How to decarbonise international shipping: Options for fuels, technologies and policies

As environmental regulations on sulphur emissions become more severe, the maritime sector is looking for alternative solutions. This study evaluates greenhouse gas (GHG) reduction alternatives and their combined ability to decarbonise international transport. Liquefied natural gas (LNG) is becoming widely used, reducing CO2 emissions by 20–30 percent, while it has similar action in other emissions such as SOX. Although costs are attractive, methane slip, which depends on the engine type, reduces GHG gains. Replacing conventional fuels such as heavy fuel oil and marine diesel oil with alternative ones is an effective method to decrease SOx emissions. Liquefied natural gas is highly appreciated as an alternative fuel for maritime transportation. In this frame, the possibility of using alternative fuels, such as LNG, to reduce NOx, CO2 and SOx emissions in Heraklion Port, including certain regionally defined waters, over the life of the vessel will also be explored. The study is conducted for ships calling at Heraklion Port and using alternative fuel such as LNG in different modes (cruising, hotelling, manoeuvring). A fuel-based emission reduction factor, rEif, is defined in relation to the comparison of two different fuels: conventional (heavy oil, marine diesel) and alternative fuels (LNG). The bottom-up method is used for this data analysis. This study, by defining the reduction of several emissions with the use of LNG, indicates that it is actually an efficient transitional fuel to lead international transport to decarbonisation.

The U.S. Department of Energy (DOE) estimates that in the coming decades the United States' natural gas (NG) demand for electricity generation will increase. Estimates also suggest that NG supply will increasingly come from imported liquefied natural gas (LNG). Additional supplies of NG could come domestically from the production of synthetic natural gas (SNG) via coal gasification-methanation. The objective of this study is to compare greenhouse gas (GHG), SOx, and NOx life-cycle emissions of electricity generated with NG/LNG/SNG and coal. This life-cycle comparison of air emissions from different fuels can help us better understand the advantages and disadvantages of using coal versus globally sourced NG for electricity generation. Our estimates suggest that with the current fleet of power plants, a mix of domestic NG, LNG, and SNG would have lower GHG emissions than coal. If advanced technologies with carbon capture and sequestration (CCS) are used, however, coal and a mix of domestic NG, LNG, and SNG would have very similar life-cycle GHG emissions. For SOx and NOx we find there are significant emissions in the upstream stages of the NG/ LNG life-cycles, which contribute to a larger range in SOx and NOx emissions for NG/LNG than for coal and SNG.

Liquefied natural gas (LNG) use as shipping fuel has increased in recent years. While LNG results in lower carbon dioxide (CO2) emissions as well as benefits in terms of air pollutants, the slip of unburned methane, the main component of LNG, has remained a concern. In this study, methane together with other climate warming agents, CO2 and black carbon (BC), as well as other emission compounds were characterized from 4-stroke low-pressure dual fuel engine on-board a newly build cruise ship utilizing LNG as well as marine gas oil (MGO). The brake specific methane slip was found to vary according to engine load, being 2.3–3.0 g/kWh at 54–80% loads, but increasing to 10 g/kWh at 25% load and 21 g/kWh at 12% load. The LNG combustion also resulted in higher formaldehyde emissions compared to MGO, but reduction in formaldehyde levels was observed over the SCR catalyst present in the exhaust line of the dual-fuel engine, without urea injection, suggesting it may provide a pathway for formaldehyde mitigation. In terms of particle emissions, LNG use reduced particle mass (PM) by 87–93% and BC by 94–99% compared to MGO combustion. Non-volatile particle number above 23 nm (PNnv,>23nm) and 10 nm (PNnv,>10nm) were reduced by 88–97% and 97–99%, except at lowest engine load where PNnv,>10nm increased by 26% compared to MGO utilization. When total greenhouse gas (GHG) emissions including CO2 and BC were considered, LNG use resulted in 13–15% lower GHG at high loads, but the benefit was undermined by the escaping methane at low load conditions. Following the engine activity profile during 8-months of vessel operation on the Mediterranean suggested, however, that in a diesel-electric cruise ship, low load conditions are used mainly during arrivals and departures from harbors, as the engine was operated at loads above 40% for 90% of the operation time. Weighted emission factor, representing the actual engine operation, resulted in methane slip of 2.8 g/kWh or 1.7% of the fuel use, which is below the value considered in the FuelEU Maritime. The results suggest that load specific methane slip, together with engine load profile should be considered when evaluating methane slip on vessel or fleet level.

