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Greenhouse-gas emissions of Canadian liquefied natural gas for use in China: Comparison and synthesis of three independent life cycle assessments
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.
... Indirect emissions from electricity supplied to run the plant such as those used to grind raw materials were also not accounted for in the study. Nevertheless, Nie et al. (2020) estimated that the upstream emissions are about 18% higher than the combustion emissions of NG. Likewise, emissions from electricity could be high, especially when sourced from a C-intensive grid system (Canada Energy Regulator, 2021;Nhuchhen et al., 2021). ...
... • The total thermal energy demand for clinker production is 3.29 and 3.79 GJ LHV /Mg clk, for the reference and cofiring scenarios, respectively (Nhuchhen et al., 2021). The C emissions associated with the combustion of NG is 57 kg CO 2e /GJ LHV (Nhuchhen et al., 2021) and those from the recovery and upgrading of NG are estimated as 18% of combustion emissions (Nie et al., 2020). • The non-CO 2 emissions associated with the combustion of biomass in a cement plant are 0.010 kg CH 4 /GJ LHV dry weight (dw) and 0.0067 kg N 2 O/GJ LHV dw (Ministry of Environment British Columbia, 2014). ...
Co‐firing residual lignocellulosic biomass with fossil fuels is often used to reduce greenhouse gas (GHG) emissions, especially in processes like cement production where fuel costs are critical and residual biomass can be obtained at a low cost. Since plants remove CO2 from the atmosphere, CO2 emissions from biomass combustion are often assumed to have zero global warming potential (GWPbCO2= 0) and do not contribute to climate forcing. However, diverting residual biomass to energy use has recently been shown to increase the atmospheric CO2 load when compared to business‐as‐usual (BAU) practices, resulting in GWPbCO2 values between 0 and 1. A detailed process model for a natural gas‐fired cement plant producing 4200 megagrams of clinker per day was used to calculate the material and energy flows, as well as the lifecycle emissions associated with cement production without and with diverted biomass (supplying 50% of precalciner energy demand) from forestry and landfill sources. Biomass co‐firing reduced natural gas demand in the precalciner of the cement plant by 39% relative to the reference scenario (100% natural gas), but the total demands for thermal, electrical, and diesel (transportation) energy increased by at least 14%. Assuming GWPbCO2 values of zero for biomass combustion, cement's lifecycle GHG intensity changed from the reference (natural gas only) plant by −40, −23, and − 89 kg CO2/Mg clinker for diverted biomass from slash burning, forest floor and landfill biomass, respectively. However, using the calculated GWPbCO2 values for diverted biomass from these same fuel sources, the lifecycle GHG intensities changes were −37, +20 and +28 kg CO2/Mg clinker, respectively. The switch from decreasing to increasing cement plant GHG emissions (i.e., forest floor or landfill feedstocks scenarios) highlights the importance of calculating and using the GWPbCO2 factor when quantifying lifecycle GHG impacts associated with diverting residual biomass to bioenergy use.
... Thus, the emissions advantage of a coal-to-gas transition will be a function of the life cycle emissions associated with the LNG supply chain. Recent life cycle assessment (LCA) studies on global LNG trade have demonstrated a wide range of emissions intensity for power generation, ranging from about 427 g CO 2 e kWh −1 to over 740 g CO 2 e kWh −1 [8,[39][40][41][42][43]. The high uncertainty in these estimates can be attributed to differences in system boundaries, methane leakage, and various assumptions related to LNG liquefaction and regasification. ...
... We evaluate the life cycle emission intensity of the LNG supply chain based on peer-reviewed literature and publicly available data across five stagesupstream, liquefaction, transportation and shipping, regasification, and end-use. Prior LCA studies of LNG exhibit large variation in emissions based on differences in system boundaries, modeling approaches, and data sources [40]. In addition to CO 2 -related combustion emissions, methane emissions from NG production, processing, and transportation are also included. ...
The shift from coal to natural gas (NG) in the power sector has led to significant reductions in carbon emissions. The shale revolution that led to this shift is now fueling a global expansion in liquefied natural gas (LNG) export infrastructure. In this work, we assess the viability of global LNG expansion to reduce global carbon emissions through coal-to-gas switching in the power sector under three temperature targets – Paris compliant 1.5ºC and 2ºC, and business-as-usual 3ºC. In the near to medium term (pre-2035), LNG-derived coal-to-gas substitution reduces global carbon emissions across all temperature targets as there is significantly more coal power generation than the LNG required to substitute it. However, we find that long-term planned LNG expansion is not compatible with the Paris climate targets of 1.5ºC and 2ºC – here, the potential for emissions reductions from LNG through coal-to-gas switching is limited by the availability of coal-based generation. In a 3ºC scenario, high levels of coal-based generation through mid-century make LNG an attractive option to reduce emissions. Thus, expanding LNG infrastructure can be considered as insurance against the potential lack of global climate action to limit temperatures to 1.5ºC or 2ºC. In all scenarios analyzed, low upstream methane leakage and high coal-to-gas substitution are critical to realize near-term climate benefits. Large-scale availability of carbon capture technology could significantly extend the climate viability of LNG. Investors and governments should consider stranded risk assets associated with potentially shorter lifetimes of LNG infrastructure in a Paris-compatible world.
... Through the gap analysis and case study, we propose a common data template to reduce gaps in emissions data collection by recommending changes to the current reporting structure that, if adopted, can aid in improved accuracy, specificity, and use of future NG LCA studies. This study's estimates have been included in two other studies (Roda-Stuart 27 and Nie et al. 22 ) for the purposes of assessing the potential impacts from a LNG project. However, the investigation of the data inputs available in the public domain have never been compared with those of company specific data. ...
