pubs.acs.org /doi/10.1021/acs.est.3c09030
Climate Impacts of Hydrogen and Methane Emissions Can Considerably Reduce the Climate Benefits across Key Hydrogen Use Cases and Time Scales
Ilissa B. Ocko170-216 minutes 21/2/2024Synopsis
This study shows that “clean” hydrogen deployment can be significantly better or worse for the climate depending on factors that are not usually considered in life cycle assessment frameworks.
1. Introduction
The urgency of addressing the climate crisis has accelerated global momentum for low-carbon (herein termed “clean”) hydrogen as a pathway to reduce carbon dioxide emissions while also providing energy security and driving economic growth. Governments, companies, and investors around the world have announced commitments to spend over $500 billion on more than 1000 hydrogen projects over the next decade. (1) Decisions to scale up clean hydrogen systems are often driven by the assumption that they will accrue large climate benefits when compared to fossil fuels. (2−6) However, there are several shortcomings within the hydrogen assessment frameworks that are often the basis for estimating hydrogen’s benefits.
Currently, conventional hydrogen technology assessments lack consideration of hydrogen emissions and their warming effects, (2−5,7−9) yet hydrogen is a leak-prone gas with a potent indirect warming effect in the near term due to the fact that its chemical oxidation in the atmosphere increases the levels of other short-lived greenhouse gases (GHGs) in the atmosphere (methane, tropospheric ozone, and stratospheric water vapor). (10−13) This needs to be considered to fully understand the implications of deploying hydrogen at scale. Hydrogen’s indirect warming effects have been documented over the past several decades, (14−23) with a consensus emerging that hydrogen’s global warming potential (GWP) is approximately 12 over a 100-year period and approximately 35–40 over a 20-year period. (10−13) The largest uncertainties in hydrogen’s GWP are associated with the removal of atmospheric hydrogen by soil and potential future changes in the atmospheric concentrations of other GHGs such as methane. (10−13)
First, hydrogen emissions are of particular concern given that molecular hydrogen is the smallest molecule and can easily leak from infrastructure in addition to being routinely released to the atmosphere through venting and purging operations. (24−28) Emission estimates to date (leakage, venting, and purging) range from <1% to 20% varying across value chain components with higher emission rates often associated with liquid hydrogen, but no empirical measurements of real-world infrastructure and facilities are available. (27,28) Given the similarity between hydrogen and natural gas infrastructure, and the fact that natural gas emissions have been shown to be higher than previously thought, (29,30) it is reasonable to expect that hydrogen emissions may also be significant.
Second, while methane emissions are often included in hydrogen technology climate impact assessments (relevant for both blue hydrogen technologies and fossil fuel alternatives), the emission rates are often not consistent with those empirically measured across a diversity of facilities and supply chains. Direct measurements that have been made over the past decade suggest that there are large regional- and basin-level variations in methane emission intensities, from <1% to >3%. (29−33) However, the assumption of a low level of methane leakage is common, while some studies assume a high level of methane leakage. (34,35) Given that ground-level, airborne, and satellite measurements of methane emissions over the past decade have greatly improved our understanding of oil and gas methane emissions, a more sophisticated treatment of methane emissions is warranted. Higher than anticipated methane emissions could undercut the climate benefits of deploying hydrogen technologies as a replacement for fossil fuels, especially in the near term. (12,34,36−38)
Third, the availability of renewable electricity is a fundamental component of the impact of the green hydrogen pathways. It is often assumed that green hydrogen production utilizes excess or new renewable resources and does not influence the rate of decarbonization of the electric grid. However, given the large gap between the availability of and demand for zero-carbon electricity, there is concern that green electrons could be diverted from decarbonizing the power grid. If this occurs, then the resulting gap would need to come from natural gas- or coal-fired power plants, leading to increased GHG emissions. (39)
Fourth, the standard metric employed for assessing climate impacts (GWP with a 100-year time horizon) does not convey warming effects in the near term and assumes an unrealistic one-time pulse of emissions rather than continuous emissions over time. GWP is used to combine emissions of multiple GHGs by converting non-carbon dioxide climate pollutant emissions to their carbon dioxide “equivalent” based on radiative properties and atmospheric lifetimes. Conventional technology assessment frameworks often use GWPs with a 100-year time horizon, which considers the long-term warming effect from a one-time pulse of emissions. For climate pollutants with short-lived warming effects, including methane and hydrogen, evaluating warming effects over 100 years masks their near-term impacts, and using a one-time pulse approach disregards their atmospheric replenishment from continuous emissions. (36,40,41)
This study addresses these shortcomings by reanalyzing a widely referenced life cycle assessment (LCA) analysis of blue and green hydrogen technologies (5) and incorporating (1) a range of plausible hydrogen emission rates, (2) a range of observed methane emission rates from different regions, (3) impacts of additional versus non-additional renewable electricity, and (4) multiple time horizons for evaluation of climate impacts and continuous emissions rather than pulse emissions (Table S1). This analysis provides an illustrative example of how the climate impacts of hydrogen deployment change when these factors are considered. It also offers a more complete understanding of the climate benefits, or lack thereof, of specific hydrogen applications relative to their fossil fuel alternatives.
2. Methods
Utilizing recent improvements in our understanding of the underlying factors affecting hydrogen value chains, we reanalyze a set of hydrogen LCA pathways published by the Hydrogen Council (2021, termed “HC21” here). (5) Although the designs of these pathways (the production method, transportation mode, and end use application) are arbitrary and do not cover all possible future hydrogen pathways comprehensively, they provide a set of illustrative blue and green hydrogen scenarios that cover diverse applications in multiple economic sectors that are envisioned for future hydrogen value chains.
The LCA analysis in HC21 includes eight hydrogen production-to-end use pathways across the industrial, power, and transportation sectors, four for blue hydrogen (natural gas autothermal reforming with a 98% carbon capture rate) used in long-distance passenger vehicles, ships, industrial heat, and ammonia-based power generation, and four for green hydrogen (electrolysis with wind and/or solar power) used in fertilizer production, buses, heavy-duty trucks, and steel making (Table S2 and Exhibit 4 in HC21). Each hydrogen pathway has a fossil fuel-based alternative, and the blue hydrogen long-distance passenger vehicle pathway also includes a low-carbon alternative, a battery electric vehicle using grid electricity.
HC21 estimates the life cycle GHG emissions for each pathway and alternative for “well-to-use” at two points in time, 2030 and 2050, with overall lower GHG emissions in 2050 due to decreased emissions from grid electricity [which is used for manufacturing, processing, and other auxiliary electricity demand (details on page 7 of HC21)]. While our analysis considers conditions in both 2030 and 2050, the results presented in the text primarily focus on 2050, with the results for 2030 presented in the Supporting Information.
We supplement HC21 with additional climate pollutants, assumptions, and metrics (Table S1). The HC21 analysis includes emissions of the following GHGs: carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), hydrofluorocarbon (HFC) 134a, and carbon tetrafluoride (CF4). Our study includes hydrogen emissions for all hydrogen pathways given that it is an indirect GHG. We assume that 1–10% of total hydrogen consumption is lost to the atmosphere. While emission rates lower or higher than this range can occur for specific components of the hydrogen value chain, the estimates are highly uncertain due to the lack of empirical evidence. (28) Therefore, we follow the assumptions of value chain hydrogen emissions from previous studies (10,20−25,27,42−46) in that we exclude the extreme cases and assume a moderate range of emission rates of 1–10%.
Given that the original upstream CH4 emissions associated with blue hydrogen production (and the fossil fuel alternatives) in the HC21 analysis are assumed to be very low (0.2–0.5% leak rate), we replace the original emission rates with three levels of emission intensities (low, 0.6%; medium, 0.9%; and high, 2.1%) based on data representative of the top 25 oil- and gas-producing countries (IEA Methane Tracker; note that these intensities are for gas-related methane emissions only and do not include oil-related methane emissions; see the Supporting Information for more information). (47) We also assess the impacts when extremely low (0.01%) and extremely high (5.4%) emission rates are considered. For the fossil fuel pathways that utilize gasoline and diesel, we replace the original upstream methane emissions rates (∼0.35 g/kWh) with multiple levels of emission intensities that are associated with oil production [extremely low, 0.006 g/kWh; low, 0.6 g/kWh; medium, 1.0 g/kWh; high, 2.6 g/kWh; and extremely high, 11.4 g/kWh (see the Supporting Information for more information)]. (47) Although the estimates of country-level methane emission intensities are highly uncertain (especially in data-poor regions), they are useful for capturing the plausible range of methane emissions associated with natural gas use for blue hydrogen production as well as fossil fuel alternatives. When we isolate the effect of hydrogen emissions in the LCA, a medium methane emission rate (0.9%) is applied to all pathways and alternatives.
The assumption of carbon capture efficiency with autothermal reforming is 98% with permanent storage in the original LCA. Given that this is a very optimistic assumption that can have significant impacts on the climate benefits of hydrogen pathways, (38,48) we also consider a lower carbon capture rate, 60%, to assess the impact of carbon capture efficiency on the climate benefits of blue hydrogen pathways (more information in the Supporting Information).
To assess how renewable electricity capacity assumptions can affect the climate impacts of green hydrogen pathways given the near-term limitation of renewable resources, we consider two alternative scenarios for 2030 in addition to the original LCA that assumes additional renewable capacity: the renewable electricity used to produce hydrogen that would have otherwise gone into the power grid, which is replaced with electricity from either (1) a natural gas power plant or (2) a coal-fired power plant. We also compare the warming effects of the utilization of a projected global-averaged grid electricity mix in 2030 [emission factors from IRENA 2022 (see Table S4)] that is consistent with a 1.5 °C decarbonization pathway. (49)
To quantify the relative climate impacts of hydrogen pathways compared to their fossil fuel alternatives, we utilize two methods. First, we compare the cumulative radiative forcing from continuous (i.e., constant) emissions from the hydrogen pathways to that from the fossil fuel pathways they are replacing, considering 10-, 20-, 50-, and 100-year time scales. This is a metric known in the literature as the technology warming potential (TWP) and was first introduced by Alvarez et al. (40) Second, we compare the total emissions in CO2 equivalences (CO2e) using GWPs for the 20- and 100-year time horizons (Table S8). While both approaches utilize the same radiative properties and lifetimes of GHGs (see the Supporting Information for equations and their inputs), the first approach (TWP) more realistically represents the climate impacts of switching from one technology to another because it considers continuous emissions as opposed to a one-time pulse. On the other hand, the second approach (CO2e) directly expands on the standard one-time pulse method used in current LCAs (and in the original HC21 LCA) by adding a near-term time scale (20 years) in addition to a long-term time scale (100 years).
3. Results
Overall, the cumulative warming impact from constant emissions of switching from fossil fuel technologies to blue or green hydrogen technologies depends on the specific application, production method, hydrogen and methane emissions rates, and time scale of interest (Figure 1). The relative impact across all time scales (under 2050 conditions) ranges from a 93% reduction in warming to a 46% increase in warming (considering extreme cases), meaning either a near elimination of the warming impacts of fossil fuel technologies or even more warming from the hydrogen technologies. The results under 2030 conditions are similar (see the Supporting Information).
Figure 1
Figure 1. Overview of the life cycle climate impacts of eight hydrogen pathways relative to their fossil fuel alternatives in 2050 considering a range of hydrogen emission rates (1–10%) and methane emission intensities (from extremely low, 0.01%, to extremely high, 5.4%). Each vertical bar represents the range of climate benefits (or disbenefits) by switching to hydrogen from fossil fuels for the best-case scenario (1% hydrogen emissions and a low methane emission intensity of 0.6%) to the worst-case scenario (10% hydrogen emissions and a high methane emissions intensity of 2.1%). Near-term (NT, 20 years) and long-term (LT, 100 years) climate impacts are presented for each pathway. The originally reported climate impacts of these pathways in Hydrogen Council report (2021) are denoted as black triangles. The climate impact of the battery electric alternative for the light-duty vehicle pathway is noted with the letter E.
For blue hydrogen applications with low methane and hydrogen emission rates, hydrogen technologies can be 64–80% (72–86%) better for the climate than fossil fuel technologies in the near (long) term. With high emission rates, hydrogen technologies can be 51% (68%) better for the climate to 14% worse (32% better) for the climate than fossil fuel technologies in the near (long) term. There are two pathways that can lead to an increase in warming in the near term under extremely high-methane and high-hydrogen emission scenarios: (1) replacing natural gas industrial heat with blue hydrogen industrial heat and (2) replacing natural gas power generation with blue ammonia (derived from hydrogen) power generation. However, if both hydrogen and methane emissions are low (extremely low), then these technologies can reduce warming impacts by more than 60% (85%).
For green hydrogen applications with low hydrogen emission rates, hydrogen technologies can be 91–94% (92–95%) better for the climate than fossil fuel technologies in the near (long) term. With high emission rates, hydrogen technologies can be 66–82% (79–88%) better for the climate than fossil fuel technologies in the near (long) term. This means that high hydrogen emissions (10% rate) can reduce the anticipated climate benefits of green hydrogen technologies by up to 25% in the near term and 13% in the long term. The technologies with the least amount of climate benefits from fuel switching under high-emission scenarios are replacing natural gas-derived fertilizer with hydrogen-derived fertilizer and replacing heavy-duty diesel internal combustion engine (ICE) trucks with hydrogen fuel cell trucks.
Figure 1 also shows the results from the original LCA analysis (HC21) under 2050 conditions, which does not consider hydrogen emissions or near-term impacts and has very low methane emission intensities. Across all cases, the original results approximately align with our best-case scenarios (extremely low methane emissions and low hydrogen emissions) where the long-term climate benefits consistently show a ≥75% decrease in warming impacts from all hydrogen technologies relative to their fossil fuel alternatives.
Furthermore, the addition of hydrogen emissions and varying levels of representative methane emissions shows that the climate benefits of battery electric vehicles (BEVs) are considerably larger than those of blue hydrogen light-duty vehicles (LDVs). Blue hydrogen LDVs can be 10–45% worse for the climate in the near term than BEVs depending on the hydrogen and methane emission levels (Figure 1). On the contrary, the hydrogen LDVs and BEVs show similar climate benefits from replacing gasoline ICE vehicles in the original LCA. However, the greater benefit of BEVs in our analysis is more pronounced under 2050 assumptions than under 2030 assumptions (Figure S1), because grid electricity used by the electric vehicle is assumed to have greater (90%) renewable penetration and thus lower GHG emissions in 2050 than in 2030 (66% renewable penetration).
3.1. Blue Hydrogen Pathways
3.1.1. Effect of Hydrogen Emissions
Figure 2 compares the life cycle warming impacts of blue hydrogen use cases with their fossil fuel counterparts under assumptions of 1–10% hydrogen emission rates with medium methane emission rates (to isolate the effects of different hydrogen emission rates). We calculate the warming impacts using both TWP [cumulative radiative forcing from continuous emissions over 10-, 20-, 50-, and 100-year time horizons (Figure 2a–d)] and the GWP/CO2e metric [for 20- and 100-year time horizons (Figure 2e–l)].
Figure 2
Figure 2. Life cycle climate impacts of four blue hydrogen pathways relative to their fossil fuel alternatives in 2050 considering a range of 1–10% hydrogen emission rates and medium, 0.9%, methane emission intensity, presented as (a–d) the percentage change in cumulative radiative forcing from continuous emissions over 10, 20, 50, and 100 years after the technology switch and (e–l) annual emissions per function unit (kilometer or kilowatt hour) in CO2e on 20- and 100-year time horizons. Values in panels a–d range from 1% hydrogen emissions (bottom of the bars) to 10% hydrogen emissions (top of the bars). Error bars indicate the uncertainties associated with hydrogen’s radiative efficiency and lifetime. The climate impact of battery electric vehicle relative to fossil fuel is shown as purple horizontal lines in panel a for comparison with blue hydrogen. Percentage changes derived from panels e–l, which are emissions based on the GWP-20 and GWP-100 metrics, are also denoted as “x” (high H2 emissions) and “Δ” (low H2 emissions) in panels a–d. Note that in the case of blue hydrogen, high hydrogen emissions also lead to a small amount of additional methane emissions from increased natural gas use to make up for lost hydrogen (see the Supporting Information for more information).
All four blue hydrogen pathways reduce the level of warming relative to the fossil fuel pathways over all time scales when medium methane emissions are assumed (this is in contrast to Figure 1, where high and extremely high methane emissions are also considered). In the near term (20 years following the technology switch), high hydrogen emissions can reduce blue hydrogen’s climate benefits from replacing fossil fuel technologies by approximately 20% to 45% compared to the benefits from low hydrogen emissions. This reduction is less pronounced in the long term (100 years following the technology switch) at 10–25%.
The technologies with the largest range of climate outcomes from different hydrogen emission rates are industrial heat and power generation. For example, one could lose 40% of the anticipated climate benefits in the near term from replacing industrial natural gas boilers with industrial hydrogen boilers and replacing natural gas turbine power generation with blue ammonia turbine power generation if hydrogen emissions are high (10% rate). Over time, the benefits of hydrogen applications become stronger, but high hydrogen emissions (10% rate) can still reduce climate benefits by 20% for these technologies in the long term compared to low emissions (1%). For the transport cases (light-duty vehicles and ships), there is still a 20% reduction in climate benefits in the near term from high hydrogen emission rates and a 10% reduction in the long term.
Analyzing the climate benefits of hydrogen technologies relative to their fossil fuel counterparts using both TWP (cumulative effects from continuous emissions) and CO2e (cumulative effects from a one-time pulse of emissions) allows for assessment of the importance of including continuous emissions in LCAs rather than relying on pulse-based metrics. We find that near-term warming effects are adequately represented using GWP with a 20-year time horizon, and long-term effects are underestimated by GWP with a 100-year time horizon, especially when hydrogen emission rates are high. For example, the blue ammonia power generation case yields a reduction in warming of 54–75% over the 100-year time scale with continuous emissions, but GWP-100 suggests a reduction of 64–81%.
3.1.2. Effect of Regional Methane Emission Intensity Variations
Figure 3 considers the influence of different methane emission levels on the climate benefits of blue hydrogen technologies. Overall, high methane emissions have fewer climate benefits (and potentially disbenefits, i.e., more warming) relative to the fossil fuel applications even though methane emissions at the same levels are also avoided from the alternative fossil fuel technologies. However, the impact of methane emissions varies considerably by use case. Methane emissions are more influential in impacting warming effects for blue hydrogen industrial heating and power generation pathways (Figure 3b,d) than for light-duty vehicle and ship pathways (Figure 4a,c). For example, high methane emissions may reduce the climate benefit of replacing natural gas with blue hydrogen for industrial heating by ∼20% in the near term and ∼10% in the long term compared with low methane emissions (Figure 3b). For the blue ammonia power generation pathway, high methane emissions can lead to more warming in the near term than using natural gas for power generation (Figure 3d). Note that we have not accounted for the various levels of N2O that can be directly emitted and indirectly formed from the release of reactive nitrogen compounds across the blue ammonia pathway, which can further increase its overall climate impact. (50,51)
Figure 3
Figure 3. Life cycle climate impacts of four blue hydrogen pathways relative to their fossil fuel alternatives in 2050 considering a range of hydrogen emission rates of 1–10% (heights of the bars) and three levels of methane emission intensities (different colored bars), presented as the percentage change in cumulative radiative forcing from continuous emissions over 10, 20, 50, and 100 years after the technology switch. The error bars indicate the uncertainties associated with hydrogen’s radiative efficiency and lifetime.