We analyze the economic effects of greenhouse gases (GHG) reduction measures of the generation sector of South Korea to accomplish the 2030 GHG reduction target using a scenario-based approach. We estimate the GHG emission of the South Korean power industry in 2030 based on both the 7th Electricity Supply and Demand Plan and the GHG emission coefficients issued by the International Atomic Energy Agency (IAEA). We establish four scenarios for reduction measures by replacing the coal-fired power plants with nuclear power, renewable energy and carbon capture and storage, and liquefied natural gas (LNG) combined cycle generation. Finally, the nuclear power scenario demonstrates the most positive measure in terms of GHG reduction and economic effects.

The liquefied natural gas (LNG) sector relies extensively on gas turbines for on-site power generation and to drive refrigeration compressors. They provide an efficient and reliable energy source for LNG operations in remote locations. With upcoming changes to the Safeguard Mechanism in Australia, there is an increased focus on Scope 1 emissions, so management and targeted reduction are a priority to reduce liabilities. Despite technology advancements, gas turbines remain one of the largest sources of carbon dioxide (CO2) emissions in LNG production facilities. Also, in Australia, many facilities are not grid-connected, meaning that displacement of Scope 1 emissions through renewable electricity sourcing is a challenge. To develop deeper cuts in Scope 1 emissions, one solution is to deploy post-combustion carbon capture and storage (CCS) on existing gas turbines, with the potential to reduce associated emissions by over 90%. Globally, a number of LNG facilities are already deploying CCS to permanently store reservoir CO2 from the LNG processing trains. Several Australian LNG facilities are located in close proximity to potential CO2 storage reservoirs, meaning that a coordinated approach to both reservoir and post-combustion CO2 should be considered when sizing pipelines, shipping systems and storage wells to optimise and leverage the required investment. This paper outlines the technological, economic and policy aspects of integrating both reservoir post-combustion CCS on LNG facilities, including barriers and opportunities for deployment. It will discuss new developments and enablers for CCS to be more widely deployed at LNG production sites.

Presented on Wednesday 22 May: Session 13 The liquefied natural gas (LNG) sector relies extensively on gas turbines for on-site power generation and to drive refrigeration compressors. They provide an efficient and reliable energy source for LNG operations in remote locations. With upcoming changes to the Safeguard Mechanism in Australia, there is an increased focus on Scope 1 emissions, so management and targeted reduction are a priority to reduce liabilities. Despite technology advancements, gas turbines remain one of the largest sources of carbon dioxide (CO2) emissions in LNG production facilities. Also, in Australia, many facilities are not grid-connected, meaning that displacement of Scope 1 emissions through renewable electricity sourcing is a challenge. To develop deeper cuts in Scope 1 emissions, one solution is to deploy post-combustion carbon capture and storage (CCS) on existing gas turbines, with the potential to reduce associated emissions by over 90%. Globally, a number of LNG facilities are already deploying CCS to permanently store reservoir CO2 from the LNG processing trains. Several Australian LNG facilities are located in close proximity to potential CO2 storage reservoirs, meaning that a coordinated approach to both reservoir and post-combustion CO2 should be considered when sizing pipelines, shipping systems and storage wells to optimise and leverage the required investment. This paper outlines the technological, economic and policy aspects of integrating both reservoir post-combustion CCS on LNG facilities, including barriers and opportunities for deployment. It will discuss new developments and enablers for CCS to be more widely deployed at LNG production sites. To access the Oral Presentation click the link on the right. To read the full paper click here