... 28,31 Raj et al. 19 provide an estimate using a bottom-up approach for BC production basins using basin properties, 32 BC production data, 32 and US literature. 33 Nie et al. 22 use results from three LCAs (one of which is presented in this paper) to estimate life cycle emissions from western Canadian NG supplied to China as LNG. Three other recent studies 7−9 assess upstream methane emissions from AB and BC oil and gas operations and conclude that reported values underrepresent actual emissions. ...
Natural gas (NG) produced in Western Canada is a major and growing source of Canada’s energy and greenhouse gas (GHG) emissions portfolio. Despite recent progress, there is still only limited understanding of the sources and drivers of Western Canadian greenhouse gas (GHG) emissions. We conduct a case study of a production facility based on Seven Generation Energy Ltd.’s Western Canadian operations and an upstream NG emissions intensity model. The case study upstream emissions intensity is estimated to be 3.1–4.0 gCO2e/MJ NG compared to current best estimates of British Columbia (BC) emissions intensities of 6.2–12 gCO2e/MJ NG and a US average estimate of 15 gCO2e/MJ. The analysis reveals that compared to US studies, public GHG emissions data for Western Canada is insufficient as current public data satisfies only 50% of typical LCA model inputs. Company provided data closes most of these gaps (∼80% of the model inputs). We recommend more detailed data collection and presentation of government reported data such as a breakdown of vented and fugitive methane emissions by source. We propose a data collection template to facilitate improved GHG emissions intensity estimates and insight about potential mitigation strategies.
... When the midstream and upstream emissions are calculated employing this median value, the SMR production path from natural gas with no CCS produces 11 kg of CO 2 eq per kg of hydrogen in total, which is an increase of 2.4 kg of CO 2 eq per kg of hydrogen. The SMR H 2 plant's direct emissions can be reduced to 0.7 kg of CO 2 eq per kg of hydrogen (capture rate 93%), but the overall emissions rise to 1.5 to 6.2 kg of CO 2 eq per kg of hydrogen when both the lower and upper limits of current global midstream and upstream emissions for natural gas supply are taken into account [59][60][61]. ...
This study emphasises the growing relevance of hydrogen as a green energy source in meeting the growing need for sustainable energy solutions. It foregrounds the importance of assessing the environmental consequences of hydrogen-generating processes for their long-term viability. The article compares several hydrogen production processes in terms of scalability, cost-effectiveness, and technical improvements. It also investigates the environmental effects of each approach, considering crucial elements such as greenhouse gas emissions, water use, land needs, and waste creation. Different industrial techniques have distinct environmental consequences. While steam methane reforming is cost-effective and has a high production capacity, it is coupled with large carbon emissions. Electrolysis, a technology that uses renewable resources, is appealing but requires a lot of energy. Thermochemical and biomass gasification processes show promise for long-term hydrogen generation, but further technological advancement is required. The research investigates techniques for improving the environmental friendliness of hydrogen generation through the use of renewable energy sources. Its ultimate purpose is to offer readers a thorough awareness of the environmental effects of various hydrogen generation strategies, allowing them to make educated judgements about ecologically friendly ways. It can ease the transition to a cleaner hydrogen-powered economy by considering both technological feasibility and environmental issues, enabling a more ecologically conscious and climate-friendly energy landscape.
... Most of the projected LNG demand stems from coal-to-gas switching in China and other fast-growing Asia Pacific regions, where natural gas is considered a suitable alternative to coal, owing to its air quality benefits and lower CO 2 emissions per unit of energy [119,120]. However, as fossil LNG infrastructure replaces coal, it can also replace low carbon/net-zero/renewable fuels and energy systems that would otherwise provide long-term climate benefits. ...
Unregulated in-use methane emissions (or methane slip) can reduce or even eliminate the overall climate benefits of using liquefied natural gas (LNG) as a marine fuel. We conduct critical review and expert interviews to identify methane slip mitigation measures, and then identify and evaluate potential policy instruments that could incentivize their uptake while considering the shipping sector’s climate targets. We find that regulatory instruments are expected to perform the best across a range of criteria when they are at the global level, include methane on a CO 2 -equivalent and lifecycle basis, promote polycentric approaches to climate governance, and allow flexibility in how the industry incorporates decarbonization measures. Market-based approaches and informational governance policies complement regulatory instruments by improving cost-effectiveness and increasing the availability of relevant information on emissions mitigation. The urgency and scale of shipping climate targets underscore the need for policy approaches that support planning for long-term decarbonization pathways and that can avoid locking into fossil-carbon intensive systems.
... In this paper we explore the prospective CI of geologic H2 using a modified version of an opensource oil and gas GHG calculation tool, the OPGEE model (Oil Production Greenhouse Gas Emissions Estimator). OPGEE was first developed by El Houjeiri and Brandt 15 , and collaborators and has been used in numerous papers [16][17][18][19][20][21] . OPGEE uses petroleum engineering fundamentals and the properties of a given oil and gas resource to estimate possible GHG emissions. ...
Geologic hydrogen (H2) deposits could be a source of climate friendly energy. In this work, we perform a prospective life cycle assessment of a generic geologic hydrogen production and processing system. While it is still too early in the development cycle to estimate precise life-cycle carbon intensities (CI) we can use fundamental engineering physics and chemistry to estimate CI. Our baseline case includes gas with 85 mol% H2, and remainder N2 (12%) and CH4 (1.5%) and other inert gases (1.5%). We set baseline productivity, depth, and other producing parameters using data from US natural gas wells drilled to date. We use a modified version of the OPGEE open-source oil & gas life cycle assessment tool to model the energy use and emissions from geologic hydrogen systems. Producing, dewatering, separating, and (if needed) compressing the gas results in a site-boundary GHG intensity of ~0.4 kg CO2eq. GHG per kg of H2 produced for the baseline case, or ~3 gCO2eq./MJ LHV H2. The largest sources of GHG emissions are fugitive losses from the system and embodied emissions in constructed wellbores and equipment. Sensitivity analysis is performed by examining varying gas compositions, as wells other resource parameters and production methods. We find that results are most sensitive to the gas composition – mainly the amount of H2 and CH4 in the raw gas stream. Other key drivers include how the process is powered and fueled, and the methods of handling and disposing of the separated non-H2 species.
