natural gas dehydration for LNG production, challenging the conventional wisdom of relying on molecular sieve. The temperature swing adsorption (TSA) process creates a harsh environment that causes regeneration reflux and retrograde condensation. These conditions cause standard molecular sieve to degrade and decrease in performance. To avoid this decrease in performance, BASF relies on a much more robust aluminosilicate gel material. This material is resistant to the physical effects experienced in the dehydration vessel and can remove bulk water and heavy hydrocarbons simultaneously. Furthermore, BASF aluminosilicate gel materials have a lower heat of adsorption, so regeneration of the material is easier.

This paper will describe the first retrofit installation of Durasorb Dehy in dehydration service in LNG pre-treatment. Equatorial Guinea LNG (EGLNG), was experiencing some of the common challenges associated with standard molecular sieve beds, including regeneration reflux and retrograde condensation. This environment caused molecular sieve degradation, pressure drop increase, and pre-mature failure of the molecular sieve bed. To address these issues, BASF employed an innovative bed design, using specialty developed molecular sieves, to solve these problems and double the bed life. This paper will describe the innovative solutions employed at the EGLNG plant to achieve this extended lifetime, which resulted in one less turnaround, significant OpEx savings, and ease of operation for the dehydration unit. Implementing the Durasorb Dehy solution establishes EGLNG as an early adopter of new technologies willing to explore opportunities to improve operations and increase plant value.

Tobias Eckardt

Global Technology Manager

BASF SE

New LNG export facilities are facing the challenge of reducing greenhouse gas (GHG) emissions in the liquefaction process. The major source of GHG emissions in current LNG liquefaction plants is the exhaust from the gas turbines which drive the refrigerant compressors. Significant efforts to reduce GHG emissions are being made with post-combustion carbon capture from the gas turbines used for mechanical drive. As an alternative solution, driving the compressors with electric motors can substantially reduce both cost and GHG emissions. The electrical power provided can be generated efficiently from a combined cycle power plant or from renewable sources. For those LNG facilities generating power onsite, employing gas turbines in a combined cycle process for power generation coupled with electric motor drive for the compressors (instead of simple cycle direct drive like most conventional LNG facilities) allows for a more efficient overall process leading to reduced GHG emissions. Furthermore, these power islands can be located away from the liquefaction unit to accommodate the potential large equipment if carbon capture is part of the solution.

This paper will discuss the benefits of e-drive that can lead to reduced cost and lower GHG emissions compared to conventional LNG facilities, including:

1. Reduced CAPEX and maintenance

2. Reduced GHG emissions and flaring

3. Easier accommodation of pre- or post-combustion carbon capture.

4. Faster LNG plant start-up

5. Increased operating flexibility and efficiency due to variable speed drives

6. Improved annual efficiency and LNG production due to constant driver power independent of ambient conditions

7. Improved refrigerant compressor aerodynamics and machinery design through the optimization of motor speed

8. Improved compressor arrangement and layout through the optimization of motor size

9. Ready modularization for motor driven compressors

This paper will also discuss how Air Products liquefaction processes are easily optimized to take advantage of e-drive solutions, including Air Products e-drive experience in LNG dating back to 2012. The paper will include detailed case studies showing the benefits and advantages of using e-drive to meet future stringent GHG regulations.

© 2022 Air Products and Chemicals, Inc. All Rights Reserved

Christopher Ott

Senior Process Engineering Associate, LNG

Air Products and Chemicals, Inc.

The LNG industry has practiced the removal of potentially freezing 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 so much experience across decades of operation, there is not a simple and clear-cut answer as to the desired design to meet LNG specification as 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. The purpose of this paper is not to recommend a single solution but rather to provide a framework for determining the optimal configuration for each specific plant.

The analysis starts with study of the feed gas composition and determination of the lean-to-rich range to be included in the design. The amount of NGL’s 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 blend in the removed heavies, and the incoming pipeline pressure favor different configurations. The range of compositions to consider also results in different design decisions. Gas from a single production source may change over time but is typically more consistent in composition and can have a narrower, targeted process. But LNG plants on a large pipeline system like the US Gulf Coast where many different producers inject gas can see significant variations, so flexibility to meet removal specifications is warranted but likely comes at a higher cost.

Higher efficiency processes like expander units and booster compressors upstream of the liquefaction process can add 10 percent or more LNG capacity when refrigeration power is fixed. The added cost and complexity are economically favorable 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.

Specific examples with relative cost and efficiency comparisons along with flexibility to handle range in composition will be presented for various designs, along with the primary factors giving advantage for specific situations:

• Up-front cryogenic expander, independent of liquefaction process

• Partial condensation with a simple flash or refluxed tower

• Adsorbent solutions and necessary processing of heavies-laden regeneration gas

• Feed gas pressure and implications on rotating equipment needed

• Open art or licensed process, and degree of NGLs removed versus maximum C4+ recovery to LNG

• Turbine or motor-driven refrigeration in regard to efficiency/production gains and resultant emissions from fuel use or power import

Justin Ellrich

Principal Process Engineer - LNG Systems Leader

Black & Veatch

There are various technologies proposed for the future export of Hydrogen as a low-carbon alternative to LNG including liquefaction, in the form of Ammonia or in Liquid Organic Carriers, all of which have techno-economic issues associated with them. The alternative of transporting Hydrogen in the form of CH4 then splitting into solid Carbon and Hydrogen at the destination port is not commonly discussed yet the liquefaction, transportation and regassification infrastructure is already there. Energy efficient technologies are emerging to separate the Carbon from the Hydrogen and produce valuable products such as Graphite, Carbon Black and Graphene able to be used in producing large scale batteries.

This paper presents a credible road map for the LNG industry to transition to a zero Scope 1, 2 and 3 emissions industry across the whole value chain. The paper addresses the steps being taken to reduce fugitive emissions, beneficially use and convert the CO2 extracted from natural gas streams, electrify the operation of LNG liquefaction facilities, use zero emissions fuels for LNG shipping whilst fully recovering boil-off gas then use emerging technologies to separate solid Carbon from the methane allowing the remaining Hydrogen to be used as a zero emissions fuel. The Carbon can be beneficially used as a saleable product that can pay for the conversion to Hydrogen making the whole process zero emissions and economically viable.

Several different technologies to convert CH4 to solid Carbon and H2 are evaluated comparing their economics technical maturity. These include methane pyrolysis using plasma technology as developed by Synergen, the latest research into methane pyrolysis from the Future Fuels Cooperative Research Centre, the Hazer process and the C-Zero process. These are compared to existing and widely used technologies such as Steam Methane Reforming combined with Carbon Capture and Storage which is often technically challenging in the regions that are currently importing LNG. The potential to use solid Carbon as a building product to reduce the demand for carbon intensive steel is also examined.

One of the main benefits of this pathway is that most of the infrastructure required already exists reducing the capital investment required, hence improving the economics. Another benefit is that there can be a staged progression to achieve zero emissions LNG driven by economics. This paper examines the cost of each stage of this road map then compares the economics of the whole value chain against other potential zero emissions technologies such as generating green Hydrogen in countries with ample renewable energy potential and exporting it to countries that do not. The economics are also considered in relation to the carbon price required to incentivize this strategy. Increasingly we are seeing a growing demand for low emissions intensity LNG with some analysts predicting that there will be a cost premium paid for low or zero emissions cargoes which becomes a further incentive for the gas industry to adopt this pathway.

Peter Cox

Vice President Energy & Chemicals - Australia East & PNG

Worley

Many countries are investigating various paths for a lower carbon footprint, including allowing green hydrogen to be added to their natural gas pipelines. This paper will discuss the effect of this hydrogen on LNG export terminals liquefying feed from these pipelines. The presence of hydrogen will affect the liquefaction process, but not necessarily in a detrimental way. The authors will show how to convert what could be a potential headache, into an asset for the site. The maximum amount of hydrogen that can be blended is limited by conduit metallurgy and end use appliances powered by this gas. Some countries are proposing up to 18% green hydrogen to be blended into their natural gas pipelines. This paper will explore the impact of various concentrations of H2 in liquefaction feed streams and propose new solutions for both existing and new-build plants. Pre-liquefaction membrane separation and post liquefactions cryogenic solutions will be discussed, along with hybrid membrane/cryogenic solutions.

Mark Roberts

Senior Research Associate

Air Products and Chemicals, Inc

Shell’s climate ambition to be a Net Zero Emissions energy business, by 2050 or sooner and in step with society, will require the decarbonization of all segments of the LNG value chain. The deep decarbonization of LNG export facilities presents both technical and economic challenges, which need to be addressed in order to realise this ambition. This paper will explore the key considerations, design choices and integration aspects for the decarbonization of both existing LNG Export Assets and future LNG Export Projects through the options of Electrification, alternative gas turbine firing solutions such as Hydrogen, and Carbon Capture, Utilisation and Storage.

Traditionally, LNG export facilities are located in areas where large electrical infrastructures are not available, and hence LNG plants typically have their own power generation utilizing natural gas to generate electrical power. However, these power generation facilities are relatively inefficient. Therefore, an opportunity exists to capitalize on the rapidly-falling cost of Renewable Power and battery storage to optimize and to decarbonize power generation in LNG facilities. In addition to reducing GHG emissions and creating a pathway towards a Net Zero Emissions LNG Facility, these solutions can result in increased LNG production, lower operating costs and improved reliability, adding to their economic attractiveness.

The largest source of emissions in an LNG facility stems from firing natural gas in the power generation and compressor gas turbines. Addressing this in a completely different manner through hydrogen firing requires vendor produced equipment modification solutions, but also needs either hydrogen supply or in situ infrastructure, in addition to optimal integration on existing plot space. Post combustion carbon capture is another credible option for decarbonizing LNG facilities, however there are significant challenges in separating the relatively low concentration of CO2 from the large volumes of N2 in the flue gas.

This paper will address the feasibility of each of these options, their relative decarbonization impact, and opportunities to optimize the solution space.

Christopher Hay

Senior Process Engineer, LNG

Shell Projects & Technology

The climate emergency is one of the biggest challenges humanity must face in the 21st century. We all need to be involved in the process of moving towards a decarbonized economy. At the same time, the advancing global energy transition faces many challenges when it comes to ensuring a sustainable, reliable and affordable energy supply. The energy industry is currently going through its biggest change in living memory, despite this gas and its valuable infrastructure continue to play a major role in a decarbonized and integrated energy system. Scaling up the transportation of renewable and low-carbon gases in our global existing and new build pipeline network is essential to deliver a reliable and affordable transition to climate neutrality. This paper will investigate the integrity implications of the introduction of hydrogen into existing and new-build pipelines. It will outline the major differences between hydrogen and natural gas from a pipeline integrity standpoint, and show how these differences can affect threats associated with pipelines. In particular the importance of material properties and crack susceptibility will be highlighted The applicability of existing codes to (converted) hydrogen pipelines will be investigated, and the concept of a hydrogen integrity framework and an underlying detailed roadmap will be shown. A holistic approach to integrity management will be discussed, including a detailed phased approach enabling operators to maintain safe and cost-effective operation during conversion. Some of the limitations inherent in existing codes (such as ASME B31.12) will be highlighted, and an engineering based approach to going beyond code while maintaining safety will be elaborated.

Roy Van Elteren

Head of Integrity Solutions

ROSEN

In this study, the design concept of OCCS (Onboard Carbon Capture and Storage) technology for 174k LNGCs was proposed, and the effect of the OCCS was analyzed in terms of managing the lifecycle carbon intensity of LNGCs in order to comply with the forthcoming CO2 emission regulation by IMO.

The OCCS system was designed to compose of an exhaust gas pre-treatment system, a CO2 capture system by chemical absorption technology, a CO2 liquefaction system, C-type liquefied CO2 storage tanks and a CO2 unloading system in consideration of the unique characteristics of exhaust gas from a state-of-the-art marine 2-stroke dual fuel engine. The design results show that it is possible to install the OCCS with a scale that can collect around 60 tons of CO2 per day and store it in liquid form during the round trip voyage of typical LNGCs with a slight reinforcement of existing hull structure. The optimized and patented solutions for onboard application was suggested to overcome limited utilities as well as footprint conditions on a ship. The solutions were comprising of

1. Advanced distillation column design for CO2 capture system considering the effect of ship motion based on the novel amine-based solvent with a low regeneration energy characteristic,

2. Dedicated waste heat recovery system from the exhaust gas from engines,

3. Optimized cold energy recovery system from the LNG fueled system, and

4. Dedicated boiler system with the exhaust gas recirculation technology.

From the energy balance calculation with combination of four patented solutions, it was calculated net reduction of CO2 emissions by up to around 2,000 ton CO2 per trip is achievable for the voyage route between North America to South Korea even considering the additional energy consumption for steam and power generation for the OCCS system operation. The optimal installation timing and the operating scenario of the OCCS was proposed for existing as well as new-build LNGCs in consideration of the typical operation route and operation profile of LNGCs in order to maximize the ship owners’ benefit while complying with the forthcoming CII (Carbon Intensity Indicator) regulation which is expected to be reinforced every year based on IMO’s GHG reduction strategy then it was concluded that the OCCS is a feasible solution to meet IMO’s ambitious target of 70% CO2 reduction by 2050 if the OCCS is implemented with combination of LNG fueled system.

Sanghyuk Lee

Senior Engineer

Samsung Heavy Industries

With the global need to decarbonize the atmosphere and our world economy heavily relying on a secure energy supply, one of the promising fast-track solutions to cover both challenges is Carbon Capture Utilization and Storage (CCUS). To achieve sustainable CCUS projects, there will be a need to transport CO₂ in an economical way and on a very large scale

To cover this need EXMAR is developing a medium sized liquid CO₂ carrier as a solution for the various CCUS projects which are arising in Europe and the rest of the world. The concept of CCUS is that CO₂ is captured from various emitters, cleaned, collected, liquefied, shipped and injected in an empty oil well where, due it physical properties, will remain stored in a safe way without harming the environment. Due to the physical characteristics of liquid CO₂ it should be transported under pressure at cryogenic temperatures. Current CO₂ carriers have sizes of abt. 3,000 m³ and transport the product at medium pressures of about 15barg in cylindrical IMO type C tanks. Looking at the potential volumes which will have to be shipped, these smaller vessels will not be sufficient to cover the demand. Building large cylindrical (or bi-lobe) tanks becomes challenging when it comes to constructability and finding suitable steel to deal with the combination of pressure a cryogenic temperature.

To tackle this hurdle EXMAR started a cooperation with LATTICE technology. The patented Latttice Pressure Vessel design allows the pressurized tank to be built in a prismatic shape (same as type A tanks or membrane tanks) which makes it possible to design the vessel with similar dimensions as a standard midsize gas carrier in a very cost efficient way. A feasibility study proved that the tank design provides the best solution for large-scale CO₂ transportation at low and medium pressures. The design and vessel size can be adjusted to meet all required transport volumes to ensure the most optimal logistical solution in the most cost-competitive way. For a similar capacity of ship, the length can be reduced with almost 30%.

Frederik Van Nuffel

Chief Technical Officer

Exmar Marine NV

First loading arms started operation at the end of the 50’s, replacing progressively hoses for shore to ship transfer. Since then, loading arms constantly evolved to adapt to energy and chemistry industries’ needs in terms of handled product diversity, operations safety, transfer capacities and vessels configurations.

With the Carbone Capture and Sequestration among the pillar technologies for the Green House Gas emissions’ reduction of the industries, a complete value chain is being created to capture, liquefy, store, transfer, ship and then sequester CO2 from the industrial emitters.

Being pioneer with the first marine loading arm (MLA) and then the first LNG MLA in the world, Technip Energies Loading Systems has always led its sector with innovation and new solutions’ development, and this innovation marker is again confirmed with the manufacturing of the 3 world first liquid CO2 Marine Loading Arms which will equip in 2022 the CO2 import terminal of the CCS Project “Northern Lights” in Norway.

