Article

Greenhouse-gas emissions of Canadian liquefied natural gas for use in China: Comparison and synthesis of three independent life cycle assessments

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Abstract

Liquefied natural gas (LNG) is a promising alternative to coal to mitigate the greenhouse gas (GHG) and particulate emissions from power, industry, and district heating in China. While numerous existing life cycle assessment (LCA) studies estimate the GHG footprint of LNG, large variation exists in these results. Such variability could be caused by differing project designs, system boundaries, modeling methods and data sources. It is not clear which of these factors is the most important. Here, three research groups from Canada and the US performed independent LCAs of the same planned LNG supply chain from Canada to China. The teams applied different methods and assumptions but used aligned system boundaries and worked with a single upstream producer to obtain production data. The GHG emissions of Canadian LNG to China for power and heat generation were found to be 427–556 g CO2-eq/kWh and 81–92 g CO2-eq/MJ. Compared with Chinese coal for power generation, 291–687 g CO2-eq (34%–62%) reduction can be achieved per kWh of power generated. The central tendency in each study is aligned more closely than the overall uncertainty range: thus, uncertainty caused by fundamental data challenges likely outweighs variability caused by use of different LCA methods. Differences in assumptions and methods among the three teams lead to moderate variation at the stage level, but in better agreement at the life-cycle level, showing the existence of compensating variation. Given the robustness to very different LCA methods, existing literature variation may be explained by project-, location- and operator-dependent parameters.

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Purpose Liquefied natural gas (LNG) is expected to become an important component of the UK’s energy supply because the national hydrocarbon reserves on the continental shelf have started diminishing. However, use of any carbon-based fuel runs counter to mitigation of greenhouse gas emissions (GHGs). Hence, a broad environmental assessment to analyse the import of LNG to the UK is required. Methods A cradle to gate life cycle assessment has been carried out of a specific but representative case: LNG imported to the UK from Qatar. The analysis covers the supply chain, from gas extraction through to distribution to the end-user, assuming state-of-the-art facilities and ships. A sensitivity analysis was also conducted on key parameters including the energy requirements of the liquefaction and vaporisation processes, fuel for propulsion, shipping distance, tanker volume and composition of raw gas. Results and discussion All environmental indicators of the CML methodology were analysed. The processes of liquefaction, LNG transport and evaporation determine more than 50% of the cradle to gate global warming potential (GWP). When 1% of the total gas delivered is vented as methane emissions leakage throughout the supply chain, the GWP increases by 15% compared to the GWP of the base scenario. The variation of the GWP increases to 78% compared to the base scenario when 5% of the delivered gas is considered to be lost as vented emissions. For all the scenarios analysed, more than 75% of the total acidification potential (AP) is due to the sweetening of the natural gas before liquefaction. Direct emissions from transport always determine between 25 and 49% of the total eutrophication potential (EP) whereas the operation and maintenance of the sending ports strongly influences the fresh water aquatic ecotoxicity potential (FAETP). Conclusions The study highlights long-distance transport of LNG and natural gas processing, including sweetening, liquefaction and vaporisation, as the key operations that strongly affect the life cycle impacts. Those cannot be considered negligible when the environmental burdens of the LNG supply chain are considered. Furthermore, the effect of possible fugitive methane emissions along the supply chain are critical for the impact of operations such as extraction, liquefaction, storage before transport, transport itself and evaporation.