... According to IEA, electricity produced by LNG produces 50 percent fewer emissions, and Canadian LNG would further reduce it to 62%, a study by the Journal of Cleaner Production. 20 Similarly, according to Oxford Institute, once operational, the global average emission intensity of LNG Canada is expected to be .15 as compared to the global average of 0.35; similarly proposed Indigenous-led project Cedar would have 0.08% and Woodfibre LNG 0.03 percent, respectively. ...
Liquified Natural Gas (LNG) has received world-wide attention due to its growing market demands as pointed out by International Energy Agency (IEA), and McKinsey. This article aims to observe contemporary European developments in accordance with the Union’s energy strategy and the Paris Agreement. With the reduction in import of Russian gas, purchasing LNG became an alternative policy option to meet overall energy needs in Europe. European governments and companies are making large investments in land-based regasification terminals and floating storage and regasification units (FSRUs). These trends have fueled hopes that Europe may be able to avoid the worst-case scenario of massive gas shortages, rationing, and industrial shutdowns in the coming months. Nonetheless, such positive short-term developments should not obscure the challenges Europe’s energy-dependent industries are facing due to high gas and electricity prices, which will likely remain elevated for some time. Industries with gas-intensive production or with high absolute demand for gas could still see disruptions during this winter. Moreover, this article also evaluates the role of carbon-neutral LNG in European energy crises and its link with eco-friendly processes as set out by the EU and its consequences for the Asian market. The major findings include that the existing carbon measurement framework does not meet the global needs of the LNG industry. Moreover, the breadth of LNG usage is linked to viable GHG emission framework availability.
... For gas supply and export emission factors, we use the literature review summary in Nie et al. Table S1, 15 to create a distribution from many existing sources. The gas demand emission factor is the natural gas carbon content. ...
We conduct a consequential lifecycle analysis (LCA) of greenhouse gas (GHG) emissions from North American liquefied natural gas (LNG) export projects, estimating the change in global natural gas and coal use resulting from the market effects of increased LNG trade. We estimate that building a 2.1 billion cubic feet per day (Bcfd) LNG export facility, equivalent to one of the larger LNG projects under development in the US today, will change global GHG emissions −39 to 11 Mt CO2e (90% range) with a median value of −8 Mt CO2e. Previous attributional LCA methods for electricity generation with LNG replacing coal find a much larger benefit of LNG exports, a median value of −36 Mt CO2e for this size project. The smaller decrease in GHGs is attributable to higher domestic coal use and a smaller decrease in international coal use than assumed by previous methods. Net global emission change estimates are most sensitive to the uncertainty in economic elasticities outside of North America. Given the scale of planned and proposed LNG export terminals, project regulators and policymakers must account for market effects to more accurately estimate the global net change in GHG emissions.
... The studies estimate that upstream GHG emissions account for 20− 45% of wellhead through power plant CO 2 e emissions on a 100 year basis, depending on exact scenario. 24,26,30,31 Cheniere is the largest LNG exporter from the U.S. in terms of volumes exported as of the end of 2020. 2 This study develops an LCA framework to estimate GHG emissions representative of Cheniere's SPL LNG supply chain. This study conducts a uniquely detailed analysis mapping the LNG supply chain both upstream and downstream from Cheniere's SPL facility for 2018 using supplier-specific data collected from wellhead through ocean transport. ...
Global trade in liquefied natural gas (LNG) is growing significantly, as is interest in the life-cycle greenhouse gas (GHG) emissions associated with LNG. Most assessments of life-cycle GHG emissions from LNG have employed national or regional average emission estimates; however, there is significant variability in emissions across different suppliers and across the natural gas supply chain. This work describes a framework for compiling supplier-specific GHG emission data for LNG, from the producing well to regasification at the destination port. A case study is presented for Cheniere Energy’s Sabine Pass Liquefaction (SPL) LNG supply chain from production in the United States and delivered to China. GHG emission intensities are estimated to be 30–43% lower than other analyses employing national or regional average emission profiles. The segments driving these differences are gas production and gathering, transmission, and ocean transport. Extending the boundaries of this analysis to the power plant illustrates the effect of fuel switching from coal to natural gas; the effect of fuel switching in China is a 47–57% reduction in GHG emission intensity, cradle through power generation. This work highlights the important role customized life-cycle assessments can play to improve GHG emission estimates and differentiate supply chains to inform business and policy decisions related to the transition to a low carbon future.
... While switching from coal to imported LNG is an alternative that would reduce combustion-related CO 2 emissions at the point of power generation, recent comparisons of the life cycle greenhouse gas impacts associated with electricity generation in China using natural gas and coal have identified the critical role of methane emissions on the favorability of switching from coal to natural gas. 4,5 Because of the variability and magnitude of methane emissions from both coal and natural gas supply chains, the radiative forcing impacts of switching between coal-and natural gas-fueled electricity generation depend on the details of the supply chains. ...
In 2019, coal power accounted for 65% of China’s electricity and coal accounted for 71% of its 10.2 GTpa CO2 emissions. To meet its pledge of peak carbon by 2030 and carbon neutrality by 2060, China plans to shift away from coal. Fuel switching to natural gas for electrical generation is an interim solution that is in the portfolio of measures for meeting these goals. However, because of variability in emissions from coal and natural gas supply chains, the potential for benefiting from fuel switching also varies. Here, we use a high-resolution basin-to-power plant analysis for estimating methane and CO2 emissions in natural gas and coal supply chains. We illustrate how the variations in supply chains at the level of the sourcing of natural gas and coal from individual production regions can lead to differences in the effectiveness of fuel switching in reducing greenhouse gas emissions. The analyses are applied to four switching scenarios from domestic coal to imported natural gas at representative power plants in China. Life cycle emission factors for the natural gas supply chains evaluated in this study range from 650 to 1000 kg carbon dioxide/MWh of electricity generated and from 2.3 to 13 kg methane/MWh, depending on the allocation choice, power generation technology, and production region. For the coal supply chain, emissions range from 850 to 1100 kg carbon dioxide/MWh and from 0.4 to 4.0 kg methane/MWh, depending on the power generation technology and production region. We show that for these scenarios, in the short term fuel switching can increase radiative forcing by a factor of 3 or decrease it by 70%, depending on the supply chains, generation technology, and, in the case of natural gas, co-product allocation choices in the supply chain. We also quantify consumptive losses of natural gas over long supply chains and show that fuel switching results in differences in radiative forcing that evolve over time due to the influence of methane emissions.