Liquid CO2 could appear like conventional petrochemical when the comparison is limited to the range of temperature and pressure conditions during transfer. However, in addition to its highly corrosive properties for the piping, the CO2 remains in a liquid phase only when the product pressure is above 5.2 bara. As a result, in case of a pressure drop during the transfer operation or emergency shutdown, liquid CO2 could change to solid phase and form dry ice, causing process challenges and calling for mitigations in the loading arms’ design.

To mitigate these risks and constraints, Technip Energies Loading Systems conducted a comprehensive design and qualification program for the swivel joints, the Emergency Release System and the sealing system to ensure a full compatibility with liquid CO2 specific properties.

Some provisions have been made on the design of the loading arm to cope with the CO2 chemical properties in particular with the corrosive property, as well as on the compatibility of the seals with CO2, and the potential risks related to Rapid Gas Decompression on the seals. The evaluation of the consequences of a possible solidification of the Liquid CO2 in case of sudden depressurization has also led to design upgrades which will be detailed during the presentation.

Eric Morilhat

Technical Director

Technip Energies

The global warming due to the growing industrialization and economic developments is being scrutinized. The energy demand has significantly increased and still fossil fuels are being used globally with the associated CO2 emissions. On the other hand there is an ongoing energy transition to clean energy but we should not forget the developments in the field of carbon capture.

More specifically the maritime transportation is a traditional industry which serves global economy developments. Goods and products transported by ships have lower carbon footprint as compared to truck or air transportation, however there is also an increasing regulatory pressure to reduce GHG emissions by ships. IMO is to implement a new regulatory measure to push for further decarbonization of the maritime transportation by the new carbon indexes EEXI and CII. The regulations will enter into force in January 2023 with the main aim of a progressive reduction of carbon intensity on short term by at least 40% in 2030 and by 70% in 2050, compared to 2008 levels.

Carbon capture developments will obviously help reducing industry emissions and has been a proven solution in the industry onshore for various applications over years but scalability of carbon capture is needed to achieve further decarbonization. On the one hand carbon can be captured and simply stored. In addition carbon captured could be used for the production of new fuels like synthetic methane or methanol by the use of green energy.

CO2 captured in industrial processes can be liquefied and transported to a storage facility for sequestration or possible utilization. Transportation of liquefied CO2 by ships may be an efficient alternative as compared to pipeline or eventually trucks. Therefore along with the development of carbon capture projects, a shipping segment is being created to help liquid CO2 transportation on a more efficient way to reduce GHG emissions in the global chain.

LCO2 carriers are evolving in size and complexity from very small ships for the food and drink industry to larger volume for the carbon capture projects still at around 18 barg pressure. But the target for large scale projects currently being assessed is to design and build mid to large liquefied gas carriers with low pressure applications at around 6 barg. Being CO2 a gas with a very specific characteristics in terms of pressure/temperature diagram and density it seems that specific new designs will have to be developed as opposed to liquefied gas carriers conversions that have also been discussed. Carbon capture on board and other technologies will obviously help reducing the global carbon footprint of these projects.

Philippe Cambos

Director of Oil and Gas Projects

Bureau Veritas Marine and Offshore

Abstract: “CO2 shipping – drivers and opportunities” We have an overall aim to achieve net zero CO2 emissions in 2050, however and unfortunately, this will not be enough. Cumulative emissions from 2020 to 2050 are calculated to 630 Gt in our PNZ (Pathway to Net Zero emissions, Energy Transition Outlook 2021, by DNV). Comparing that to a 1.5°C carbon budget of 400 Gt, we therefore have an overshoot of the 1.5°C carbon budget of 230 Gt in 2050.

Several abatement technologies are under development within the different sectors, but to achieve our goal we need to capture a significant part of the CO2 and store it – in a safe and secure place underground – either onshore or offshore. For this purpose, transfer of CO2 via pipelines and “on keel” will play an important role going forward.

CO2 shipping has existed for more than 20 years, but only for commercial purposes. The fleet of CO2 carriers we have today are all small (less than 2K), medium pressure and classed with DNV. We have however recently seen 2 X 7.5K CO2 vessels been ordered at DSIC for the Northern Light project, for the purpose of carrying CO2 from the Heidelberg cement factory outside Oslo to a temporary storage site outside Bergen on the west coast of Norway, before it will transferred via pipeline, off the coast, into the seabed.

Johan Tutturen

Vice President, Special Projects - Gas

DNV

Context & Objective

Demand for LNG bunkering has been growing, with an LNG-fueled fleet which grew by 550% over 2016-2021, and is set to grow by +49% p.a. until 2024, according to DNV. Our in-house projections indicate an increase of LNG market share in global marine fuels from 6% in 2020 to 23.6% in 2035, as LNG replaces oil products to limit the maritime industry emissions. This growth requires an essential infrastructure: the small-scale LNG (“ssLNG”) reloading facility, integrated in a large-scale LNG terminal. As LNG bunkering develops, the design of adequate regulatory and commercial frameworks governing ssLNG reloading has become a central topic. Our research provides a comprehensive review of how ssLNG regulatory and commercial conditions are set, and how they compare across European and Asian terminals, providing market participants with a structured understanding of ssLNG infrastructure’s regulations and prices.

Approach

Regulation of ssLNG is generally influenced by the regulation or non-regulation of LNG terminals’ other activities, but with specific considerations addressing three possible market failures, where ssLNG could:

1. Form incomplete markets: infrastructure is not built for lack of demand, demand does not appear for lack of infrastructure;

2. Fail to incorporate externalities through cost sharing and environmental benefits, with inadequate levels of cross-subsidies vis-à-vis other gas users and taxpayers;

3. Offer excessive market power infrastructure owners: undue rents or inefficient pricing result.

In a first-of-its-kind exercise, we thoroughly reviewed the regulatory and commercial frameworks governing ssLNG infrastructure access and tariffs in more than 50 European and Asian LNG terminals, assessing and categorizing the answers provided by regulators, energy ministries and terminal operators to these possible market failures, along with the practical access conditions and tariffs for ssLNG infrastructure.

Results & impact

Our benchmark demonstrated a wide range of answers to the challenges of regulating ssLNG. We particularly noted that:

1. Risk sharing is addressed differently, from merchant models dominating in Asia, to de-risked approaches common in Europe, with sometimes asymmetric risk-reward models aiming at fostering market development (Spain) or at capturing rents for local end-users (Singapore).

2. Our analysis of the treatment of ssLNG externalities addresses issues of cost sharing between large-scale users and small-scale users, between gas network users and ssLNG users, and rules and subsidies set out to internalize the environmental benefits brought by ssLNG. Answers vary, with for instance almost all shared costs covered by large-scale LNG users in Croatia and Belgium, subsidizing of ssLNG infrastructure in the EU, or port cost discounts for LNG-fueled vessels in Singapore.

3. Concern about market power varies from no intervention in vertically integrated businesses in Japan, to detailed regulation up to the approval of every tariff in the EU. This role can also evolve over time: France deregulated ssLNG in 2021 after an unsuccessful regulation.

Our paper describes the families of approaches taken by regulators and terminal operators in the world, highlighting their advantages and limitations, as well as their practical consequences in terms of ssLNG access rules and actual tariffs.

Emmanuel Grand

Senior Managing Director

FTI Consulting France SAS

In 2021, a record 52 MMt/y of LNG sales and purchase agreements (SPAs) were signed. The price mechanisms for new deals have been evolving with gas and hybrid contracts representing a larger share of the market. With the signing of these deals, the longer-term market is more influenced by LNG/gas prices than oil. This is a promising development given the tenuous relationship between oil fundamentals and factors driving gas demand.

Not only have pricing trends shifted, but the players have, too, with more end-users and suppliers signing contracts rather than traders or aggregators last year. With the shift in players, so too came a shift in SPA tenors. There were more 16-20 years SPAs signed in 2021 than in recent years, reflecting the need to underpin financing for new projects.

Another factor to watch is what type of contracts will be signed by some of the new regasification projects under consideration in Europe as consumers try to wean themselves off Russian supply following its invasion of Ukraine.

The trends in today’s market represent a change in the approach to contracting taken by the industry. With today’s high prices and the extreme volatility, broadening the price indices allows buyers and sellers to spread out basis risk. Further, the lack of new capacity starting up in the next several years will keep the market tight and prices high. This could be exacerbated as sanctions against Russia threaten its access to technology and capital and thereby its ambitious LNG expansion plans. Whether other producing countries can bridge this potential supply gap remains to be seen.

Trends in 2022 are only starting to emerge. Short-term contracts may be hard to come by at reasonable prices as JKM and TTF remain elevated. Over the next three years, supply is forecast to grow only 35 MMt compared to 25 MMt in 2021 alone. However, long-term deals will still be sought as there are still many projects, especially in the US, looking to take FID. More contracts are expected to be signed in 2022 as sponsors look to make final investment decisions on 230 MMt worth of LNG projects.

To understand how the changing market fundamentals will affect future transactions, we examine:

• How shifting price formulas for today’s SPAs affect realized prices in the market versus previously signed contracts

• What is driving the behavior of buyers and sellers amid tremendous market uncertainty

• How will Russia’s invasion of Ukraine affect contracts in the market and will new players emerge?

• How contract length correlates with contract volume and buyer/seller type. Is one type of SPA preferred over another?

• The ability of sellers to leverage short-term market tightness in setting prices for long-term volumes.

• Which projects are likely to take FID based on their contract activity and how will other sellers respond to gain advantage over them.

Kristen Holmquist

Head of Data Analytics

Poten & Partners

The recent dramatic and unprecedented developments in the LNG market have encouraged and sometimes forced structural shifts in relationship between LNG market players. The global LNG market is expected to observe more interactions between different regions, as more consuming markets are emerging and supply sources expand, with some legacy LNG sales contracts expire. Market players' compositions, business models, and their behaviours are all evolving.

Although traditionally big LNG buyers and sellers continue respecting their relationship with traditional counterparties, some of those parties have come out of their fixed roles to assume different roles in the LNG market. Traditional LNG buyers in Japan sell more secondary cargoes to other buyers in the surrounding region and traditional LNG sellers buy more LNG cargoes from third parties more regular basis. Japanese trading houses assume more roles as project developers on both producing and consuming sides, as well as trading commodities - both LNG and gas-fired power outputs.

As many players optimise their own positions depending on market conditions, traditional volume and demand adjustment under fixed term contracts have gradually decreased. Some forms of good-faith arrangements have now been converted into more commercial-oriented deals with prices on them.

LNG market players have recognised the above-mentioned structural shifts in the LNG market with more flexible volumes and arrangements with expansions and evolutions of LNG supply sources, as well as mushrooming LNG consuming markets in Asia and Europe. Since traditional LNG project development models of vertical integration from wellhead production to final consumption are about to go, the market needs to find alternative ways to secure funding to develop additional LNG value-chains to meet expected gas demand in the future.

Long-term contracts are expected to continue playing key roles to underwrite LNG production projects, although contracts length and final consuming market commitment may differ much from traditional ones. This aspect will be even more important with an expected smaller role of Russia as an incremental LNG supply source in the wake of the recent conflict in the western side of the Former Soviet Union - although the existing LNG projects in the country should continue being important.

To make different arrangements possible, different types of alliances between parties - trespassing regional borders - should increase in the future.

This is particularly important for Japanese players, who have been and will be key players in the LNG market, as one of the biggest LNG consuming markets in the world and the most important players in the market dealing with more than 100 million tonnes per year of LNG - not only buying but also selling and trading cargoes.

The Japanese players are expected to continue contributing to the healthy development of the global LNG market in the years to come, through alliances with players in other countries. Potential collaborations include joint procurement arrangements - by combining markets with different seasonal demand profiles could mitigate fluctuations of market balances, swapping volumes depending on market conditions, as well as joint infrastructure development in emerging markets.

Hiroshi Hashimoto

Head of Gas Group

Institute of Energy Economics, Japan (IEEJ)

Energy transition – the long-term shift towards a mix of low- or zero-carbon energy sources – is a critical global imperative. Even so, ADI Analytics’ modeling has shown that even in the most aggressive and rapid energy transition scenarios, natural gas will contribute to as much as 15% to 20% of the global energy mix in 2050. Natural gas and, in particular, LNG’s role are well known in cutting down greenhouse gas emissions by displacing coal for power generation.

What is less appreciated is that LNG, in particular small-scale projects, can accelerate the Energy Transition at a faster pace by displacing diesel whose use for back-up power generation in some emerging economies can be more CO2-intensive than coal-fired power generation. Recognizing this opportunity to enable Energy Transition through small-scale LNG, ADI Analytics co-led a study assessing the potential of small-scale LNG specifically in Central & Eastern Europe as a regional case-study. The project was based on a mix of primary and secondary research, market size and greenhouse gas emission modeling, and consultations with a wide range of stakeholders.

A few key findings of our are presented briefly here:

1. A third of the countries in the region can immediately benefit from small-scale LNG given the growth in their economy growth and demand for diesel, remote energy, and natural gas. Also shown in the exhibit, are Czech Republic, Slovenia, Croatia, and Bosnia & Herzegovina that have opportunities in the medium-term and Austria, Bulgaria, Kosovo, Romania, and Montenegro that have long-term opportunities around use and adoption of small-scale LNG.

2. Trucking and industrial followed by marine are promising applications for small-scale LNG in Central and Eastern Europe. Payback periods for LNG-fueled trucks are most attractive followed by ships and industrial boilers with robust price differentials to incumbent fuels in most cases. Industrial demand will be in areas inadequately connected to existing gas grids and defined as remote energy demand in our study.

3. We find that the region has limited LNG infrastructure and particularly at the smaller scale. Even so, LNG is increasingly cost-competitive that it can compete even if trucked or barged into the region from nearby terminals. New investments are necessary in small-scale LNG services at existing or upcoming terminals or new sea and river ports to handle ISO containers.

These and other findings from our work will be shared further in our presentation at Gastech should this paper be accepted.

Uday Turaga

Chief Executive Officer

ADI Analytics LLC

Bjorn Otto Sverdrup will share a fresh vision of the oil and gas industry as a lead protagonist in the climate emergency survival story. His call to action will frame a vision for supporting the broad transformation of society to meet a collective goal of removing 20-gigatonnes of carbon from our atmosphere.  

Bjorn Otto Sverdrup

Chair of the Executive Committee

Oil and Gas Climate Initiative (OGCI)

How can climate-aware energy players work with Industry 4.0 disruptors to harness the new and emerging technologies and accelerate the net zero transition?

Marco Alverà

Chief Executive Officer

TES-H2

Our expert speaker will examine energy system investment priorities, as well as how they are evolving in the context of geopolitical and economic uncertainty to reframe financing choices on the journey to decarbonisation.  

Anna Mascolo

Executive Vice President, Emerging Energy Solutions

Shell

The LNG and gas markets are going through unprecedented times. A combination of factors led LNG and natural gas prices reach historical highs: in absolute values and in terms of volatility. In 2021, some of the factors behind the price moves were temporary and conjunctural: cold and prolonged winter delaying storage injections in Europe; drought in Brazil; post-covid economic recovery, in particular in Asia. Other factors were structural like the scarcity of spare LNG supply and shipping capacity. Some other factors - perceived as temporary last year - risk becoming structural: this is the case of the geopolitical tensions between Russia and the West with their effect – realised or potential - on gas and LNG flows.

In normal times, gas prices have a seasonal shape reflecting supply and demand dynamics and the needs to have adequate levels of gas in storage to face unexpected events, mostly linked to weather. In a tight market situation as experienced in 2021 though, prices temporarily diverge from usual trends with correlations between regional indices or other related commodities dropping and price volatility rising.

The structural factors leading to price anomalies in 2021 - in particular the tightness of the LNG market - are expected to last until 2024/2025 on the back of steady demand growth but primarily given the lack of LNG supply investments in recent years. This could be exacerbated by the current geopolitical situation which is leading to LNG being increasingly seen as the most efficient and flexible tool for gas supply diversification in Europe. Thus, we can expect price divergence from common trends, volatility and unstable correlations to characterise the market over the next few years.