Liquified natural gas (LNG), with its low sulphur content, its favorable hydrogen-to-carbon ratio, and the lower nitrogen oxide emission when combusted compared to conventional fuels, fulfils all International Maritime Organization (IMO) air emission regulations. For the cruise industry, with their large number of customers and their high public visibility, LNG has therefore become a tempting option for new cruise ships. However, larger well-to-tank (WTT) emissions for the LNG supply chain as well as un-combusted methane (CH4) from the ship’s engine might more than nullify any greenhouse gas (GHG) gains. Previous studies have shown very different GHG impacts from the use of LNG as a ship fuel. With climate change potentially being the largest threat to mankind, it is important that decisions with an impact on future GHG emissions are based on the best available knowledge within a sector and across sectors. The motivation for this study has therefore been to establish comparable GHG estimates for well-to-wake (WTW) emissions for LNG and traditional fuels in a transparent way. The results show that there is a need for adopting policies that can reduce the broader GHG emissions of shipping instead of CO2 only, including the well-to-tank emissions of ship fuels. If not, we might end up with a large number of ships with GHG savings on paper only, while the real GHG emissions increases.

<div class="section abstract"><div class="htmlview paragraph">With increased awareness and scrutiny of greenhouse gas (GHG) emissions, the heavy-duty truck industry is on the lookout for solutions that can maximize GHG savings, through either lowering fuel consumption and lowering methane slip. This paper focuses on whether it is possible to provide a differentiated Liquefied Natural Gas (LNG) that supports the further improvement of a High-Pressure Direct Injection (HPDI) Engine. Desired improvements from this LNG blend are the lowering or substitution of the pilot Diesel use of the current HPDI engine, the lowering of the raw exhaust gas methane concentration and any additional performance improvements. Sixty-five substances were identified that could potentially be blended into cryogenic methane thus creating a differentiated LNG fuel. This paper goes through the process of additive selection and then focuses primarily on the results for using Dimethyl Ether (DME) as an LNG component, one of the candidate substances, but also showcases some of the other potential additives.</div><div class="htmlview paragraph">To study the autoignition properties of DME/LNG blends, autoignition delay times were simulated and then measured in a Rapid Compression Machine at engine conditions. The results were used to optimize the chemical mechanism that is used as input into a High-Pressure Direct Injection engine model. It was found that more than 5 vol% DME is required to reach a significant reduction in the autoignition delay time at typical operating conditions. The engine modelling results were also used to determine the initial conditions for HDPI engine tests using a modified 15L-Westport engine.</div><div class="htmlview paragraph">These engine tests showed that an LNG/DME blend could potentially be used to develop a mono-fuel HPDI engine. However, it was found that although the mono-fuel concept works for high load conditions with the existing HPDI engine, further research is needed to enable stable combustion at lower loads and idling while keeping DME proportions at levels that could be dissolved in LNG. It was also found that higher proportions of DME in the LNG could lead to a reduction of the methane slip.</div></div>

The war in Ukraine caused Europe to more than double its imports of liquefied natural gas (LNG) in only one year. In addition, imported LNG remains a crucial source of energy for resource-poor countries, such as Japan, where LNG imports satisfy about a quarter of the country’s primary energy demand. However, an increasing number of countries are formulating stringent decarbonization plans. Liquefied hydrogen and liquefied ammonia coupled with carbon capture and storage (LH2-CCS, LNH3-CCS) are emerging as the front runners in the search for low-carbon alternatives to LNG. Yet, little is currently known about the full environmental profile of LH2-CCS and LNH3-CCS because several characteristics of the two alternatives have only been analyzed in isolation in previous work. Here we show that the potential of these fuels to reduce greenhouse gas (GHG) emissions throughout the supply chain is highly uncertain. Our best estimate is that LH2-CCS and LNH3-CCS can reduce GHG emissions by 25%–61% relative to LNG assuming a 100 year global warming potential. However, directly coupling LNG with CCS would lead to substantial GHG reductions on the order of 74%. Further, under certain conditions, emissions from LH2-CCS and LNH3-CCS could exceed those of LNG, by up to 44%. These results question the suitability of LH2-CCS and LNH3-CCS for stringent decarbonization purposes.