... Three emissions allocation methodsallocation based on mass, energy, and market valuewere used to allocate the emissions from production to both wheat grain and wheat straw. The allocation factor was calculated using the following equation [85,86]: ...
This study compares the life cycle energy consumption and greenhouse gas (GHG) emissions of electricity generation from bio-coals produced from various biomass feedstocks via dry torrefaction (DT) and wet torrefaction (WT) processes. Wheat straw, pine woodchips, grape pomace, manure and algae are the main feedstocks evaluated. The energy consumption and the associated GHG emissions at each life cycle stage were calculated. The main stages included are in-field preparation, feedstocks transportation to torrefaction plant, torrefaction process, bio-coal transportation to power plant, and power plant operations. The results show that all pathways are competitive with coal-based electricity in terms of GHG emissions except pathways with algae as feedstock and manure biochar-based electricity generation. Among the pathways, electricity generation from pine woodchips biochar appears to be the best option, with an 88% GHG emissions reduction compared to coal-derived electricity, followed by grape pomace hydrochar with an 85% emission reduction. Electricity generation from wheat straw biochar, grape pomace hydrochar, and pine woodchips biochar lead to the highest net energy ratios (NERs) of 4.19, 4.08, and 3.58, respectively. The developed information is novel and can be used for investment decisions and policy formulation around the world.
... • Upstream emissions associated with the production and pipeline distribution of NG are estimated to be 18% more compared to its carbon intensity [43]. Therefore, for the reference plant, including life cycle emissions would increase energy emissions by about 34 CO 2 e/t clk. ...
Cement-making is an energy-intensive industrial process that contributes 8% of the global CO2 emissions. This study develops a thermal energy flow model (TEF) for 4200 tonnes of clinker per day, a natural gas-fired cement plant in which 50% of the pre-calciner energy requirements can be supplied by alternative fuels (AF) including biomass, plastics, etc. The TEF shows that the lower heating value (LHV dry), oxygen content (dry basis) and moisture content of the AF, as well as the flue gas oxygen concentration [O2] needed for complete combustion, affect the thermal energy intensity (TEI) and total air demand (AD). Compared to the reference system fueled by natural gas (NG) that burns completely at 1% [O2] in flue gas, all AFs require more total air and thermal energy demand, especially when the solid AFs need a higher [O2] in the flue gas (typically 3%) to ensure complete combustion. Due to the higher carbon (C) intensity, co-firing AFs could increase the total CO2 emissions by 1% to 18%. For the wood dust with 100% biogenic C, 50% NG replacement in pre-calciner could avoid 55.5 and 43.1 kgCO2/t clinker at 1% and 3% [O2] in flue gas respectively, an equivalent of 7.5% and 5.8% decrease in total GHG emissions relative to the reference case. Results of the TEF model from 24 diverse AFs were used to generate regressions that link fuel properties and flue gas oxygen requirement with TEI, making it possible to compare highly diverse AFs for their likely performance in the clinker-making.
... Mallapragada et al. (2018) estimated GWP and water consumption ascribed to Marcellus shale gas for an electricity generation purpose in various importers with (2019) compared two ways of freight transport and concluded that integrated logistics using both trucks and ships together would be a better option than only using trucks for given supply chain scenarios. A specific LNG supply case was dealt with by three independent research groups from environmental perspectives and one of their conclusions implied that data depending on the region and operational profile would be more influential on the results than establishing sound methodologies and reasonable assumptions applied to the analysis (Nie et al., 2020). Yuan et al. (2020) pointed out the necessity of system optimization in accordance with regional gas composition by focusing on the emissions produced during NG re-liquification process in various cases. ...
The marine industry has been striving to seek for proper strategies to curb air emissions from global shipping activities. To support the transition to sustainable shipping, this paper was proposed to evaluate the holistic environmental benefits of the LNG partial re-liquefaction system applied to LNG carriers by comparing among five different combination/configuration of LNG re-liquefaction systems. The theory of life cycle assessment was employed with the help of a commercial software, Sphera GaBi version 2019 to quantify the magnitude of various emissions under different life stages of the proposed systems: manufacturing, installation, use and recycling. A case study was implemented with a 174,200 m 3 LNG carrier and the input data for the analysis was collected from true-to-life sources provided by manufacturers and ship operators. The electric consumption of the five systems were calculated by means of Aspen HYSYS software. A range from 1.23 to 1.64 kWh/kg was estimated and was used as key parameters to confirm the onboard electricity demands at the use phase of the five systems. The results revealed that the partial re-liquefaction system had considerable effects on the reduction in emission levels across the following five impact categories: Global Warming Potential, Particulate Matter, Photochemical Ozone Creation Potential, Eutrophication Potential and Acidification Potential. An optimal option which adopted the partial re-liquefaction system was found to release 4.49 Â 10 8 kg CO 2 eq. 1.25 Â 10 6 kg PM 2.5 eq. 7.16 Â 10 6 kg NMVOC eq. 2.46 Â 10 6 kg N eq. and 1.13 Â 10 7 kg SO 2 eq. in its lifetime, which were roughly equivalent to 25% emission reductions compared to the rest of the candidates to which the partial re-liquefaction principle was not applied. Lastly, it clearly presents the effectiveness of life cycle assessment. This research, particularly, suggests that this holistic approach should not be underused for resolving innumerable maritime environmental issues that appear unsolvable with the current practices in the maritime industry.