Figure 4
Figure 4. Life cycle climate impacts of four green hydrogen pathways relative to their fossil fuel alternatives in 2050 considering a range of hydrogen emission rates of 1–10%, presented as (a–d) the percentage change in cumulative radiative forcing from continuous emissions over 10, 20, 50, and 100 years after the technology switch and (e–l) annual emissions per function unit (kilometer or kilogram of product) in CO2e on 20- and 100-year time horizons. Values in panels a–d range from 1% hydrogen emissions (bottoms of bars) to 10% hydrogen emissions (tops of bars). The error bars indicate the uncertainties associated with hydrogen’s radiative efficiency and lifetime. Percentage changes derived from panels e–l, which are emissions based on the GWP-20 and GWP-100 metrics, are also denoted as “x” (high H2 emissions) and “Δ” (low H2 emissions) in panels a–d. Note there is a small amount of methane emissions associated with the green hydrogen pathways due to the inclusion of manufacturing emissions associated with the end use equipment.
3.1.3. Effect of Carbon Capture Rates
The original LCA assumes a 98% carbon capture rate with autothermal reforming in the blue hydrogen pathways, which is an optimistic assumption given that current operating carbon capture with steam methane reforming plants can only remove 30–60% of the CO2 emissions at the facility level, partly due to not capturing combustion CO2 emissions. (38,48) Figure S4 shows an illustrative example of how a lower carbon capture rate can substantially increase the climate impact of blue hydrogen pathways, undercutting their climate benefits relative to fossil fuel technologies. Compared to the assumption of a 98% carbon capture rate (Figure 2), a 60% carbon capture rate can reduce the climate benefits of blue hydrogen pathways by 15–50% in the near term and 20–60% in the long term (Figure S4). Unlike the strong near-term impact of hydrogen and methane emissions, the impact of the carbon capture rate is more pronounced in the long term, because CO2 is a long-lived GHG.
3.2. Green Hydrogen Pathways
3.2.1. Effect of Hydrogen Emissions
Figure 4 compares the life cycle warming impacts of green hydrogen use cases with their fossil fuel counterparts under assumptions of 1–10% hydrogen emissions rates with the same methods and time horizons as in Figure 2. Note that medium methane emission rates are applied to fossil fuel technologies where appropriate.
Overall, green hydrogen pathways consistently reduce warming impacts from fossil fuel technologies by >60% for all time scales, even when hydrogen emission rates are high. However, limiting hydrogen emissions to the lower end (e.g., 1%) greatly increases climate benefits to >90%. For example, replacing natural gas-derived fertilizer with green hydrogen-derived fertilizer can achieve an ∼90% reduction in warming over the 20 years following the technology switch if hydrogen emissions are low but a reduction of only ∼70% if hydrogen emissions are high (Figure 4a).
For all green hydrogen pathways, high hydrogen emissions considerably reduce the climate benefits from switching from fossil fuel technologies to hydrogen alternatives. This effect is more pronounced in the near term than in the long term. In the near term (20 years following the technology switch), high hydrogen emission rates relative to low rates can reduce climate benefits by ∼10%, ∼15%, and ∼25% for steel production, buses and heavy-duty trucking, and fertilizer production, respectively. In the long term, the decrease in the level of benefits is as much as 10% for fertilizer and as little as 4% for steel production.
Unlike blue hydrogen, green hydrogen pathways do not have significant methane emissions. Therefore, regional variations in methane emission intensities mostly impact the warming effects from fossil fuel alternatives. However, we find only small impacts on the magnitudes of climate benefits from fuel switching when we consider different methane emission intensity levels (not shown). We also find that both GWP-20 and GWP-100 adequately convey the results from the more sophisticated continuous emissions method.
3.2.2. Effect of GHG Emissions Associated with Electricity Supply
The original LCA assumed that renewable electricity used for green hydrogen production is additional to what is needed to decarbonize the electric grid. Figure 5 shows an example of the added warming effects if the renewable electricity used in 2030 is not in addition to what is needed to decarbonize the electric grid, and therefore, the electricity needs to be replaced by natural gas or coal. We also compare these scenarios to warming impacts from using grid electricity to produce hydrogen. For all of the green hydrogen pathways of switching from diesel buses to hydrogen fuel cell buses, we find that the additional GHGs emitted from needing to generate more electricity to support the grid can greatly increase overall climate impacts if one must rely on fossil fuels. If natural gas- or coal-based electricity is used, the added GHG emissions would lead to an increase in the level of warming over all time scales (by 15–150%) as a systemwide impact from replacing fossil fuel technologies with non-additional renewable-based green hydrogen. If a globally averaged grid electricity mix is assumed (using the conditions projected for 2030), the climate benefit from replacing the diesel buses with green hydrogen fuel cell buses is significantly reduced by ∼45% for the near term and long term. Similar results are found in the other three green hydrogen pathways (Figure S3).
Figure 5
Figure 5. Life cycle climate impacts of a green hydrogen fuel cell bus relative to the diesel alternative in 2030 considering a range of hydrogen emission rates of 1–10% and different power supply assumptions (dashed lines), presented as annual emissions per kilometer of vehicle operation in CO2e on 20- and 100-year time horizons. The emission factors of the electricity grid mix in 2030 follow the 1.5 °C-compatible pathway projection by the International Renewable Energy Agency (IRENA). (49) The emission factors of natural gas- and coal-fired power plant are also taken from IRENA. Similar analyses are conducted for the other three green hydrogen pathways and shown in Figure S3.
4. Discussion
We find that the climate benefits of hydrogen applications depend strongly on the specific use case, the production method, the hydrogen and methane emission rates, the availability of renewable electricity, and the time scale of interest. The climate impacts of hydrogen technologies range from a near elimination of warming to increased warming relative to the fossil fuel technologies that are replaced. For blue hydrogen applications, the range is a 93% reduction in warming to a 46% increase in warming. For green hydrogen applications, the range is a 66–95% reduction in warming with additional renewable electricity but nearly a quadrupling of the fossil fuel technology’s warming impacts if renewable electricity is non-additional and is replaced in the grid by coal-fired power plants. These results are in stark contrast to the original LCA (HC21) that found that the blue (green) hydrogen pathways cause a 77–92% (94–96%) reduction in warming relative to the replaced fossil fuel technologies because of the strong near-term warming effects of both hydrogen and methane.
Our analysis builds upon previous studies that show how hydrogen emissions can considerably reduce the climate benefits of hydrogen systems by quantitatively evaluating how hydrogen emissions affect the climate impacts of individual use cases. (11−13,36) The inclusion of hydrogen emissions increases the warming effects of all hydrogen pathways analyzed, especially in the near and medium term because hydrogen’s warming effects are short-lived. (11,13) Hydrogen emissions have been omitted from analysis of the benefit of deploying hydrogen as a decarbonization strategy as it is not included in the list of GHGs considered under the Kyoto Protocol, and until recently, there was a low level of awareness of its atmospheric warming effects. However, this assessment makes it clear that ignoring hydrogen emissions can considerably overestimate the decarbonization benefits of hydrogen systems. This is particularly relevant when hydrogen systems are compared to other clean alternatives, such as direct electrification. It is important to note that the rates of hydrogen emissions are currently unknown across the value chain. (28) Empirical measurements are needed to improve our understanding of where emissions are coming from and in what quantities.
Methane emissions also play a major role in reducing the climate benefits of blue hydrogen applications, as shown in previous studies. (12,34,36−38) However, our analysis shows that because methane emissions are also associated with fossil fuel technologies, the trade-offs and net warming effects are complex and vary considerably. The energy efficiency of end use applications in particular plays a large role in how much natural gas or oil is needed (and, therefore, how much methane is emitted or avoided). For example, in the blue hydrogen light-duty vehicle and ship pathways, hydrogen fuel cell engines are more energy efficient than internal combustion engines; (52,53) a light-duty vehicle consumes 0.3 kWh of hydrogen or 0.5 kWh of gasoline per kilometer, and a ship consumes 65 kWh of hydrogen or 83 kWh of diesel per kilometer, which helps counteract the energy used in blue hydrogen production. Therefore, blue hydrogen used in fuel cells is more efficient at replacing gasoline and diesel and therefore at avoiding the upstream methane emissions associated with crude oil production. In contrast, the heating and power generation pathways use similar boiler and turbine technologies for blue hydrogen/ammonia and natural gas with similar energy efficiencies; (54,55) a boiler for heating consumes 1.1 kWh of either hydrogen or natural gas per kilowatt hour of thermal energy generated, and a turbine for power consumes 1.7 kWh of either ammonia or natural gas per kilowatt hour of electricity generated, which does not help to offset the energy intensity of producing blue hydrogen or ammonia. Therefore, there is a net increase in upstream methane emissions in blue hydrogen/ammonia pathways compared to directly using natural gas because more natural gas is needed to compensate for the energy loss during conversions to hydrogen or ammonia (Figure 3c,d). Note that we do not explicitly analyze a situation in which high methane intensity blue hydrogen from one country or region is used to replace fossil fuel applications with low methane emission intensity in another country or region, or vice versa, which can have implications for the international or interstate trade of blue hydrogen.
Our analysis of additional versus non-additional renewable capacity is also consistent with previous studies that show how green hydrogen production could lead to an increase in fossil fuel-based electricity generation and increase in GHG emissions on the system level. (39,56) In our analysis, we find that the potential emission increases due to non-additional renewable electricity could make green hydrogen marginally beneficial or even worse for the climate (increased warming up to a factor of 4) in the near term and long term. Although the policy and/or regulatory mechanisms that can ensure that green hydrogen does not inadvertently delay grid decarbonization are highly debated, (57−59) the significance of the renewable fraction of the power grid in determining the climate benefits (or lack thereof) of green hydrogen is clear. This illustrative analysis highlights the importance of considering the system-level impact of producing green hydrogen and not unintentionally increasing the demand for fossil fuel-based electricity generation.
The time scale and methods for evaluating emissions over time are clearly significant in our results, as well. The climate benefits of hydrogen technologies can be considerably reduced in the near term if there are high emissions of hydrogen and/or methane, each of which has short-lived, but powerful, warming effects. If long-term time horizons are used exclusively, then potentially large near-term warming effects are overlooked.
Our analysis provides an improved temporal framework for technology assessments by directly comparing the total cumulative radiative forcing from annual and continuous emissions of climate pollutants. If hydrogen emissions were incorporated into simple climate models, such as the Finite Amplitude Impulse Response (FaIR) model and Model for the Assessment of Greenhouse Gas Induced Climate Change (MAGICC), it will enable faster quantification of climate impacts from hydrogen emissions to inform decision making. However, in general, we find that using GWPs with both 20- and 100-year time horizons can adequately characterize climate impacts of continuous emissions and over all time scales if reported simultaneously, consistent with findings from previous studies. (36,60) This approach can be applied to existing assessment tools (such as LCAs) with small adjustments in functionality.
There are other factors that influence the climate implications of deploying hydrogen that have not been fully explored in this study. For example, we test the effect of different carbon capture rates at blue hydrogen production facilities but how the captured carbon is utilized and the permanence of carbon storage can also affect the overall climate impacts of hydrogen deployment. (61,62) Moreover, deploying hydrogen to replace fossil fuel may reduce other co-emitted pollutants such as carbon monoxide, nitrogen oxides, and volatile organic compounds. These species are also indirect greenhouse gases that impact atmospheric chemistry and ultimately yield relatively short-lived warming or cooling effects on the climate. More work is needed to fully understand the atmospheric chemistry dynamics among all of these emitted species as their concentrations change in the future. (11) We have also not considered the implications of deploying hydrogen that is extracted from geological reservoirs. (63) These are important factors to consider in the development of future climate scenarios that include substantial hydrogen deployment.
Our analysis is subject to the same uncertainties as simplified climate metrics, such as in radiative properties, atmospheric lifetimes, and atmospheric chemistry parametrizations. Furthermore, as in any evaluation of the impacts of different technologies, the results depend strongly on the specific well-to-use pathway. Climate impacts and benefits relative to alternative fossil fuel technologies will vary across the value chains. This analysis is intended to explore the implications of considering additional climate pollutants, more realistic assumptions, and multiple time scales in hydrogen assessments through a limited set of illustrative examples. Given that the case study pathways that we examine are relatively arbitrary, our analysis does not serve as a comparison of climate benefits between different hydrogen applications. A more comprehensive comparison between hydrogen applications will be addressed in future work. Lastly, it is important to note that additional environmental factors such as water demand, raw material requirement, and air quality impacts are often included in LCA frameworks but are not explored in this study. These aspects are also critical considerations in policy making.
While there are many tools for decarbonization, hydrogen has the potential to serve an important role for certain value chains. By including hydrogen emissions, observed methane emissions, systemwide energy impacts, and multiple time scales, we can more accurately determine the climate benefits of different clean energy alternatives that thus serve as the basis for more effective policy making.
Supporting Information
The Supporting Information is available free of charge at https://pubs.acs.org/doi/10.1021/acs.est.3c09030.
More detailed information about methods and data used in this study as well as additional figures that show the climate impact of hydrogen pathways relative to other alternatives under the 2030 condition (PDF)
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Author Information
Eriko Shrestha - Environmental Defense Fund, New York, New York 10010, United States
Steven P. Hamburg - Environmental Defense Fund, New York, New York 10010, United States
Roland Kupers - University of Arizona, Tucson, Arizona 85721, United States
T.S., I.B.O., and S.P.H. conceptualized the study. T.S., I.B.O., and E.S. conducted the data analysis, prepared the figures, and drafted the manuscript. All authors contributed to refining the analysis, refining the figures, and editing of the manuscript.
This research was conducted with support from ClimateWorks Foundation and Breakthrough Energy. Results reflect the views of the authors and not necessarily those of the supporting organizations.
The authors declare no competing financial interest.
Acknowledgments
The authors thank Ludwig-Bölkow-Systemtechnik GmbH for helping us to understand the data in the Hydrogen Council report and Jane Long and Joan Odgen for insightful discussions that helped improve this study. Results reflect the views of the authors and not necessarily those of the supporting organizations.
This article references 63 other publications.
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Valente, A.; Iribarren, D.; Dufour, J. Life Cycle Assessment of Hydrogen Energy Systems: A Review of Methodological Choices. Int. J. Life Cycle Assess. 2017, 22 (3), 346– 363, DOI: 10.1007/s11367-016-1156-z
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Life cycle assessment of hydrogen energy systems: a review of methodological choices
Valente, Antonio; Iribarren, Diego; Dufour, Javier
International Journal of Life Cycle Assessment (2017), 22 (3), 346-363CODEN: IJLCFF; ISSN:0948-3349. (Springer)
Purpose: As a first step towards a consistent framework for both individual and comparative life cycle assessment (LCA) of hydrogen energy systems, this work performs a thorough literature review on the methodol. choices made in LCA studies of these energy systems. Choices affecting the LCA stages "goal and scope definition", "life cycle inventory anal." (LCI) and "life cycle impact assessment" (LCIA) are targeted. Methods: This review considers 97 scientific papers published until Dec. 2015, in which 509 original case studies of hydrogen energy systems are found. Based on the hydrogen prodn. process, these case studies are classified into three technol. categories: thermochem., electrochem. and biol. A subdivision based on the scope of the studies is also applied, thus distinguishing case studies addressing hydrogen prodn. only, hydrogen prodn. and use in mobility and hydrogen prodn. and use for power generation. Results and discussion: Most of the hydrogen energy systems apply cradle/gate-to-gate boundaries, while cradle/gate-to-grave boundaries are found mainly for hydrogen use in mobility. The functional unit is usually mass- or energy-based for cradle/gate-to-gate studies and travelled distance for cradle/gate-to-grave studies. Multifunctionality is addressed mainly through system expansion and, to a lesser extent, phys. allocation. Regarding LCI, scientific literature and life cycle databases are the main data sources for both background and foreground processes. Regarding LCIA, the most common impact categories evaluated are global warming and energy consumption through the IPCC and VDI methods, resp. The remaining indicators are often evaluated using the CML family methods. The level of agreement of these trends with the available FC-HyGuide guidelines for LCA of hydrogen energy systems depends on the specific methodol. aspect considered. Conclusions: This review on LCA of hydrogen energy systems succeeded in finding relevant trends in methodol. choices, esp. regarding the frequent use of system expansion and secondary data under prodn.-oriented attributional approaches. These trends are expected to facilitate methodol. decision making in future LCA studies of hydrogen energy systems. Furthermore, this review may provide a basis for the definition of a methodol. framework to harmonise the LCA results of hydrogen available so far in the literature.
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Rinawati, D. I.; Keeley, A. R.; Takeda, S.; Managi, S. A Systematic Review of Life Cycle Assessment of Hydrogen for Road Transport Use. Prog. Energy 2022, 4 (1), 012001 DOI: 10.1088/2516-1083/ac34e9
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Rinawati, D. I.; Keeley, A. R.; Takeda, S.; Managi, S. Life-Cycle Assessment of Hydrogen Utilization in Power Generation: A Systematic Review of Technological and Methodological Choices. Front. Sustain. 2022, 3, 920876 DOI: 10.3389/frsus.2022.920876
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Bhandari, R.; Trudewind, C. A.; Zapp, P. Life Cycle Assessment of Hydrogen Production via Electrolysis – a Review. J. Clean. Prod. 2014, 85, 151– 163, DOI: 10.1016/j.jclepro.2013.07.048
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Cetinkaya, E.; Dincer, I.; Naterer, G. F. Life Cycle Assessment of Various Hydrogen Production Methods. Int. J. Hydrogen Energ 2012, 37 (3), 2071– 2080, DOI: 10.1016/j.ijhydene.2011.10.064
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Life cycle assessment of various hydrogen production methods
Cetinkaya, E.; Dincer, I.; Naterer, G. F.
International Journal of Hydrogen Energy (2012), 37 (3), 2071-2080CODEN: IJHEDX; ISSN:0360-3199. (Elsevier Ltd.)
A comprehensive life cycle assessment (LCA) is reported for five methods of hydrogen prodn., namely steam reforming of natural gas, coal gasification, water electrolysis via wind and solar electrolysis, and thermochem. water splitting with a Cu-Cl cycle. Carbon dioxide equiv. emissions and energy equiv. of each method are quantified and compared. A case study is presented for a hydrogen fueling station in Toronto, Canada, and nearby hydrogen resources close to the fueling station. In terms of carbon dioxide equiv. emissions, thermochem. water splitting with the Cu-Cl cycle is found to be advantageous over the other methods, followed by wind and solar electrolysis. In terms of hydrogen prodn. capacities, natural gas steam reforming, coal gasification and thermochem. water splitting with the Cu-Cl cycle methods are found to be advantageous over the renewable energy methods.
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Lee, D.-Y.; Elgowainy, A.; Kotz, A.; Vijayagopal, R.; Marcinkoski, J. Life-Cycle Implications of Hydrogen Fuel Cell Electric Vehicle Technology for Medium- and Heavy-Duty Trucks. J. Power Sources 2018, 393, 217– 229, DOI: 10.1016/j.jpowsour.2018.05.012
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Life-cycle implications of hydrogen fuel cell electric vehicle technology for medium- and heavy-duty trucks
Lee, Dong-Yeon; Elgowainy, Amgad; Kotz, Andrew; Vijayagopal, Ram; Marcinkoski, Jason
Journal of Power Sources (2018), 393 (), 217-229CODEN: JPSODZ; ISSN:0378-7753. (Elsevier B.V.)
This study provides a comprehensive and up-to-date life-cycle comparison of hydrogen fuel cell elec. trucks (FCETs) and their conventional diesel counterparts in terms of energy use and air emissions, based on the ensemble of well-established methods, high-fidelity vehicle dynamic simulations, and real-world vehicle test data. For the centralized steam methane reforming (SMR) pathway, hydrogen FCETs reduce life-cycle or well-to-wheel (WTW) petroleum energy use by more than 98% compared to their diesel counterparts. The redn. in WTW air emissions for gaseous hydrogen (G.H2) FCETs ranges from 20 to 45% for greenhouse gases, 37-65% for VOC, 49-77% for CO, 62-83% for NOx, 19-43% for PM10, and 27-44% for PM2.5, depending on vehicle wt. classes and truck types. With the current U. S. av. electricity generation mix, FCETs tend to create more WTW SOx emissions than their diesel counterparts, mainly because of the upstream emissions related to electricity use for hydrogen compression/liquefaction. Compared to G. H2, liq. hydrogen (L.H2) FCETs generally provide smaller WTW emissions redns. For both G.H2 and L. H2 pathways for FCETs, because of electricity consumption for compression and liquefaction, spatio-temporal variations of electricity generation can affect the WTW results. FCETs retain the WTW emission redn. benefits, even when considering aggressive diesel engine efficiency improvement.