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Purpose Good background data are an important requirement in LCA. Practitioners generally make use of LCI databases for such data, and the ecoinvent database is the largest transparent unit-process LCI database worldwide. Since its first release in 2003, it has been continuously updated, and version 3 was published in 2013. The release of version 3 introduced several significant methodological and technological improvements, besides a large number of new and updated datasets. The aim was to expand the content of the database, set the foundation for a truly global database, support regionalized LCIA, offer multiple system models, allow for easier integration of data from different regions, and reduce maintenance efforts. This article describes the methodological developments. Methods Modeling choices and raw data were separated in version 3, which enables the application of different sets of modeling choices, or system models, to the same raw data with little effort. This includes one system model for Consequential LCA. Flow properties were added to all exchanges in the database, giving more information on the inventory and allowing a fast calculation of mass and other balances. With version 3.1, the database is generally water-balanced, and water use and consumption can be determined. Consumption mixes called market datasets were consistently added to the database, and global background data was added, often as an extrapolation from regional data. Results and discussion In combination with hundreds of new unit processes from regions outside Europe, these changes lead to an improved modeling of global supply chains, and a more realistic distribution of impacts in regionalized LCIA. The new mixes also facilitate further regionalization due to the availability of background data for all regions. Conclusions With version 3, the ecoinvent database substantially expands the goals and scopes of LCA studies it can support. The new system models allow new, different studies to be performed. Global supply chains and market datasets significantly increase the relevance of the database outside of Europe, and regionalized LCA is supported by the data. Datasets are more transparent, include more information, and support, e.g., water balances. The developments also support easier collaboration with other database initiatives, as demonstrated by a first successful collaboration with a data project in Québec. Version 3 has set the foundation for expanding ecoinvent from a mostly regional into a truly global database and offers many new insights beyond the thousands of new and updated datasets it also introduced.
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In reviewing the carbon footprint of the production and transportation of 1m³ of LNG to China, this life cycle assessment (LCA) has confirmed that the production and liquefaction stage generates the most GHG emissions (45.4%) followed by the natural gas exploration and separation stage (39%) and the exportation and transportation stage (15.7%). The utilisation of wind power energy as a replacement of gas fired electricity generation could possibly reduce the 'energy consumption' related GHG emissions of LNG production by some 36-51%. Similarly, the utilisation of carbon capture and storage to sequester the GHG emitted during electricity production could potentially reduce 'energy consumption' related GHG emissions by 33-45%. This LCA will assist exporters, manufacturers, and suppliers in the LNG supply chain with enhanced environmental supply chain management and the management of any future carbon trading pressures on LNG markets.
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Chapter
Natural gas-fired baseload power production has life cycle greenhouse gas emissions 42to 53 percent lower than those for coal-fired baseload electricity, after accounting for a widerange of variability and compared across different assumptions of climate impact timing. Thelower emissions for natural gas are primarily due to differences in the current fleets' averageefficiency - 53 percent for natural gas versus 35 percent for coal, and a higher carbon contentper unit of energy for coal than natural gas. Even using unconventional natural gas, from tightsands, shale and coal beds, and compared with a 20-year global warming potential (GWP),natural gas-fired electricity has 39 percent lower greenhouse gas emissions than coal perdelivered megawatt-hour (MWh) using current technology.In a life cycle analysis (LCA), comparisons must be based on providing an equivalentservice or function, which in this study is the delivery of 1 MWh of electricity to an end user.This life cycle greenhouse gas inventory also developed upstream (from extraction to deliveryto a power plant) emissions for delivered energy feedstocks, including six different domesticsources of natural gas, of which three are unconventional gas, and two types of coal, and thencombines them both into domestic mixes. These are important characterizations for the LCAcommunity, and can be used as inputs into a variety of processes. However, these upstream,or cradle-to-gate, results are not appropriate to compare when making energy policydecisions, since the two uncombusted fuels do not provide an equivalent function. Theseresults highlight the importance of specifying an end-use basis-not necessarily powerproduction-when comparing