Reducing air pollution and greenhouse gas emissions has become one of the primary tasks for the shipping industry over the past few years. Among alternative marine fuels, liquefied natural gas (LNG) is regarded as one of the most popular alternative marine fuels because it is one of the cleanest fossil marine fuels. Therefore, a practical way to implement green shipping is to deploy dual-fuel ships that can burn conventional fuel oil and LNG on various ship routes. However, a severe problem faced by dual-fuel ships is methane slip from the engines of ships. Therefore, this study formulates a nonlinear mixed-integer programming model for an integrated optimization problem of fleet deployment, ship refueling, and speed optimization for dual-fuel ships, with the consideration of fuel consumption of both main and auxiliary engines, ship carbon emissions, availability of LNG at different ports of call, and methane slip from the main engines of ships. Several linearization techniques are applied to transform the nonlinear model into a linear model that can be directly solved by off-the-shelf solvers. A large number of computational experiments are carried out to assess the model performance. The proposed linearized model can be solved quickly by Gurobi, namely shorter than 0.12 s, which implies the possibility of applying the proposed model to practical problems to help decision-makers of shipping liners make operational decisions. In addition, sensitivity analyses with essential parameters, such as the price difference between the conventional fuel oil and LNG, carbon tax, and methane slip amount, are conducted to investigate the influences of these factors on operational decisions to seek managerial insights. For example, even under the existing strictest carbon tax policy, shipping liners do not need to deploy more ships and slow steaming to reduce the total weekly cost.

In light of the International Maritime Organization’s (IMO) ambitious Initial GHG Strategy, the rise in international shipping’s carbon dioxide emissions by 2 percent in 2022 compared to 2019 poses a formidable challenge. This increase underscores the pressing need to address the limited availability of green hydrogen, prompting the exploration of mid-term solutions to bridge this critical gap. The IMO’s 2023 Strategy on Reduction of GHG Emissions from Ships attempted to tackle this challenge head-on, recognizing the urgency of reducing the industry’s substantial carbon footprint. While hydrogen offers a simple solution as a zero-carbon fuel, LNG remains the most widespread alternative fuel to date. LNG has gained traction for its potential to significantly reduce emissions compared to traditional heavy fuel oils, offering lower levels of sulfur oxides (SOx), nitrogen oxides (NOx), and particulate matter (PM). However, LNG’s limited capacity for GHG reduction necessitates innovative approaches. Blending LNG with hydrogen has emerged as a promising mid-term solution to enhance its environmental performance and close the emissions gap. This strategic approach underscores the imperative of expediting the adoption of transitional cleaner fuels and emphasizes collaborative efforts in achieving sustainability goals within the maritime sector. The research journey described in this thesis carefully explores immediate and medium-term strategies to reduce greenhouse gas emissions in maritime shipping, aligning with IMO’s GHG Strategy. It begins by examining liquefied natural gas (LNG) as a cleaner fuel, thoroughly analyzing its combustion characteristics and onboard emissions. It also investigates hydrogen enrichment in LNG as a practical solution, conducting targeted laboratory experiments to address real-world implementation challenges. A pivotal aspect of the research lies in the comprehensive analysis of engine performance and emissions throughout the life cycle of hydrogen-enriched LNG. By conducting real-world engine testing across various engine loads and hydrogen fractions, the study seeks to glean valuable insights into the operational feasibility and environmental implications of utilizing hydrogen-LNG fuel blends in maritime propulsion systems. This empirical approach allows for a nuanced understanding of the practical implications of transitioning to hydrogen-enriched LNG. Moreover, the study culminates in a holistic assessment that integrates experimental data with comprehensive life cycle assessment (LCA). By considering both environmental and economic factors, including cost-benefit analyses and economic modelling, stakeholders are empowered to make well-informed decisions regarding the adoption of hydrogen-enriched LNG as a transitional fuel. This integrated approach underscores the environmental and economic benefits of hydrogen-enriched LNG, positioning it as a promising solution for sustainable