Low-carbon hydrogen is considered a key component of global energy system decarbonization strategy. The US Inflation Reduction Act includes incentives in the form of production tax credits for low-carbon hydrogen production, provided the lifecycle greenhouse gas (GHG) emissions intensity (EI) of hydrogen is below 4 kg CO2e/kg H2. Blue hydrogen or hydrogen produced from natural gas coupled with carbon capture and sequestration is one such pathway. In this work, we develop a geospatial, measurement-informed model to estimate supply chain specific lifecycle GHG EI of blue hydrogen produced with natural gas sourced from the Marcellus and Permian shale basins. We find that blue hydrogen production using Permian gas has a lifecycle EI of 7.4 kg CO2e/kg H2, more than twice the EI of hydrogen produced using Marcellus gas of 3.3 kg CO2e/kg H2. We conclude that eligibility for tax credits should therefore be based on lifecycle assessments that are supply chain specific and measurement informed to ensure blue hydrogen projects are truly low carbon.
Increased consumption of low-carbon hydrogen is prominent in the decarbonisation strategies of many jurisdictions. Yet prior studies assessing the current most prevalent production method, steam reformation of natural gas (SRNG), have not sufficiently evaluated how process design decisions affect life cycle greenhouse gas (GHG) emissions. This technoeconomic case study assesses cradle-to-gate emissions of hydrogen produced from SRNG with CO2 capture and storage (CCS) in British Columbia, Canada. Four process configurations with amine-based CCS using existing technology and novel process designs are evaluated. We find that cradle-to-gate GHG emission intensity ranges from 0.7-2.7 kgCO2e/kgH2 – significantly lower than previous studies of SRNG with CCS and similar to the range of published estimates for hydrogen produced from renewable-powered electrolysis. The levelized cost of hydrogen (LCOH) in this study (US$1.1-1.3/kgH2) is significantly lower than published estimates for renewable-powered electrolysis.
British Columbia (BC) recently released the CleanBC policy framework to promote clean energy and mitigate greenhouse gas (GHG) emissions. However, CleanBC lacks concrete measures to reverse the growth of energy demand. Although BC has rich biomass and hydroelectric resources, it remains unclear whether these renewable resources will be enough to meet future energy demand. In this work, the potential in BC for increasing production and use of bioenergy, renewable electricity, and low‐carbon hydrogen was assessed, and the most efficient measures were identified. Energy scenarios were constructed to explore BC's future renewable energy demands for meeting GHG mitigation targets. The results show CleanBC will drastically raise renewable energy demands but fail to achieve the 2030 target without radical demand reduction. Seen as the core strategy in CleanBC, electrification will require at least 60 PJ of additional electricity supply for 2030 and 160 PJ for carbon neutrality in 2050. This implies implementing wind and solar generation in capacities comparable to massive hydroelectric projects. Alternative to electrification is the bioenergy‐centered strategy. Existing waste biomass must be fully exploited; even then, roughly 250 and 460 PJ of additional primary bioenergy will be needed for 2030 and 2050, respectively, well beyond any foreseeable waste supply within BC. Hence, it is essential to utilize all the available biomass and renewable electricity resources and promote a diversified renewable energy portfolio. Hydrogen used as an energy carrier must be produced from natural gas with carbon capture to avoid competition for the limited renewable energy resources. This article is protected by copyright. All rights reserved.
With the deterioration of global climate and environment, the carbon emission of the oil and gas industry has been an important issue of global concern. At present, there is a lack of systematic research on carbon emission calculation of natural gas pipeline from construction to disposal. We propose a life cycle assessment method for natural gas pipeline in order to quantify the carbon emissions from construction to disposal. The carbon emissions of natural gas pipeline are divided into four parts in this model: manufacturing, construction, operation, and recycling. For each of the four stages, carbon emissions from material production and construction, facility construction and equipment operation are all detailedly calculated. In addition, methane, the main component of natural gas, has a non-negligible impact on the atmosphere. Therefore, gas leakage from the pipeline system is also considered in this paper. And data from actual pipelines are utilized in the case study. The results show that the carbon emissions of these pipelines are in the range of 26.58–67.14 t CO2 / (km×10⁸ m³ / a) and 11.41–30.27 t CH4 / (km×10⁸ m³ / a). Among them, the production process of pipelines contributes the most to carbon emissions, accounting for about 80% of the total CO2 emissions. Through sensitivity analysis, we found that pipeline parameter, power emission factor, and compressor operation status turn out to be the main factors affecting carbon emission. With the establishment of this model, potential carbon emission of planned pipelines can be estimated, which has guiding significance for future pipeline construction.
To reduce fossil–fuel consumption and improve the efficiency of renewable energy usage in the manufacturing industry, several studies have investigated the environmental and economic impacts of integrated energy systems under various optimization scenarios. To analyze the cost–effectiveness of heat supply scenarios for a typical manufacturing industry using the photovoltaic (PV) technology and municipal solid waste incineration, herein, a metal–assembly paint factory was selected as the research target. The CO2 emission and energy–consumption cost of a paint factory in 24 h are estimated as 31,229 kg and 12,314 CNY, respectively. Solar–to–Energy (StE(a–d)) and Waste–to–Energy (WtE) correspond to the nonenergy–storage, heat–storage, PV power–storage, PV technology's green power–procurement, and waste–incineration district heating scenarios, respectively. The results show that (1) (1) under the nonenergy storage (StE(a)) scenario, the emissions of the paint factory can be reduced by 288 kg/24 h; however, the operation cost is increased by 1142 CNY/24 h. (2) StE(b) has a better economic performance (cost reduction by 2472 CNY/24 h) than StE(c) (cost increased by 1546 CNY/24 h). Additionally, the reduction in the CO2 emissions in StE(b) (12,057 kg/24 h) is considerably higher than that of StE(c) (7644 kg/24 h). (3) In the case of sufficient energy supply, StE(d) (24,361 kg/24 h) reduces CO2 emissions more effectively, followed by WtE (CO2–emission reduction = 17,994 kg/24 h), than the other scenarios (for a paint factory). However, from the perspective of cost reduction, WtE showed to have a more outstanding performance (cost reduction 1428 CNY/24 h).