different fuels.Despite the conclusion that natural gas has lower greenhouse gases than coal on adelivered power basis, the extraction and delivery of the gas has a large climate impact -32percent of U.S. methane emissions and 3 percent of U.S. greenhouse gases (EPA, 2011b). AsFigure ES-2 shows, there are significant emissions and use of natural gas-13 percent at thecity or plant gate-even without considering final distribution to small end-users. The vastmajority of the reduction in extracted natural gas -64 percent cradle-to-gate-are notemitted to the atmosphere, but can be attributed to the use of the natural gas as fuel forextraction and transport processes such as compressor operations. Increasing compressorefficiency would lower both the rate of use and the CO2 emissions associated with thecombustion of the gas for energy. Note that this figure accounts for the total mass of naturalgas extracted from the earth, including water, acid gases, and other non-methane content. But, with methane making up 75 to 95 percent of the natural gas flow, there are manyopportunities for reducing the climate impact associated with direct venting to theatmosphere. A further 24 percent of the natural gas losses can be characterized as pointsource, and have the potential to be flared-essentially a conversion of GWP-potent methaneto carbon dioxide. The conclusions drawn from this analysis are robust to a wide array of assumptions.However, as with any inventory, they are dependent on the underlying data, and there aremany opportunities to enhance the information currently being collected. This analysis showsthat the results are both sensitive to and impacted by the uncertainty of a few key parameters:use and emission of natural gas along the pipeline transmission network; the rate of naturalgas emitted during unconventional gas extraction processes such as well completion andworkovers; and the lifetime production of wells, which determine the denominator overwhich lifetime emissions are placed.This analysis inventoried both average and marginal production rates for each natural gastype, with results shown in Table ES-1. The average represents natural gas produced from allwells, including older and low productivity stripper wells. The marginal production raterepresents natural gas from newer, higher productivity wells. The largest difference was foronshore conventional natural gas, which had a 41 percent reduction in upstream greenhousegas emissions from 20.1 to 34.2 lbs CO2e/MMBtu when going from marginal to averageproduction rates. This change has little impact on emissions from power production.This inventory and analysis are for greenhouse gases only, and there are many otherfactors that must be considered when comparing energy options. A full inventory ofconventional and toxic air emissions, water use and quality, and land use is currently underdevelopment, and will allow comparison of these fuels across multiple environmentalcategories. Further, all options need to be evaluated on a sustainable energy basis, consideringfull environmental performance, as well as economic and social performance, such as theability to maintain energy reliability and security. There are many opportunities fordecreasing the greenhouse gas emissions from natural gas and coal extraction, delivery andpower production, including reducing fugitive methane emissions at wells and mines, andimplementing advanced combustion technologies and carbon capture and storage.
Article
This study analyzes how incremental U.S. liquefied natural gas (LNG) exports affect global greenhouse gas (GHG) emissions. Emissions of LNG exported from U.S. ports to Asian and European markets account for only 3.5-5.5% of pre-combustion life cycle emissions, hence shipping distance is not a major driver of GHGs. This study finds exported U.S. LNG has mean pre-combustion emissions of 37g CO2-equiv/MJ when regasified in Europe and Asia. A scenario-based analysis addressing how potential end uses (electricity and industrial heating) and displacement of existing fuels (coal and Russian natural gas) affect GHG emissions shows the mean emissions for electricity generation using U.S. exported LNG were 655 g CO2-equiv/kWh (with a 90% confidence interval of 562-770), an 11% increase over U.S. natural gas electricity generation. Mean emissions from industrial heating were 104 g CO2-equiv/MJ (90% CI: 87-123). By displacing coal, LNG saves 550 g CO2-equiv per kWh of electricity and 20 g per MJ of heat. LNG saves GHGs under upstream fugitive emissions rates up to 9% and 5% for electricity and heating, respectively. GHG reductions were found if Russian pipeline natural gas was displaced for electricity and heating use regardless of GWP, as long as U.S. fugitive emission rates remain below the estimated 5-7% rate of Russian gas. However, from a country specific carbon accounting perspective, there is an imbalance in accrued social costs and benefits. Assuming a mean social cost of carbon of $49/metric ton, mean global savings from U.S. LNG displacement of coal for electricity generation are $1.50 per thousand cubic feet (Mcf) of gaseous natural gas exported as LNG ($.027/kWh). Conversely, the U.S. carbon cost of exporting the LNG is $1.80/Mcf ($.013/kWh), or $0.50-$5.50/Mcf across the range of potential discount rates. This spatial shift in embodied carbon emissions is important to consider in national interest estimates for LNG exports.