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Frank, E. D.; Elgowainy, A.; Reddi, K.; Bafana, A. Life-Cycle Analysis of Greenhouse Gas Emissions from Hydrogen Delivery: A Cost-Guided Analysis. Int. J. Hydrogen Energ 2021, 46 (43), 22670– 22683, DOI: 10.1016/j.ijhydene.2021.04.078
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Life-cycle analysis of greenhouse gas emissions from hydrogen delivery: A cost-guided analysis
Frank, Edward D.; Elgowainy, Amgad; Reddi, Krishna; Bafana, Adarsh
International Journal of Hydrogen Energy (2021), 46 (43), 22670-22683CODEN: IJHEDX; ISSN:0360-3199. (Elsevier Ltd.)
The cost of hydrogen delivery for transportation accounts for most of the current H2 selling price; delivery also requires substantial amts. of energy. We developed harmonized techno-economic and life-cycle emissions models of current and future H2 prodn. and delivery pathways. Our techno-economic anal. of dispensed H2 costs guided our selection of pathways for the life-cycle anal. In this paper, we present the results of market expansion scenarios using existing capabilities (for example, those that use H2 from steam methane reforming, chlor-alkali, and natural gas liq. cracker plants), as well as results for future electrolysis plants that use nuclear, solar, and hydroelec. power. Redns. in greenhouse gas emissions for fuel cell elec. vehicles compared to conventional gasoline pathways vary from 40% redn. for fossil-derived H2 to 20-fold for clean H2. Supplemental tables with greenhouse gas emissions data for each step in the H2 pathways enable readers to evaluate addnl. scenarios.
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Paulot, F.; Paynter, D.; Naik, V.; Malyshev, S.; Menzel, R.; Horowitz, L. W. Global Modeling of Hydrogen Using GFDL-AM4.1: Sensitivity of Soil Removal and Radiative Forcing. Int. J. Hydrogen Energ 2021, 46 (24), 13446– 13460, DOI: 10.1016/j.ijhydene.2021.01.088
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Global modeling of hydrogen using GFDL-AM4.1: Sensitivity of soil removal and radiative forcing
Paulot, Fabien; Paynter, David; Naik, Vaishali; Malyshev, Sergey; Menzel, Raymond; Horowitz, Larry W.
International Journal of Hydrogen Energy (2021), 46 (24), 13446-13460CODEN: IJHEDX; ISSN:0360-3199. (Elsevier Ltd.)
Hydrogen (H2) was proposed as an alternative energy carrier to reduce the carbon footprint and assocd. radiative forcing of the current energy system. Here, we describe the representation of H2 in the GFDL-AM4.1 model including updated emission inventories and improved representation of H2 soil removal, the dominant sink of H2. The model best captures the overall distribution of surface H2, including regional contrasts between climate zones, when vd(H2) is modulated by soil moisture, temp., and soil carbon content. We est. that the soil removal of H2 increases with warming (2-4% per K), with large uncertainties stemming from different regional response of soil moisture and soil carbon. We est. that H2 causes an indirect radiative forcing of 0.84 mW m-2/(Tg(H2)yr-1) or 0.13 mW m-2 ppbv-1, primarily due to increasing CH4 lifetime and stratospheric water vapor prodn.
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Warwick, N. J.; Archibald, A. T.; Griffiths, P. T.; Keeble, J.; O’Connor, F. M.; Pyle, J. A.; Shine, K. P. Atmospheric Composition and Climate Impacts of a Future Hydrogen Economy. Atmos. Chem. Phys. 2023, 23 (20), 13451– 13467, DOI: 10.5194/acp-23-13451-2023
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Atmospheric composition and climate impacts of a future hydrogen economy
Warwick, Nicola J.; Archibald, Alex T.; Griffiths, Paul T.; Keeble, James; O'Connor, Fiona M.; Pyle, John A.; Shine, Keith P.
Atmospheric Chemistry and Physics (2023), 23 (20), 13451-13467CODEN: ACPTCE; ISSN:1680-7324. (Copernicus Publications)
Hydrogen is expected to play a key role in the global energy transition to net zero emissions in many scenarios. However, fugitive emissions of hydrogen into the atm. during its prodn., storage, distribution and use could reduce the climate benefit and also have implications for air quality. Here, we explore the atm. compn. and climate impacts of increases in atm. hydrogen abundance using the UK Earth System Model (UKESM1) chem.-climate model. Increases in hydrogen result in increases in methane, tropospheric ozone and stratospheric water vapor, resulting in a pos. radiative forcing. However, some of the impacts of hydrogen leakage are partially offset by potential redns. in emissions of methane, carbon monoxide, nitrogen oxides and volatile org. compds. from the consumption of fossil fuels. We derive a refined methodol. for detg. indirect global warming potentials (GWPs) from parameters derived from steady-state simulations, which is applicable to both shorter-lived species and those with intermediate and longer lifetimes, such as hydrogen. Using this methodol., we det. a 100-yr global warming potential for hydrogen of 12 ± 6. Based on this GWP and hydrogen leakage rates of 1% and 10%, we find that hydrogen leakage offsets approx. 0.4% and 4% resp. of total equiv. CO2 emission redns. in our global hydrogen economy scenario. To maximise the benefit of hydrogen as an energy source, emissions assocd. with hydrogen leakage and emissions of the ozone precursor gases need to be minimised.
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Hauglustaine, D.; Paulot, F.; Collins, W.; Derwent, R.; Sand, M.; Boucher, O. Climate Benefit of a Future Hydrogen Economy. Commun. Earth Environ 2022, 3 (1), 295, DOI: 10.1038/s43247-022-00626-z
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Sand, M.; Skeie, R. B.; Sandstad, M.; Krishnan, S.; Myhre, G.; Bryant, H.; Derwent, R.; Hauglustaine, D.; Paulot, F.; Prather, M.; Stevenson, D. A Multi-Model Assessment of the Global Warming Potential of Hydrogen. Commun. Earth Environ. 2023, 4 (1), 203, DOI: 10.1038/s43247-023-00857-8
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Hauglustaine, D. A.; Ehhalt, D. H. A Three-dimensional Model of Molecular Hydrogen in the Troposphere. J. Geophys. Res.: Atmos. 2002, 107 (D17), ACH 4-1– ACH 4-16, DOI: 10.1029/2001JD001156
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Field, R. A.; Derwent, R. G. Global Warming Consequences of Replacing Natural Gas with Hydrogen in the Domestic Energy Sectors of Future Low-Carbon Economies in the United Kingdom and the United States of America. Int. J. Hydrogen Energ 2021, 46 (58), 30190– 30203, DOI: 10.1016/j.ijhydene.2021.06.120
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Global warming consequences of replacing natural gas with hydrogen in the domestic energy sectors of future low-carbon economies in the United Kingdom and the United States of America
Field, R. A.; Derwent, R. G.
International Journal of Hydrogen Energy (2021), 46 (58), 30190-30203CODEN: IJHEDX; ISSN:0360-3199. (Elsevier Ltd.)
Hydrogen has a potentially important future role as a replacement for natural gas in the domestic sector in a zero-carbon economy for heating homes and cooking. To assess this potential, an understanding is required of the global warming potentials (GWPs) of methane and hydrogen and of the leakage rates of the natural gas distribution system and that of a hydrogen system that would replace it. The GWPs of methane and hydrogen were estd. using a global chem.-transport model as 29.2 ± 8 and 3.3 ± 1.4, resp., over a 100-yr time horizon. The current natural gas leakage rates from the distribution system were estd. for the UK by the ethane tracer method to be ∼0.64 Tg CH4/yr (2.3%) and for the US by literature review to be of the order of 0.69-2.9 Tg CH4/yr (0.5-2.1%). On this basis, with the inclusion of carbon dioxide emissions from combustion, replacing natural gas with green hydrogen in the domestic sectors of both countries should reduce substantially the global warming consequences of domestic sector energy use both in the UK and in the US, provided care is taken to reduce hydrogen leakage to a min. A perfectly sealed zero-carbon green hydrogen distribution system would save the entire 76 million tonnes CO2 equivalent per yr in the UK.
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Derwent, R. G.; Stevenson, D. S.; Utembe, S. R.; Jenkin, M. E.; Khan, A. H.; Shallcross, D. E. Global Modelling Studies of Hydrogen and Its Isotopomers Using STOCHEM-CRI: Likely Radiative Forcing Consequences of a Future Hydrogen Economy. Int. J. Hydrogen Energ 2020, 45 (15), 9211– 9221, DOI: 10.1016/j.ijhydene.2020.01.125
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Global modelling studies of hydrogen and its isotopomers using STOCHEM-CRI: Likely radiative forcing consequences of a future hydrogen economy
Derwent, Richard G.; Stevenson, David S.; Utembe, Steven R.; Jenkin, Michael E.; Khan, Anwar H.; Shallcross, Dudley E.
International Journal of Hydrogen Energy (2020), 45 (15), 9211-9221CODEN: IJHEDX; ISSN:0360-3199. (Elsevier Ltd.)
A global chem.-transport model was employed to describe the global sources and sinks of hydrogen (H2) and its isotopomer (HD). The model is able to satisfactorily describe the obsd. tropospheric distributions of H2 and HD and deliver budgets and turnovers which agree with literature studies. We than go on to quantify the methane and ozone responses to emission pulses of hydrogen and their likely radiative forcing consequences. These radiative forcing consequences were expressed on a 1 Tg basis and integrated over a hundred-year time horizon. When compared to the consequences of a 1 Tg emission pulse of carbon dioxide, 1 Tg of hydrogen causes 5 ± 1 times as much time-integrated radiative forcing over a hundred-year time horizon. That is to say, hydrogen has a global warming potential (GWP) of 5 ± 1 over a hundred-year time horizon. The global warming consequences of a hydrogen-based low-carbon energy system therefore depend critically on the hydrogen leakage rate. If the leakage of hydrogen from all stages in the prodn., distribution, storage and utilization of hydrogen is efficiently curtailed, then hydrogen-based energy systems appear to be an attractive proposition in providing a future replacement for fossil-fuel based energy systems.
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Derwent, R.; Simmonds, P.; O’Doherty, S.; Manning, A.; Collins, W.; Stevenson, D. Global Environmental Impacts of the Hydrogen Economy. Int. J. Nucl. Hydrogen Prod Appl. 2006, 1 (1), 57, DOI: 10.1504/IJNHPA.2006.009869
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Derwent, R. G.; Collins, W. J.; Johnson, C. E.; Stevenson, D. S. Transient Behaviour of Tropospheric Ozone Precursors in a Global 3-D CTM and Their Indirect Greenhouse Effects. Climatic Change 2001, 49 (4), 463– 487, DOI: 10.1023/A:1010648913655
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Transient behaviour of tropospheric ozone precursors in a global 3-D CTM and their indirect greenhouse effects
Derwent, R. G.; Collins, W. J.; Johnson, C. E.; Stevenson, D. S.
Climatic Change (2001), 49 (4), 463-487CODEN: CLCHDX; ISSN:0165-0009. (Kluwer Academic Publishers)
The global three-dimensional Lagrangian chem.-transport model STOCHEM has been used to follow the changes in the tropospheric distributions of the two major radiatively-active trace gases, methane and tropospheric ozone, following the emission of pulses of the short-lived tropospheric ozone precursor species, methane, carbon monoxide, NOx and hydrogen. The radiative impacts of NOx emissions were dependent on the location chosen for the emission pulse, whether at the surface or in the upper troposphere or whether in the northern or southern hemispheres. Global warming potentials were derived for each of the short-lived tropospheric ozone precursor species by integrating the methane and tropospheric ozone responses over a 100-yr time horizon. Indirect radiative forcing due to methane and tropospheric ozone changes appear to be significant for all of the tropospheric ozone precursor species studied. Whereas the radiative forcing from methane changes is likely to be dominated by methane emissions, that from tropospheric ozone changes is controlled by all the tropospheric ozone precursor gases, particularly NOx emissions. The indirect radiative forcing impacts of tropospheric ozone changes may be large enough such that ozone precursors should be considered in the basket of trace gases through which policy-makers aim to combat global climate change.
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Prather, M. J. An Environmental Experiment with H2?. Science 2003, 302 (5645), 581– 582, DOI: 10.1126/science.1091060
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Atmospheric science: An environmental experiment with H2?
Prather, Michael J.
Science (Washington, DC, United States) (2003), 302 (5645), 581-582CODEN: SCIEAS; ISSN:0036-8075. (American Association for the Advancement of Science)
A review of the environmental consequences of a H2 fuel economy, including leaks that would cause large increases in atm. H2, affecting stratospheric water vapor, temp. and O3; natural and anthropogenic sources of H2; atm. and soil sinks of H2; indirect greenhouse gas effects; indirect increases of CH4; and NOx redns.
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Schultz, M. G.; Diehl, T.; Brasseur, G. P.; Zittel, W. Air Pollution and Climate-Forcing Impacts of a Global Hydrogen Economy. Science 2003, 302 (5645), 624– 627, DOI: 10.1126/science.1089527
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Air pollution and climate-forcing impacts of a global hydrogen economy
Schultz, Martin G.; Diehl, Thomas; Brasseur, Guy P.; Zittel, Werner
Science (Washington, DC, United States) (2003), 302 (5645), 624-627CODEN: SCIEAS; ISSN:0036-8075. (American Association for the Advancement of Science)
If today's surface traffic fleet were powered entirely by H fuel cell technol., anthropogenic emissions of the ozone precursors NOx and CO could be reduced by ≤50%, leading to significant improvements in air quality throughout the Northern Hemisphere. Model simulations of such a scenario predict a decrease in global OH and an increased lifetime of CH4, caused primarily by the redn. of the NOx emissions. The sign of the change in climate forcing caused by CO2 and CH4 depends on the technol. used to generate the H2. A possible rise in atm. H concns. is unlikely to cause significant perturbations of the climate system.
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Warwick, N. J.; Bekki, S.; Nisbet, E. G.; Pyle, J. A. Impact of a Hydrogen Economy on the Stratosphere and Troposphere Studied in a 2-D Model. Geophys. Res. Lett. 2004, 31 (5), L05107 DOI: 10.1029/2003GL019224
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Impact of a hydrogen economy on the stratosphere and troposphere studied in a 2-D model
Warwick, N. J.; Bekki, S.; Nisbet, E. G.; Pyle, J. A.
Geophysical Research Letters (2004), 31 (5), L05107/1-L05107/4CODEN: GPRLAJ; ISSN:0094-8276. (American Geophysical Union)
A switch from a fossil fuel to a hydrogen-based energy system could cause significant changes in the magnitude and compn. of anthropogenic emissions. Model simulations suggest the most significant impact of these emission changes would occur in the troposphere, affecting OH. This impact is dependent upon the magnitude and nature of trade-offs in changing fossil fuel use. In the stratosphere, changes in water vapor resulting from expected increases in surface mol. hydrogen emissions via leaks occurring during prodn., transport, and storage, are found to be significantly smaller than previous ests. We conclude that the expected increase in mol. hydrogen emissions is unlikely to have a substantial impact on stratospheric ozone, certainly much smaller than the ozone changes obsd. in the last two decades.
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Colella, W. G.; Jacobson, M. Z.; Golden, D. M. Switching to a U.S. Hydrogen Fuel Cell Vehicle Fleet: The Resultant Change in Emissions, Energy Use, and Greenhouse Gases. J. Power Sources 2005, 150, 150– 181, DOI: 10.1016/j.jpowsour.2005.05.092
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Switching to a U.S. hydrogen fuel cell vehicle fleet: The resultant change in emissions, energy use, and greenhouse gases
Colella, W. G.; Jacobson, M. Z.; Golden, D. M.
Journal of Power Sources (2005), 150 (), 150-181CODEN: JPSODZ; ISSN:0378-7753. (Elsevier B.V.)
This study examines the potential change in primary emissions and energy use as a result of replacing the current U.S. fleet of fossil-fuel on-road vehicles (FFOV) with hybrid elec. fossil fuel vehicles or hydrogen fuel cell vehicles (HFCV). Emissions and energy usage are analyzed for three different HFCV scenarios, with hydrogen produced by (a) steam reforming of natural gas, (b) electrolysis powered by wind energy, and (c) coal gasification. With the U.S. EPA National Emission Inventory as the baseline, other emission inventories are created using a life cycle assessment of alternative fuel supply chains. For a range of reasonable HFCV efficiencies and methods of producing hydrogen, we find that the replacement of FFOV with HFCV significantly reduces emission assocd. with air pollution, compared even with a switch to hybrids. All HFCV scenarios decrease net air pollution emission, including nitrogen oxides, volatile org. compds., particulate matter, ammonia, and carbon monoxide. These redns. are achieved with hydrogen prodn. from either a fossil fuel source such as natural gas or a renewable source such as wind. Furthermore, replacing FFOV with hybrids or HFCV with hydrogen derived from natural gas, wind or coal may reduce the global warming impact of greenhouse gases and particles (measured in carbon dioxide equiv. emission) by 6, 14, 23, and 1%, resp. Finally, even if HFCV are fueled by a fossil fuel such as natural gas, if no carbon is sequestered during hydrogen prodn., and 1% of methane in the feedstock gas is leaked to the environment, natural gas HFCV still may achieve a significant redn. in greenhouse gas and air pollution emission over FFOV.
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Arrigoni, A.; Bravo, D. L. Hydrogen Emissions from a Hydrogen Economy and Their Potential Global Warming Impact. 2022; OP KJ-NA-31-188-EN-N. DOI: 10.2760/065589
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Cooper, J.; Dubey, L.; Bakkaloglu, S.; Hawkes, A. Hydrogen Emissions from the Hydrogen Value Chain-Emissions Profile and Impact to Global Warming. Sci. Total Environ. 2022, 830, 154624 DOI: 10.1016/j.scitotenv.2022.154624
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Hydrogen emissions from the hydrogen value chain-emissions profile and impact to global warming
Cooper, Jasmin; Dubey, Luke; Bakkaloglu, Semra; Hawkes, Adam
Science of the Total Environment (2022), 830 (), 154624CODEN: STENDL; ISSN:0048-9697. (Elsevier B.V.)
Future energy systems could rely on hydrogen (H2) to achieve decarbonisation and net-zero goals. In a similar energy landscape to natural gas, H2 emissions occur along the supply chain. It has been studied how current gas infrastructure can support H2, but there is little known about how H2 emissions affect global warming as an indirect greenhouse gas. In this work, we have estd. for the first time the potential emission profiles (g CO2eq/MJ H2,HHV) of H2 supply chains, and found that the emission rates of H2 from H2 supply chains and methane from natural gas supply are comparable, but the impact on global warming is much lower based on current ests. This study also demonstrates the crit. importance of establishing mobile H2 emission monitoring and reducing the uncertainty of short-lived H2 climate forcing so as to clearly address H2 emissions for net-zero strategies.
https://chemport.cas.org/services/resolver?origin=ACS&resolution=options&coi=1%3ACAS%3A528%3ADC%252BB38XotFOnsLo%253D&md5=bd58067a99a6742196ce967dc802e37c
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Fan, Z.; Sheerazi, H.; Bhardwaj, A.; Corbeau, A.-S.; Longobardi, K.; Castañeda, A.; Merz, A.-K.; Woodall, C. M.; Agrawal, M.; Orozco-Sanchez, S.; Friedmann, J. Hydrogen Leakage: A Potential Risk for the Hydrogen Economy; Center on Global Energy Policy. 2022. https://www.energypolicy.columbia.edu/publications/hydrogen-leakage-potential-risk-hydrogen-economy/ (last accessed 2024-01-12).