The first wave of incremental LNG volumes coming to the market will be the one linked to projects sanctioned in 2019 with 40% to 50% of these located in the United States. Given the peculiar business model of the US LNG projects with contracts not linked to a specific destination and the presence of several portfolio players as lifters, those volumes will play a key role in helping navigating uncertain times and uncommon price evolutions. Indeed those players having invested in optimization capabilities and more flexible portfolios will be able to adjust to changing market dynamics, explore more market opportunities, and achieve long-term resilience. In order to ensure this constant match of supply and demand in a tight market environment, LNG trading and the share of the spot and short-term market are set to grow. Instrumental to this is a liquid, flexible and competitive shipping market requiring a large number of players, a high level of trading and spot chartering activity so that charterers are able to find a vessel whenever it is required, and available to deliver wherever they want. Ultimately and from a broader perspective portfolio optimizers and a well-functioning shipping market can have a positive impact on the energy market by reducing inefficiencies and making the overall system more resistant to shocks leading to more affordable, uninterrupted energy available around the world.

Patrick Dugas

Vice President, LNG Trading

TotalEnergies Gas and Power

Another year of volatile LNG freight rates and more records being broken as rising LNG demand pushed and pulled against supply constraints. Our BLNG2g benchmark (LNG-fuelled US Gulf to UK round voyage) reached a peak of USD 265,067 at the end November, as Europe struggled to secure enough cargoes to meet projected winter gas demand, before sinking to negative USD 14,489 by 25 February 2022. Just two weeks later, rates rose sharply again with the Russian invasion and the real and perceived insecurities that threat brought to the market.

We have examples in the past year of there simply not being enough LNG vessels to meet demand and rates skyrocketing as Shippers scrambled to fix ships. We know that demand is ever growing; China alone increased its LNG imports to 79 million tonnes in 2021. In 2021, the global demand was calculated at around 365 million tonnes, and it is projected that by 2040 LNG demand will rise above 700 million tonnes.

With the promise of higher average rates then, the market might appear rosy for the Owners of LNG vessels (if their vessels are in the right position to take advantage, that is) but what about the 140 LNG vessels on order?

So, what does the outlook appear to be? Here we can turn to our Baltic LNG Forward Assessments. Currently (end March) the market is pricing Q4 2022 BLNG2g (LNG-fuelled US Gulf to UK round voyage) at $135,000 per day but we know from experience it takes very little to tip freight rates in either direction. Incidentally, Q1 2023 BLNG2 (IFO-fuelled) is pricing at $83,125. This time last year Q1 2022 was priced at $62,625; it is currently at $15,284.

The question is then, how is an LNG freight market participant expected to manage their bottom line with this amount of volatility? Volatility well beyond normal seasonal fluctuations.

The answer, we believe, lies with the Baltic Exchange LNG Freight Indices. Founded in 1744, the Baltic Exchange is regulated by the UK’s Financial Conduct Authority (FCA) and is the trusted provider of data for the settlement of physical and derivative freight contracts, underpinning risk management tools for the shipping and transportation markets.

We believe there is no reason why the developing spot LNG market cannot enjoy the same hedging tool benefits experienced by the wet and dry shipping markets, and this is why we created our BLNG freight indices.

Our presentation will give an understanding of the BLNG indices and explain basic risk management using BLNG FFAs to mitigate the effects of freight volatility, as well as practical application of BLNG FFAs to freight contracts and time charters. We will discuss why it matters that it is the regulated Baltic Exchange that is producing these indices and our role in supporting the cleared FFA markets. Additionally, we will cover BLNG OPEX Indices, whereby vessel operational costs can be tracked with our quarterly assessments.

Matthew Cox

Head of Benchmark Production

The Baltic Exchange Ltd

Interest

A look at long-term LNG time charterparty negotiations from an Owner and Charterer perspective. With the significant growth in the industry over the last 15 years or so is it possible that the industry could develop a “standard form” long-term project LNG time charters to streamline LNG charter tenders?

Topicality

With a number of large orders for LNG carriers being placed and energy security being the word on everyone’s lips, does the industry still have time for time consuming LNG shipping tenders? A discussion regarding time-consuming elements of LNG project time charter negotiation.

Originality

In a fast-moving world, a speedy understanding of each party’s main drivers in LNG charter negotiations could help free up significant resources in manpower and time.

Richard Howley

Partner, Head of Asset Finance

Norton Rose Fulbright

Russia’s invasion of Ukraine saw gas prices spike, with Italy switching back to coal power and Germany fast-tracking the construction of two LNG (Liquefied Natural Gas) terminals while extending the life of its coal and nuclear power plants. With the Nord Stream 2 pipeline now suspended, Europe is in a difficult position moving into next winter, with gas storage levels close to a five-year low and LNG imports near capacity. This has led to a huge effort to move away from Russian gas dependence and an acceleration of the energy transition including €300 million of funding for renewable hydrogen. European exposure to Russian gas is highest in Eastern Europe where 60% of gas demand is supplied through Russia. in Southern Europe this falls to 20% with imports coming via North Africa. Investors in blue hydrogen in Eastern Europe may see the region as an unacceptable risk (due to its high exposure to Russian gas) and look to develop projects in Western European countries such as those in the North Sea region and the Iberian Peninsula where exposure to Russian gas is minimal. However, blue hydrogen projects in Portugal and Spain would have to compete with green hydrogen projects in the region which are likely to produce gas at less than $4/kg based on recent renewables auction prices. With current gas, electricity, and carbon emissions costs, blue hydrogen has reached over $14/kg in recently making it significantly more expensive to produce than green hydrogen. As blue hydrogen costs are highly dependent on gas prices, the effect of Russia’s invasion of the Ukraine could lead to long term increases in gas prices and supply risks, boosting green hydrogen investments at the expense of blue hydrogen projects and spelling the end of blue hydrogen in the region.

Minh Le

Lead Analyst

Rystad Energy

We have been here before: Two decades ago predictions were made, plans laid, budgets committed, headlines boldly announced the ushering of a new era, conferences debated the best way forward, billions of public and private funds were invested, deals announced and, yet, hydrogen production methods have not meaningfully changed, its price has hardly budged and, disconcertingly, its carbon footprint remains unacceptably high.

The attendees of this conference are at the vanguard of the industry and it behooves us to find what the stumbling blocks were. If we fail to learn from past errors, today’s energetic drive toward multicoloured hydrogen, media frenzy notwithstanding, could quickly evaporate in a colourless whiff of nothingness as similar drives did before. We owe the next generation, our investors and ourselves a hard cold look at (i) the root causes for failure; (ii) what current policies and regulations aim at; (iii) what they are likely to achieve; and (iv) what better targets should be.

The analysis must begin with the needs and preferences of end-users who drive companies revenues and policy makers’ duration in office. End-users not only vote but also - if lucky - buy food every day and choose between firewood and heating oil, and consider global warming as one of the many challenges to their wellbeing and comfort. Hydrogen touches every aspect of our lives. It allows us to have enough food for eight billion people and low-cost transportation and heat.

The prices of food and fuel is how revolutions are born: Fear of tomorrow’s flood never equals the raging anger when you cannot afford to feed your child. Understanding end-users’ needs, preferences, price elasticity, and how it may impact politicians is crucial to the resiliency of the hydrogen's necessary revolution.

The looming threats of climate change and risks to energy security, fuel public anxiety and lead to seemingly accommodating policies. While capitalising on this momentum, we should be cognisant of the brevity of political attention span and fluctuating priorities. We should also be concerned about what is becoming a grants feeding-frenzy, inadvertently garnered by certain policies, where deep pocketed leading companies compete for grants for implementing the equivalent of high-school science projects.

Governments resources and supportive policies are insufficient - and too ephemeral - to get hydrogen to reach its full potential. Worse still, misallocations of resources and risk making, due to short-lived accommodating policies, have historically caused more damage than good (ethanol, nuclear industry).

The scarce available resources should focus on lowering the cost of emission-free hydrogen production dramatically below SMR’s as the only practical way to get economics behind the vision and making it a reality. Commodities' price is the single most powerful predictor of demand. Policies should set performance standards and timelines (CFC, lead-free gasoline), and the market should develop technologies to meet these. This approach is more likely to inspire the cost breakthroughs necessary for emission-free hydrogen production, decarbonisation of industrial demand, and a realistic vista for hydrogen use as fuel.

Matty Vengerik

Director

g2H2 Ltd

Discussion of hydrogen as a fuel in the United States is not new. The 2000s saw President Bush advocating for the development of a “hydrogen economy” where hydrogen was primarily meant to be used as a fuel within the transportation sector to curb the US’ demand for oil. However, recent discussions of hydrogen within the US have taken a different tone. Hydrogen is now not simply meant to replace gasoline and diesel in the transportation sector, but also to serve as a decarbonization agent for many other sectors of the economy.

Officials in Washington, DC are actively discussing measures that could drive demand for clean hydrogen within the US and project developers are reacting. The most discussed hydrogen-related policy measure in the US has been the $8 billion available for the development of hydrogen hubs. This $8 billion is meant to be split across at least four hydrogen hub systems, each of which will demonstrate supply and demand options. For example, at least one hub must be focused on the production of clean hydrogen via nuclear power, and another must be developed in a region that has historically produced natural gas. With the $8 billion allocated, the Department of Energy (DOE) will release the request for proposals (RFP) through which it will solicit bids for hydrogen hub funding.

The second most discussed measure in US hydrogen-related discourse is that of the tax credit for clean hydrogen production. This tax credit is available to clean hydrogen producers throughout the US, either as an investment tax credit (ITC) or a production tax credit (PTC). The PTC is the more discussed of the two. This PTC, as originally drafted in the Build Back Better Act, is a tax credit granted to the hydrogen supplier based on the amount of clean hydrogen produced and the carbon intensity of the produced hydrogen. If the produced hydrogen emits less than 0.45 kilograms of carbon dioxide per kilogram of hydrogen produced, it qualifies for a $3/kg tax credit. While this bill has not been passed into law – and there are many strings tied to the actual qualification of the tax credit – commercial enthusiasm around the development of a hydrogen sector in the US is predicated on this PTC.

These two policy levers, combined with decarbonization goals and a desire to continue developing technology that competes on a global scale, have driven newfound interest in hydrogen as many see an opportunity to extract significant value from the sector. One should expect ample change in the US hydrogen landscape between March and September 2022 as Congress continues to deliberate, and will potentially pass, the PTC and the formal RFP for hydrogen hub funding from the DOE is released. However, even with this enthusiasm, significant strides must be taken regarding the development of a regulatory framework for hydrogen in the US as the gas moves from an industrial feedstock to a more robust energy vector.

Drake Hernandez

Senior Associate

Charles River Associates (CRA)

The present abstract will illustrate a case study showing feasible opportunities to capitalize on the conversion of existing decommissioned power plants operating with heavy fuel oil to be converted to a natural gas powering electrical plants.

The western region of the USA was quite famous for its rugged and huge operating power plants with heavy fuel oil. Due to the environmental burdens and restrictions concerning emissions, in the last few decades the Independent Power Operators (IPP) along with California Environmental Officials decided for the prompt replacement of these units. The case study is based under the dilemma of the decommissioning and demolition costs compared to innovative alternatives of revival and transformation for these goliath 300 Mw-Hr. power plants to be converted to natural gas (LNG) power plants.

The economic studies were evidently clear to show the costs associated with demolition and the environmental spillover to remove them. Therefore, the suitable and convincing alternative to disassemble these plants to their bare bones and later completely overhaul them with brand new turbines with certification F-5, new dynamos, boilers, control panels and multiple sub-systems gave the awesome opportunity to obtain fully re-powered and overhauled power plants feed with natural gas under an operating combined cycle, which it's a miracle of thermodynamics with excess outputs over 15% of the final electrical loads.

Thus, with all these evident developments, there is no further reason to speculate why a nation or an IPP can’t use natural gas to feed power plants.

Benefits associated are so many, let’s start citing the main ones, the level of emissions will obviously reduce so significantly that the contribution to carbón credits will be a major plus, in addition, the use of a new power source will produce a new pool of economic development in supply and demand, also new sources of well paid jobs and more importantly, a steady source of clean power with very low emissions controlled with leading edge technologies to minimize impacts on the environment.

Now, let’s talk about aspects that many developers in the trade would like to hear, the comparative cost and schedule of implementation under engineering-procurement-construction (EPC) contracts under normal economic trends the cost to produce a Mw-Hr in new power plants can vary between $1.1 to $1.7 million US dollars and the time to fabricate them can take between 3 to even 5 years, because the major manufacturers of the world are just only 5 to 6 and they have established orders and schedules to observe, so the time it’s brutally impacted to make these decisions.

In comparison a re-powered and fully overhauled power plant can be delivered with discounted cost of 25% to 30% from the new ones. Regarding schedules of implementation, these ones can be developed in record times to a minimum of 12 months to an average of 18 months depending of geographical location, logistics and local laws to allow a quick permitting process.

Carl De La Fuente

President and General Manager

Pacific Blue Technologies, LLC

This paper describes how Shell, Bechtel, and Cumulus achieved substantial leak reduction and productivity savings deploying a novel digital flange management system on 120,000 bolted joints at Shell's new Pennsylvania Chemicals facility (PennChem). Pre-commissioning pressure testing performed in 2021 found that flange assemblies performed using this new system had an approximately 0.1% leak rate, easily a 100-fold reduction in the leak rate compared to the over 10% leak rates often seen on projects using traditional methods.

Nearly 20% of leaks at LNG facilities and chemical plants can be traced to some form of improper flange management during construction or maintenance activities. Engineering standards such as ASME PCC-1 provide well understood technical guidance on proper bolted joint assemblies; however, adherence to PCC-1 and other widely accepted industry standards can be hampered by ineffective training programs, unqualified inspectors, conflicts of interest between contractors and owners, and inadequate recordkeeping.

Digitalization can be a force multiplier for project engineering and inspection teams. By transforming existing processes. Shell, Bechtel, and Cumulus successfully scaled a new digital technology to enforce project engineering controls and digitize recordkeeping for more than 120,000 bolted joint assemblies on PennChem during a three-year construction period.

Transforming engineering controls and eliminating paperwork significantly reduced leaks on the PennChem project when compared to projects using traditional methodologies. The system also improved the productivity of the entire project team, from pipe fitters to field engineers to project management. Digitalization proved particularly valuable in maintaining records and avoiding rework when the project was shut down for six weeks at the start of the COVID-19 pandemic.

However, the project team encountered numerous challenges deploying the system at scale. Obstacles the team overcame include managing data inputs, handling data conflicts between systems, validating data output from the system, training the craft, and encouraging a workforce to adopt new methods.

Matthew Kleiman

Chief Executive Officer

Cumulus Digital Systems

John Tottenham

Innovation Implementation Manager

Bechtel Corporation

LNG plant start-up is a challenging process that requires simultaneous control and monitoring of different units. Any wrong decision or miscommunication could cause delays to rectify issues, costly maintenance and loss of production opportunity. Typically, different panel operators have different approaches to start-up the plant based on their individual experience and tacit knowledge, yielding varied results. To capture the valuable tacit knowledge from experienced operators and leverage on data insights from over two decades of operating the facilities, an AI-driven live advisory was developed to provide panel operators with real-time parameters control advisory in response to actual unit conditions, enabling consistent and optimised plant start-up. Combination of machine learning algorithms was used to learn from 3.4 billion data points from over 1800 sensors readings for the past 20 years. The model built predicts the main cryogenic heat exchanger (MCHE) temperature profile with respect to inputs and controllable parameters. The predictive model is then augmented with optimisation algorithms to generate real-time advisory of the parameters control that would result in optimum cooling down of MCHE, given the actual state of the plant. Inputs from experienced panel operators and engineers were also codified in the algorithms to ensure the advisory generated is feasible considering process and equipment limitations. The live advisory has been employed in seven start-ups of LNG trains in PETRONAS LNG Complex for pre-cooldown process. It successfully achieved consistent and optimised cooling rate of MCHE, resulting in reduction of overall duration by 42% and carbon emission by 14%, as compared to the past average. On top of that, six of the start-ups achieved the top pre-cooldown execution in the last 20 years when benchmarked against all the historical occurrences of the respective plants using established criteria like overall duration, temperature rate of change, temperature compliance and gas usage. The innovation has also received recognition by professional and reputable institutions at international level such as IChemE Global Award (Process Automation and Digitalisation), Gastech Engineering Partnership of the Year and Malaysia Technology Excellence Awards (AI - Oil & Gas).