Article
Natural Gas (NG) has been regarded as a bridge fuel towards renewable sources and is expected to play a greater role in future global energy mix; however, a high degree of uncertainty exists concerning upstream (Well-to-Tank, WtT) Greenhouse Gas (GHG) emissions of NG. In this article, a Life-Cycle (LC) model is built to assess uncertainty in WtT GHG emissions of Liquefied NG (LNG) supplied to Europe by Nigeria. The 90% prediction interval of GHG intensity of Nigerian LNG was found to range between 14.9 and 19.3 g CO2 eq/MJ, with a mean value of 16.8 g CO2 eq/MJ. This intensity was estimated considering no venting practice in Nigerian fields. The mean estimation can shift up to 25 g CO2 eq when considering a scenario with a higher rate of venting emissions. A sensitivity analysis of the time horizon to calculate GHG intensity was also performed showing that higher GHG intensity and uncertainty are obtained for shorter time horizons, due to the higher impact factor of methane. The uncertainty calculated for Nigerian LNG, specifically regarding the gap of data for methane emissions, recommends initiatives to measure and report emissions, and further LC studies to identify hotspots to reduce the GHG intensity of LNG chains.
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Fugitive emissions from oil and gas operations are a source of direct and indirect greenhouse gas emissions in many countries. Unfortunately, these emissions are difficult to quantify with a high degree of accuracy and there remains substantial uncertainty in the values available for some of the major oil and gas producing countries (e.g., Russia 1 and members of OPEC 2 ). This is partly due to the types of sources being considered. Furthermore, the oil and gas industry is very large, diverse and complex making it difficult to ensure complete and accurate results. The key emission assessment issues are: (a) use of simple production-based emission factors is susceptible to excessive errors; (b) use of rigorous bottom-up approaches requires expert knowledge to apply and relies on detailed data which may be difficult and costly to obtain; and (c) measurement programmes are time consuming and very costly to perform. Nevertheless, the industry has a high profile and is very advanced technically which should facilitate the supply of high-quality data, and it is good practice to involve technical representatives from the industry in the development of the inventory. The Revised 1996 IPCC Guidelines for National Greenhouse Gas Inventories (IPCC Guidelines) provide a three-tier approach for assessing fugitive emissions from oil and gas activities. These approaches range from the use of simple production-based emission factors and high-level production statistics (i.e., Tier-1) to the use of rigorous estimation techniques involving highly disaggregated activity and data sources (i.e., Tier-3), and could include measurement and monitoring programmes. The intent is that countries with significant oil and gas industries would use the more rigorous or refined approaches, and countries with smaller industries and limited resources would use the simplest approach. However, the IPCC Guidelines lack definition and direction in conducting the refined approaches, and the factors available for the simplified approach are in need of further refinement and updating. In addition to that , the established IPCC reporting format contains some deficiencies and should include requirements to provide some general activity summaries and performance indicators to help put the emission results in proper perspective. Accordingly, this paper provides specific recommendations for improvements of the IPCC methodology for oil and gas systems, and generally defines good practice in developing these inventories (including a discussion of key issues, and specific limitations and barriers). Furthermore, it identifies relevant new emission factors and methodological advancements made since the last update of the IPCC Guidelines. A summary of the major oil and gas producers is provided in Annex 1. Annex 2 contains a summary of useful conversion factors for various common oil and gas statistics. Annex 3 presents typical compositions of processed natural gas and liquefied petroleum gas. Notwithstanding the foregoing, the basic outline of this paper is consistent with that established by the General Background Paper prepared for all Expert Group Meetings on Good Practice in Inventory Preparation. Responses to the specific issues raised therein are provided, and matters discussed during the breakout sessions
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The recent increase in the production of natural gas from shale deposits has significantly changed energy outlooks in both the US and world. Shale gas may have important climate benefits if it displaces more carbon-intensive oil or coal, but recent attention has discussed the potential for upstream methane emissions to counteract this reduced combustion greenhouse gas emissions. We examine six recent studies to produce a Monte Carlo uncertainty analysis of the carbon footprint of both shale and conventional natural gas production. The results show that the most likely upstream carbon footprints of these types of natural gas production are largely similar, with overlapping 95% uncertainty ranges of 11.0-21.0 g CO(2)e/MJ(LHV) for shale gas and 12.4-19.5 g CO(2)e/MJ(LHV) for conventional gas. However, because this upstream footprint represents less than 25% of the total carbon footprint of gas, the efficiency of producing heat, electricity, transportation services, or other function is of equal or greater importance when identifying emission reduction opportunities. Better data are needed to reduce the uncertainty in natural gas's carbon footprint, but understanding system-level climate impacts of shale gas, through shifts in national and global energy markets, may be more important and requires more detailed energy and economic systems assessments.