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Esquivel-Elizondo, S.; Hormaza Mejia, A.; Sun, T.; Shrestha, E.; Hamburg, S. P.; Ocko, I. B. Wide Range in Estimates of Hydrogen Emissions from Infrastructure. Front. Energy Res. 2023, 11, 01– 08, DOI: 10.3389/fenrg.2023.1207208
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Alvarez, R. A.; Zavala-Araiza, D.; Lyon, D. R.; Allen, D. T.; Barkley, Z. R.; Brandt, A. R.; Davis, K. J.; Herndon, S. C.; Jacob, D. J.; Karion, A.; Kort, E. A.; Lamb, B. K.; Lauvaux, T.; Maasakkers, J. D.; Marchese, A. J.; Omara, M.; Pacala, S. W.; Peischl, J.; Robinson, A. L.; Shepson, P. B.; Sweeney, C.; Townsend-Small, A.; Wofsy, S. C.; Hamburg, S. P. Assessment of Methane Emissions from the U.S. Oil and Gas Supply Chain. Science 2018, 361 (6398), 186– 188, DOI: 10.1126/science.aar7204
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Assessment of methane emissions from the U.S. oil and gas supply chain
Alvarez, Ramon A.; Zavala-Araiza, Daniel; Lyon, David R.; Allen, David T.; Barkley, Zachary R.; Brandt, Adam R.; Davis, Kenneth J.; Herndon, Scott C.; Jacob, Daniel J.; Karion, Anna; Kort, Eric A.; Lamb, Brian K.; Lauvaux, Thomas; Maasakkers, Joannes D.; Marchese, Anthony J.; Omara, Mark; Pacala, Stephen W.; Peischl, Jeff; Robinson, Allen L.; Shepson, Paul B.; Sweeney, Colm; Townsend-Small, Amy; Wofsy, Steven C.; Hamburg, Steven P.
Science (Washington, DC, United States) (2018), 361 (6398), 186-188CODEN: SCIEAS; ISSN:0036-8075. (American Association for the Advancement of Science)
Considerable amts. of the greenhouse gas methane leak from the U.S. oil and natural gas supply chain. Alvarez et al. reassessed the magnitude of this leakage and found that in 2015, supply chain emissions were ∼60% higher than the U.S. Environmental Protection Agency inventory est. They suggest that this discrepancy exists because current inventory methods miss emissions that occur during abnormal operating conditions. These data, and the methodol. used to obtain them, could improve and verify international inventories of greenhouse gases and provide a better understanding of mitigation efforts outlined by the Paris Agreement.
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Shen, L.; Gautam, R.; Omara, M.; Zavala-Araiza, D.; Maasakkers, J. D.; Scarpelli, T. R.; Lorente, A.; Lyon, D.; Sheng, J.; Varon, D. J.; Nesser, H.; Qu, Z.; Lu, X.; Sulprizio, M. P.; Hamburg, S. P.; Jacob, D. J. Satellite Quantification of Oil and Natural Gas Methane Emissions in the US and Canada Including Contributions from Individual Basins. Atmos. Chem. Phys. 2022, 22 (17), 11203– 11215, DOI: 10.5194/acp-22-11203-2022
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Satellite quantification of oil and natural gas methane emissions in the US and Canada including contributions from individual basins
Shen, Lu; Gautam, Ritesh; Omara, Mark; Zavala-Araiza, Daniel; Maasakkers, Joannes D.; Scarpelli, Tia R.; Lorente, Alba; Lyon, David; Sheng, Jianxiong; Varon, Daniel J.; Nesser, Hannah; Qu, Zhen; Lu, Xiao; Sulprizio, Melissa P.; Hamburg, Steven P.; Jacob, Daniel J.
Atmospheric Chemistry and Physics (2022), 22 (17), 11203-11215CODEN: ACPTCE; ISSN:1680-7324. (Copernicus Publications)
We use satellite methane observations from the Tropospheric Monitoring Instrument (TROPOMI), for May 2018 to Feb. 2020, to quantify methane emissions from individual oil and natural gas (O/G) basins in the US and Canada using a high-resoln. (∼25 km) atm. inverse anal. Our satellite-derived emission ests. show good consistency with in situ field measurements (R = 0.96) in 14 O/G basins distributed across the US and Canada. Aggregating our results to the national scale, we obtain O/G-related methane emission ests. of 12.6 ± 2.1 Tg a-1 for the US and 2.2 ± 0.6 Tg a-1 for Canada, 80% and 40%, resp., higher than the national inventories reported to the United Nations. About 70% of the discrepancy in the US Environmental Protection Agency (EPA) inventory can be attributed to five O/G basins, the Permian, Haynesville, Anadarko, Eagle Ford, and Barnett basins, which in total account for 40% of US emissions. We show more generally that our TROPOMI inversion framework can quantify methane emissions exceeding 0.2-0.5 Tg a-1 from individual O/G basins, thus providing an effective tool for monitoring methane emissions from large O/G basins globally.
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Foulds, A.; Allen, G.; Shaw, J. T.; Bateson, P.; Barker, P. A.; Huang, L.; Pitt, J. R.; Lee, J. D.; Wilde, S. E.; Dominutti, P.; Purvis, R. M.; Lowry, D.; France, J. L.; Fisher, R. E.; Fiehn, A.; Pühl, M.; Bauguitte, S. J. B.; Conley, S. A.; Smith, M. L.; Lachlan-Cope, T.; Pisso, I.; Schwietzke, S. Quantification and Assessment of Methane Emissions from Offshore Oil and Gas Facilities on the Norwegian Continental Shelf. Atmos Chem. Phys. 2022, 22 (7), 4303– 4322, DOI: 10.5194/acp-22-4303-2022
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Quantification and assessment of methane emissions from offshore oil and gas facilities on the Norwegian continental shelf
Foulds, Amy; Allen, Grant; Shaw, Jacob T.; Bateson, Prudence; Barker, Patrick A.; Huang, Langwen; Pitt, Joseph R.; Lee, James D.; Wilde, Shona E.; Dominutti, Pamela; Purvis, Ruth M.; Lowry, David; France, James L.; Fisher, Rebecca E.; Fiehn, Alina; Puhl, Magdalena; Bauguitte, Stephane J. B.; Conley, Stephen A.; Smith, Mackenzie L.; Lachlan-Cope, Tom; Pisso, Ignacio; Schwietzke, Stefan
Atmospheric Chemistry and Physics (2022), 22 (7), 4303-4322CODEN: ACPTCE; ISSN:1680-7324. (Copernicus Publications)
The oil and gas (O&G) sector is a significant source of methane (CH4) emissions. Quantifying these emissions remains challenging, with many studies highlighting discrepancies between measurements and inventory-based ests. In this study, we present CH4 emission fluxes from 21 offshore O&G facilities collected in 10 O&G fields over two regions of the Norwegian continental shelf in 2019. Emissions of CH4 derived from measurements during 13 aircraft surveys were found to range from 2.6 to 1200 t yr-1 (with a mean of 211 t yr-1 across all 21 facilities). Comparing this with aggregated operator-reported facility emissions for 2019, we found excellent agreement (within 1σ uncertainty), with mean aircraft-measured fluxes only 16% lower than those reported by operators. We also compared aircraft-derived fluxes with facility fluxes extd. from a global gridded fossil fuel CH4 emission inventory compiled for 2016. We found that the measured emissions were 42% larger than the inventory for the area covered by this study, for the 21 facilities surveyed (in aggregate). We interpret this large discrepancy not to reflect a systematic error in the operator-reported emissions, which agree with measurements, but rather the representativity of the global inventory due to the methodol. used to construct it and the fact that the inventory was compiled for 2016 (and thus not representative of emissions in 2019). This highlights the need for timely and up-to-date inventories for use in research and policy. The variable nature of CH4 emissions from individual facilities requires knowledge of facility operational status during measurements for data to be useful in prioritising targeted emission mitigation solns. Future surveys of individual facilities would benefit from knowledge of facility operational status over time. Field-specific aggregated emissions (and uncertainty statistics), as presented here for the Norwegian Sea, can be meaningfully estd. from intensive aircraft surveys. However, field-specific ests. cannot be reliably extrapolated to other prodn. fields without their own tailored surveys, which would need to capture a range of facility designs, oil and gas prodn. vols., and facility ages. For year-on-year comparison to annually updated inventories and regulatory emission reporting, analogous annual surveys would be needed for meaningful top-down validation. In summary, this study demonstrates the importance and accuracy of detailed, facility-level emission accounting and reporting by operators and the use of airborne measurement approaches to validate bottom-up accounting.
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MacKay, K.; Lavoie, M.; Bourlon, E.; Atherton, E.; O’Connell, E.; Baillie, J.; Fougère, C.; Risk, D. Methane Emissions from Upstream Oil and Gas Production in Canada Are Underestimated. Sci. Rep-uk 2021, 11 (1), 8041, DOI: 10.1038/s41598-021-87610-3
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Chen, Y.; Sherwin, E. D.; Berman, E. S. F.; Jones, B. B.; Gordon, M. P.; Wetherley, E. B.; Kort, E. A.; Brandt, A. R. Quantifying Regional Methane Emissions in the New Mexico Permian Basin with a Comprehensive Aerial Survey. Environ. Sci. Technol. 2022, 56 (7), 4317– 4323, DOI: 10.1021/acs.est.1c06458
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Quantifying Regional Methane Emissions in the New Mexico Permian Basin with a Comprehensive Aerial Survey
Chen, Yuanlei; Sherwin, Evan D.; Berman, Elena S. F.; Jones, Brian B.; Gordon, Matthew P.; Wetherley, Erin B.; Kort, Eric A.; Brandt, Adam R.
Environmental Science & Technology (2022), 56 (7), 4317-4323CODEN: ESTHAG; ISSN:1520-5851. (American Chemical Society)
Limiting emissions of climate-warming methane from oil and gas (O&G) is a major opportunity for short-term climate benefits. We deploy a basin-wide airborne survey of O&G extn. and transportation activities in the New Mexico Permian Basin, spanning 35 923 km2, 26 292 active wells, and over 15 000 km of natural gas pipelines using an independently validated hyperspectral methane point source detection and quantification system. The airborne survey repeatedly visited over 90% of the active wells in the survey region throughout Oct. 2018 to Jan. 2020, totaling approx. 98 000 well site visits. We est. total O&G methane emissions in this area at 194 (+72/-68, 95% CI) metric tonnes per h (t/h), or 9.4% (+3.5%/-3.3%) of gross gas prodn. 50% of obsd. emissions come from large emission sources with persistence-averaged emission rates over 308 kg/h. The fact that a large sample size is required to characterize the heavy tail of the distribution emphasizes the importance of capturing low-probability, high-consequence events through basin-wide surveys when estg. regional O&G methane emissions.
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Howarth, R. W.; Jacobson, M. Z. How Green Is Blue Hydrogen?. Energy Sci. Eng. 2021, 9, 1676– 1687, DOI: 10.1002/ese3.956
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How green is blue hydrogen?
Howarth, Robert W.; Jacobson, Mark Z.
Energy Science & Engineering (2021), 9 (10), 1676-1687CODEN: ESENGX; ISSN:2050-0505. (John Wiley & Sons Ltd.)
A review. Hydrogen is often viewed as an important energy carrier in a future decarbonized world. Currently, most hydrogen is produced by steam reforming of methane in natural gas ("gray hydrogen"), with high carbon dioxide emissions. Increasingly, many propose using carbon capture and storage to reduce these emissions, producing so-called "blue hydrogen," frequently promoted as low emissions. We undertake the first effort in a peer-reviewed paper to examine the lifecycle greenhouse gas emissions of blue hydrogen accounting for emissions of both carbon dioxide and unburned fugitive methane. Far from being low carbon, greenhouse gas emissions from the prodn. of blue hydrogen are quite high, particularly due to the release of fugitive methane. For our default assumptions (3.5% emission rate of methane from natural gas and a 20-yr global warming potential), total carbon dioxide equiv. emissions for blue hydrogen are only 9%-12% less than for gray hydrogen. While carbon dioxide emissions are lower, fugitive methane emissions for blue hydrogen are higher than for gray hydrogen because of an increased use of natural gas to power the carbon capture. Perhaps surprisingly, the greenhouse gas footprint of blue hydrogen is more than 20% greater than burning natural gas or coal for heat and some 60% greater than burning diesel oil for heat, again with our default assumptions. In a sensitivity anal. in which the methane emission rate from natural gas is reduced to a low value of 1.54%, greenhouse gas emissions from blue hydrogen are still greater than from simply burning natural gas, and are only 18%-25% less than for gray hydrogen. Our anal. assumes that captured carbon dioxide can be stored indefinitely, an optimistic and unproven assumption. Even if true though, the use of blue hydrogen appears difficult to justify on climate grounds.
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Stocks, M.; Fazeli, R.; Hughes, L.; Beck, F. J. Global Emissions Implications from Co-Combusting Ammonia in Coal Fired Power Stations: An Analysis of the Japan-Australia Supply Chain. J. Clean. Prod. 2022, 336, 130092 DOI: 10.1016/j.jclepro.2021.130092
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Ocko, I. B.; Hamburg, S. P. Climate Consequences of Hydrogen Emissions. Atmos. Chem. Phys. 2022, 22, 9349– 9368, DOI: 10.5194/acp-22-9349-2022
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Climate consequences of hydrogen emissions
Ocko, Ilissa B.; Hamburg, Steven P.
Atmospheric Chemistry and Physics (2022), 22 (14), 9349-9368CODEN: ACPTCE; ISSN:1680-7324. (Copernicus Publications)
Given the urgency to decarbonize global energy systems, governments and industry are moving ahead with efforts to increase deployment of hydrogen technologies, infrastructure, and applications at an unprecedented pace, including USD billions in national incentives and direct investments. While zero- and low-carbon hydrogen hold great promise to help solve some of the world's most pressing energy challenges, hydrogen is also an indirect greenhouse gas whose warming impact is both widely overlooked and underestimated. This is largely because hydrogen's atm. warming effects are short-lived - lasting only a couple decades - but std. methods for characterizing climate impacts of gases consider only the long-term effect from a one-time pulse of emissions. For gases whose impacts are short-lived, like hydrogen, this long-term framing masks a much stronger warming potency in the near to medium term. This is of concern because hydrogen is a small mol. known to easily leak into the atm., and the total amt. of emissions (e.g., leakage, venting, and purging) from existing hydrogen systems is unknown. Therefore, the effectiveness of hydrogen as a decarbonization strategy, esp. over timescales of several decades, remains unclear. This paper evaluates the climate consequences of hydrogen emissions over all timescales by employing already published data to assess its potency as a climate forcer, evaluate the net warming impacts from replacing fossil fuel technologies with their clean hydrogen alternatives, and est. temp. responses to projected levels of hydrogen demand. We use the std. global warming potential metric, given its acceptance to stakeholders, and incorporate newly published equations that more fully capture hydrogen's several indirect effects, but we consider the effects of const. rather than pulse emissions over multiple time horizons. We account for a plausible range of hydrogen emission rates and include methane emissions when hydrogen is produced via natural gas with carbon capture, usage, and storage (CCUS) ("blue" hydrogen) as opposed to renewables and water ("green" hydrogen). For the first time, we show the strong timescale dependence when evaluating the climate change mitigation potential of clean hydrogen alternatives, with the emission rate detg. the scale of climate benefits or disbenefits. For example, green hydrogen applications with higher-end emission rates (10%) may only cut climate impacts from fossil fuel technologies in half over the first 2 decades, which is far from the common perception that green hydrogen energy systems are climate neutral. However, over a 100-yr period, climate impacts could be reduced by around 80%. On the other hand, lower-end emissions (1%) could yield limited impacts on the climate over all timescales. For blue hydrogen, assocd. methane emissions can make hydrogen applications worse for the climate than fossil fuel technologies for several decades if emissions are high for both gases; however, blue hydrogen yields climate benefits over a 100-yr period. While more work is needed to evaluate the warming impact of hydrogen emissions for specific end-use cases and value-chain pathways, it is clear that hydrogen emissions matter for the climate and warrant further attention from scientists, industry, and governments. This is crit. to informing where and how to deploy hydrogen effectively in the emerging decarbonized global economy.
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Bertagni, M. B.; Pacala, S. W.; Paulot, F.; Porporato, A. Risk of the Hydrogen Economy for Atmospheric Methane. Nat. Commun. 2022, 13 (1), 7706, DOI: 10.1038/s41467-022-35419-7
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Risk of the hydrogen economy for atmospheric methane
Bertagni, Matteo B.; Pacala, Stephen W.; Paulot, Fabien; Porporato, Amilcare
Nature Communications (2022), 13 (1), 7706CODEN: NCAOBW; ISSN:2041-1723. (Nature Portfolio)
Hydrogen (H2) is expected to play a crucial role in reducing greenhouse gas emissions. However, hydrogen losses to the atm. impact atm. chem., including pos. feedback on methane (CH4), the second most important greenhouse gas. Here we investigate through a minimalist model the response of atm. methane to fossil fuel displacement by hydrogen. We find that CH4 concn. may increase or decrease depending on the amt. of hydrogen lost to the atm. and the methane emissions assocd. with hydrogen prodn. Green H2 can mitigate atm. methane if hydrogen losses throughout the value chain are below 9 ± 3%. Blue H2 can reduce methane emissions only if methane losses are below 1%. We address and discuss the main uncertainties in our results and the implications for the decarbonization of the energy sector.
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Bauer, C.; Treyer, K.; Antonini, C.; Bergerson, J.; Gazzani, M.; Gencer, E.; Gibbins, J.; Mazzotti, M.; McCoy, S. T.; McKenna, R.; Pietzcker, R.; Ravikumar, A. P.; Romano, M. C.; Ueckerdt, F.; Vente, J.; van der Spek, M. On the Climate Impacts of Blue Hydrogen Production. Sustainable Energy Fuels 2021, 6 (1), 66– 75, DOI: 10.1039/D1SE01508G
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Ricks, W.; Xu, Q.; Jenkins, J. D. Minimizing Emissions from Grid-Based Hydrogen Production in the United States. Environ. Res. Lett. 2023, 18 (1), 014025 DOI: 10.1088/1748-9326/acacb5
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Alvarez, R. A.; Pacala, S. W.; Winebrake, J. J.; Chameides, W. L.; Hamburg, S. P. Greater Focus Needed on Methane Leakage from Natural Gas Infrastructure. Proc. National Acad. Sci. 2012, 109 (17), 6435– 6440, DOI: 10.1073/pnas.1202407109
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Greater focus needed on methane leakage from natural gas infrastructure
Alvarez, Ramon A.; Pacala, Stephen W.; Winebrake, James J.; Chameides, William L.; Hamburg, Steven P.
Proceedings of the National Academy of Sciences of the United States of America (2012), 109 (17), 6435-6440, S6435/1-S6435/7CODEN: PNASA6; ISSN:0027-8424. (National Academy of Sciences)
Natural gas is seen by many as the future of American energy: a fuel that can provide energy independence and reduce greenhouse gas emissions in the process. However, there has also been confusion about the climate implications of increased use of natural gas for elec. power and transportation. We propose and illustrate the use of technol. warming potentials as a robust and transparent way to compare the cumulative radiative forcing created by alternative technologies fueled by natural gas and oil or coal by using the best available ests. of greenhouse gas emissions from each fuel cycle (i.e., prodn., transportation and use). We find that a shift to compressed natural gas vehicles from gasoline or diesel vehicles leads to greater radiative forcing of the climate for 80 or 280 yr, resp., before beginning to produce benefits. Compressed natural gas vehicles could produce climate benefits on all time frames if the well-to-wheels CH4 leakage were capped at a level 45-70% below current ests. By contrast, using natural gas instead of coal for elec. power plants can reduce radiative forcing immediately, and reducing CH4 losses from the prodn. and transportation of natural gas would produce even greater benefits. There is a need for the natural gas industry and science community to help obtain better emissions data and for increased efforts to reduce methane leakage in order to minimize the climate footprint of natural gas.