Kian Seng Lee

Product Manager

PETRONAS

The development of digital solutions, automation and robotics has tremendously advanced during the past 20 years. Robots explore neighbor planets and build cars, 3D printers produce machine parts, unmanned drones survey the ground and cars are currently learning to drive autonomously. These developments will affect the future of plant construction as well. The advantages are obvious. Robots can work during day and night. They also can execute works that may be too dangerous for human being. Robots do not get tired and continuous work quality can be expected as well as increased all-over working speed. The work results can be expected with upmost design conformity avoiding costly changes during execution. A further advantage is the direct link to the engineering data base that feeds all actual working information in and back. The minimization of interfaces will lead to all-over performance increase resulting in a shorter schedule and reduced execution costs. Experiencing the ongoing pandemic, a conclusion is that robots are robust against infections and are not impacted from such.

TGE’s vision is, the today available robot technology will soon be applied also to the construction of storage terminals. This will for instance include welding robots, supervision and laser scan drones, material transportation robots, 3D printing, painting robots and many more This presentation will outline and present the current developments, discuss the advantages, and show a robotics-animated movie construction in a real TGE liquefied gas terminal.

Julian Terpitz

Product Development Manager

TGE Gas Engineering GmbH

Forecasting a project schedule is a key enabler of a successful project management. Accurate schedule prediction leads to better resource management and ultimately more value gained from the investment made for the project. The higher the complexity of the project, the higher the importance of having an accurate schedule prediction to minimize the risks associated with the project.

Accurate forecast of project schedule has been attempted using off-the-shelf project management software where each project tasks and its estimated duration are inputted into the software and the software calculated the estimated project completion. Using this method, the software can only calculate the estimate completion of the whole project but not the completion of the individual tasks. Although useful, it can still be improved. With the advancement of data science technology and the immense amount of accumulated data from previous projects, there is an opportunity to leverage machine learning method to predict task completion with high accuracy.

The Field X Expansion Project provided an excellent case study of successful pilot implementation of supervised machine learning to predict the completion of the project tasks. The Field X Expansion Project is designed to further increase total daily production from the giant Field X reservoir and maximize the ultimate recovery of resources. The project itself costs more than USD 45 Billion, therefore it is crucial to complete the project on schedule to maintain its economic value. However, the challenging project terrain and geography, unforgiving weather and project logistics from all around the globe brought uncertainties and complexities to the schedule prediction that conventional method cannot solve.

This paper discusses the big data analytics approach in predicting individual project task completion by pulling the tasks data from the project management software database and analyzing the impact of various variables and features of the project to the project schedule. The features with the most significant impact is then used as predictors to forecast the completion of each of the project task. Using this method, task completion can be predicted with 93% accuracy and 90% recall. With this accuracy the project can avoid millions of dollars loss from poor project management.

Ir. Muhammad Riandhy

Field Engineer - PSM

Pertamina Hulu Rokan

Korea Shipbuilding and Offshore Engineering (KSOE) develops new marine hydrogen system to commercialize liquid hydrogen carrier. KSOE’s onboard hydrogen system consists of safe liquid hydrogen tank and cost-effective hydrogen cargo handling system. HYUNDAI LH2 Carrier is the concept ship equipped with KSOE’s hydrogen system.

At present, the main technical issue on liquid hydrogen carrier is to manage generated boil-off gas (BOG), which is 10 times of that from LNG, and there are some concerns that liquid hydrogen cannot be transported by ships with current technologies. As the solution of this issue, HYUNDAI LH2 Carrier is equipped with double wall vacuum tank and LNG-H2 mixed fuel burning engine to consume generated BOG, which enables zero hydrogen cargo loss during voyage.

KSOE develops new marine liquid hydrogen tank with the capacity of 5,000 m3. This tank is designed to accumulate the generated BOG during voyage. Double wall vacuum tank technology is proven technology for land applications but it is the first large tank, which can maintain its strength and insulation performance under marine conditions with various loading conditions, ship motions, and various ship operations.

Pressure control is the key technology of liquid hydrogen tank. In LNG carriers, it is general to install re-liquefaction system to re-store BOG in liquid state, which can minimize BOG waste during voyage, but it consumes additional power and increase the cost of the ship. Furthermore, since hydrogen can be liquefied by expensive helium gas only at the extremely cryogenic temperature, hydrogen re-liquefaction system seems non-economical and has not been developed so far. KSOE’s new liquid hydrogen system, instead of utilizing re-liquefaction system onboard, controls the pressure by utilizing BOG as the fuel of engine. The ship is equipped with LNG-H2 mixed burning HIMSEN Engine by Hyundai Heavy Industries (HHI). HHI completed H2 fuel blending burning test in 2022 and the results show that HIMSEN engine runs on a blend of 50%v hydrogen without additional hardware change. This percentage enables maintaining tank pressure more safely without any cost increase and additionally it makes a result to lower carbon emission from the ship.

Based on new marine hydrogen system, KSOE is conduction joint development projects for techno-economic assessment for marine hydrogen transport to Korea with international hydrogen companies. Those project covers total marine hydrogen value chain including hydrogen production, liquefaction, liquid hydrogen terminals, and ship transport. Those  simulation studies show that no hydrogen cargo is wasted during voyage by adopting KSOE’s marine hydrogen system onboard, which indicates that new marine system can provide cost-effective ship solution and accelerate the commercialization of liquid hydrogen shipping.

Dr Byeongyong Yoo

Vice President

Korea Shipbuilding & Offshore Engineering (KSOE, HHI Group)

The emergence of a hydrogen economy now has real momentum and represents a major opportunity for energy producers – many of whom have existing skills, experience and infrastructure which can be repurposed for the hydrogen industry. However, there is a missing piece of the jigsaw when considering the full value chain for hydrogen.

This is the ability to store and transport hydrogen in large quantities. Hydrogen as an energy carrier has a relatively low volumetric energy density compared to fossil fuels, resulting in significant handling difficulties. A solution for transporting hydrogen at scale from one location to another to balance supply and demand and to reach large scale end-users is therefore needed. The UK Government commissioned ERM to design two industrial scale trial projects to address these considerations. Key learnings from these projects will be presented to Gastech delegates, including technical challenges and solutions, commercial drivers and optimizers, and health, safety and stakeholder considerations and approaches.

The two industrial scale trial projects together cover the full value chain for liquid organic hydrogen carrier (LOHC) storage, transport and use in a marine context. LOHCs are a viable means of transporting hydrogen in large quantities and have several advantages over other carriers such as ammonia, methanol or liquid hydrogen. In particular, LOHCs can be stored at ambient pressure and temperature, enabling the repurposing of existing oil infrastructure for storage and transportation.

The first industrial trial evaluates the feasibility of storing LOHC in conventional oil storage tanks, transporting it via oil pipelines, transporting it at bulk scale using conventional marine tankers and loading/unloading at existing oil jetties using standard equipment (loading arms, valves, pumps, etc). Both the technical and economic feasibility are considered. The trial includes a controlled series of tests to demonstrate how LOHC performs in terms of fluid behavior, hydrogen retention, level of contamination from residual contaminants in pipelines and storage tanks, etc. The second industrial trial involves demonstrating a design for a bunkering vessel that can supply large quantities of hydrogen at high pressure to local marine vessels in ports using a cargo of LOHC.

The vessel is a carrier of ‘charged’ LOHC (i.e. LOHC carrying a high quantity of hydrogen) and is designed to enable hydrogen to be released from the LOHC on-board and the ‘depleted’ LOHC (i.e. LOHC with hydrogen removed) to be stored in a unique cascade tankage system. The released hydrogen is compressed and used to supply other hydrogen vessels at high pressure (300-700 bar) or, at lower levels of compression, used to directly connect to a hydrogen supply line onshore (e.g. the hydrogen equivalent of an LNG regasification vessel). Insights from these industrial scale trials will be presented to Gastech delegates. The learnings cover the entire LOHC value chain including storage, transport and use in a marine context – and there will be particular focus on the technical and economic potential to repurpose existing oil and gas infrastructure for hydrogen transport via LOHC.

Molly Iliffe

Principal Consultant

ERM

The world needs to take urgent action to tackle climate change. The Paris Agreement set a goal of maintaining the rise in the global temperature well below 2°C above pre-industrial levels and to pursue efforts to limit the temperature increase even further to 1.5°C.

In April 2020, Shell extended its previous environmental ambitions to be a net-zero emissions energy business by 2050, or sooner, in line with society. There is growing political, societal, and financial market pressure to accelerate decarbonisation. One of the key sectors in focus is Shipping. Shell has a significant maritime presence as a vessel operator, charterer, and fuel supplier (bunker fuels and LNG) and recognizes the need to decarbonise the international shipping sector. Global seaborne trade is forecasted to more than double by 2050. To reduce its impact, the fleet needs to dramatically reduce its forecast emissions, while growing to meet the demands of expanding trade. The shipping sector is looking for new marine fuels to reduce its dependency on hydrocarbons to help meet international emissions reduction targets. One fuel being evaluated is hydrogen. However, for hydrogen to be a successful energy source, it needs to be produced in regions of low cost renewable energy, or have access to CCUS, and this means it will need to be shipped to locations of high energy demand. In gaseous form hydrogen has a relatively low energy density (compared to hydrocarbon fuels), and therefore to be transported economically it needs to be shipped in liquid form.

Understanding the potential energy losses in bulk transport of liquid hydrogen, especially when loading and discharging to or from ships is critical. To date, limited research has been carried out in this area, therefore this paper will undertake thermodynamic calculations using the Darcy-Weisbach method to investigate these losses to inform future ship designs. Various arrangements of vacuum insulation piping, pumps, valves and other components are studied. The paper demonstrates that the losses in loading and unloading liquid hydrogen from a ship can result in a product temperature rise of up to 2.15K. In addition, liquid hydrogen temperature increases during loading and discharging as pipeline diameter reduces and length increases for a range of scenarios modeled. The work provides a shipyard or designer models that can support the design of future liquid hydrogen carriers and therefore help enable the zero carbon fuel required to meet the Paris Agreement goals.

James Helliwell

Project Engineer, Technology

Shell

The hydrogen industry has decades of experience in generating liquid hydrogen, albeit only on a relatively small-scale. In the coming years, however, the demand for hydrogen is expected to dramatically increase as the mobility market shifts to carbon-free fuels, such as hydrogen for use in fuel-cell electric vehicles (FCEVs). At a time when renewables are becoming cheaper, the importance of hydrogen production and transportation in the energy transition and global net-zero commitments is more critical than ever before.

Hydrogen transportation and storage are energy intensive and are more commonly performed in liquid form using insulated cryogenic vessels to minimize the boil-off gas. In liquid form, hydrogen is 800 times smaller in volume than in gaseous form. This tremendous change in volume allows significant increases in energy density, which is crucial for efficient high-volume hydrogen transportation and storage. Depending on geographical location and transportation opportunities, hydrogen liquefiers can be small scale and localized with productions ranging from 10-30 TPD (tons per day). Alternatively, they can be large scale (industrial size) with capacities up to 500 TPD. The liquefaction processes are either the traditional Claude cycle or closed-loop Brayton refrigeration cycle, both of which involve pre-cooling down to 90 K and further primary cooling down to 29 K or lower. Pre-cooling is normally achieved with liquid nitrogen or the nitrogen refrigeration cycle. And primary cooling is performed either by pure hydrogen, a hydrogen-neon mixture, or helium, depending on the end-user preference and process optimization considerations. Refrigeration for all liquefiers is provided by turboexpanders, which expand high-pressure hydrogen (or other refrigerant mixtures) in a near-isentropic process. Rotating equipment optimization can facilitate a substantial reduction in the liquefier specific power, defined in units of kilowatt hours per kilogram of liquid hydrogen (kWh/kgLH2) produced. In state-of-the art liquefiers, the turboexpander shaft power is also utilized either for re-compression of the refrigerant or for electricity production, both of which will further reduce the plant specific power.

Process optimization involves using high-speed oil-free turboexpanders, a special aerodynamic design for high head and low volume, and minimizing heat losses and parasitic loads. This paper includes a review of the challenges surrounding different-sized liquefiers, an economic review examining liquefiers and their size, and a review of machinery options, in particular pure hydrogen turboexpanders. This includes how to influence the process to reduce the number of refrigeration cycle turboexpander stages while maintaining high machinery performance and low-specific power liquefiers. The authors will also discuss novel aerodynamic and mechanical design features. In addition, they will cover economic evaluation of single liquefier versus two half-size trains, liquefier-cycle optimization based on cycle choice, turn-down capabilities, thermal management, and product configuration selection.

Louis Mann

Research and Development Manager

Atlas Copco Gas and Process

Mazdak Shokrian

Vice President of Technology, Engineering & Design

Joule Process

1. Introduction Conversion of plastic waste to hydrogen will be a promising technology because of its ability to solve a growing challenge of plastic waste and establish an environmentally friendly hydrogen supply. In this paper, JGC Group would like to introduce our advanced solution for them with plastic waste gasification technology “Ebara Ube Process” (hereafter EUP).

2. Plastic Waste to Hydrogen Plastic Pollution and Recycling Technology Plastic pollution becomes a growing concern all over the world. Mechanical recycling of plastic waste is widely implemented. However, it is not enough to solve the evolving plastic problem because the number of times of recycling and applicable plastic waste are limited. Therefore, a plastic waste recycling technology which can handle the mixed and contaminated plastic and produce high quality product is strongly required. Gasification is one of the most promising technology because it can upcycle the wide range qualities of plastic waste into high value products such as hydrogen, ammonia, methanol and olefin through syngas. Supply of Low Carbon Hydrogen Hydrogen is important fuel for both transportation and power generation sectors because it contributes to high efficiency and low CO2 emission. Demands of low carbon hydrogen will also increase along with an expansion of hydrogen usage. Hydrogen produced from plastic waste is considered as low carbon hydrogen because fossil resources usage and related CO2 emission can be reduced. Therefore, hydrogen production from plastic waste can contributes expansion of hydrogen economy. Local production and local consumption of hydrogen Production of hydrogen from plastic waste realizes a local production and local consumption of hydrogen. It can be implemented without development of huge infrastructure for the import of liquefied hydrogen such as receiving terminal which requires large investment and long time. This technology is suitable to supply hydrogen in medium scale, which will be the most important during energy transition period from fossil fuel to low carbon fuel.

3. Solution of JGC group JGC group provides the license and facilities of EUP for production of hydrogen from plastic waste. In addition, JGC group also focuses on building a value chain in collaboration with governmental agencies, local governments, and industry (trading companies, financial institutions, petroleum / petrochemical / chemical companies, waste plastic collectors, etc.) and is working to promote gasification chemical recycling of waste plastics from a comprehensive perspective.

Reference: Plastic waste gasification technology EUP EUP developed by Ebara Environmental Plant and Ube Industries is a process that gasifies plastic waste using partial oxidation with oxygen and steam, producing synthesis gases that can be utilized in the synthesis of chemical products, and a gasification facility operating at Showa Denko's Kawasaki Plastic Recycle Plant (hereafter KPR) since 2003 applies EUP. In KPR, about 70,000 tons of post consumed plastic collected mainly from households are recycled to ammonia. EUP continues to be the only technology for gasification chemical recycling in the world with a long-term track record of commercial operation. JGC group provides license of EUP based on the contract with the three companies mentioned above.

Takahiro Obase

Program Manager

JGC Holdings Corporation

Background: By focusing on the Liquid Low-carbon Hydrogen supply chain, high efficiency and low energy consumption is an important step to ensure the competitiveness of this new supply chain especially for the hydrogen mobility market. By researching optimisations and synergies to decrease energy consumption, it appears that one of the key enablers is to implement a hydrogen production and liquefaction plant inside an existing industrial environment.