Emissions Reduction Visual Presentation R07 The international liquefied natural gas (LNG) trade is a growing sector in the global energy market driven, in part, by the transition from carbon-intensive energy sources such as coal and diesel to lower-carbon alternatives. The emergence of the ‘green LNG’ market, which involves offsetting emissions through carbon credits, highlights the industry’s shift towards sustainability. However, a critical challenge lies in estimating and managing emissions across the entire value chain, particularly in Scope 3 emissions, such as Upstream Transportation and Distribution (Category 4). This study employs a Monte Carlo model implemented in a hydrocarbon management system (EnergySys) to analyse greenhouse gas (GHG) emissions associated with each stage of an LNG voyage from Gladstone Island, Australia, to Himeji, Japan. The analysis incorporates variables such as engine type, voyage duration, fuel consumption and methane slip. Results indicate that the cargo and ballast voyage stages are the largest contributors to total emissions, accounting for over 80% of the journey’s 4193 tCO2-e. This paper aims to support the understanding of GHG emissions across the various stages of the LNG voyage, providing a structured analytical approach that highlights key emission sources in LNG transportation. To access the Visual Presentation click on the link on the right. To read the full paper click here

The international liquefied natural gas (LNG) trade is a growing sector in the global energy market driven, in part, by the transition from carbon-intensive energy sources such as coal and diesel to lower-carbon alternatives. The emergence of the ‘green LNG’ market, which involves offsetting emissions through carbon credits, highlights the industry’s shift towards sustainability. However, a critical challenge lies in estimating and managing emissions across the entire value chain, particularly in Scope 3 emissions, such as Upstream Transportation and Distribution (Category 4). This study employs a Monte Carlo model implemented in a hydrocarbon management system (EnergySys) to analyse greenhouse gas (GHG) emissions associated with each stage of an LNG voyage from Gladstone Island, Australia, to Himeji, Japan. The analysis incorporates variables such as engine type, voyage duration, fuel consumption and methane slip. Results indicate that the cargo and ballast voyage stages are the largest contributors to total emissions, accounting for over 80% of the journey’s 4193 tCO2-e. This paper aims to support the understanding of GHG emissions across the various stages of the LNG voyage, providing a structured analytical approach that highlights key emission sources in LNG transportation.

Chapter 38 - Gas Plants

The last decade has seen a signifi cant increase in the research and development of CO 2 capture and storage (CCS) technology. CCS is now considered to be one of the key options for climate change mitigation. This perspective provides a brief summary of the state of the art regarding CCS development and discusses the implications for the further development of CCS, particularly with respect to climate change policy. The aim is to provide general perspectives on CCS, although examples used to illustrate the prospects for CCS are mainly taken from Europe. The rationale for developing CCS should be the over-abundance of fossil fuel reserves (and resources) in a climate change context. However, CCS will only be implemented if society is willing to attach a suffi ciently high price to CO 2 emissions. Although arguments have been put forward both in favor and against CCS, the author of this perspective argues that the most important outcome from the successful commercialization of CCS will be that fossil-fuel-dependent economies will fi nd it easier to comply with stringent greenhouse gas (GHG) reduction targets. In contrast, failure to implement CCS will require that the global community agrees almost immediately to start phasing out the use of fossil fuels; such an agreement seems more unrealistic than reaching a global agreement on stringent GHG reductions. Thus, in the near term, it is crucial to initiate demonstration projects, such as those supported by the EU. If this is not done, there is a risk that the introduction of CCS will be signifi cantly delayed. Among the stakeholders in CCS technologies (R&D actors in industry and academia), the year 2020 is typically considered to be the year in which CCS will be commercially available. Considering the lead times for CCS development and the slow pace of implementation of climate policy (post-Copenhagen), the target year of 2020 seems rather optimistic.