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Ocko, I. B.; Hamburg, S. P. Climate Impacts of Hydropower: Enormous Differences among Facilities and over Time. Environ. Sci. Technol. 2019, 53 (23), 14070– 14082, DOI: 10.1021/acs.est.9b05083
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Climate Impacts of Hydropower: Enormous Differences among Facilities and over Time
Ocko, Ilissa B.; Hamburg, Steven P.
Environmental Science & Technology (2019), 53 (23), 14070-14082CODEN: ESTHAG; ISSN:0013-936X. (American Chemical Society)
To stabilize climate, humans must rapidly displace fossil fuels with clean energy technologies. Currently, hydropower dominates renewable electricity generation, accounting for 2/3 globally; it is expected to grow at least 45% by 2040. While it is broadly assumed that hydropower facilities emit greenhouse gases on par with wind, there is mounting evidence that emissions can be considerably greater, with some facilities even on par with fossil fuels. However, analyses of climate impacts of hydropower facilities have been simplistic, emphasizing aggregated 100-yr impacts from a one-year emissions pulse. Such analyses mask near-term impacts of CH4 emissions central to many current policy regimes, tending to omit CO2 emissions assocd. with initial facility development, and not considering the effect of atm. gas accumulation over time. An analytic approach which addresses these issues was developed. By analyzing climate impacts of sustained hydropower emissions over time, the authors detd. there are enormous differences in climate impacts among facilities and over time. If minimizing climate impacts are not a priority for design and construction of new hydropower facilities, it could lead to limited or even no climate benefits.
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Tromp, T. K.; Shia, R.-L.; Allen, M.; Eiler, J. M.; Yung, Y. L. Potential Environmental Impact of a Hydrogen Economy on the Stratosphere. Science 2003, 300 (5626), 1740– 1742, DOI: 10.1126/science.1085169
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Potential Environmental Impact of a Hydrogen Economy on the Stratosphere
Tromp, Tracey K.; Shia, Run-Lie; Allen, Mark; Eiler, John M.; Yung, Y. L.
Science (Washington, DC, United States) (2003), 300 (5626), 1740-1742CODEN: SCIEAS; ISSN:0036-8075. (American Association for the Advancement of Science)
The widespread use of hydrogen fuel cells could have hitherto unknown environmental impacts due to unintended emissions of mol. hydrogen, including an increase in the abundance of water vapor in the stratosphere (plausibly by as much as ∼1 part per million by vol.). This would cause stratospheric cooling, enhancement of the heterogeneous chem. that destroys ozone, an increase in noctilucent clouds, and changes in tropospheric chem. and atm.-biosphere interactions.
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Jacobson, M. Z.; Colella, W. G.; Golden, D. M. Cleaning the Air and Improving Health with Hydrogen Fuel-Cell Vehicles. Science 2005, 308 (5730), 1901– 1905, DOI: 10.1126/science.1109157
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Cleaning the Air and Improving Health with Hydrogen Fuel-Cell Vehicles
Jacobson, M. Z.; Colella, W. G.; Golden, D. M.
Science (Washington, DC, United States) (2005), 308 (5730), 1901-1905CODEN: SCIEAS; ISSN:0036-8075. (American Association for the Advancement of Science)
A review. Converting all U.S. onroad vehicles to hydrogen fuel-cell vehicles (HFCVs) may improve air quality, health, and climate significantly, whether the hydrogen is produced by steam reforming of natural gas, wind electrolysis, or coal gasification. Most benefits would result from eliminating current vehicle exhaust. Wind and natural gas HFCVs offer the greatest potential health benefits and could save 3700 to 6400 U.S. lives annually. Wind HFCVs should benefit climate most. An all-HFCV fleet would hardly affect tropospheric water vapor concns. Conversion to coal HFCVs may improve health but would damage climate more than fossil/elec. hybrids. The real cost of hydrogen from wind electrolysis may be below that of U.S. gasoline.
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Jacobson, M. Z. Effects of Wind-powered Hydrogen Fuel Cell Vehicles on Stratospheric Ozone and Global Climate. Geophys. Res. Lett. 2008, 35 (19), L19803 DOI: 10.1029/2008GL035102
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Effects of wind-powered hydrogen fuel cell vehicles on stratospheric ozone and global climate
Jacobson, Mark Z.
Geophysical Research Letters (2008), 35 (19), L19803/1-L19803/5CODEN: GPRLAJ; ISSN:0094-8276. (American Geophysical Union)
A review. Converting the world's fossil-fuel onroad vehicles (FFOV) to hydrogen fuel cell vehicles (HFCV), where the H2 is produced by wind-powered electrolysis, is estd. to reduce global fossil, biofuel, and biomass-burning emissions of CO2 by ∼13.4%, NOx ∼23.0%, nonmethane org. gases ∼18.9%, black carbon ∼8% H2 ∼3.2% (at 3% leakage), and H2O ∼0.2%. Over 10 years, such redns. were calcd. to reduce tropospheric CO ∼5%, NOx ∼5-13%, most org. gases ∼3-15%, OH ∼4%, ozone ∼6%, and PAN ∼13%, but to increase tropospheric CH4 ∼0.25% due to the lower OH. Lower OH also increased upper tropospheric/lower stratospheric ozone, increasing its global column by ∼0.41%. WHFCV cooled the troposphere and warmed the stratosphere, reduced aerosol and cloud surface areas, and increased pptn. Other renewable-powered HFCV or battery elec. vehicles should have similar impacts.
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van Ruijven, B.; Lamarque, J.-F.; van Vuuren, D. P.; Kram, T.; Eerens, H. Emission Scenarios for a Global Hydrogen Economy and the Consequences for Global Air Pollution. Global Environ. Change 2011, 21 (3), 983– 994, DOI: 10.1016/j.gloenvcha.2011.03.013
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Bond, S. W.; Gül, T.; Reimann, S.; Buchmann, B.; Wokaun, A. Emissions of Anthropogenic Hydrogen to the Atmosphere during the Potential Transition to an Increasingly H2-Intensive Economy. Int. J. Hydrogen Energ 2011, 36 (1), 1122– 1135, DOI: 10.1016/j.ijhydene.2010.10.016
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Emissions of anthropogenic hydrogen to the atmosphere during the potential transition to an increasingly H2-intensive economy
Bond, S. W.; Guel, T.; Reimann, S.; Buchmann, B.; Wokaun, A.
International Journal of Hydrogen Energy (2011), 36 (1), 1122-1135CODEN: IJHEDX; ISSN:0360-3199. (Elsevier Ltd.)
Current and future anthropogenic atm. H2 emissions from technol. processes were assessed. Current emissions are dominated by direct exhaust gas of road-based motor vehicles and losses during industrial H2 prodn. from fossil fuels. H2 emissions from transportation were estd. to be 4.5 Tg for 2010. An addnl. ∼0.5-2 Tg H2 were estd. to be lost to the atm. from industrial processes in 2010. In 2020, emissions from transportation are estd. to be ∼50% of those in 2010. Future emissions will occur as losses along the entire prodn., distribution, and end-use chain, including emissions from H2 fuel cell vehicles (FCV). In 2050, overall anthropogenic H2 emissions will only approach current levels at high-end loss rates; direct emissions from transportation are expected to be significantly lower than current levels. In 2100, an av. 0.5% loss rate would result in overall H2 emissions exceeding current levels, even with no net H2 emissions from FCV; however, based on an av. 0.1% loss rate, H2 emission factors from FCV on the order of 120-170 mg/km are projected to result in overall anthropogenic H2 emissions similar to 2010 levels.
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Bertagni, M. B.; Socolow, R. H.; Martirez, J. M. P.; Carter, E. A.; Greig, C.; Ju, Y.; Lieuwen, T.; Mueller, M. E.; Sundaresan, S.; Wang, R.; Zondlo, M. A.; Porporato, A. Minimizing the Impacts of the Ammonia Economy on the Nitrogen Cycle and Climate. Proc. Natl. Acad. Sci. United States Am. 2023, 120 (46), e2311728120 DOI: 10.1073/pnas.2311728120
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Wolfram, P.; Kyle, P.; Zhang, X.; Gkantonas, S.; Smith, S. Using Ammonia as a Shipping Fuel Could Disturb the Nitrogen Cycle. Nat. Energy 2022, 7 (12), 1112– 1114, DOI: 10.1038/s41560-022-01124-4
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Using ammonia as a shipping fuel could disturb the nitrogen cycle
Wolfram, Paul; Kyle, Page; Zhang, Xin; Gkantonas, Savvas; Smith, Steven
Nature Energy (2022), 7 (12), 1112-1114CODEN: NEANFD; ISSN:2058-7546. (Nature Portfolio)
A polemic in response to Paul Wolfram et al is given. Ammonia has been proposed as a shipping fuel, yet potential adverse side-effects are poorly understood. We argue that if nitrogen releases from ammonia are not tightly controlled, the scale of the demands of maritime transport are such that the global nitrogen cycle could be substantially altered.
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Ueckerdt, F.; Bauer, C.; Dirnaichner, A.; Everall, J.; Sacchi, R.; Luderer, G. Potential and Risks of Hydrogen-Based e-Fuels in Climate Change Mitigation. Nat. Clim Change 2021, 11 (5), 384– 393, DOI: 10.1038/s41558-021-01032-7
54
Potential and risks of hydrogen-based e-fuels in climate change mitigation
Ueckerdt, Falko; Bauer, Christian; Dirnaichner, Alois; Everall, Jordan; Sacchi, Romain; Luderer, Gunnar
Nature Climate Change (2021), 11 (5), 384-393CODEN: NCCACZ; ISSN:1758-6798. (Nature Portfolio)
Abstr.: E-fuels promise to replace fossil fuels with renewable electricity without the demand-side transformations required for a direct electrification. However, e-fuels' versatility is counterbalanced by their fragile climate effectiveness, high costs and uncertain availability. E-fuel mitigation costs are euro800-1,200 per tCO2. Large-scale deployment could reduce costs to euro20-270 per tCO2 until 2050, yet it is unlikely that e-fuels will become cheap and abundant early enough. Neglecting demand-side transformations threatens to lock in a fossil-fuel dependency if e-fuels fall short of expectations. Sensible climate policy supports e-fuel deployment while hedging against the risk of their unavailability at large scale. Policies should be guided by a 'merit order of end uses' that prioritizes hydrogen and e-fuels for sectors that are inaccessible to direct electrification.
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Gudmundsson, O.; Thorsen, J. E. Source-to-Sink Efficiency of Blue and Green District Heating and Hydrogen-Based Heat Supply Systems. Smart Energy 2022, 6, 100071 DOI: 10.1016/j.segy.2022.100071
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Source-to-sink efficiency of blue and green district heating and hydrogen-based heat supply systems
Gudmundsson, Oddgeir; Thorsen, Jan Eric
Smart Energy (2022), 6 (), 100071CODEN: SEMNBM; ISSN:2666-9552. (Elsevier Ltd.)
Hydrogen is commonly mentioned as a future proof energy carrier. Hydrogen supporters advocate for repurposing existing natural gas grids for a sustainable hydrogen supply. While the long-term vision of the hydrogen community is green hydrogen the community acknowledges that in the short term it will be to large extent manufd. from natural gas, but in a decarbonized way, giving it the name blue hydrogen. While hydrogen has a role to play in hard to decarbonize sectors its role for building heating demands is doubtful, as mature and more energy efficient alternatives exist. As building heat supply infrastructures built today will operate for the decades to come it is of highest importance to ensure that the most efficient and sustainable infrastructures are chosen. This paper compares the source to sink efficiencies of hydrogen-based heat supply system to a district heating system operating on the same primary energy source. The results show that a natural gas-based district heating could be 267% more efficient, and consequently have significantly lower global warming potential, than a blue hydrogen-based heat supply A renewable power-based district heating could achieve above 440% higher efficiency than green hydrogen-based heat supply system.
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de Kleijne, K.; de Coninck, H.; van Zelm, R.; Huijbregts, M. A. J.; Hanssen, S. V. The Many Greenhouse Gas Footprints of Green Hydrogen. Sustainable Energy Fuels 2022, 6, 4383– 4387, DOI: 10.1039/D2SE00444E
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The many greenhouse gas footprints of green hydrogen
de Kleijne, Kiane; de Coninck, Heleen; van Zelm, Rosalie; Huijbregts, Mark A. J.; Hanssen, Steef V.
Sustainable Energy & Fuels (2022), 6 (19), 4383-4387CODEN: SEFUA7; ISSN:2398-4902. (Royal Society of Chemistry)
Green hydrogen could contribute to climate change mitigation, but its greenhouse gas footprint varies with electricity source and allocation choices. Using life-cycle assessment we conclude that if electricity comes from addnl. renewable capacity, green hydrogen outperforms fossil-based hydrogen. In the short run, alternative uses of renewable electricity likely achieve greater emission redns.
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Pototschnig, A. Renewable Hydrogen and the “Additionality” Requirement: Why Making It More Complex than Is Needed?. European University Institute 2021, 1– 6, DOI: 10.2870/201657
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Ocko, I. B.; Hamburg, S. P.; Jacob, D. J.; Keith, D. W.; Keohane, N. O.; Oppenheimer, M.; Roy-Mayhew, J. D.; Schrag, D. P.; Pacala, S. W. Unmask Temporal Trade-Offs in Climate Policy Debates. Science 2017, 356 (6337), 492– 493, DOI: 10.1126/science.aaj2350
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Unmask temporal trade-offs in climate policy debates
Ocko, Ilissa B.; Hamburg, Steven P.; Jacob, Daniel J.; Keith, David W.; Keohabne, Nathaniel O.; Oppenheimer, Michael; Roy-Mayhew, Joseph D.; Schrag, Daniel P.; Pacala, Stephen W.
Science (Washington, DC, United States) (2017), 356 (6337), 492-493CODEN: SCIEAS; ISSN:0036-8075. (American Association for the Advancement of Science)
There is no expanded citation for this reference.
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Deng, H.; Bielicki, J. M.; Oppenheimer, M.; Fitts, J. P.; Peters, C. A. Leakage Risks of Geologic CO2 Storage and the Impacts on the Global Energy System and Climate Change Mitigation. Clim. Chang. 2017, 144 (2), 151– 163, DOI: 10.1007/s10584-017-2035-8
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Leakage risks of geologic CO2 storage and the impacts on the global energy system and climate change mitigation
Deng, Hang; Bielicki, Jeffrey M.; Oppenheimer, Michael; Fitts, Jeffrey P.; Peters, Catherine A.
Climatic Change (2017), 144 (2), 151-163CODEN: CLCHDX; ISSN:0165-0009. (Springer)
This study investigated how subsurface and atm. leakage from geol. CO2 storage reservoirs could impact the deployment of Carbon Capture and Storage (CCS) in the global energy system. The Leakage Risk Monetization Model was used to est. the costs of leakage for representative CO2 injection scenarios, and these costs were incorporated into the Global Change Assessment Model. Worst-case scenarios of CO2 leakage risk, which assume that all leakage pathway permeabilities are extremely high, were simulated. Even with this extreme assumption, the assocd. costs of monitoring, treatment, containment, and remediation resulted in minor shifts in the global energy system. For example, the redn. in CCS deployment in the electricity sector was 3% for the "high" leakage scenario, with replacement coming from fossil fuel and biomass without CCS, nuclear power, and renewable energy. In other words, the impact on CCS deployment under a realistic leakage scenario is likely to be negligible. We also quantified how the resulting shifts will impact atm. CO2 concns. Under a carbon tax that achieves an atm. CO2 concn. of 480 ppm in 2100, technol. shifts due to leakage costs would increase this concn. by less than 5 ppm. It is important to emphasize that this increase does not result from leaked CO2 that reaches the land surface, which is minimal due to secondary trapping in geol. strata above the storage reservoir. The overall conclusion is that leakage risks and assocd. costs will likely not interfere with the effectiveness of policies for climate change mitigation.
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Vinca, A.; Emmerling, J.; Tavoni, M. Bearing the Cost of Stored Carbon Leakage. Front. Energy Res. 2018, 6, 40, DOI: 10.3389/fenrg.2018.00040
Abstract
Figure 1
Figure 1. Overview of the life cycle climate impacts of eight hydrogen pathways relative to their fossil fuel alternatives in 2050 considering a range of hydrogen emission rates (1–10%) and methane emission intensities (from extremely low, 0.01%, to extremely high, 5.4%). Each vertical bar represents the range of climate benefits (or disbenefits) by switching to hydrogen from fossil fuels for the best-case scenario (1% hydrogen emissions and a low methane emission intensity of 0.6%) to the worst-case scenario (10% hydrogen emissions and a high methane emissions intensity of 2.1%). Near-term (NT, 20 years) and long-term (LT, 100 years) climate impacts are presented for each pathway. The originally reported climate impacts of these pathways in Hydrogen Council report (2021) are denoted as black triangles. The climate impact of the battery electric alternative for the light-duty vehicle pathway is noted with the letter E.
Figure 2
Figure 2. Life cycle climate impacts of four blue hydrogen pathways relative to their fossil fuel alternatives in 2050 considering a range of 1–10% hydrogen emission rates and medium, 0.9%, methane emission intensity, presented as (a–d) the percentage change in cumulative radiative forcing from continuous emissions over 10, 20, 50, and 100 years after the technology switch and (e–l) annual emissions per function unit (kilometer or kilowatt hour) in CO2e on 20- and 100-year time horizons. Values in panels a–d range from 1% hydrogen emissions (bottom of the bars) to 10% hydrogen emissions (top of the bars). Error bars indicate the uncertainties associated with hydrogen’s radiative efficiency and lifetime. The climate impact of battery electric vehicle relative to fossil fuel is shown as purple horizontal lines in panel a for comparison with blue hydrogen. Percentage changes derived from panels e–l, which are emissions based on the GWP-20 and GWP-100 metrics, are also denoted as “x” (high H2 emissions) and “Δ” (low H2 emissions) in panels a–d. Note that in the case of blue hydrogen, high hydrogen emissions also lead to a small amount of additional methane emissions from increased natural gas use to make up for lost hydrogen (see the Supporting Information for more information).
Figure 3
Figure 3. Life cycle climate impacts of four blue hydrogen pathways relative to their fossil fuel alternatives in 2050 considering a range of hydrogen emission rates of 1–10% (heights of the bars) and three levels of methane emission intensities (different colored bars), presented as the percentage change in cumulative radiative forcing from continuous emissions over 10, 20, 50, and 100 years after the technology switch. The error bars indicate the uncertainties associated with hydrogen’s radiative efficiency and lifetime.
Figure 4
Figure 4. Life cycle climate impacts of four green hydrogen pathways relative to their fossil fuel alternatives in 2050 considering a range of hydrogen emission rates of 1–10%, presented as (a–d) the percentage change in cumulative radiative forcing from continuous emissions over 10, 20, 50, and 100 years after the technology switch and (e–l) annual emissions per function unit (kilometer or kilogram of product) in CO2e on 20- and 100-year time horizons. Values in panels a–d range from 1% hydrogen emissions (bottoms of bars) to 10% hydrogen emissions (tops of bars). The error bars indicate the uncertainties associated with hydrogen’s radiative efficiency and lifetime. Percentage changes derived from panels e–l, which are emissions based on the GWP-20 and GWP-100 metrics, are also denoted as “x” (high H2 emissions) and “Δ” (low H2 emissions) in panels a–d. Note there is a small amount of methane emissions associated with the green hydrogen pathways due to the inclusion of manufacturing emissions associated with the end use equipment.