Aims: The objective is to optimize the overall integrated value chain of Low-carbon hydrogen by valorizing the cold heat from LNG regasification into the two following main process units: CO2 capture/liquefaction and hydrogen liquefaction. Based on Air Liquide know-how and plant references on the ASU integration with cold LNG, AL is developing a similar integration for these two units. Methods and Results:

1. Hydrogen liquefaction consists of two major steps: a pre-cooling step from ambient temperature to ~80K achieved through the use of a closed refrigeration loop N2/MR (mixed refrigerant) and a liquefaction step from 80 to 20K using a H2/He cycle closed loop. The objective is to warm up LNG against an intermediate fluid through a dedicated heat exchanger. Once cooled down, this intermediate fluid is sent to the pre-cooling unit of the LH2 process unit: It improves the efficiency of the liquefaction cycles: flow and process integration. It decreases the size of the machines, simplifies the equipment arrangement and increases the efficiency of the machines. Overall, a gain of at least 25% to 50% is expected on the specific energy consumption, overtaking the aim of 6kWh/kg.

2. CO2 Capture (Cryocap™ H2) unit: Air Liquide owns a unique range of proprietary technology for CO2 capture called Cryocap™ which is specifically applicable to H2 production by means of SMR, ATR or POx. The characteristic of this technology is to use a Cryogenic step to perform the separation of CO2 rather than using a solvent-based technology. This creates obvious heat integration synergies with cold heat that is available in an LNG terminal. The same synergies can also be available when CO2 is to be liquefied. Considering the specificity of CO2, and especially its triple point at - 55°C, this integration needs to be handled carefully to avoid any risk of freezing. In addition, taking into account that the cold for CO2 capture and/or liquefaction is used at ~-50°C, whereas it can be used at -140°C for H2 liquefaction, the priority is to use it for this latter purpose. If some additional cold heat is still available from LNG vaporisation, a significant power reduction (> 30%) for the CO2 capture/liquefaction can be achieved with a smart cold integration.

Conclusion: There are clear advantages in creating synergies between LNG vaporisation and liquid Low-carbon hydrogen production, as demonstrated by the reduction of energy consumption (more than 25%, equivalent to 190kWh power savings per ton of LNG for LH2 unit and up to 80kWh power savings per ton of LNG for Cryocap H2) and potential to reduce total installed costs.

Vanessa Turmel

LH2 Proposal Manager

Air Liquide E&C France

The latest report of the Intergovernmental Panel on Climate Change (IPCC) from August 2021 highlights the severe consequences of global warming caused by human activities. Since they are mainly caused by anthropogenic GHG emissions from fossil fuel consumption, the global community reached an agreement in Paris to limit global warming by significantly reducing GHG emissions, followed by several net zero commitments and roadmaps on national level. Mechanisms like the European ETS (emission trading system) are put in place to put a price on carbon and therefore increase pressure on carbon-intensive sectors. Some of these sectors are hard to abate as direct electrification reaches its limit. This is where clean hydrogen and its derivates play an increasingly crucial role.

One of these widely discussed derivates is ammonia, as it is both attractive as vector for the storage and intercontinental transport of hydrogen, but also usable in its raw form. Clean ammonia may be used as a building block for clean fertilizers & chemcials and creates an opportunity as clean bunker fuel for large ocean-going vessels.

When producing ammonia from fluctuating renewable energy sources such as wind and solar, a multitude of challenges arise regarding the design of the respective value chain. The background of these challenges will be described in this presentation. To start with, production assets are mainly planned where solar radiation and wind are abundant and predictable, often resulting in remote locations where no power grid and possibly no potable water are available. Further, the fluctuation of power results in a complex optimization problem on how to design & operate such a process.

Options to remedy include the buffering of electrical energy in electro-chemical form, buffering of hydrogen as pressurized gas or liquid as well as increasing process flexibility for extreme turndown ratios. All these options need to be evaluated on a techno-economical level.

Each option as well as the different production steps towards green ammonia via the Linde Ammonia Concept (LAC™) are discussed in more detail: High purity hydrogen production via proton exchange membrane electrolyser (PEM) technology from ITM Linde Electrolysis; high purity nitrogen generation within the FlexASU® air separation technology from Linde; hydrogen liquefaction; energy buffering concepts and finally the synthesis of ammonia within the Linde Ammonia Concept (LAC™).

An energy evaluation to produce green ammonia is shown, highlighting the main heat losses along the production chain plus, an additional comparison of energy efficiency of green versus conventional ammonia production. Several solutions for a highly dynamic operation are identified and evaluated. Finally, an outlook is presented on concepts for ammonia as intercontinental energy carrier.

The relevant experience is drawn from a multitude of executed studies as well as different scale proposals. Linde combines all key technology elements to produce green ammonia under one roof. The deep technological expertise to integrate and optimize the overall plant concept combined with proven EPC competence for each production step towards green ammonia, qualifies Linde as a powerhouse for integrated green ammonia plants.

Julien Brunel

Business Development Manager, Hydrogen & Syngas Plants

Linde plc

On Sept 2017, at the occasion of the COP23, French container shipping major CMA CGM confirmed the option of adopting LNG as fuel for the new series of 9 x 23,000 TEU containerships. By 2021 June, all vessels were successfully built and delivered, at China CSSC’s Hudong-Zhonghua and Jiangnan shipyards. These flagships vessels are nowadays seen as pioneers, urging on use of greener fuels and speeding up worldwide development of LNG supply chain. CMA CGM and GTT are today joining hands to deliver a comprehensive retrospective of the World First and Largest LNG fuel Ultra Large Container Vessels project. The first part focus on project genesis, the Europe-Asia Line basics and the early-stage development of LNG fuel system onboard an Ultra large container vessel. Comprehensive tests including a 6-axis hexapod model tests campaign were carried out to model North Atlantic conditions, calculate dynamics loads and eventually design an optimized containment system. Reliability and Boil-Off-Gas high-level performance continuously drove the development process.

In a second time, authors develop the technical aspects of ship design, construction, and commissioning. In the spotlight, CSSC MARIC -the ship designer- cooperated with both shipyards, gas engine maker WIN-GD, and French technology provider GTT to offer a 26-months shipbuilding schedule. Milestones such as 63,840 kW’s 12X92 DF engine lifting and outfitting of 4,400 m² of GTT technology insulation panels were key challenges. Gas trials have been carried out successfully with key stakeholders’ involvement as well as BUREAU VERITAS newbuilding supervision. In parallel, risks assessments workshop dealing with 1st bunkering operations and SIMOPS were organized with additional parties such as port authorities and LNG bunkering supplier. Those events happened just a few months later in the port of Rotterdam. MOL/TOTAL Gas Agility LNG Bunkering Vessel delivered the cryogenic molecule onboard of the 23,000 TEU containership, making industry breakthrough. Bunkering feedback such as difference between theoretical model and measured data, fuel tanks parameters change will be detailed in this second part.

Last but not least, first lessons learned and operational return of experience a year after the ninth vessel’s delivery are presented in the third section. Nowadays vessels are sailing on the Europe-Asia Lines, demonstrating excellent environmental performances. Authors would eventually deliver insights on Bio-LNG, which is already part of the Liner’s marine fuels portfolio. It reduces greenhouse gas emissions including carbon dioxide by at least 67% relative to well-to-wake VLSFO. Simultaneously synthetic LNG initiatives have been launched, to prepare large-scale production of carbon-neutral LNG. Such alternative fuel is waited for many reasons, environment performance, compatibility with today’s engines and bunkering infrastructure, and safe operability by already trained crews.

Thibaut Raeis

Technical Manager

GTT China

In 2018, the International Maritime Organization (IMO) adopted a strategy to reduce Green House Gas (GHG) emissions from international shipping. To meet the GHG reduction targets in 2050, the maritime industry is evaluating ammonia and methanol fuel as the most suitable fuel for carbon neutral shipping, and this paper covers ammonia fueled ships. Ammonia has several characteristics that differ from hydrocarbon fuels. Ammonia is a gas that is harmful to the human body even at low concentrations. Also because it is difficult to burn ammonia, diesel cycle Dual Fuel (DF) engines are being developed for efficient combustion, and a suitable Liquefied Fuel Supply System (LFSS) is required accordingly. Finally, ammonia requires storage conditions at a temperature and pressure similar to that of liquefied propane and requires a large fuel tank due to its low calorific value. Ensuring safety against toxicity is the most important requirement for ship owners. Therefore, Korea Shipbuilding and Offshore Engineering (KSOE) is developing a toxic safety system as a key technology for ammonia fueled ships. The LFSS has various scenarios of discharging fuel to the outside. The first is purge gas, which is the residual fuel in the LFSS piping. The second is the released gas of the Pressure Relief Valve (PRV), which is generated when the fuel system is over pressurized. Third, there is ventilation gas in the double pipe or fuel preparation room that is generated when the fuel system leaks. KSOE built a test facility of ammonia vapor processing unit in September 2021 and completed the performance test of individual equipment by December 2021. The test facility consisted of a water-based ammonia diffusion tank and ammonia scrubber, and a zeolite-based ammonia adsorber and ammonia oxidation catalyst. The performance and characteristics of individual equipment were identified through the demonstration test, and some equipment achieved an ammonia emission concentration of less than 25 ppm under reasonable operating conditions. Based on the results of the test in 2021, KSOE is preparing for next test to verify the performance of the ammonia vapor processing unit. A simulation model was estimated based on the test results in 2021. We plan to design a test facility that can satisfy ammonia emission concentration of less than 30 ppm. Testing in 2022 will validate our design process, and the test results will be used in the design of ammonia engine test facilities and ammonia propulsion ships In this research, we analyzed the risk factors of ammonia fueled ship through risk analysis to build a safe ship, and will present the process design of the fuel supply system. The test results of equipment to reduce the toxicity of ammonia will be presented, and the analysis results and test results of the ammonia toxicity reduction system designed based on this will be shown. Finally, we will compare the differences between ammonia fueled ships and conventional gas fueled ships.

Yeongjong Ahn

Researcher

Korea Shipbuilding & Offshore Engineering (KSOE, HHI Group)

Green hydrogen is the key element in decarbonizing global shipping, as an alternative fuel itself or as an ingredient for electrofuels such as green ammonia, green methanol or synthetic LNG. Increased availability of green hydrogen in the following years will also accelerate interest on fuel cells for powering marine vessels of several types and various sizes. Marine fuel cell systems are currently available with power ratings of a few hundred kilowatts and can be reasonably scaled up to a few megawatts. However, it is anticipated that fuel cell systems at MW power ratings are required to fulfill the market needs at various segments of marine vessels until 2025 and onwards.

ABB and Ballard Power Systems initiated their joint development of 3 MW marine fuel cell unit at 2018 and have received approval in principle from DNV, confirming that the design is feasible and fulfills the essential safety requirements. The key principle in MW-scale fuel cell unit is the hydrogen-proof enclosure comprising the fuel cell stacks and other hydrogen-carrying components. The air in the enclosure is taken directly from the exterior of the vessel and not mixed with the surrounding ambient air. The same principle is applied for the process air, cathode exhaust and anode purge accordingly. The risk of leaking flammable gas mixtures is eliminated by following a double-barrier principle, which enables the system to be installed in non-hazardous areas.

While the cabinet-based low-power fuel cell installations have low-power auxiliary subsystems in each cabinet, the MW-scale fuel cell unit is equipped with industrial-scale balance of plant for handling the hydrogen, process air and cooling. The unit has a single interface to external systems with internal manifolds to split the stream of fuel, air and coolant equally for each stack. Components in the high-power units are designed for long lifetime expectancy and are not planned to be replaced regularly. The fuel cell stacks will still degrade after certain period, and the system is designed to allow stack replacement onboard the ship without docking. Preventive maintenance is performed according to the planned maintenance schedule, optimizing the total lifecycle cost.

Fuel cells usually provide the best performance with electric propulsion or supplying auxiliary power systems. Nevertheless, it is also possible to combine fuel cells effectively with mechanical propulsion in hybrid configuration. Shaft generator with PTO/PTI functionality allows to distribute the electric power from the fuel cells flexibly between auxiliary systems and propulsion. Hybrid propulsion system with electric motor and twin-shaft gearbox allows to generate even larger share of the propulsion power by fuel cells.

Dr Sami Kanerv

Global Product Manager

ABB Marine & Ports

Industry Partners; DNV, Total Energies, Major Shipowner & Hyundai Heavy Industries, have concluded a study investigating modern LNG carriers and how a current design (delivery 2025) can meet defined CO2 emissions targets towards 2050.

In other words, what are the “best” measures available today and how to chart a practical path to comply with the carbon reduction trajectories over the coming years.

A realistic baseline vessel and operational profile has been established by key industry players/stakeholders and focus has been set on environmental, cost & operational impacts.

Options to reduce carbon intensity over the vessels lifetime has then been reviewed by means of a decarbonisation stairway by investigating & incorporating the following:

• Energy Efficiency Measures (eg. wind assisted propulsion, shore power, CCS, fuel cells)
• Alternative Fuel Options
• Fuel Expenditure • Practical consequences
• Economic potential of ship fuel strategies & timelines

The outcomes for two operational profiles embarking on four different strategies will be presented and insight into a more ambitious target of zero-emissions by 2040 has also been considered along with the potential for CO2 tax in what can be considered as two additional and extremely viable ‘what if’ scenarios.

Rational for this paper: With IMO’s GHG reduction strategy 2050 in place, the maritime shipping industry – and all its stakeholders – needs to prepare for significant emission improvements towards 2050. To meet the 2050 goals drastic measures will/must be considered, whereas some of the measures/solutions are still not available. The intermediate 2030 goals can, however, be achieved by available technology and solutions.

More specifically, for any new build to be delivered in the coming years, the owner/operator needs to ensure that the vessel will be able to meet increasingly demanding reduction requirements on CO2 emissions.

Martin Cartwright

Global Business Director, Gas Carriers and FSRUs

DNV

On November 22, 2021, Woodside announced it had approved the Final Investment Decision to sanction its Scarborough and Pluto Train 2 developments. The Scarborough Project consists of a world-class Scarborough offshore development of 11.1 Tcf dry gas (100%); whereas the onshore development will produce 5 Mtpa of LNG at Pluto Train 2, provide up to 3 Mtpa equivalent of feed gas for Pluto Train 1, and produce 225 TJ/day of new domestic gas capacity. With a composition of ~95% CH4, ~5.0% N2, ~0.1% CO2 and a heavy hydrocarbon tail, feed gas from the Scarborough Field is well positioned to support the decarbonization goals of Woodside’s LNG customers in Northern Asia. Furthermore, by utilizing Optimized Cascade™ liquefaction technology, Pluto Train 2 will be one of the lowest carbon intensity projects for LNG delivered to those customers.

This paper will present an overview of four types of enhancements to Pluto Train 2’s design that enable it to have a greenhouse gas intensity of ~0.26 tCO2e/tLNG: 1) the use of high efficiency aero-derivative gas turbines, 2) waste heat recovery, 3) inlet air chilling, and 4) process design optimizations. The process design optimizations include the use of an OCP Nitro™ integrated nitrogen removal unit (NRU), as well as an OCP CryoSep™ heavies removal unit (HRU) that utilizes external solvent injection, recovery and circulation to process Scarborough’s lean gas with its heavy hydrocarbon tail.

Tom Feutrill

Pluto Train 2 Project Manager

Woodside Energy USA (Inc)

The Mozambique LNG Project started with the discovery of a vast quantity of natural gas off the coast of northern Mozambique in 2010, leading to a $20 billion Final Investment Decision in 2019. The Project is operated by TotalEnergies – the world’s second largest LNG player with a leading presence in Africa – which is uniquely qualified to ensure the Mozambique LNG Project helps to meet the world’s increasing demand for sustainable, reliable and cleaner energy sources. Mozambique LNG is a two-trains, nominal 6.44 MTPA per train, LNG facility using APCI C3MR liquefaction technology. Hydrocarbon condensate, separated from the feed is processed and exported separately. The facility will be constructed at a remote coastal location in the Cabo Delgado province of Mozambique.