The ever-increasing anthropogenic greenhouse gas (GHG) emissions worldwide make it quite challenging to meet country-specific Nationally Determined Contributions (NDC) targets. Therefore, it is evident that the existing emissions abatement measures need to be taken a step further. Internationally Transferred Mitigation Outcomes (ITMOs) are allowed in Article 6.2 of the Paris Agreement as a cooperative approach to achieving NDC goals. There is a potential to create ITMOs between Canada and China by replacing coal use in China with British Columbia (BC)'s liquefied natural gas (LNG) supply. Replacing coal with LNG in energy generation applications is a promising approach to mitigate emissions. With global and national pressures to reduce emissions, China has created a market for LNG imports to cater to its rising natural gas (NG) consumption due to the coal-to-gas source switching strategy. However, the terms under Article 6.2 requires generated ITMOs to ensure environmental integrity, support sustainable development goals, and have a robust accounting system. Therefore, the current study aims to quantify the life cycle environmental outcomes of generating ITMOs by exporting LNG from BC to Chinese end-users while integrating uncertainties and to provide policy recommendations in adherence with the requirements of Article 6.2. Different LNG export scenarios were generated in the study and environmental impacts of each scenario were assessed and compared using a life cycle assessment (LCA) framework developed by the authors. Sensitivity and uncertainty analyses were conducted to understand the impacts created by the data uncertainties in the final result. By replacing conventional coal with NG, approximately 40–45% and 26%–32% emissions reductions can be obtainable for Chinese textile and chemical industries, respectively. The highest emissions reduction of approximately 60% was observed when coal is replaced with NG for district heating. The life cycle emissions (LCE) quantification framework provided in the study provides stakeholders with a systematic approach to determine the total GHG emissions and emissions reduction potential of different LNG export scenarios.
Producing liquefied natural gas (LNG) from coke oven gas (COG) is a promising option to partly alleviate the shortage of natural gas supply and effectively utilize the byproduct of coking production in China. In order to systematically evaluate the energy consumption and environmental impact of COG-based LNG process, the life cycle assessment (LCA) method was introduced in this study. Two synthesized approaches were considered and compared, namely decarbonization process and methanation process. Besides, whether with or without H2 extraction in methanation process is also discussed. Inventory data are obtained from onsite investigations of representative enterprises in China. The results indicate that, LNG production stage is the dominated unit in the overall environmental impacts of decarbonization process, next is LNG evaporation stage, while coking stage only contributes 2.38%. The reason is that COG is only responsible for less upstream environmental burdens as a byproduct. In LNG production stage, medium pressure steam, COG and electricity are the key substances. Comparative LCA shows that methanation process shows better environmental performance than decarbonization process in COG-based LNG production since more LNG product are produced. It is suggested that methanation process with H2 extraction is more desirable considering economic performance. This work intends to provide useful insights on the sustainability development of COG utilization in coking industry.
Natural gas (NG) produced in Western Canada is a major and growing source of Canada’s energy and greenhouse gas (GHG) emissions portfolio. Despite recent progress, there is still only limited understanding of the sources and drivers of Western Canadian greenhouse gas (GHG) emissions. We conduct a case study of a production facility based on Seven Generation Energy Ltd.’s Western Canadian operations and an upstream NG emissions intensity model. The case study upstream emissions intensity is estimated to be 3.1–4.0 gCO2e/MJ NG compared to current best estimates of British Columbia (BC) emissions intensities of 6.2–12 gCO2e/MJ NG and a US average estimate of 15 gCO2e/MJ. The analysis reveals that compared to US studies, public GHG emissions data for Western Canada is insufficient as current public data satisfies only 50% of typical LCA model inputs. Company provided data closes most of these gaps (∼80% of the model inputs). We recommend more detailed data collection and presentation of government reported data such as a breakdown of vented and fugitive methane emissions by source. We propose a data collection template to facilitate improved GHG emissions intensity estimates and insight about potential mitigation strategies.
As natural gas demand surges in China, driven by the coal-to-gas switching policy, widespread attention is focused on its impacts on global gas supply-demand rebalance and greenhouse gas (GHG) emissions. Here, for the first time, we estimate well-to-city-gate GHG emissions of gas supplies for China, based on analyses of field-specific characteristics of 104 fields in 15 countries. Results show GHG intensities of supplies from 104 fields vary from 6.2 to 43.3 g CO2eq MJ−1. Due to the increase of GHG-intensive gas supplies from Russia, Central Asia, and domestic shale gas fields, the supply-energy-weighted average GHG intensity is projected to increase from 21.7 in 2016 to 23.3 CO2eq MJ−1 in 2030, and total well-to-city-gate emissions of gas supplies are estimated to grow by ~3 times. While securing gas supply is a top priority for the Chinese government, decreasing GHG intensity should be considered in meeting its commitment to emission reductions. The carbon footprints of natural gas supplies at the field level are unclear. Here the authors analysed the GHG intensities of gas supplies from 104 fields and show that their GHG intensities range from 6.2 to 43.3 g CO2eq MJ-1.