Figure 5
Figure 5. Life cycle climate impacts of a green hydrogen fuel cell bus relative to the diesel alternative in 2030 considering a range of hydrogen emission rates of 1–10% and different power supply assumptions (dashed lines), presented as annual emissions per kilometer of vehicle operation in CO2e on 20- and 100-year time horizons. The emission factors of the electricity grid mix in 2030 follow the 1.5 °C-compatible pathway projection by the International Renewable Energy Agency (IRENA). (49) The emission factors of natural gas- and coal-fired power plant are also taken from IRENA. Similar analyses are conducted for the other three green hydrogen pathways and shown in Figure S3.
This article references 63 other publications.
Valente, A.; Iribarren, D.; Dufour, J. Life Cycle Assessment of Hydrogen Energy Systems: A Review of Methodological Choices. Int. J. Life Cycle Assess. 2017, 22 (3), 346– 363, DOI: 10.1007/s11367-016-1156-z
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Life cycle assessment of hydrogen energy systems: a review of methodological choices
Valente, Antonio; Iribarren, Diego; Dufour, Javier
International Journal of Life Cycle Assessment (2017), 22 (3), 346-363CODEN: IJLCFF; ISSN:0948-3349. (Springer)
Purpose: As a first step towards a consistent framework for both individual and comparative life cycle assessment (LCA) of hydrogen energy systems, this work performs a thorough literature review on the methodol. choices made in LCA studies of these energy systems. Choices affecting the LCA stages "goal and scope definition", "life cycle inventory anal." (LCI) and "life cycle impact assessment" (LCIA) are targeted. Methods: This review considers 97 scientific papers published until Dec. 2015, in which 509 original case studies of hydrogen energy systems are found. Based on the hydrogen prodn. process, these case studies are classified into three technol. categories: thermochem., electrochem. and biol. A subdivision based on the scope of the studies is also applied, thus distinguishing case studies addressing hydrogen prodn. only, hydrogen prodn. and use in mobility and hydrogen prodn. and use for power generation. Results and discussion: Most of the hydrogen energy systems apply cradle/gate-to-gate boundaries, while cradle/gate-to-grave boundaries are found mainly for hydrogen use in mobility. The functional unit is usually mass- or energy-based for cradle/gate-to-gate studies and travelled distance for cradle/gate-to-grave studies. Multifunctionality is addressed mainly through system expansion and, to a lesser extent, phys. allocation. Regarding LCI, scientific literature and life cycle databases are the main data sources for both background and foreground processes. Regarding LCIA, the most common impact categories evaluated are global warming and energy consumption through the IPCC and VDI methods, resp. The remaining indicators are often evaluated using the CML family methods. The level of agreement of these trends with the available FC-HyGuide guidelines for LCA of hydrogen energy systems depends on the specific methodol. aspect considered. Conclusions: This review on LCA of hydrogen energy systems succeeded in finding relevant trends in methodol. choices, esp. regarding the frequent use of system expansion and secondary data under prodn.-oriented attributional approaches. These trends are expected to facilitate methodol. decision making in future LCA studies of hydrogen energy systems. Furthermore, this review may provide a basis for the definition of a methodol. framework to harmonise the LCA results of hydrogen available so far in the literature.
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Rinawati, D. I.; Keeley, A. R.; Takeda, S.; Managi, S. A Systematic Review of Life Cycle Assessment of Hydrogen for Road Transport Use. Prog. Energy 2022, 4 (1), 012001 DOI: 10.1088/2516-1083/ac34e9
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Rinawati, D. I.; Keeley, A. R.; Takeda, S.; Managi, S. Life-Cycle Assessment of Hydrogen Utilization in Power Generation: A Systematic Review of Technological and Methodological Choices. Front. Sustain. 2022, 3, 920876 DOI: 10.3389/frsus.2022.920876
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Bhandari, R.; Trudewind, C. A.; Zapp, P. Life Cycle Assessment of Hydrogen Production via Electrolysis – a Review. J. Clean. Prod. 2014, 85, 151– 163, DOI: 10.1016/j.jclepro.2013.07.048
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Cetinkaya, E.; Dincer, I.; Naterer, G. F. Life Cycle Assessment of Various Hydrogen Production Methods. Int. J. Hydrogen Energ 2012, 37 (3), 2071– 2080, DOI: 10.1016/j.ijhydene.2011.10.064
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Life cycle assessment of various hydrogen production methods
Cetinkaya, E.; Dincer, I.; Naterer, G. F.
International Journal of Hydrogen Energy (2012), 37 (3), 2071-2080CODEN: IJHEDX; ISSN:0360-3199. (Elsevier Ltd.)
A comprehensive life cycle assessment (LCA) is reported for five methods of hydrogen prodn., namely steam reforming of natural gas, coal gasification, water electrolysis via wind and solar electrolysis, and thermochem. water splitting with a Cu-Cl cycle. Carbon dioxide equiv. emissions and energy equiv. of each method are quantified and compared. A case study is presented for a hydrogen fueling station in Toronto, Canada, and nearby hydrogen resources close to the fueling station. In terms of carbon dioxide equiv. emissions, thermochem. water splitting with the Cu-Cl cycle is found to be advantageous over the other methods, followed by wind and solar electrolysis. In terms of hydrogen prodn. capacities, natural gas steam reforming, coal gasification and thermochem. water splitting with the Cu-Cl cycle methods are found to be advantageous over the renewable energy methods.
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Lee, D.-Y.; Elgowainy, A.; Kotz, A.; Vijayagopal, R.; Marcinkoski, J. Life-Cycle Implications of Hydrogen Fuel Cell Electric Vehicle Technology for Medium- and Heavy-Duty Trucks. J. Power Sources 2018, 393, 217– 229, DOI: 10.1016/j.jpowsour.2018.05.012
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Life-cycle implications of hydrogen fuel cell electric vehicle technology for medium- and heavy-duty trucks
Lee, Dong-Yeon; Elgowainy, Amgad; Kotz, Andrew; Vijayagopal, Ram; Marcinkoski, Jason
Journal of Power Sources (2018), 393 (), 217-229CODEN: JPSODZ; ISSN:0378-7753. (Elsevier B.V.)
This study provides a comprehensive and up-to-date life-cycle comparison of hydrogen fuel cell elec. trucks (FCETs) and their conventional diesel counterparts in terms of energy use and air emissions, based on the ensemble of well-established methods, high-fidelity vehicle dynamic simulations, and real-world vehicle test data. For the centralized steam methane reforming (SMR) pathway, hydrogen FCETs reduce life-cycle or well-to-wheel (WTW) petroleum energy use by more than 98% compared to their diesel counterparts. The redn. in WTW air emissions for gaseous hydrogen (G.H2) FCETs ranges from 20 to 45% for greenhouse gases, 37-65% for VOC, 49-77% for CO, 62-83% for NOx, 19-43% for PM10, and 27-44% for PM2.5, depending on vehicle wt. classes and truck types. With the current U. S. av. electricity generation mix, FCETs tend to create more WTW SOx emissions than their diesel counterparts, mainly because of the upstream emissions related to electricity use for hydrogen compression/liquefaction. Compared to G. H2, liq. hydrogen (L.H2) FCETs generally provide smaller WTW emissions redns. For both G.H2 and L. H2 pathways for FCETs, because of electricity consumption for compression and liquefaction, spatio-temporal variations of electricity generation can affect the WTW results. FCETs retain the WTW emission redn. benefits, even when considering aggressive diesel engine efficiency improvement.
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Frank, E. D.; Elgowainy, A.; Reddi, K.; Bafana, A. Life-Cycle Analysis of Greenhouse Gas Emissions from Hydrogen Delivery: A Cost-Guided Analysis. Int. J. Hydrogen Energ 2021, 46 (43), 22670– 22683, DOI: 10.1016/j.ijhydene.2021.04.078
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Life-cycle analysis of greenhouse gas emissions from hydrogen delivery: A cost-guided analysis
Frank, Edward D.; Elgowainy, Amgad; Reddi, Krishna; Bafana, Adarsh
International Journal of Hydrogen Energy (2021), 46 (43), 22670-22683CODEN: IJHEDX; ISSN:0360-3199. (Elsevier Ltd.)
The cost of hydrogen delivery for transportation accounts for most of the current H2 selling price; delivery also requires substantial amts. of energy. We developed harmonized techno-economic and life-cycle emissions models of current and future H2 prodn. and delivery pathways. Our techno-economic anal. of dispensed H2 costs guided our selection of pathways for the life-cycle anal. In this paper, we present the results of market expansion scenarios using existing capabilities (for example, those that use H2 from steam methane reforming, chlor-alkali, and natural gas liq. cracker plants), as well as results for future electrolysis plants that use nuclear, solar, and hydroelec. power. Redns. in greenhouse gas emissions for fuel cell elec. vehicles compared to conventional gasoline pathways vary from 40% redn. for fossil-derived H2 to 20-fold for clean H2. Supplemental tables with greenhouse gas emissions data for each step in the H2 pathways enable readers to evaluate addnl. scenarios.
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Paulot, F.; Paynter, D.; Naik, V.; Malyshev, S.; Menzel, R.; Horowitz, L. W. Global Modeling of Hydrogen Using GFDL-AM4.1: Sensitivity of Soil Removal and Radiative Forcing. Int. J. Hydrogen Energ 2021, 46 (24), 13446– 13460, DOI: 10.1016/j.ijhydene.2021.01.088
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Global modeling of hydrogen using GFDL-AM4.1: Sensitivity of soil removal and radiative forcing
Paulot, Fabien; Paynter, David; Naik, Vaishali; Malyshev, Sergey; Menzel, Raymond; Horowitz, Larry W.
International Journal of Hydrogen Energy (2021), 46 (24), 13446-13460CODEN: IJHEDX; ISSN:0360-3199. (Elsevier Ltd.)
Hydrogen (H2) was proposed as an alternative energy carrier to reduce the carbon footprint and assocd. radiative forcing of the current energy system. Here, we describe the representation of H2 in the GFDL-AM4.1 model including updated emission inventories and improved representation of H2 soil removal, the dominant sink of H2. The model best captures the overall distribution of surface H2, including regional contrasts between climate zones, when vd(H2) is modulated by soil moisture, temp., and soil carbon content. We est. that the soil removal of H2 increases with warming (2-4% per K), with large uncertainties stemming from different regional response of soil moisture and soil carbon. We est. that H2 causes an indirect radiative forcing of 0.84 mW m-2/(Tg(H2)yr-1) or 0.13 mW m-2 ppbv-1, primarily due to increasing CH4 lifetime and stratospheric water vapor prodn.
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Warwick, N. J.; Archibald, A. T.; Griffiths, P. T.; Keeble, J.; O’Connor, F. M.; Pyle, J. A.; Shine, K. P. Atmospheric Composition and Climate Impacts of a Future Hydrogen Economy. Atmos. Chem. Phys. 2023, 23 (20), 13451– 13467, DOI: 10.5194/acp-23-13451-2023
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Atmospheric composition and climate impacts of a future hydrogen economy
Warwick, Nicola J.; Archibald, Alex T.; Griffiths, Paul T.; Keeble, James; O'Connor, Fiona M.; Pyle, John A.; Shine, Keith P.
Atmospheric Chemistry and Physics (2023), 23 (20), 13451-13467CODEN: ACPTCE; ISSN:1680-7324. (Copernicus Publications)
Hydrogen is expected to play a key role in the global energy transition to net zero emissions in many scenarios. However, fugitive emissions of hydrogen into the atm. during its prodn., storage, distribution and use could reduce the climate benefit and also have implications for air quality. Here, we explore the atm. compn. and climate impacts of increases in atm. hydrogen abundance using the UK Earth System Model (UKESM1) chem.-climate model. Increases in hydrogen result in increases in methane, tropospheric ozone and stratospheric water vapor, resulting in a pos. radiative forcing. However, some of the impacts of hydrogen leakage are partially offset by potential redns. in emissions of methane, carbon monoxide, nitrogen oxides and volatile org. compds. from the consumption of fossil fuels. We derive a refined methodol. for detg. indirect global warming potentials (GWPs) from parameters derived from steady-state simulations, which is applicable to both shorter-lived species and those with intermediate and longer lifetimes, such as hydrogen. Using this methodol., we det. a 100-yr global warming potential for hydrogen of 12 ± 6. Based on this GWP and hydrogen leakage rates of 1% and 10%, we find that hydrogen leakage offsets approx. 0.4% and 4% resp. of total equiv. CO2 emission redns. in our global hydrogen economy scenario. To maximise the benefit of hydrogen as an energy source, emissions assocd. with hydrogen leakage and emissions of the ozone precursor gases need to be minimised.
https://chemport.cas.org/services/resolver?origin=ACS&resolution=options&coi=1%3ACAS%3A528%3ADC%252BB3sXisVaru7rN&md5=a6a9757216e4ee8bc7a2a2f4147da356
Hauglustaine, D.; Paulot, F.; Collins, W.; Derwent, R.; Sand, M.; Boucher, O. Climate Benefit of a Future Hydrogen Economy. Commun. Earth Environ 2022, 3 (1), 295, DOI: 10.1038/s43247-022-00626-z
There is no corresponding record for this reference.
Sand, M.; Skeie, R. B.; Sandstad, M.; Krishnan, S.; Myhre, G.; Bryant, H.; Derwent, R.; Hauglustaine, D.; Paulot, F.; Prather, M.; Stevenson, D. A Multi-Model Assessment of the Global Warming Potential of Hydrogen. Commun. Earth Environ. 2023, 4 (1), 203, DOI: 10.1038/s43247-023-00857-8
There is no corresponding record for this reference.
Hauglustaine, D. A.; Ehhalt, D. H. A Three-dimensional Model of Molecular Hydrogen in the Troposphere. J. Geophys. Res.: Atmos. 2002, 107 (D17), ACH 4-1– ACH 4-16, DOI: 10.1029/2001JD001156
There is no corresponding record for this reference.
Field, R. A.; Derwent, R. G. Global Warming Consequences of Replacing Natural Gas with Hydrogen in the Domestic Energy Sectors of Future Low-Carbon Economies in the United Kingdom and the United States of America. Int. J. Hydrogen Energ 2021, 46 (58), 30190– 30203, DOI: 10.1016/j.ijhydene.2021.06.120
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Global warming consequences of replacing natural gas with hydrogen in the domestic energy sectors of future low-carbon economies in the United Kingdom and the United States of America
Field, R. A.; Derwent, R. G.
International Journal of Hydrogen Energy (2021), 46 (58), 30190-30203CODEN: IJHEDX; ISSN:0360-3199. (Elsevier Ltd.)
Hydrogen has a potentially important future role as a replacement for natural gas in the domestic sector in a zero-carbon economy for heating homes and cooking. To assess this potential, an understanding is required of the global warming potentials (GWPs) of methane and hydrogen and of the leakage rates of the natural gas distribution system and that of a hydrogen system that would replace it. The GWPs of methane and hydrogen were estd. using a global chem.-transport model as 29.2 ± 8 and 3.3 ± 1.4, resp., over a 100-yr time horizon. The current natural gas leakage rates from the distribution system were estd. for the UK by the ethane tracer method to be ∼0.64 Tg CH4/yr (2.3%) and for the US by literature review to be of the order of 0.69-2.9 Tg CH4/yr (0.5-2.1%). On this basis, with the inclusion of carbon dioxide emissions from combustion, replacing natural gas with green hydrogen in the domestic sectors of both countries should reduce substantially the global warming consequences of domestic sector energy use both in the UK and in the US, provided care is taken to reduce hydrogen leakage to a min. A perfectly sealed zero-carbon green hydrogen distribution system would save the entire 76 million tonnes CO2 equivalent per yr in the UK.
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Derwent, R. G.; Stevenson, D. S.; Utembe, S. R.; Jenkin, M. E.; Khan, A. H.; Shallcross, D. E. Global Modelling Studies of Hydrogen and Its Isotopomers Using STOCHEM-CRI: Likely Radiative Forcing Consequences of a Future Hydrogen Economy. Int. J. Hydrogen Energ 2020, 45 (15), 9211– 9221, DOI: 10.1016/j.ijhydene.2020.01.125
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Global modelling studies of hydrogen and its isotopomers using STOCHEM-CRI: Likely radiative forcing consequences of a future hydrogen economy
Derwent, Richard G.; Stevenson, David S.; Utembe, Steven R.; Jenkin, Michael E.; Khan, Anwar H.; Shallcross, Dudley E.
International Journal of Hydrogen Energy (2020), 45 (15), 9211-9221CODEN: IJHEDX; ISSN:0360-3199. (Elsevier Ltd.)
A global chem.-transport model was employed to describe the global sources and sinks of hydrogen (H2) and its isotopomer (HD). The model is able to satisfactorily describe the obsd. tropospheric distributions of H2 and HD and deliver budgets and turnovers which agree with literature studies. We than go on to quantify the methane and ozone responses to emission pulses of hydrogen and their likely radiative forcing consequences. These radiative forcing consequences were expressed on a 1 Tg basis and integrated over a hundred-year time horizon. When compared to the consequences of a 1 Tg emission pulse of carbon dioxide, 1 Tg of hydrogen causes 5 ± 1 times as much time-integrated radiative forcing over a hundred-year time horizon. That is to say, hydrogen has a global warming potential (GWP) of 5 ± 1 over a hundred-year time horizon. The global warming consequences of a hydrogen-based low-carbon energy system therefore depend critically on the hydrogen leakage rate. If the leakage of hydrogen from all stages in the prodn., distribution, storage and utilization of hydrogen is efficiently curtailed, then hydrogen-based energy systems appear to be an attractive proposition in providing a future replacement for fossil-fuel based energy systems.
https://chemport.cas.org/services/resolver?origin=ACS&resolution=options&coi=1%3ACAS%3A528%3ADC%252BB3cXislCisbs%253D&md5=98845e1f6b04fcc55ac633e2d425645c
Derwent, R.; Simmonds, P.; O’Doherty, S.; Manning, A.; Collins, W.; Stevenson, D. Global Environmental Impacts of the Hydrogen Economy. Int. J. Nucl. Hydrogen Prod Appl. 2006, 1 (1), 57, DOI: 10.1504/IJNHPA.2006.009869
There is no corresponding record for this reference.
Derwent, R. G.; Collins, W. J.; Johnson, C. E.; Stevenson, D. S. Transient Behaviour of Tropospheric Ozone Precursors in a Global 3-D CTM and Their Indirect Greenhouse Effects. Climatic Change 2001, 49 (4), 463– 487, DOI: 10.1023/A:1010648913655
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Transient behaviour of tropospheric ozone precursors in a global 3-D CTM and their indirect greenhouse effects
Derwent, R. G.; Collins, W. J.; Johnson, C. E.; Stevenson, D. S.