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The aim of the present study was to compare the life cycle, in terms of greenhouse gas (GHG) emissions, of diesel and liquefied natural gas (LNG) used as fuels for heavy-duty vehicles in the European market (EU-15). A literature review revealed that the numerous studies conducted have reported different results when the authors departed from different baseline assumptions and reference scenarios. For our study, we concentrated on the European scenario and on heavy-duty road transport vehicles, given their important incidence on the global emissions of GHG. Two possible LNG procurement strategies were considered i.e. purchasing it directly from the regasification terminal (LNG-TER) or producing LNG locally (at the service station) with small-scale plants (LNG-SSL). We ascertained that the use of LNG-TER enables a 10% reduction in GHG emissions by comparison with diesel, while the emissions resulting from the LNG-SSL solution are comparable with those of diesel.
Article
Natural gas has long been used in China mainly as chemical raw material. With the increasing emphasis on urban air pollution prevention, the issue of natural gas substitution to coal has been raised in many large Chinese cities. This paper reviews the environmental–economic–technical rationality of dashing-for-gas in urban area, especially for civil use such as cooking and heating in China. Taking Beijing and Chongqing as study cases, a cost–benefit analysis of natural gas substitution is done and the ongoing economic and system barriers to natural gas penetration are analyzed. Indications of natural gas penetration incentive policy making are given finally.
Article
Increasing concerns about greenhouse gas (GHG) emissions in the United States have spurred interest in alternate low carbon fuel sources, such as natural gas. Life cycle assessment (LCA) methods can be used to estimate potential emissions reductions through the use of such fuels. Some recent policies have used the results of LCAs to encourage the use of low carbon fuels to meet future energy demands in the U.S., without, however, acknowledging and addressing the uncertainty and variability prevalent in LCA. Natural gas is a particularly interesting fuel since it can be used to meet various energy demands, for example, as a transportation fuel or in power generation. Estimating the magnitudes and likelihoods of achieving emissions reductions from competing end-uses of natural gas using LCA offers one way to examine optimal strategies of natural gas resource allocation, given that its availability is likely to be limited in the future. In this study, the uncertainty in life cycle GHG emissions of natural gas (domestic and imported) consumed in the U.S. was estimated using probabilistic modeling methods. Monte Carlo simulations are performed to obtain sample distributions representing life cycle GHG emissions from the use of 1 MJ of domestic natural gas and imported LNG. Life cycle GHG emissions per energy unit of average natural gas consumed in the U.S were found to range between -8 and 9% of the mean value of 66 g CO(2)e/MJ. The probabilities of achieving emissions reductions by using natural gas for transportation and power generation, as a substitute for incumbent fuels such as gasoline, diesel, and coal were estimated. The use of natural gas for power generation instead of coal was found to have the highest and most likely emissions reductions (almost a 100% probability of achieving reductions of 60 g CO(2)e/MJ of natural gas used), while there is a 10-35% probability of the emissions from natural gas being higher than the incumbent if it were used as a transportation fuel. This likelihood of an increase in GHG emissions is indicative of the potential failure of a climate policy targeting reductions in GHG emissions.
Article
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.
Commentary: Heating Chinese Cities while Enhancing Air Quality
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