Reducing methane emissions from the oil and gas industry is a critical climate action policy tool in Canada and the US. Optical gas imaging-based leak detection and repair (LDAR) surveys are commonly used to address fugitive methane emissions or leaks. Despite widespread use, there is little empirical measurement of the effectiveness of LDAR programs at reducing long-term leakage, especially over the scale of months to years. In this study, we measure the effectiveness of LDAR surveys by quantifying emissions at 36 unconventional liquids-rich natural gas facilities in Alberta, Canada. A representative subset of these 36 facilities were visited twice by the same detection team: an initial survey and a post-repair re-survey occurring ∼0.5–2 years after the initial survey. Overall, total emissions reduced by 44% after one LDAR survey, combining a reduction in fugitive emissions of 22% and vented emissions by 47%. Furthermore, >90% of the leaks found in the initial survey were not emitting in the re-survey, suggesting high repair effectiveness. However, fugitive emissions reduced by only 22% because of new leaks that occurred between the surveys. This indicates a need for frequent, effective, and low-cost LDAR surveys to target new leaks. The large reduction in vent emissions is associated with potentially stochastic changes to tank-related emissions, which contributed ∼45% of all emissions. Our data suggest a key role for tank-specific abatement strategies as an effective way to reduce oil and gas methane emissions. Finally, mitigation policies will also benefit from more definitive classification of leaks and vents.
Accurate assessment of anthropogenic carbon dioxide
(CO2) emissions and their redistribution among the atmosphere,
ocean, and terrestrial biosphere – the “global carbon budget” – is
important to better understand the global carbon cycle, support the
development of climate policies, and project future climate change. Here we
describe data sets and methodology to quantify the five major components of
the global carbon budget and their uncertainties. Fossil CO2
emissions (EFF) are based on energy statistics and cement
production data, while emissions from land use and land-use change (ELUC),
mainly deforestation, are based on land use and land-use change data and
bookkeeping models. Atmospheric CO2 concentration is measured
directly and its growth rate (GATM) is computed from the annual
changes in concentration. The ocean CO2 sink (SOCEAN)
and terrestrial CO2 sink (SLAND) are estimated with
global process models constrained by observations. The resulting carbon
budget imbalance (BIM), the difference between the estimated
total emissions and the estimated changes in the atmosphere, ocean, and
terrestrial biosphere, is a measure of imperfect data and understanding of
the contemporary carbon cycle. All uncertainties are reported as ±1σ. For the last decade available (2008–2017), EFF was
9.4±0.5 GtC yr−1, ELUC 1.5±0.7 GtC yr−1, GATM 4.7±0.02 GtC yr−1,
SOCEAN 2.4±0.5 GtC yr−1, and SLAND 3.2±0.8 GtC yr−1, with a budget imbalance BIM of
0.5 GtC yr−1 indicating overestimated emissions and/or underestimated
sinks. For the year 2017 alone, the growth in EFF was about 1.6 %
and emissions increased to 9.9±0.5 GtC yr−1. Also for 2017,
ELUC was 1.4±0.7 GtC yr−1, GATM was 4.6±0.2 GtC yr−1, SOCEAN was 2.5±0.5 GtC yr−1, and SLAND was 3.8±0.8 GtC yr−1,
with a BIM of 0.3 GtC. The global atmospheric
CO2 concentration reached 405.0±0.1 ppm averaged over 2017.
For 2018, preliminary data for the first 6–9 months indicate a renewed
growth in EFF of +2.7 % (range of 1.8 % to 3.7 %) based
on national emission projections for China, the US, the EU, and India and
projections of gross domestic product corrected for recent changes in the
carbon intensity of the economy for the rest of the world. The analysis
presented here shows that the mean and trend in the five components of the
global carbon budget are consistently estimated over the period of 1959–2017,
but discrepancies of up to 1 GtC yr−1 persist for the representation
of semi-decadal variability in CO2 fluxes. A detailed comparison
among individual estimates and the introduction of a broad range of
observations show (1) no consensus in the mean and trend in land-use change
emissions, (2) a persistent low agreement among the different methods on
the magnitude of the land CO2 flux in the northern extra-tropics,
and (3) an apparent underestimation of the CO2 variability by ocean
models, originating outside the tropics. This living data update documents
changes in the methods and data sets used in this new global carbon budget
and the progress in understanding the global carbon cycle compared with
previous publications of this data set (Le Quéré et al., 2018, 2016,
2015a, b, 2014, 2013). All results presented here can be downloaded from
https://doi.org/10.18160/GCP-2018.
Producing, transporting, and refining crude oil into fuels such as gasoline and diesel accounts for ∼15 to 40% of the “well-to-wheels” life-cycle greenhouse gas (GHG) emissions of transport fuels (1). Reducing emissions from petroleum production is of particular importance, as current transport fleets are almost entirely dependent on liquid petroleum products, and many uses of petroleum have limited prospects for near-term substitution (e.g., air travel). Better understanding of crude oil GHG emissions can help to quantify the benefits of alternative fuels and identify the most cost-effective opportunities for oil-sector emissions reductions (2). Yet, while regulations are beginning to address petroleum sector GHG emissions (3–5), and private investors are beginning to consider climate-related risk in oil investments (6), such efforts have generally struggled with methodological and data challenges. First, no single method exists for measuring the carbon intensity (CI) of oils. Second, there is a lack of comprehensive geographically rich datasets that would allow evaluation and monitoring of life-cycle emissions from oils. We have previously worked to address the first challenge by developing open-source oil-sector CI modeling tools [OPGEE (7, 8), supplementary materials (SM) 1.1]. Here, we address the second challenge by using these tools to model well-to-refinery CI of all major active oil fields globally—and to identify major drivers of these emissions.
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.
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.
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.