Climatic Change (2001), 49 (4), 463-487CODEN: CLCHDX; ISSN:0165-0009. (Kluwer Academic Publishers)
The global three-dimensional Lagrangian chem.-transport model STOCHEM has been used to follow the changes in the tropospheric distributions of the two major radiatively-active trace gases, methane and tropospheric ozone, following the emission of pulses of the short-lived tropospheric ozone precursor species, methane, carbon monoxide, NOx and hydrogen. The radiative impacts of NOx emissions were dependent on the location chosen for the emission pulse, whether at the surface or in the upper troposphere or whether in the northern or southern hemispheres. Global warming potentials were derived for each of the short-lived tropospheric ozone precursor species by integrating the methane and tropospheric ozone responses over a 100-yr time horizon. Indirect radiative forcing due to methane and tropospheric ozone changes appear to be significant for all of the tropospheric ozone precursor species studied. Whereas the radiative forcing from methane changes is likely to be dominated by methane emissions, that from tropospheric ozone changes is controlled by all the tropospheric ozone precursor gases, particularly NOx emissions. The indirect radiative forcing impacts of tropospheric ozone changes may be large enough such that ozone precursors should be considered in the basket of trace gases through which policy-makers aim to combat global climate change.
https://chemport.cas.org/services/resolver?origin=ACS&resolution=options&coi=1%3ACAS%3A528%3ADC%252BD3MXks1KqsrY%253D&md5=9e198162fdbb77f5fbac0f59b89f7c7a
Prather, M. J. An Environmental Experiment with H2?. Science 2003, 302 (5645), 581– 582, DOI: 10.1126/science.1091060
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Atmospheric science: An environmental experiment with H2?
Prather, Michael J.
Science (Washington, DC, United States) (2003), 302 (5645), 581-582CODEN: SCIEAS; ISSN:0036-8075. (American Association for the Advancement of Science)
A review of the environmental consequences of a H2 fuel economy, including leaks that would cause large increases in atm. H2, affecting stratospheric water vapor, temp. and O3; natural and anthropogenic sources of H2; atm. and soil sinks of H2; indirect greenhouse gas effects; indirect increases of CH4; and NOx redns.
https://chemport.cas.org/services/resolver?origin=ACS&resolution=options&coi=1%3ACAS%3A528%3ADC%252BD3sXosVOmsrY%253D&md5=1d8cd5fadf37e7a24e3c0d7d06325ffe
Schultz, M. G.; Diehl, T.; Brasseur, G. P.; Zittel, W. Air Pollution and Climate-Forcing Impacts of a Global Hydrogen Economy. Science 2003, 302 (5645), 624– 627, DOI: 10.1126/science.1089527
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Air pollution and climate-forcing impacts of a global hydrogen economy
Schultz, Martin G.; Diehl, Thomas; Brasseur, Guy P.; Zittel, Werner
Science (Washington, DC, United States) (2003), 302 (5645), 624-627CODEN: SCIEAS; ISSN:0036-8075. (American Association for the Advancement of Science)
If today's surface traffic fleet were powered entirely by H fuel cell technol., anthropogenic emissions of the ozone precursors NOx and CO could be reduced by ≤50%, leading to significant improvements in air quality throughout the Northern Hemisphere. Model simulations of such a scenario predict a decrease in global OH and an increased lifetime of CH4, caused primarily by the redn. of the NOx emissions. The sign of the change in climate forcing caused by CO2 and CH4 depends on the technol. used to generate the H2. A possible rise in atm. H concns. is unlikely to cause significant perturbations of the climate system.
https://chemport.cas.org/services/resolver?origin=ACS&resolution=options&coi=1%3ACAS%3A528%3ADC%252BD3sXotlWqt7w%253D&md5=ff58cd50004918295f54e659d490f8db
Warwick, N. J.; Bekki, S.; Nisbet, E. G.; Pyle, J. A. Impact of a Hydrogen Economy on the Stratosphere and Troposphere Studied in a 2-D Model. Geophys. Res. Lett. 2004, 31 (5), L05107 DOI: 10.1029/2003GL019224
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Impact of a hydrogen economy on the stratosphere and troposphere studied in a 2-D model
Warwick, N. J.; Bekki, S.; Nisbet, E. G.; Pyle, J. A.
Geophysical Research Letters (2004), 31 (5), L05107/1-L05107/4CODEN: GPRLAJ; ISSN:0094-8276. (American Geophysical Union)
A switch from a fossil fuel to a hydrogen-based energy system could cause significant changes in the magnitude and compn. of anthropogenic emissions. Model simulations suggest the most significant impact of these emission changes would occur in the troposphere, affecting OH. This impact is dependent upon the magnitude and nature of trade-offs in changing fossil fuel use. In the stratosphere, changes in water vapor resulting from expected increases in surface mol. hydrogen emissions via leaks occurring during prodn., transport, and storage, are found to be significantly smaller than previous ests. We conclude that the expected increase in mol. hydrogen emissions is unlikely to have a substantial impact on stratospheric ozone, certainly much smaller than the ozone changes obsd. in the last two decades.
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Colella, W. G.; Jacobson, M. Z.; Golden, D. M. Switching to a U.S. Hydrogen Fuel Cell Vehicle Fleet: The Resultant Change in Emissions, Energy Use, and Greenhouse Gases. J. Power Sources 2005, 150, 150– 181, DOI: 10.1016/j.jpowsour.2005.05.092
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Switching to a U.S. hydrogen fuel cell vehicle fleet: The resultant change in emissions, energy use, and greenhouse gases
Colella, W. G.; Jacobson, M. Z.; Golden, D. M.
Journal of Power Sources (2005), 150 (), 150-181CODEN: JPSODZ; ISSN:0378-7753. (Elsevier B.V.)
This study examines the potential change in primary emissions and energy use as a result of replacing the current U.S. fleet of fossil-fuel on-road vehicles (FFOV) with hybrid elec. fossil fuel vehicles or hydrogen fuel cell vehicles (HFCV). Emissions and energy usage are analyzed for three different HFCV scenarios, with hydrogen produced by (a) steam reforming of natural gas, (b) electrolysis powered by wind energy, and (c) coal gasification. With the U.S. EPA National Emission Inventory as the baseline, other emission inventories are created using a life cycle assessment of alternative fuel supply chains. For a range of reasonable HFCV efficiencies and methods of producing hydrogen, we find that the replacement of FFOV with HFCV significantly reduces emission assocd. with air pollution, compared even with a switch to hybrids. All HFCV scenarios decrease net air pollution emission, including nitrogen oxides, volatile org. compds., particulate matter, ammonia, and carbon monoxide. These redns. are achieved with hydrogen prodn. from either a fossil fuel source such as natural gas or a renewable source such as wind. Furthermore, replacing FFOV with hybrids or HFCV with hydrogen derived from natural gas, wind or coal may reduce the global warming impact of greenhouse gases and particles (measured in carbon dioxide equiv. emission) by 6, 14, 23, and 1%, resp. Finally, even if HFCV are fueled by a fossil fuel such as natural gas, if no carbon is sequestered during hydrogen prodn., and 1% of methane in the feedstock gas is leaked to the environment, natural gas HFCV still may achieve a significant redn. in greenhouse gas and air pollution emission over FFOV.
https://chemport.cas.org/services/resolver?origin=ACS&resolution=options&coi=1%3ACAS%3A528%3ADC%252BD2MXhtVShtLbE&md5=cd456d14dad18a183a293f78e4e54ff1
Wuebbles, D. J. Evaluation of the Potential Environmental Impacts from Large-Scale Use and Production of Hydrogen in Energy and Transportation Applications. 2008. https://digital.library.unt.edu/ark:/67531/metadc841210/ (last accessed 2024-01-12).
There is no corresponding record for this reference.
Arrigoni, A.; Bravo, D. L. Hydrogen Emissions from a Hydrogen Economy and Their Potential Global Warming Impact. 2022; OP KJ-NA-31-188-EN-N. DOI: 10.2760/065589
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Cooper, J.; Dubey, L.; Bakkaloglu, S.; Hawkes, A. Hydrogen Emissions from the Hydrogen Value Chain-Emissions Profile and Impact to Global Warming. Sci. Total Environ. 2022, 830, 154624 DOI: 10.1016/j.scitotenv.2022.154624
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Hydrogen emissions from the hydrogen value chain-emissions profile and impact to global warming
Cooper, Jasmin; Dubey, Luke; Bakkaloglu, Semra; Hawkes, Adam
Science of the Total Environment (2022), 830 (), 154624CODEN: STENDL; ISSN:0048-9697. (Elsevier B.V.)
Future energy systems could rely on hydrogen (H2) to achieve decarbonisation and net-zero goals. In a similar energy landscape to natural gas, H2 emissions occur along the supply chain. It has been studied how current gas infrastructure can support H2, but there is little known about how H2 emissions affect global warming as an indirect greenhouse gas. In this work, we have estd. for the first time the potential emission profiles (g CO2eq/MJ H2,HHV) of H2 supply chains, and found that the emission rates of H2 from H2 supply chains and methane from natural gas supply are comparable, but the impact on global warming is much lower based on current ests. This study also demonstrates the crit. importance of establishing mobile H2 emission monitoring and reducing the uncertainty of short-lived H2 climate forcing so as to clearly address H2 emissions for net-zero strategies.
https://chemport.cas.org/services/resolver?origin=ACS&resolution=options&coi=1%3ACAS%3A528%3ADC%252BB38XotFOnsLo%253D&md5=bd58067a99a6742196ce967dc802e37c
Fan, Z.; Sheerazi, H.; Bhardwaj, A.; Corbeau, A.-S.; Longobardi, K.; Castañeda, A.; Merz, A.-K.; Woodall, C. M.; Agrawal, M.; Orozco-Sanchez, S.; Friedmann, J. Hydrogen Leakage: A Potential Risk for the Hydrogen Economy; Center on Global Energy Policy. 2022. https://www.energypolicy.columbia.edu/publications/hydrogen-leakage-potential-risk-hydrogen-economy/ (last accessed 2024-01-12).
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Esquivel-Elizondo, S.; Hormaza Mejia, A.; Sun, T.; Shrestha, E.; Hamburg, S. P.; Ocko, I. B. Wide Range in Estimates of Hydrogen Emissions from Infrastructure. Front. Energy Res. 2023, 11, 01– 08, DOI: 10.3389/fenrg.2023.1207208
There is no corresponding record for this reference.
Alvarez, R. A.; Zavala-Araiza, D.; Lyon, D. R.; Allen, D. T.; Barkley, Z. R.; Brandt, A. R.; Davis, K. J.; Herndon, S. C.; Jacob, D. J.; Karion, A.; Kort, E. A.; Lamb, B. K.; Lauvaux, T.; Maasakkers, J. D.; Marchese, A. J.; Omara, M.; Pacala, S. W.; Peischl, J.; Robinson, A. L.; Shepson, P. B.; Sweeney, C.; Townsend-Small, A.; Wofsy, S. C.; Hamburg, S. P. Assessment of Methane Emissions from the U.S. Oil and Gas Supply Chain. Science 2018, 361 (6398), 186– 188, DOI: 10.1126/science.aar7204
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Assessment of methane emissions from the U.S. oil and gas supply chain
Alvarez, Ramon A.; Zavala-Araiza, Daniel; Lyon, David R.; Allen, David T.; Barkley, Zachary R.; Brandt, Adam R.; Davis, Kenneth J.; Herndon, Scott C.; Jacob, Daniel J.; Karion, Anna; Kort, Eric A.; Lamb, Brian K.; Lauvaux, Thomas; Maasakkers, Joannes D.; Marchese, Anthony J.; Omara, Mark; Pacala, Stephen W.; Peischl, Jeff; Robinson, Allen L.; Shepson, Paul B.; Sweeney, Colm; Townsend-Small, Amy; Wofsy, Steven C.; Hamburg, Steven P.
Science (Washington, DC, United States) (2018), 361 (6398), 186-188CODEN: SCIEAS; ISSN:0036-8075. (American Association for the Advancement of Science)
Considerable amts. of the greenhouse gas methane leak from the U.S. oil and natural gas supply chain. Alvarez et al. reassessed the magnitude of this leakage and found that in 2015, supply chain emissions were ∼60% higher than the U.S. Environmental Protection Agency inventory est. They suggest that this discrepancy exists because current inventory methods miss emissions that occur during abnormal operating conditions. These data, and the methodol. used to obtain them, could improve and verify international inventories of greenhouse gases and provide a better understanding of mitigation efforts outlined by the Paris Agreement.
https://chemport.cas.org/services/resolver?origin=ACS&resolution=options&coi=1%3ACAS%3A528%3ADC%252BC1cXhtlahsbjJ&md5=1f2ed89d2780077eb9257501dcc4b3ac
Shen, L.; Gautam, R.; Omara, M.; Zavala-Araiza, D.; Maasakkers, J. D.; Scarpelli, T. R.; Lorente, A.; Lyon, D.; Sheng, J.; Varon, D. J.; Nesser, H.; Qu, Z.; Lu, X.; Sulprizio, M. P.; Hamburg, S. P.; Jacob, D. J. Satellite Quantification of Oil and Natural Gas Methane Emissions in the US and Canada Including Contributions from Individual Basins. Atmos. Chem. Phys. 2022, 22 (17), 11203– 11215, DOI: 10.5194/acp-22-11203-2022
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Satellite quantification of oil and natural gas methane emissions in the US and Canada including contributions from individual basins
Shen, Lu; Gautam, Ritesh; Omara, Mark; Zavala-Araiza, Daniel; Maasakkers, Joannes D.; Scarpelli, Tia R.; Lorente, Alba; Lyon, David; Sheng, Jianxiong; Varon, Daniel J.; Nesser, Hannah; Qu, Zhen; Lu, Xiao; Sulprizio, Melissa P.; Hamburg, Steven P.; Jacob, Daniel J.
Atmospheric Chemistry and Physics (2022), 22 (17), 11203-11215CODEN: ACPTCE; ISSN:1680-7324. (Copernicus Publications)
We use satellite methane observations from the Tropospheric Monitoring Instrument (TROPOMI), for May 2018 to Feb. 2020, to quantify methane emissions from individual oil and natural gas (O/G) basins in the US and Canada using a high-resoln. (∼25 km) atm. inverse anal. Our satellite-derived emission ests. show good consistency with in situ field measurements (R = 0.96) in 14 O/G basins distributed across the US and Canada. Aggregating our results to the national scale, we obtain O/G-related methane emission ests. of 12.6 ± 2.1 Tg a-1 for the US and 2.2 ± 0.6 Tg a-1 for Canada, 80% and 40%, resp., higher than the national inventories reported to the United Nations. About 70% of the discrepancy in the US Environmental Protection Agency (EPA) inventory can be attributed to five O/G basins, the Permian, Haynesville, Anadarko, Eagle Ford, and Barnett basins, which in total account for 40% of US emissions. We show more generally that our TROPOMI inversion framework can quantify methane emissions exceeding 0.2-0.5 Tg a-1 from individual O/G basins, thus providing an effective tool for monitoring methane emissions from large O/G basins globally.
https://chemport.cas.org/services/resolver?origin=ACS&resolution=options&coi=1%3ACAS%3A528%3ADC%252BB38Xitl2msb3L&md5=1e14b4c05a5d6766e9ba6199fd3c12e4
Foulds, A.; Allen, G.; Shaw, J. T.; Bateson, P.; Barker, P. A.; Huang, L.; Pitt, J. R.; Lee, J. D.; Wilde, S. E.; Dominutti, P.; Purvis, R. M.; Lowry, D.; France, J. L.; Fisher, R. E.; Fiehn, A.; Pühl, M.; Bauguitte, S. J. B.; Conley, S. A.; Smith, M. L.; Lachlan-Cope, T.; Pisso, I.; Schwietzke, S. Quantification and Assessment of Methane Emissions from Offshore Oil and Gas Facilities on the Norwegian Continental Shelf. Atmos Chem. Phys. 2022, 22 (7), 4303– 4322, DOI: 10.5194/acp-22-4303-2022
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Quantification and assessment of methane emissions from offshore oil and gas facilities on the Norwegian continental shelf
Foulds, Amy; Allen, Grant; Shaw, Jacob T.; Bateson, Prudence; Barker, Patrick A.; Huang, Langwen; Pitt, Joseph R.; Lee, James D.; Wilde, Shona E.; Dominutti, Pamela; Purvis, Ruth M.; Lowry, David; France, James L.; Fisher, Rebecca E.; Fiehn, Alina; Puhl, Magdalena; Bauguitte, Stephane J. B.; Conley, Stephen A.; Smith, Mackenzie L.; Lachlan-Cope, Tom; Pisso, Ignacio; Schwietzke, Stefan
Atmospheric Chemistry and Physics (2022), 22 (7), 4303-4322CODEN: ACPTCE; ISSN:1680-7324. (Copernicus Publications)
The oil and gas (O&G) sector is a significant source of methane (CH4) emissions. Quantifying these emissions remains challenging, with many studies highlighting discrepancies between measurements and inventory-based ests. In this study, we present CH4 emission fluxes from 21 offshore O&G facilities collected in 10 O&G fields over two regions of the Norwegian continental shelf in 2019. Emissions of CH4 derived from measurements during 13 aircraft surveys were found to range from 2.6 to 1200 t yr-1 (with a mean of 211 t yr-1 across all 21 facilities). Comparing this with aggregated operator-reported facility emissions for 2019, we found excellent agreement (within 1σ uncertainty), with mean aircraft-measured fluxes only 16% lower than those reported by operators. We also compared aircraft-derived fluxes with facility fluxes extd. from a global gridded fossil fuel CH4 emission inventory compiled for 2016. We found that the measured emissions were 42% larger than the inventory for the area covered by this study, for the 21 facilities surveyed (in aggregate). We interpret this large discrepancy not to reflect a systematic error in the operator-reported emissions, which agree with measurements, but rather the representativity of the global inventory due to the methodol. used to construct it and the fact that the inventory was compiled for 2016 (and thus not representative of emissions in 2019). This highlights the need for timely and up-to-date inventories for use in research and policy. The variable nature of CH4 emissions from individual facilities requires knowledge of facility operational status during measurements for data to be useful in prioritising targeted emission mitigation solns. Future surveys of individual facilities would benefit from knowledge of facility operational status over time. Field-specific aggregated emissions (and uncertainty statistics), as presented here for the Norwegian Sea, can be meaningfully estd. from intensive aircraft surveys. However, field-specific ests. cannot be reliably extrapolated to other prodn. fields without their own tailored surveys, which would need to capture a range of facility designs, oil and gas prodn. vols., and facility ages. For year-on-year comparison to annually updated inventories and regulatory emission reporting, analogous annual surveys would be needed for meaningful top-down validation. In summary, this study demonstrates the importance and accuracy of detailed, facility-level emission accounting and reporting by operators and the use of airborne measurement approaches to validate bottom-up accounting.
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MacKay, K.; Lavoie, M.; Bourlon, E.; Atherton, E.; O’Connell, E.; Baillie, J.; Fougère, C.; Risk, D. Methane Emissions from Upstream Oil and Gas Production in Canada Are Underestimated. Sci. Rep-uk 2021, 11 (1), 8041, DOI: 10.1038/s41598-021-87610-3
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Chen, Y.; Sherwin, E. D.; Berman, E. S. F.; Jones, B. B.; Gordon, M. P.; Wetherley, E. B.; Kort, E. A.; Brandt, A. R. Quantifying Regional Methane Emissions in the New Mexico Permian Basin with a Comprehensive Aerial Survey. Environ. Sci. Technol. 2022, 56 (7), 4317– 4323, DOI: 10.1021/acs.est.1c06458
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Quantifying Regional Methane Emissions in the New Mexico Permian Basin with a Comprehensive Aerial Survey
Chen, Yuanlei; Sherwin, Evan D.; Berman, Elena S. F.; Jones, Brian B.; Gordon, Matthew P.; Wetherley, Erin B.; Kort, Eric A.; Brandt, Adam R.