The feed stream is fed to the LNG plant which comprises gas/liquid separation, gas treatment (removal of acid gas, dehydration and mercury), heavy component (C5+) removal followed by gas liquefaction, storage and export. Condensate stabilization and export facilities are also included.

Mozambique LNG is characterized by one of the largest LNG train production capacities using APCI C3MR technology. To achieve the large propane refrigeration duty with one propane refrigerant compression string, a very peculiar configuration has been designed and implemented, with two parallel compressors driven by the same gas turbine. This process scheme is first of a kind for an LNG application. The configuration includes a common anti-surge valve and a common Cooler (Desuperheater) per each stage for both compressors with; same applies for common KO Drums. No provision for suction throttling valves has been considered.

A joint approach has been shared with TotalEnergies to mitigate the technical risk of this new configuration.

A dynamic simulation study has been performed by CCS JV to assess which is the expected propane circuit behavior during transient operations, identified to be representative in terms of compressor safety and stability (MR trip, Blocked Outlet, etc.).

Conclusion was that the current configuration can operate in a safe and stable manner and that the selected control system will provide adequate protection from surge, thereby maintaining compressor integrity for all the analyzed scenarios. This has been also confirmed by the compressor’s performance test done at the Compressor’s Manufacturer Yard.

This paper offers an insight in the design challenges and returns of experience of such an innovative scheme.

Sergio Armenante

LNG Project Engineering Manager

Saipem

David Anderson

Engineering Manager

TotalEnergies

Amelie Pesquet

Rotating Equipment Specialist MzLNG

TotalEnergies MzLNG Project

ExxonMobil has completed a successful field trial of RapAdsorb¬TM for compact natural gas dehydration and CO2 removal. A deep dehydration field trial unit capable of treating 40 MMSCFD was built and commissioned in 2020 at an operating compressor station in Fort Worth, TX. During testing in 2020 and 2021, the unit achieved a product water content of less than 1 ppm with an inlet content of 810 ppm (38 lb/MMSCF), suitable for LNG and NGL recovery pre-treatment. The system met this specification while operating at 150% of the design flow rate. In late 2021, the unit was modified to test CO2 removal and was able to meet a product CO2 content of less than 50 ppm.

The RapAdsorbTM gas treating solution is enabled by a structured adsorbent bed operated with rapid pressure-swing and/or temperature-swing cycles. This allows for a compact system with gas treating footprint up to 50% smaller than conventional technologies, making it well suited for skid-based deployment and offering execution efficiencies through improved modularization and expansion flexibility. The solution is ideal for projects in challenging cost environments such as deep water, arctic, and remote offshore, which benefit significantly from the reductions in size, weight and footprint. The system also requires lower regeneration temperatures than conventional technologies, eliminating otherwise required fired heaters and associated emissions.

This paper will provide a brief overview on the RapAdsorbTM gas treating technology, key technology enablers, scale-up approach, field trial unit performance, and the future development and deployment plan.

Mark Mikhaeil

Process Research Engineer, Gas Treating Research, Technology & Digital Development

ExxonMobil

With the Train 7 Project, Nigeria LNG decided to invest in the expansion of its natural gas liquefaction complex in Bonny Island to boost its export capabilities taking advantage of the solid experience in the LNG industry.

The Train 7 Project will add around 8 million tonnes per annum of LNG to Nigeria LNG’s production capacity, taking the total export from its complex to around 30 MTPA and reinforcing Nigeria’s position as one of the top five LNG exporters in the world.

The scope of work includes a.o. a complete LNG train “CT”, a functional replica of the existing Trains 4/5/6 and a common liquefaction unit “CLU”, a brand-new and flexible debottlenecking concept, receiving gas from eight different sources within the existing Trains 4/5/6 and the CT.

Since the award date for the EPC lump sum contract in May 2020, SCDJV, the Saipem-led joint venture that includes Daewoo E&C and Chiyoda, has been working in close cooperation with Nigeria LNG to handle project challenges in the COVID-19 pandemic scenario thanks to a consolidated Project Performance Management, a Continuous Improvement approach, and the enhancement of a “One Team” culture across all Project levels.

The paper will present some of the technical and managerial challenges which have been undertaken so far, including the strong focus on Safety in Design with a holistic approach applied to the joint reviews and workshops, the teamworking from remote, the Advanced Work Package (AWP) Methodology, the SIMOPS management, the optimization of key equipment and environmental performances (including measures that will lead to a significant reduction of GHG emissions, waste water, plastic and other solids wastes) within the constraints of a brownfield context.

In addition, the paper will detail the tangible benefits resulting from the above-mentioned innovative work methodologies, highlighting the key experiences and learnings bringing added value to Nigeria LNG and SCDJV as a result of the effective mitigation of identified construction and commissioning challenges.

Davide De Bacco

LNG Technologies SME

Saipem

If rapid decarbonization is the most important goal, and if renewables and hydrogen are integral parts of the solution, it is important to understand that natural gas and LNG are not only desirable but necessary features of the path to a lower carbon future. Without expanded use natural gas/LNG, there may be no clear path to decarbonization in a reasonable timeframe for most countries. To understand why that is the case, this paper will undertake a pragmatic, non-political review of (i) scale, cost, and other drivers for the development of renewables and low-carbon hydrogen in local and global markets, (ii) the relationship of natural gas and LNG to the development of renewables and low-carbon hydrogen, (iii) the importance of carbon capture, use, and sequestration (CCUS) in combination with natural gas and LNG, (iv) alternatives to natural gas and LNG in supporting renewables and low-carbon hydrogen, and (v) delays, impediments, and deal-killers for the energy transition and rapid decarbonization.

The debate around decarbonization and the energy transition has too-often focused on the long-term targets and how to make a rapid switch in energy generation, use, and GHG emissions intensity, rather than focusing on the need for immediate de-carbonizing action that keeps the energy transition on target to reach a long-term destination. Politics has to date displaced pragmatism in achieving climate goals. This Paper with undertake a balanced non-political examination of the potential role natural gas and LNG in accelerating the energy transition and supporting more rapid growth of renewables and low-carbon hydrogen, as well as the potentials risks if politics attempts to exclude natural gas and LNG from playing that role.

Jason Bennett

Partner and Chair of the Global Projects Department

Baker Botts L.L.P.

Markets call for durable, long-term solutions to future energy needs, in terms of sustainable energy generation, storage and utilization. While already rooted in the energy industry for over 50 years, hydrogen is an integral part of the Energy Transition, and essential to the “difficult-to-decarbonize” sectors of energy markets. The global installed hydrogen generation capacity has already grown significantly, a trend anticipated to accelerate towards 2050.

Industrial-scale, on-purpose hydrogen manufacture is today broadly based on reforming technology, whereby a hydrocarbon (ranging from natural gas to naphtha) reacts catalytically with steam to form a mixture of hydrogen and carbon oxides. Co-produced CO2 may be captured by various means, and diverted for use and/or permanent storage (CCUS), to arrive at so-called low-carbon “blue” hydrogen. Alternatively, “green” hydrogen may be derived from renewable resources, such as renewable electricity or carbon-neutral feedstock.

This paper addresses aspects, strengths, weaknesses, trends and myths concerning various hydrogen production vectors: ranging from traditional (grey) hydrogen, through blue hydrogen under various schemes and capture depths, to green hydrogen via the electrolysis or even carbon-negative routes.

This paper further outlines Technip Energies’ (T.EN’s) portfolio of low-cost, low-carbon hydrogen solutions:

• Over 95% reduction in the carbon footprint compared to the traditional hydrogen process – from ~10 down below 0.5 kilogram CO2 per kilogram H2, while maintaining flexibility to be tailored to each individual application.

• Maximum hydrogen yield, minimum energy demand (fuel + power), and highly-efficient carbon avoidance and carbon capture utilization & storage (CCUS) techniques, to arrive at the lowest cost of hydrogen (LCOH).

• Comprising “flight proven” technologies and equipment, available today.

Matt Pitcher

Head of Hydrogen Technology Portfolio

Technip Energies

INTEREST

ESG is shaping the energy market far beyond the pressing requirements of emission reduction, sustainable fuels and net zero targets. Investors are increasingly required to consider and report upon their own ESG impacts including up and downstream supply chains. Corporate reporting guidelines, developing taxonomies and sustainability reporting standards are only likely to strengthen and increase the pace of change. What can energy companies do to attract ESG investment and how do they get ahead of the tide? In this session we will examine global trends and look at what is likely to be next for energy companies and sustainable fuels as the investment market responds to ESG requirements.

TOPICALITY

Growing energy demand across the world and increasing energy prices as a result of the global pandemic and now the war in Ukraine means that this is now a critical issue not just for the industry but for Governments and citizens worldwide. Can supply security and sustainability go hand in hand with investment?

ORIGINALITY

This is a global session from one of the leading global law firms. This enables us to provide a comprehensive review not only of legal and regulatory frameworks but also market experience from our clients in the energy and service supply sectors and beyond. In this session we will look at the direction of travel for ESG and anticipated future developments.

Caroline May

Sustainability Partner and Global Co-Head of ESG

Norton Rose Fulbright

• LNG is destined to be an important part of the LNG transition and will continue to be a power generation fuel in the ultimate net zero environment. • Future-proof LNG liquefaction facilities by mitigating greenhouse gas emissions and by providing the flexibility to co-produce energy transition fuel.
• This paper will present the economics of using a green LNG facility as a hub in co-producing energy transition fuels such as hydrogen, methanol, and ammonia.
• The paper will discuss the economics of carbon capture vs hydrogen fueled gas turbines vs electric motor drives (edrive) for LNG liquefaction, and using natural gas for producing low-carbon (blue) hydrogen, methanol, or ammonia with pre- and post-combustion carbon capture. National and corporate net-zero targets are leading LNG producers to consider reducing the greenhouse gas footprints of their current and future LNG liquefaction facilities. These same net-zero drivers could also lead LNG producers to consider co-producing low carbon fuels and products at their LNG production site, such as hydrogen, methanol, and ammonia.

Reducing the greenhouse gas emissions from LNG liquefaction facilities will require capture and sequestration of the CO2 contained in the natural gas feed to the liquefaction facility as well as reducing the CO2 emissions from the LNG refrigerant system by either capturing the CO2 from gas turbines, using hydrogen as fuel for the gas turbines, or using edrive instead of gas turbines. Reducing the greenhouse gas emissions from co-production of hydrogen, ammonia, or methanol from natural gas will require post-combustion capture of the CO2 from the natural gas reformer heater as well as capture of the CO2 upstream of the hydrogen/ammonia/methanol unit using a solvent-based high-pressure absorber. The economic evaluation of the green LNG facility with co-production of energy transition products will take into account the additional capital and operational costs of mitigating the facility CO2 emissions, including the compression and dehydration of captured CO2. Economies of scale and energy integration help to make this concept economically feasible.

Tom Maramba

Senior Director

Fluor Inc.

As the world begins to recover from the COVID-19 pandemic, global efforts are turning to addressing the climate crisis. The Glasgow Climate Pact, released as the agreed outcome of COP26, has emphasized the continued commitment to limiting warming to 1.5°C and therefore an urgent requirement for deep decarbonisation.

Achieving net-zero emissions by mid-century will demand an unprecedented pace and scale of global energy, chemical and resource infrastructure development, and engineered solutions. In 2021, Worley joined forces with Princeton University’s Andlinger Centre for Energy and the Environment to develop the practical steps necessary to deliver the net-zero infrastructure required. Our joint publication “From ambition to reality: weaving the threads of net-zero delivery” was built from Princeton’s detailed decarbonization pathway analysis for the US economy, which included downscale mapping of the actual infrastructure required.

The fundamental finding from our work together is the need to dramatically rethink project delivery. If we develop energy infrastructure the way we always have, we won’t get to net zero by 2050. We might not even get halfway.

Dr Paul Ebert

Group Director – Sustainability and Energy Transition Leadership

Worley

The EU strategic long-term vision, in line with the objective of Paris agreement, aims to reach climate neutrality by 2050 and hence its energy strategy demands significant reduction of greenhouse gas emissions and calls for an increase of renewable sources in the energy mix. In this framework, closed loop Joule-Brayton power cycles operating with supercritical carbon dioxide (sCO2) can play a major role, thanks to the high conversion efficiency, extreme compactness, reduced or avoided water consumption, and fuel flexibility. The technical implementation of sCO2 power systems introduces new challenges, from turbomachinery standpoint; this new scenario requires novel design concepts and strategies, as well as proper tools to achieve reliable predictions.

Within the sCO2Flex project, funded by European Union Program Horizon 2020 (grant agreement #764690), the consortium addresses the necessities to upgrade existing fossil fuel plants to integrate renewable energy sources increasing the overall efficiency in power generation plus avoiding the use of water. Deliverable of the project is the development and validation of all main components of a sCO2 Brayton cycle capable to provide 25MWe at 100% load ensuring a wide plant flexibility (from 100% to 20% of the electrical load). Moreover, a centrifugal compressor prototype has been designed and manufactured to operate in proximity of CO2 critical point, with the aim of maximizing the thermodynamic cycle efficiency. Specific models and equation of state have been implemented to properly predict CO2 behavior close to critical point, even in the event of multi-phase conditions which could occur in low-pressure regions inside the gas path. Turbomachinery validation in partial load operation, obtained through dedicated full-cycle process simulations, will also be presented together with the definition of a preliminary control philosophy. Required cycle flexibility can be achieved maximizing turbomachines and plant efficiency in the entire operating range.

The present work will conclude with highlights of the complete experimental campaign carried out in Baker Hughes facilities to assess the performance of the 5 MW compressor prototype at different operating conditions, both in proximity of critical point and far from it. Test results fully characterize the effect of suction conditions on compressor behavior, highlighting the importance of gradients in thermodynamic properties ad potential phase-change on compressor operation.

The data collected confirm the expected performance and permit a consistent validation of the compressor design. Moreover, it is experimentally confirmed that compressor inlet thermodynamic conditions close to critical point led to significant advantages in terms of compressor power absorption.

Roberto Valente

Senior Aerodynamics Engineer

Baker Hughes

It is widely recognised that deployment of Carbon Capture, Utilisation and Storage (CCUS) technologies at scale is essential to enable hard-to-abate industrial sectors to reduce emissions in line with the Paris accord, and the subsequent targets established through the COP process.

This paper reviews the characteristics of a novel enzymatic carbon capture absorbent process that can cost effectively deliver Carbon Capture at scale and eliminate the need for toxic solvents.

Using a naturally occurring biocatalyst, the carbonic anhydrase enzyme used in a carbonate solvent yields excellent performance while removing shortcomings of other solvent and carbonate technologies:

• Carbonates are insensitive to oxidation and tolerate high SOx and NOx • Carbonates with enzyme are non-toxic, non-volatile, and no aerosols are formed through process

• Fast kinetics from enzymatic catalysis allow absorption at atmospheric pressures and single stage stripping

• Stripping at 75°C enables reuse of low-grade waste heat at 85°C (hot water) collected from the host plant to regenerate solvent, significantly reducing both the GHG footprint and the parasitic load

• Carbonates are less corrosive and consequently require less stringent material selection than Amine based technologies

Whilst carbonate-based solvents have been used by industry for decades in many gas treating applications, carbonate systems without an activator have poor kinetics which are compensated by performing absorption at high pressure and having double strippers. In addition, some chemical activators used by carbonate technologies can be toxic. Saipem’s carbonic anhydrase enzyme eliminates these problems. Current amine-based technology has several significant performance challenges:

• Solvent performance is affected by polymerization and degradation due to the presence of SOx, NOx and oxygen, which can generate undesirable aerosols in absorber outlet, increasing environmental impact and solvent costs

• High parasitic load on host plant or high GHG footprint. Large-scale capture projects need significant ancillary power plants to provide regeneration steam

• Capture units have high capex and opex which slow down deployment Despite current efforts to address these problems, volatile organic solvent mixtures remain vulnerable to oxidation and the formation of aerosols. Although progress has been made on parasitic load, current amines still require steam to regenerate the solvent, increasing the plant’s capture load.