China has experienced increasingly deteriorating haze pollution characterized by high concentrations of fine particles during the last two decades, mainly caused by the coal-dominated energy structure. Natural gas is regarded as an effective alternative energy to tackle exacerbated air pollution. In this study, we investigated the impacts of natural gas infrastructures and consumption on the annual average PM2.5 concentrations covering 204 of China's prefecture-level cities during the period from 2008 to 2016. To take the potential spatial spillovers and dynamics of PM2.5 concentrations into consideration, the appropriate dynamic spatial econometric models were mainly utilized. The main findings of the study are that the deployment of natural gas pipelines and gas consumption can effectively mitigate the PM2.5 concentrations. The existence of a significant spatial correlation of PM2.5 concentrations at the city level implies that PM2.5 concentrations in different regions influence each other, especially PM2.5 hot-spots can disperse to the surrounding areas. Our results also emphasize that the environmental effect exhibits obvious heterogeneity in the user and regional aspects, and, since the results are relatively robust in various model specifications and subsamples, our findings hold significant implications for the Chinese PM2.5 alleviation policy.
Coal consumption in China has been almost equal to the consumption of all other countries since 2011, and influenced not only global climate change but also domestic air pollution control, energy production and consumption revolution. Coal consumption is closely related to China's whole economy, and its cap control should be based on comprehensive understanding of different economic agents' interactions. Therefore, this study uses the input-output model to identify key relationships to be adjusted which have their significant direct and indirect effects on coal consumption. We find that fixed capital formation in construction having a significant indirect impact on coal consumption in all main coal-intensive sectors, and most of the important production relationships in a sector involve inputs of basic raw materials or fuel, such as building materials in construction. From the perspective of fine structure adjustment to control coal effectively, some non-basic inputs need massive restrictions, such as substantially reducing pesticide and fertilizer application in agriculture, and construction expansion should be limited to a rational growth through reducing short-lived buildings, constraining low-level redundant construction of roads and buildings, and minimizing the vacancy rate and incremental construction area. Moreover, export of coke, chemicals, and chemical products should be discouraged from the perspective of coal control, and urban households should consume daily chemical and pharmaceutical products more rationally.
Fossil fuel-based power generation technologies with and without CO 2 capture offer a number of alternatives, which involve different fuel production and supply, power generation and capture routes with varied energy consumption rates and subsequent environmental impacts. The holistic perspective offered by Life Cycle Assessment (LCA) can help decision makers to quantify the trade-offs inherent in any change to the fuel supply and power production systems and ensure that a reduction in greenhouse gas (GHG) emissions does not result in increases in other environmental impacts. Beside energy and non-energy related GHG releases, LCA also tracks various other environmental emissions, such as solid wastes, toxic substances and common air pollutants, as well as the consumption of resources, such as water, minerals and land use. In this respect, the dynamic LCA model developed at Imperial College incorporates fossil fuel production, transportation, power generation, CO 2 capture, CO 2 conditioning, p...
China accounts for half of the world's annual coal consumption. Coal is the primary energy source for heating in urban areas, particularly in northern China. This causes significant challenges for urban air quality problems in China and greenhouse gases emissions. Urban district heating (DH) systems penetration is very high in northern China. It supplies space heating to more than 80% of urban buildings in the area. Unlike the electricity and transportation sectors, the heating sector has received little attention from policy makers and researchers in China, DH systems are an enabling infrastructure which facilitates energy efficiency improvements and the use of renewable energy sources. This study explores the dynamics and possibility to expand alternative energy sources (natural gas, biomass, direct geothermal heat, ground-source heat pump, municipal waste heat, industrial waste heat) for DH in China. We apply an analytical framework largely based on the multi-level perspective in socio-technical transitions theory, in which transitions are interpreted as the result of the functioning of niche, regime and landscape elements, and interactions between them. The study provides an integrated picture of the socio-technical structure and functioning of DH in China. The results show that an energy transition in Chinese DH systems has barely started. The system is characterised by stability of the coal-based DH regime, while a number of alternative niches are struggling to emerge. Among these, natural gas is the most successful example. However, at local level different niches present opportunities in terms of physical availability, economic viability and technical capacity to address changes in landscape pressures. A sustainable heat roadmap based on integrated energy planning and policy attention at the national level could be developed as one mechanism for instigating a much needed energy transition in DH in China.
Recently, the share of natural gas in the generation of electricity has shown a dramatic increase in China. However, the domestic natural gas source, natural gas price and unclear policy environment are the barriers lying on the development way of natural gas power generation. This paper aims to evaluate development pattern and constraints in the development of China's natural gas power generation by system dynamics methodology. The natural gas price for generation is predicted by market netback pricing method which sets up price linkage mechanism and bundles the natural gas price with alternative energy price. The downturn of international oil market pushes natural gas price down. In spite of the over-demand domestic natural gas market, the long term Take-or-Pay Clauses provide a guarantee for adequate gas supply. Hence, the natural gas price and source are no longer the case. Meanwhile, the promotion policies including subsidy and emission trade scheme are analyzed. As a result, the natural gas power generation will witness explosive development with an average annual growth rate of about 10%. By 2030, natural gas generation installed capacity will reach 235.7 GW.
China has two choices to meet the gap between its gas demand and supply in the short term: coal-based synthetic natural gas and imported natural gas. China currently faces the following question: between coal-based synthetic natural gas and imported natural gas, which is the better choice for China? To provide a reference for policy makers and investors, this paper compares the energy efficiency of the Datang coal gasification project, which is the first demonstration project in China, with that of imported natural gas by an energy return on investment analysis. The results show that when the environmental inputs are not considered, the energy return on investment values of coal-based synthetic natural gas with different boundaries range from 1.7:1 to 6.9:1. The values of the total imported natural gas decreased from 14.5:1 in 2009 to 7.5:1 in 2014 and then increased to 9.2:1 in 2015. When the environmental inputs are considered, the energy return on investment values of coal-based synthetic natural gas and that of imported natural gas decrease to 1.4:1-3.4:1 and 5.9:1-9.6:1, respectively. Regardless of whether the environmental inputs are considered, imported natural gas generally has a better energy return on investment than coal-based synthetic natural gas. These results suggest that from a net energy perspective, policy makers and investors should encourage to import more natural gas and be prudent about developing the coal gasification industry.
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.
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.
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.
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
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.
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.
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.
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.
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.
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