Richard Surprenant

Commercial Manager, Carbon Capture Technologies

Saipem SpA

CO2 emitting industries share the same goal to reduce the CO2 footprint, whilst starting from very different initial conditions. That is true for both the CO2 concentration in the emitted gas stream as well as the product specification of the captured CO2. Latter being determined by the downstream application, such as sequestration or utilization. The adsorption based HISORP® CC process is the optimal technology to reduce carbon footprint of hydrogen production plants (both for new-built and retrofit), such as Steam-Methane-Reformers (SMRs), Autothermal Reformers (ATRs), partial oxidation (POX), and gasification reactors. To produce blue hydrogen, it can be applied for pre-combustion CO2 capture in the syngas or H2-PSA tail gas route of existing SMRs and ATRs as well as for post-combustion CO2 capture from flue gases achieving overall CO2 capture rates of greater 95%. It is flexible in scale (covering all relevant industrial sizes), in CO2 feed concentration, in states (gaseous, liquid, or supercritical) and purities (low purity for EOR to high purity or food grade) of the CO2 to be exported. The main advantages of HISORP CC are:

- No steam required for regeneration of solvent (e.g., MDEA) and therefore no additional CO2 generation

- No environmental issues with solvent traces in emissions and CO2 product

- No extra cost for solvent make-up, handling, and waste treatment

- Only electric power is required for HISORP CC – no steam consumption (environmentally benign since usage of 100% renewable power is possible)

- No Hydrogen losses

In detail, three different types of HISORP CC can be applied to capture CO2 for blue hydrogen production: HISORP CC syngas, HISORP CC tailgas, and HISORP CC flue gas. Downstream the CO shift, HISORP CC syngas can be applied to separate CO2 with overall capture rates of >60-75% (standard SMR) or >95% (ATR). It is the optimum solution (low CAPEX and OPEX) for low carbon, blue hydrogen without loss of H2 product. In the low-pressure tail gas, downstream the existing H2 PSA, HISORP CC tailgas with a compression unit allows for overall CO2 capture rates of >60-75% which is an optimum retrofit solution for blue hydrogen production. In order to achieve overall CO2 capture rates of >95% for existing SMRs, HISORP CC flue gas is the optimum retrofit solution with the lowest impact on the SMR process and no hydrogen is lost. In addition, HISORP CC can be applied to other industries and flue gas sources, where CO2 emissions are hard to abate, such as steel and cement industry and power plants (gas and coal).

Marc Scherle

Project Manager Business Development and Sales

Linde GmbH

Hydrogen is seen as a future major energy carrier. However, current hydrogen production technologies from fossil fuels (so-called “grey” hydrogen) emit considerable amounts of CO2 as a co-product and carbon-free technologies (such as for instance “green” hydrogen produced through electrolysis of water with renewable electricity source) are still in early stages of development. One mid-term solution to reduce CO2 emissions in an attempt to reach COP21 objectives for 2050 is to capture CO2 released by the production of hydrogen from fossil fuels.

This paper focuses on carbon capture (CCS) in the syngas produced in a steam methane reformer (SMR) using the reactive absorption of CO2 with an amine solvent and its impact on the SMR design.

AXENS as Licensor of AdvAmine™ technology for gas sweetening process and provider of reformer furnaces through its Heurtey Petrochem Solutions brand detains an independent expertise for the evaluation of optimum design conditions of the amine system to minimize OPEX of the CO2 capture, and for the evaluation of the impact on the reformer, as well as the overall carbon footprint of the hydrogen produced, under the various considered process configurations. In a first step several process schemes, using AdvAmine™ for the carbon capture from a syngas flow exiting a SMR unit are investigated and compared to minimize the energy consumption. To do so, the studied schemes are optimized by process simulation using a dedicated proprietary software, sized and then compared with techno-economic criteria.

In a second step, this paper evaluates the impact of removing CO2 from the syngas with such amine process, on the overall design of the SMR. The removal of CO2 from the syngas significantly modifies the composition at the inlet of the hydrogen purification through Pressure Swing Adsorption (PSA). Even though it may lead to only minor modifications on the PSA required for the purification of hydrogen, this change in PSA feed gas composition will drastically change the composition of the PSA purge gas. This PSA purge gas being recycled as an fuel to main SMR furnace, this will then impact the reformer section design and operation. Accordingly the impact on the overall balances for make-up fuel requirement, steam production and overall CO2 footprint of the SMR are addressed considering two distinct scenario cases: the SMR grassroot design and existing SMR revamp case. Heat integration between the reformer and the amine carbon capture unit have also been considered, in order to optimize the overall process configuration. The specific constraints of the revamp case, for which some of the existing equipment items cannot be modified, lead to a less effective carbon capture than for the grassroot case.

The overall carbon footprint, can be reduced for the studied case and under the proposed configuration from its initial figure of 13.25 kg CO2/kg H2, down to 5.34 kg CO2/kg H2 for the grassroot SMR, and to 6.13 for the revamp case.

Clement Salais

Low Carbon Solutions Technology Manager

AXENS

The commercial solution developed in the LNG’s early years permitted it to grow from a niche business to the industry it is today, despite daunting economic headwinds. The successful package included:

• Long-term, bankable contracts

• Risk sharing

• Government support

• Focus on capacity utilization and efficiency along value chain

• Management of broader communities to build and sustain consensus

• Maximizing communication and sharing of learnings and experience along the value chain and across industry players

The same winning package can and should be applied to develop the international hydrogen economy.

LNG is often presented as a bridge between the fossil fuels dominating the 20th century and the world of low-carbon energy that must be created in the 21st. The bridge metaphor is used vaguely to mean that the world will keep using LNG while the low-carbon future is forged, because LNG is cleaner than coal or oil.

Such vagueness is unmindful of LNG’s origins. The industry began as a bridge—not to zero-carbon, but rather from dependence on OPEC oil to greater energy security. First Japan, then Korea, developed and consolidated the commercial foundation for LNG’s growth following the oil shocks of the 1970s and early 1980s. It was complex and took time. It was expensive. But it worked.

The vagueness also, and consequently, misses a big opportunity. The circumstances and solutions enabling LNG to serve as a bridge then closely fit the circumstances and solutions that may unlock massive international hydrogen trade now.

We will identify the geopolitical and national political and economic context leading to the initial boom of LNG ventures centering on Japan and then Korea, identifying the specific – particularly commercial– issues overcome to create a major industry. We will briefly describe how the LNG industry evolved to its current structure, considering how the factors driving its shift from niche to mainstream, and from rigid to flexible trade flows, interacted with development of liquid and flexible gas markets and market-oriented reforms in major demand centers. Our paper will consider the extent to which the conditions and solutions for the LNG industry’s early development relate to international hydrogen today, and how the current, more evolved structure of today’s LNG industry may complicate hydrogen industry development. Finally, we will show how the efforts to develop international hydrogen thus far have overlooked the lessons of early LNG.

We will utilize close historical analysis and analogy, drawing on the authors’ many decades of professional immersion in the LNG industry as well as resources of their employer, Poten & Partners, which has been a leading advisor to the LNG industry almost from inception. Furthermore, we will utilize elementary game theory, in particular Nash equilibria, to explore how a consensus to proceed with LNG development was achieved, in tension with, if not fully in opposition to, the dictates of conventional economics.

Our paper will highlight specific lessons learned and recommendations for policy makers and industry strategists to advance the development of a global hydrogen industry.

Stephen Thompson

Global Head, LNG and Natural Gas Advisors

Poten & Partners, Inc.

Shipping compressed hydrogen in specialized bulk carriers is poised to open international markets for hydrogen trade. Recently the American Bureau of Shipping issued Approval in Principle (AIP) for a novel compressed hydrogen carrier developed by Global Energy Ventures Ltd (GEV). This unique vessel has the capacity to carry up to 2,000 tonnes of hydrogen at ambient temperature and 250 bar pressure.

Compressed hydrogen shipping’s major advantage is that it avoids the capital and energy intensive processes of either liquefaction, or conversion into ammonia or other chemicals, and then reconverting back to hydrogen. Compressed hydrogen remains a gas throughout the entire shipping process.

Compressed hydrogen shipping allows green hydrogen producers to connect to growth markets where green hydrogen demand is not be met by domestic supply. The advantages of compression include:

> Compression is a proven, low-cost technology able to deliver hydrogen at a competitive cost.

> Compression is commercial at low volumes as it does not require economies of scale.

> Compression has a small footprint compared to liquefaction or ammonia facilities.

> Compressed hydrogen can be loaded at a jetty or an offshore buoy.

> Compression facilities are easily expanded in a modular fashion and thereby aligns with market growth.

GEV is developing the Tiwi Hydrogen Export Project and collaborating on the HyEnergy Export Project which envisions shipping green hydrogen from Northern Australia to markets in Southeast Asia (Singapore, Indonesia, Korea and Japan). Both projects would start small utilizing a fleet of 430 tonne compressed hydrogen ships.

Developing a ship to efficiently carry compressed hydrogen faced critical challenges. These challenges can be thought of in two broad categories: the hydrogen tank itself, and the integration of the tank into the ship.

To be cost effective, the tank must be constructed of strong, low-cost materials. The natural choice is high-strength steel but steel at these pressures is susceptible to hydrogen embrittlement. To avoid embrittlement, the steel can be protected by a stainless steel liner. The result of this work was the development of an exceptionally large tank composed of an inner layer of stainless steel surrounded by five layers of high-strength steel. This layered tank had its unique design challenges, but the result was an extremely safe, low-cost tank.

The optimum ship to contain these large tanks is one with an open cargo space, free of transverse bulkheads, and separated into single port and starboard holds by a centerline longitudinal bulkhead. One hydrogen tank is placed into each hold. The tanks themselves are integrated into the ship structure which significantly strengthens the ship.

The conceptual design of the ship, especially the compressed hydrogen cargo containment system, was assessed by ABS through a collaborative What-if/Hazard Identification (HAZID) workshop.

This paper explores the challenges and solutions encountered in developing GEV’s novel proprietary compressed hydrogen ship and the ABS approval process leading to Approval in Principle. The paper will conclude with an overview of the Tiwi Hydrogen Export Project targeting first commercial scale hydrogen exports by 2026.

Harish Patel

Senior Technical Advisor

ABS

Gas will be a major transition fuel in the move towards net zero, but currently, the oil and gas industry alone emit over 84 million tons of methane each year, the equivalent of all the emissions from the world’s on-road transport fleet. However, according to the IEA, 75% of methane emissions from oil and gas production can be technically abated today.

With recent events leading to a planned reduction of Russian gas imports to Europe, it is expected that LNG exports will increase to make up much of this supply loss. This year, an estimated 14.5MTPA additional LNG supply will be online compared to 2021 – this is only around 13% of the amount of Russian gas imports into Europe in 2021. With more supply needed, it is expected new LNG export projects will be approved and begin construction, most of which will be from the US.

With over 9,000 independent oil and gas producers in the US, liquefaction facilities have many options when it comes to their gas supply contracts for their liquefaction plant. With differences in operators’ emissions management and the sources’ geological make up, it’s no wonder the methane intensity (MI) in US gas production can range from around 0.56% in the Appalachian Basin to 2.96% in the Arkoma Basin. Disturbingly, research has shown that above a 3% MI, gas has no environmental benefit over coal.

Regulation on methane emissions from oil and gas production will come, but unfortunately it will likely take some time. This means that voluntary initiatives and individual companies need to act to reduce methane emissions across the LNG supply chain.

Unfortunately, gas buyers rarely have any credible assessment of the emissions performance of a batch of gas they are buying, and regulators have no credible way to assess and compare the methane performance of any batch of natural gas that imported into their jurisdiction.

Independent, transparent, and third-party-audited natural gas certification schemes can help address this information shortfall and create incentives for operators to reduce emissions and meet the market’s demand for cleaner energy.

As LNG exports increase, it’s imperative that all gas is not treated equally. Actors in all parts of the supply chain should demand transparency on the gas they are trading and purchasing. Independent gas certification schemes give these gas producers, buyers, and traders the tools they need to understand the environmental impact of individual batches of gas on a granular level.

Saima Yarrow

Head of LNG

MiQ

On December 16th, 2021, the European Parliament and the Council published the proposal for a regulation on “methane emissions reduction in the energy sector and amending Regulation (EU) 2019/942”. The proposal is meant to support the widespread development of a robust MRV (Monitoring, Report and Verification) standard for methane emission in the energy sector and to put into EU law an obligation on leak detection and repair (LDAR), given that NGOs and industry respondents to the open public consultation believed that it is indeed feasible to phase out routine venting and flaring associated with energy produced and consumed in the EU.

The impact of the regulation is going to be huge and therefore the proposal is currently under scrutiny by most operators and key stakeholders, both at/ European and national levels.

This paper has been prepared by the members of Assorisorse Working Group on Methane Emissions, representing players along the whole value chain: technology providers, engineering contractors, EPC contractors, operators, testing, inspection and certification bodies and consultants focused on environment protection, H&S, and R&D. The group has been established at the end of 2021 to intercept the growing interest on the topic and the need to reduce emissions to the atmosphere, whatever the origin, reason, and duration: incident emissions from unplanned events, incomplete combustion, operational emissions, permeation, pneumatic, and vented emissions. The need for reduction goes together with the need to keep stakeholders and the community informed, which is achieved through the publication of yearly sustainability reports.

Assorisorse is committed to support public decision makers and key stakeholders and engaged in constant monitoring and proposal action – at European, national, and local level – relating to legislative and regulatory activity, and collaborate with various national and international bodies, creating synergies that favor business operations and developing common strategies on core topics.

The paper addresses the key changes introduced by the proposal and highlights some of the “hot topics” under discussion to contribute to the final version of the regulation, such as the prescriptive nature of some of the requirements, the lack of specific requirements for the various industries involved, the lack of cost-to-benefit analysis to prioritize interventions and maximize the positive return of the investments, the timing for the implementation, and the consistency between current technical standards and future ones.

The paper also addresses the best available technologies, design standards and O&M practices to reduce emissions and to improve the accuracy of their estimate, monitoring, and reporting, with a focus on innovation, R&D, and showing a few significant case histories.

Dr Angelo Lo Nigro

Senior Director Engineering Solutions

RINA Consulting S.p.A.

Abatement of fugitive methane emissions in the oil and gas sector can be achieved with relatively simple technical measures such as regular leak detection and repair (LDAR), increased maintenance frequency, modernizing equipment (such as replacing pumps or using electric motor equipment as well as replacing compressor seals or rods), and installing equipment to flare rather than vent the gas to the atmosphere. Despite estimated low net abatement costs, current emission levels suggest however that there are insufficient incentives for the oil and gas industry to invest in methane abatement. Policy instruments could provide these incentives. Pricing methane emissions, for example through a methane emission fee or inclusion in a cap and trade program, could provide a strong incentive to reduce methane emissions in the oil and gas industry.

However, many oil and gas producing countries - with some notable exceptions such as Norway - are yet to seriously tackle their methane emissions. At the same time, gas importing countries and regions like the European Union are concerned about the footprint emissions associated with their fossil fuel imports. The European Commission in their legislative proposal from December 2021 therefore proposed to set up transparency tools for methane emissions occurring outside the EU. These measures include an obligation by importers of fossil fuels to provide information on measurement, reporting and mitigation of methane emissions undertaken by exporters. The proposal also includes a review clause that preserves the option to amend legislation to impose more stringent measures on importers once better global methane emission data are available. Such stringent measures could include putting restrictions on the methane emission intensity of imported fossil fuels with associated penalties. Relatedly, ideas around a Clean Gas Buyers Coalition of countries expanding beyond the EU and where all member countries would put methane emission restrictions on their gas imports have sprung up. In this study, we explore the impact of different levels of methane prices for upstream methane emissions implemented by different potential coalitions of gas importing countries and analyze the impacts on global methane emissions and trade flows.

Huong Nguyen

Senior Economics and Policy Analyst

Environmental Defense Fund

The trend for numbers of LNG Fuelled vessels coming in operation is exponential, and the shipping industry’s demand for LNG Bunker Vessels is following suit. The type and size of LNG bunker vessel the market demands is not sophisticated and a multi-purpose vessel, but a serially produced, fit-for-purpose “work horse”. Taking advantage of Schulte Groups own present in-house and past experience, we have developed such a vessel in close cooperation and in a Joint Venture with the Ship designer TECHNOLOG Services GmbH, Hamburg. The key features of the vessel are:

• Safety – That the vessels design inherently and naturally allows for safe operation and safety contingencies. • Compatibility – To ensure the vessel is Compatible with any LNG fuelled vessel or unit, large or small, featuring protruding lifeboats or not.

• ECO friendly - Prepared for future more stringent requirements – Zero-Carbon.

• Conditioning and Servicing of LNG Fuelled vessels bunker tanks – The vessel is equipped with system for fast and efficient inerting and warm-up of client vessels tanks - for example in preparations for special survey docking or emergency docking for damage repairs.

• Low CAPEX and OPEX – To ensure the end client does not need to pay additional surcharge for the last leg of the LNG fuel delivery.

• Scalable – The vessel’s basic “feeder” vessel version is technically prepared in readiness to add options such as; Sub-coolers, GCUs, forward bunker manifolds, alternative fender solutions and upper manifolds.

• Future proofing – The vessel has options allowing for easy Methanol and Ammonia conversion.

My paper walks through the lessons learned from past and present hands-on practical LNG Bunkering experiences – both highs’ and lows’ – and extrapolates and explores the key features for next generation LNG and “Low flashpoint” bunker vessels.

Johan Lillieskold

Gas Solution Specialist

Schulte Group

Bunkering LNG ship-to-ship (STS) has become a reality with approximately 15 LNG bunkering vessels (LNGBVs) in service and a similar number of ships on order as of December 2021. In addition some LNG bunker barges have been developed in the last years, including very small units for restricted or inland navigation service currently in operation. The locations where STS operations are developed includes nowadays Europe, America and Asia with focus a in North Europe, US and South East Asia but many other regions will also propose infrastructure in the coming future. Gaztransport & Technigaz (GTT) and Bureau Veritas (BV) are two of the most active global stakeholders with two different roles; cargo containment system/ship design and classification/certification of ships and equipment respectively. For many years both companies have been involved in significant developments including highly innovative LNGBVs designs or dedicated systems for this specific growing segment. A review of the evolution of LNGBVs projects developed in the last years will be an introduction subject in the presentation. A revolutionary design which involves GTT technology Mark III Flex and BV classification had materialized with the largest ever LNGBV in operation, the Gas Agility and the Gas Vitality of 18,600 m3 capacity based in the ARA region and Marseille respectively owned by MOL and built by Hudong shopyard (China). These LNGBVs have demonstrated the feasibility to use membrane technology for LNGBVs and respond to the market need to significantly increase the cargo capacity for specific bunkering applications. Brand new ideas which will help further development of the LNG bunkering vessel industry have been developed recently. On this respect the GTT “Shear-Water” design is very relevant among the current proposals for which Bureau Veritas will provide an approval in principle (AIP). The GTT “Shear-Water” design will be presented at large in the paper together with the key aspects covered by BV in the approval. Based on the currently proven size of 18,700 m3 capacity in two membrane tanks, the design features a very new ship shape in “V” which differs from the standard square shaped midship sections traditionally used for LNG carriers.

The design is categorized as “Green Ship” due to several advantageous characteristics:

- Absence of ballast water and in this context no need for ballast water treatment system and less equipment on board.

- Easy maintenance of void spaces surrounding the cargo tanks.

- Reduced propulsion power when compared to similar ships

In addition, an exhaustive testing campaign has been carried out at the HSVA Hamburg tank test facility in connection with power-speed, maneuverability and sea keeping and a model test sloshing campaign performed in GTT facilities to ensure the technical feasibility of the project. Last but not least the GTT “Shear-Water” design is scalable to other sizes such as 7,500 m3 or even 25,000 m3 and the project is feasible as small scale LNG feeder as well as LNGBV.

Carlos Guerrero

Global Market Leader of Gas Carriers and Tankers

Bureau Veritas Marine & Offshore

Jonathan Blicher

Product Line Developer

GTT

The Messina strait is currently a sea route of pivotal importance in the Mediterranean Sea and his competitiveness to manage large volumes of traffic in the near future is strictly related to the availability of a small scale and bunkering LNG facility able to serve all the several ports located in the area, very close one to the other.

The Messina Strait Port Authority (“Autorità di Sistema Portuale dello Stretto” – AdSP) is therefore interested in promoting the development of an LNG-related infrastructure in the area which could act as a regional hub to facilitate the delivery of LNG through bunker vessels transiting the area as well as trucks.

Since all the ports above are adjacent to or in the proximity of urban areas, selection of the optimum location is of primary importance to ensure not only compliance with Port regulations and other territorial constraints, but also high operability over the year, proximity to transport infrastructures and easiness of performing bunkering services, as well as safety and environmental impact minimization during both the construction stage and the operation. A multi-criteria approach was therefore needed to properly address all the technical, financial, HSE and permitting issues that could determine the best location and LNG concept solution. In this framework, in 2021 RINA undertook a Technical and Economic Feasibility Study for the AdSP aiming to define both the best location to house the small-scale depot and plant’s main features, through a concept selection process among proven solutions available on the market. A multi-step procedure to shortlist potential suitable alternatives in the wide area first (according to large scale technical, territorial and environmental constraints) and secondly to select the best technical and financial option according to local peculiarities, safety impact in the surrounding due to accidental scenarios and economics (thanks to a financial assessment and a cost-benefit analysis) was developed.

At the completion, preliminary design, overall schedule and cost estimate of the best option were carried out, along with the provision of recommendations for project future development and construction stage.

Andrea Sola

LNG Business Development Manager

RINA Consulting S.p.A.

LNG plant’s carbon footprint reduction via H2 injection into Gas Turbines Natural gas, as transition energy vector, will play a key role in the overall energy mix at least for the next two decades. However, beyond the remarkable characteristics of this fuel, the natural gas industry continuously works at reducing Greenhouse Gas (GHG) emissions of the production chain to make it sustainable. In this context, TotalEnergies and Saipem are jointly developing solutions including the optimized source mix for powering brownfield LNG production facilities. Among the different paths explored towards this objective, the use of hydrogen was assessed. The analysis consisted in checking the possibility to inject hydrogen into the fuel gas network feeding the Main Refrigerant Compressor Gas Turbines and Power Generation Gas Turbines which are the main CO2 emitters in an LNG complex. 16% GHG emissions reduction are immediately achievable with reasonable cost of avoided CO2, with no further development for most of existing Gas Turbines. The study included a proper analysis of the costs of the avoided CO2, mainly driven by the investment required for the hydrogen production facilities, the carbone capture, the integration in the LNG facilities, and the retrofit of the machinery engines and ancillaries. In addition to the capital expenditure, the operational costs of the Hydrogen production facilities during the lifecycle of the plant were also considered in the analysis. The study was developed involving the most referenced turbomachinery suppliers to set the allowable hydrogen content admissible in the selected Gas Turbines. Also, for low carbon hydrogen production, the main implications related to the use of different technologies, such as a natural gas reforming plant equipped with carbon capture and sequestration (Blue Hydrogen) versus a water electrolysis unit fed by renewable sources, photovoltaic units in this case (Green Hydrogen) were addressed. For the Green Hydrogen Case, the study screened different hydrogen production rates with or without hydrogen storage, to achieve the most optimal option. Furthermore, the required surface for the photovoltaic plant and the selection of the best-in-class Alkaline technology for the electrolyzer were included in the Green Hydrogen installation design. For the Blue Hydrogen case, the selection of the most appropriate syngas production process (including the comparison between Steam Methane Reformer vs Auto Thermal Reformer screening several licensed technologies) was an important step for the determination of the implications and the costs. This was carried out in conjunction with the screening of different alternatives for the CO2 capture. Finally, the conceptual design for the selected solution was developed considering the required auxiliaries and the synergies with the available utilities already foreseen for the LNG facilities, with specific optimization for the integration of the heat recovery and electric power production management.

Thomas Brenas

Hydrogen Process Department Head

TotalEnergies

Tiziano DE PAOLIS

CCUS Solution Manager

Saipem S.p.A.

In the overall scenario of energy sector decarbonization, one of the promising technology solution to reduce emissions is burning low-carbon fuels in the Gas Turbines. Among low-carbon fuels, hydrogen is the one whose application is expected to grow most. Burning hydrogen in the Gas Turbine will allow to reduce carbon emissions at the exhaust, lowering carbon footprint of combustion in all energy sectors. Hydrogen combustion, in fact, does not produce carbon emissions, since hydrogen molecule does not contain carbon atoms. However, hydrogen combustion can generate high content of nitrogen oxides (NOx) emissions.

Along the years, gas turbine manufacturers developed combustion system capable to maintain low NOx levels using premixed combustion technology. Burning natural gas limiting NOx emissions till reaching single digit capabilities, without the need of an abatement fluid, is a spread technology applied worldwide. Unfortunately, premixed combustion technology is limited in burning hydrogen. Dry-Low NOx combustion technology, in fact, is not capable to burn very high percentage of hydrogen.

Instead looking at the diffusion combustion system, this technology allows a full burnability of hydrogen, permitting to reach a full decarbonization solution. On the other side a critical aspect that needs to be managed is related to already mentioned NOx emissions. In fact the diffusion system is more prone to produce NOx emissions.

In this paper Baker Hughes is going to present a configuration system that will allow to operate the gas turbine with low emissions. This system is currently under development, assuring burning hydrogen in diffusion system avoiding emissions of Carbon Dioxide and still maintaining low NOx. This achievement can be reached with enhanced design of diffusion system combustion, including mixing hydrogen and nitrogen in a fuel mixing blend before injecting it in the combustion chamber. Nitrogen, mixed with hydrogen, will assure a reduction flame temperature acting as abatement system. The overall configuration can be further enhanced with integration of PEMS (Predictive Emissions Management System) or CEMS (Continuous Emissions Management System).

Marco Baldini

Strategic DTI Manager Hydrogen GTs and Systems

Baker Hughes

Shell’s climate ambition to be a Net Zero Emissions energy business, by 2050 or sooner and in step with society, will require not only decarbonization of all segments of the existing LNG value chain, but creative solutions to harness renewable energy into creating net zero products. One such product is Liquid Synthetic Methane, also referred to as e-LNG or Synthetic LNG, which combines green Hydrogen with CO2 to make methane. Renewable energy sources are often geographically distanced from high demand centers and LSM is effectively a CO2 neutral trajectory between the two. It is envisaged as a drop-in substitute for conventional fossil LNG, effectively providing an attractive solution without requiring modifications to the customer infrastructure.

There are multiple, discrete technical building blocks that can create various pathways to market, and the utilization of existing LNG infrastructure can make this a compelling value proposition. This paper will address the opportunities and risks of various pathways, and opportunities to optimize the solution space by exploring key considerations, design choices and integration aspects.

Priscilla Chandrasekaran

LNG Technology Program Manager

Shell Projects & Technology

McDermott has identified multiple pathways to decarbonize LNG facilities, reducing operational emissions by greater than 95% and emissions associated with construction by 65%.

McDermott’s key client base has publicized carbon reduction strategies and targets to radically decarbonize their businesses to achieve net zero emissions by 2050 or sooner. LNG is seen as a key element enabling a realistic journey to provide clean energy to the global markets. However, the current position of the LNG industry requires additional carbon reduction efforts for LNG to play a continued role in global decarbonization allowing the forecasted LNG demand growth to become reality.

McDermott has developed these pathways for both Greenfield and Brownfield LNG facilities through a systematic approach in identifying technologies, processes and techniques that can reduce or eliminate GHG emissions. The paper describes the practicalities, challenges, and costs associated in achieving these goals thereby limiting the requirement to apply carbon offsets to achieve Net Zero.

Supplementary to this McDermott have leveraged their construction, modularization, and fabrication yard experience to provide lower carbon solutions for the construction / execution phases of these projects.

James Primrose

Principal Process Engineer

McDermott International Ltd

There has been a lot of discussion about spiking hydrogen into Natural Gas Networks. One of the practical considerations will be the requirement to blend various streams in order to meet downstream H2 composition limits that are imposed by pipeline integrity issues. For each pipeline segment, there will be a maximum allowable H2 concentration, based on fracture, fatigue and ductile concerns. Since pipeline networks are built with pipeline segments that have different operational history, design and grade, different material, different segments could potentially accept different maximum H2 threshold limits. For large complex network of pipelines, it would be essential to determine the flow split during normal and transient operations which was found to be very complex.

Even if blending would be possible from operation and integrity points of view, blending should be managed efficiently to ensuring the Wobbe index is consistent and meets contractual obligations for all customers. This is very important as H2 has a lower Wobbe than natural gas.

This paper we will share our past lessons learnt and will discuss an example system, that can be applied to other networks. In this example, the two downstream branches have different H2 Composition Limits and there are three upstream branches. If the gas mixture cannot be blended to certain specification then either the transport should be stopped or if storage is available the gas should be stored so that the remaining gas can be exported or flared. Then later if possible when the upstream mixture is improved, gas can be pulled out of storage. The ability to effectively blend gas will be vital if the H2 is generated by green energy, since the amount of H2 will be variable depending on the climate and even during day and nights. This paper will provide via examples, the various scenarios which an operator could expect and the challenges associated with it. For example, various transient events in the upstream network can introduce spikes in the H2 concentration. These spikes will need to be tracked so that the system can perform feed-forward control with feedback. Also the model will calculate a weighted expose to H2 concentration and this paper will show how proper blending can reduce this cumulative exposure.

James Holbeach

Global Director – Energy Transition and Flow Assurance

Wood PLC

Hydrogen can support the use of renewables and decarbonised energy in Australia and globally but it needs to be stored and transported efficiently. Pipelines can simultaneously both transport and store energy and existing pipelines offer a particularly cost-effective solution in supporting the energy transition.

Future Fuels CRC is studying the conversion of sections of the Australian natural gas pipeline network to hydrogen service. This process could be replicated globally using the engineering research we are developing.

To deliver this conversion, gas pipeline engineers and operators need new knowledge and practical guidance in the form of standards.

Testing existing pipelines to prepare for conversion

When a steel pipeline is used to transport hydrogen, atomic hydrogen is absorbed into the steel and can reduce the ductility, toughness and fatigue life of the steel. This means engineering, material testing and applied research are all required to support the pipeline’s conversion.

Future Fuels CRC has already delivered the results of testing the mechanical properties of pipelines in air at atmospheric pressure, and the predicted behaviour of the material in hydrogen assessed through engineering calculations and comparison with international literature. The results are overwhelmingly positive and are now being followed by testing in a gaseous hydrogen environment. This second phase of research is providing additional confidence of the service performance and allowing detailed safety studies and conversion plans to be developed.

This conference paper will provide an overview of the results to date in view of applicable standards, as well as risk assessment and management frameworks.

Delivering a Hydrogen Pipelines Code of Practice

Pipeline infrastructure remains a highly cost-effective means of transporting and storing low carbon energy in the form of gaseous hydrogen but it must be done reliably, cost effectively and most importantly, safely. A key aspect of achieving this goal is the development of standards and guidelines that both address the unique demands of hydrogen service and support its future adoption within Australian and international standards.

To achieve this, Future Fuels CRC is developing a new Code of Practice to provide guidance and recommended practice for the design, construction and operation of transmission pipelines for the intended purpose of transporting gaseous hydrogen or blends of hydrogen and hydrocarbon fluids, including in steel and high pressure composite materials.

The Hydrogen Pipelines Code of Practice consolidates current knowledge, with a specific focus on hydrogen fluid compatibility with pipeline materials and differences compared to hydrocarbon fluids.

The Code of Practice is a key step in converting research outcomes, both domestically and internationally, into usable knowledge and guidance for application by the industry. The presentation and paper will highlight the content of the Code of Practice and how industry will use it to support safe and reliable transmission of hydrogen in new and existing pipelines.

David Norman

Chief Executive Officer

Future Fuels CRC Ltd