Environmental Science & Technology (2022), 56 (7), 4317-4323CODEN: ESTHAG; ISSN:1520-5851. (American Chemical Society)
Limiting emissions of climate-warming methane from oil and gas (O&G) is a major opportunity for short-term climate benefits. We deploy a basin-wide airborne survey of O&G extn. and transportation activities in the New Mexico Permian Basin, spanning 35 923 km2, 26 292 active wells, and over 15 000 km of natural gas pipelines using an independently validated hyperspectral methane point source detection and quantification system. The airborne survey repeatedly visited over 90% of the active wells in the survey region throughout Oct. 2018 to Jan. 2020, totaling approx. 98 000 well site visits. We est. total O&G methane emissions in this area at 194 (+72/-68, 95% CI) metric tonnes per h (t/h), or 9.4% (+3.5%/-3.3%) of gross gas prodn. 50% of obsd. emissions come from large emission sources with persistence-averaged emission rates over 308 kg/h. The fact that a large sample size is required to characterize the heavy tail of the distribution emphasizes the importance of capturing low-probability, high-consequence events through basin-wide surveys when estg. regional O&G methane emissions.
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Howarth, R. W.; Jacobson, M. Z. How Green Is Blue Hydrogen?. Energy Sci. Eng. 2021, 9, 1676– 1687, DOI: 10.1002/ese3.956
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How green is blue hydrogen?
Howarth, Robert W.; Jacobson, Mark Z.
Energy Science & Engineering (2021), 9 (10), 1676-1687CODEN: ESENGX; ISSN:2050-0505. (John Wiley & Sons Ltd.)
A review. Hydrogen is often viewed as an important energy carrier in a future decarbonized world. Currently, most hydrogen is produced by steam reforming of methane in natural gas ("gray hydrogen"), with high carbon dioxide emissions. Increasingly, many propose using carbon capture and storage to reduce these emissions, producing so-called "blue hydrogen," frequently promoted as low emissions. We undertake the first effort in a peer-reviewed paper to examine the lifecycle greenhouse gas emissions of blue hydrogen accounting for emissions of both carbon dioxide and unburned fugitive methane. Far from being low carbon, greenhouse gas emissions from the prodn. of blue hydrogen are quite high, particularly due to the release of fugitive methane. For our default assumptions (3.5% emission rate of methane from natural gas and a 20-yr global warming potential), total carbon dioxide equiv. emissions for blue hydrogen are only 9%-12% less than for gray hydrogen. While carbon dioxide emissions are lower, fugitive methane emissions for blue hydrogen are higher than for gray hydrogen because of an increased use of natural gas to power the carbon capture. Perhaps surprisingly, the greenhouse gas footprint of blue hydrogen is more than 20% greater than burning natural gas or coal for heat and some 60% greater than burning diesel oil for heat, again with our default assumptions. In a sensitivity anal. in which the methane emission rate from natural gas is reduced to a low value of 1.54%, greenhouse gas emissions from blue hydrogen are still greater than from simply burning natural gas, and are only 18%-25% less than for gray hydrogen. Our anal. assumes that captured carbon dioxide can be stored indefinitely, an optimistic and unproven assumption. Even if true though, the use of blue hydrogen appears difficult to justify on climate grounds.
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Stocks, M.; Fazeli, R.; Hughes, L.; Beck, F. J. Global Emissions Implications from Co-Combusting Ammonia in Coal Fired Power Stations: An Analysis of the Japan-Australia Supply Chain. J. Clean. Prod. 2022, 336, 130092 DOI: 10.1016/j.jclepro.2021.130092
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Ocko, I. B.; Hamburg, S. P. Climate Consequences of Hydrogen Emissions. Atmos. Chem. Phys. 2022, 22, 9349– 9368, DOI: 10.5194/acp-22-9349-2022
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Climate consequences of hydrogen emissions
Ocko, Ilissa B.; Hamburg, Steven P.
Atmospheric Chemistry and Physics (2022), 22 (14), 9349-9368CODEN: ACPTCE; ISSN:1680-7324. (Copernicus Publications)
Given the urgency to decarbonize global energy systems, governments and industry are moving ahead with efforts to increase deployment of hydrogen technologies, infrastructure, and applications at an unprecedented pace, including USD billions in national incentives and direct investments. While zero- and low-carbon hydrogen hold great promise to help solve some of the world's most pressing energy challenges, hydrogen is also an indirect greenhouse gas whose warming impact is both widely overlooked and underestimated. This is largely because hydrogen's atm. warming effects are short-lived - lasting only a couple decades - but std. methods for characterizing climate impacts of gases consider only the long-term effect from a one-time pulse of emissions. For gases whose impacts are short-lived, like hydrogen, this long-term framing masks a much stronger warming potency in the near to medium term. This is of concern because hydrogen is a small mol. known to easily leak into the atm., and the total amt. of emissions (e.g., leakage, venting, and purging) from existing hydrogen systems is unknown. Therefore, the effectiveness of hydrogen as a decarbonization strategy, esp. over timescales of several decades, remains unclear. This paper evaluates the climate consequences of hydrogen emissions over all timescales by employing already published data to assess its potency as a climate forcer, evaluate the net warming impacts from replacing fossil fuel technologies with their clean hydrogen alternatives, and est. temp. responses to projected levels of hydrogen demand. We use the std. global warming potential metric, given its acceptance to stakeholders, and incorporate newly published equations that more fully capture hydrogen's several indirect effects, but we consider the effects of const. rather than pulse emissions over multiple time horizons. We account for a plausible range of hydrogen emission rates and include methane emissions when hydrogen is produced via natural gas with carbon capture, usage, and storage (CCUS) ("blue" hydrogen) as opposed to renewables and water ("green" hydrogen). For the first time, we show the strong timescale dependence when evaluating the climate change mitigation potential of clean hydrogen alternatives, with the emission rate detg. the scale of climate benefits or disbenefits. For example, green hydrogen applications with higher-end emission rates (10%) may only cut climate impacts from fossil fuel technologies in half over the first 2 decades, which is far from the common perception that green hydrogen energy systems are climate neutral. However, over a 100-yr period, climate impacts could be reduced by around 80%. On the other hand, lower-end emissions (1%) could yield limited impacts on the climate over all timescales. For blue hydrogen, assocd. methane emissions can make hydrogen applications worse for the climate than fossil fuel technologies for several decades if emissions are high for both gases; however, blue hydrogen yields climate benefits over a 100-yr period. While more work is needed to evaluate the warming impact of hydrogen emissions for specific end-use cases and value-chain pathways, it is clear that hydrogen emissions matter for the climate and warrant further attention from scientists, industry, and governments. This is crit. to informing where and how to deploy hydrogen effectively in the emerging decarbonized global economy.
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Bertagni, M. B.; Pacala, S. W.; Paulot, F.; Porporato, A. Risk of the Hydrogen Economy for Atmospheric Methane. Nat. Commun. 2022, 13 (1), 7706, DOI: 10.1038/s41467-022-35419-7
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Risk of the hydrogen economy for atmospheric methane
Bertagni, Matteo B.; Pacala, Stephen W.; Paulot, Fabien; Porporato, Amilcare
Nature Communications (2022), 13 (1), 7706CODEN: NCAOBW; ISSN:2041-1723. (Nature Portfolio)
Hydrogen (H2) is expected to play a crucial role in reducing greenhouse gas emissions. However, hydrogen losses to the atm. impact atm. chem., including pos. feedback on methane (CH4), the second most important greenhouse gas. Here we investigate through a minimalist model the response of atm. methane to fossil fuel displacement by hydrogen. We find that CH4 concn. may increase or decrease depending on the amt. of hydrogen lost to the atm. and the methane emissions assocd. with hydrogen prodn. Green H2 can mitigate atm. methane if hydrogen losses throughout the value chain are below 9 ± 3%. Blue H2 can reduce methane emissions only if methane losses are below 1%. We address and discuss the main uncertainties in our results and the implications for the decarbonization of the energy sector.
https://chemport.cas.org/services/resolver?origin=ACS&resolution=options&coi=1%3ACAS%3A528%3ADC%252BB38XjtFarsbvK&md5=f09124e43832eb073d36ebe00664b958
Bauer, C.; Treyer, K.; Antonini, C.; Bergerson, J.; Gazzani, M.; Gencer, E.; Gibbins, J.; Mazzotti, M.; McCoy, S. T.; McKenna, R.; Pietzcker, R.; Ravikumar, A. P.; Romano, M. C.; Ueckerdt, F.; Vente, J.; van der Spek, M. On the Climate Impacts of Blue Hydrogen Production. Sustainable Energy Fuels 2021, 6 (1), 66– 75, DOI: 10.1039/D1SE01508G
There is no corresponding record for this reference.
Ricks, W.; Xu, Q.; Jenkins, J. D. Minimizing Emissions from Grid-Based Hydrogen Production in the United States. Environ. Res. Lett. 2023, 18 (1), 014025 DOI: 10.1088/1748-9326/acacb5
There is no corresponding record for this reference.
Alvarez, R. A.; Pacala, S. W.; Winebrake, J. J.; Chameides, W. L.; Hamburg, S. P. Greater Focus Needed on Methane Leakage from Natural Gas Infrastructure. Proc. National Acad. Sci. 2012, 109 (17), 6435– 6440, DOI: 10.1073/pnas.1202407109
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Greater focus needed on methane leakage from natural gas infrastructure
Alvarez, Ramon A.; Pacala, Stephen W.; Winebrake, James J.; Chameides, William L.; Hamburg, Steven P.
Proceedings of the National Academy of Sciences of the United States of America (2012), 109 (17), 6435-6440, S6435/1-S6435/7CODEN: PNASA6; ISSN:0027-8424. (National Academy of Sciences)
Natural gas is seen by many as the future of American energy: a fuel that can provide energy independence and reduce greenhouse gas emissions in the process. However, there has also been confusion about the climate implications of increased use of natural gas for elec. power and transportation. We propose and illustrate the use of technol. warming potentials as a robust and transparent way to compare the cumulative radiative forcing created by alternative technologies fueled by natural gas and oil or coal by using the best available ests. of greenhouse gas emissions from each fuel cycle (i.e., prodn., transportation and use). We find that a shift to compressed natural gas vehicles from gasoline or diesel vehicles leads to greater radiative forcing of the climate for 80 or 280 yr, resp., before beginning to produce benefits. Compressed natural gas vehicles could produce climate benefits on all time frames if the well-to-wheels CH4 leakage were capped at a level 45-70% below current ests. By contrast, using natural gas instead of coal for elec. power plants can reduce radiative forcing immediately, and reducing CH4 losses from the prodn. and transportation of natural gas would produce even greater benefits. There is a need for the natural gas industry and science community to help obtain better emissions data and for increased efforts to reduce methane leakage in order to minimize the climate footprint of natural gas.
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Ocko, I. B.; Hamburg, S. P. Climate Impacts of Hydropower: Enormous Differences among Facilities and over Time. Environ. Sci. Technol. 2019, 53 (23), 14070– 14082, DOI: 10.1021/acs.est.9b05083
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Climate Impacts of Hydropower: Enormous Differences among Facilities and over Time
Ocko, Ilissa B.; Hamburg, Steven P.
Environmental Science & Technology (2019), 53 (23), 14070-14082CODEN: ESTHAG; ISSN:0013-936X. (American Chemical Society)
To stabilize climate, humans must rapidly displace fossil fuels with clean energy technologies. Currently, hydropower dominates renewable electricity generation, accounting for 2/3 globally; it is expected to grow at least 45% by 2040. While it is broadly assumed that hydropower facilities emit greenhouse gases on par with wind, there is mounting evidence that emissions can be considerably greater, with some facilities even on par with fossil fuels. However, analyses of climate impacts of hydropower facilities have been simplistic, emphasizing aggregated 100-yr impacts from a one-year emissions pulse. Such analyses mask near-term impacts of CH4 emissions central to many current policy regimes, tending to omit CO2 emissions assocd. with initial facility development, and not considering the effect of atm. gas accumulation over time. An analytic approach which addresses these issues was developed. By analyzing climate impacts of sustained hydropower emissions over time, the authors detd. there are enormous differences in climate impacts among facilities and over time. If minimizing climate impacts are not a priority for design and construction of new hydropower facilities, it could lead to limited or even no climate benefits.
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Tromp, T. K.; Shia, R.-L.; Allen, M.; Eiler, J. M.; Yung, Y. L. Potential Environmental Impact of a Hydrogen Economy on the Stratosphere. Science 2003, 300 (5626), 1740– 1742, DOI: 10.1126/science.1085169
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Potential Environmental Impact of a Hydrogen Economy on the Stratosphere
Tromp, Tracey K.; Shia, Run-Lie; Allen, Mark; Eiler, John M.; Yung, Y. L.
Science (Washington, DC, United States) (2003), 300 (5626), 1740-1742CODEN: SCIEAS; ISSN:0036-8075. (American Association for the Advancement of Science)
The widespread use of hydrogen fuel cells could have hitherto unknown environmental impacts due to unintended emissions of mol. hydrogen, including an increase in the abundance of water vapor in the stratosphere (plausibly by as much as ∼1 part per million by vol.). This would cause stratospheric cooling, enhancement of the heterogeneous chem. that destroys ozone, an increase in noctilucent clouds, and changes in tropospheric chem. and atm.-biosphere interactions.
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Jacobson, M. Z.; Colella, W. G.; Golden, D. M. Cleaning the Air and Improving Health with Hydrogen Fuel-Cell Vehicles. Science 2005, 308 (5730), 1901– 1905, DOI: 10.1126/science.1109157
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Cleaning the Air and Improving Health with Hydrogen Fuel-Cell Vehicles
Jacobson, M. Z.; Colella, W. G.; Golden, D. M.
Science (Washington, DC, United States) (2005), 308 (5730), 1901-1905CODEN: SCIEAS; ISSN:0036-8075. (American Association for the Advancement of Science)
A review. Converting all U.S. onroad vehicles to hydrogen fuel-cell vehicles (HFCVs) may improve air quality, health, and climate significantly, whether the hydrogen is produced by steam reforming of natural gas, wind electrolysis, or coal gasification. Most benefits would result from eliminating current vehicle exhaust. Wind and natural gas HFCVs offer the greatest potential health benefits and could save 3700 to 6400 U.S. lives annually. Wind HFCVs should benefit climate most. An all-HFCV fleet would hardly affect tropospheric water vapor concns. Conversion to coal HFCVs may improve health but would damage climate more than fossil/elec. hybrids. The real cost of hydrogen from wind electrolysis may be below that of U.S. gasoline.
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Jacobson, M. Z. Effects of Wind-powered Hydrogen Fuel Cell Vehicles on Stratospheric Ozone and Global Climate. Geophys. Res. Lett. 2008, 35 (19), L19803 DOI: 10.1029/2008GL035102
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Effects of wind-powered hydrogen fuel cell vehicles on stratospheric ozone and global climate
Jacobson, Mark Z.
Geophysical Research Letters (2008), 35 (19), L19803/1-L19803/5CODEN: GPRLAJ; ISSN:0094-8276. (American Geophysical Union)
A review. Converting the world's fossil-fuel onroad vehicles (FFOV) to hydrogen fuel cell vehicles (HFCV), where the H2 is produced by wind-powered electrolysis, is estd. to reduce global fossil, biofuel, and biomass-burning emissions of CO2 by ∼13.4%, NOx ∼23.0%, nonmethane org. gases ∼18.9%, black carbon ∼8% H2 ∼3.2% (at 3% leakage), and H2O ∼0.2%. Over 10 years, such redns. were calcd. to reduce tropospheric CO ∼5%, NOx ∼5-13%, most org. gases ∼3-15%, OH ∼4%, ozone ∼6%, and PAN ∼13%, but to increase tropospheric CH4 ∼0.25% due to the lower OH. Lower OH also increased upper tropospheric/lower stratospheric ozone, increasing its global column by ∼0.41%. WHFCV cooled the troposphere and warmed the stratosphere, reduced aerosol and cloud surface areas, and increased pptn. Other renewable-powered HFCV or battery elec. vehicles should have similar impacts.
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van Ruijven, B.; Lamarque, J.-F.; van Vuuren, D. P.; Kram, T.; Eerens, H. Emission Scenarios for a Global Hydrogen Economy and the Consequences for Global Air Pollution. Global Environ. Change 2011, 21 (3), 983– 994, DOI: 10.1016/j.gloenvcha.2011.03.013
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Bond, S. W.; Gül, T.; Reimann, S.; Buchmann, B.; Wokaun, A. Emissions of Anthropogenic Hydrogen to the Atmosphere during the Potential Transition to an Increasingly H2-Intensive Economy. Int. J. Hydrogen Energ 2011, 36 (1), 1122– 1135, DOI: 10.1016/j.ijhydene.2010.10.016
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Emissions of anthropogenic hydrogen to the atmosphere during the potential transition to an increasingly H2-intensive economy
Bond, S. W.; Guel, T.; Reimann, S.; Buchmann, B.; Wokaun, A.
International Journal of Hydrogen Energy (2011), 36 (1), 1122-1135CODEN: IJHEDX; ISSN:0360-3199. (Elsevier Ltd.)
Current and future anthropogenic atm. H2 emissions from technol. processes were assessed. Current emissions are dominated by direct exhaust gas of road-based motor vehicles and losses during industrial H2 prodn. from fossil fuels. H2 emissions from transportation were estd. to be 4.5 Tg for 2010. An addnl. ∼0.5-2 Tg H2 were estd. to be lost to the atm. from industrial processes in 2010. In 2020, emissions from transportation are estd. to be ∼50% of those in 2010. Future emissions will occur as losses along the entire prodn., distribution, and end-use chain, including emissions from H2 fuel cell vehicles (FCV). In 2050, overall anthropogenic H2 emissions will only approach current levels at high-end loss rates; direct emissions from transportation are expected to be significantly lower than current levels. In 2100, an av. 0.5% loss rate would result in overall H2 emissions exceeding current levels, even with no net H2 emissions from FCV; however, based on an av. 0.1% loss rate, H2 emission factors from FCV on the order of 120-170 mg/km are projected to result in overall anthropogenic H2 emissions similar to 2010 levels.
https://chemport.cas.org/services/resolver?origin=ACS&resolution=options&coi=1%3ACAS%3A528%3ADC%252BC3MXht1Cqtr8%253D&md5=3bb9bab78bfe124afde21fc0d271db38
Bertagni, M. B.; Socolow, R. H.; Martirez, J. M. P.; Carter, E. A.; Greig, C.; Ju, Y.; Lieuwen, T.; Mueller, M. E.; Sundaresan, S.; Wang, R.; Zondlo, M. A.; Porporato, A. Minimizing the Impacts of the Ammonia Economy on the Nitrogen Cycle and Climate. Proc. Natl. Acad. Sci. United States Am. 2023, 120 (46), e2311728120 DOI: 10.1073/pnas.2311728120
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Wolfram, P.; Kyle, P.; Zhang, X.; Gkantonas, S.; Smith, S. Using Ammonia as a Shipping Fuel Could Disturb the Nitrogen Cycle. Nat. Energy 2022, 7 (12), 1112– 1114, DOI: 10.1038/s41560-022-01124-4
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Using ammonia as a shipping fuel could disturb the nitrogen cycle
Wolfram, Paul; Kyle, Page; Zhang, Xin; Gkantonas, Savvas; Smith, Steven
Nature Energy (2022), 7 (12), 1112-1114CODEN: NEANFD; ISSN:2058-7546. (Nature Portfolio)
A polemic in response to Paul Wolfram et al is given. Ammonia has been proposed as a shipping fuel, yet potential adverse side-effects are poorly understood. We argue that if nitrogen releases from ammonia are not tightly controlled, the scale of the demands of maritime transport are such that the global nitrogen cycle could be substantially altered.
https://chemport.cas.org/services/resolver?origin=ACS&resolution=options&coi=1%3ACAS%3A528%3ADC%252BB38Xis1eju7%252FE&md5=dab6f28ad2f38a315051e11625306398
Ueckerdt, F.; Bauer, C.; Dirnaichner, A.; Everall, J.; Sacchi, R.; Luderer, G. Potential and Risks of Hydrogen-Based e-Fuels in Climate Change Mitigation. Nat. Clim Change 2021, 11 (5), 384– 393, DOI: 10.1038/s41558-021-01032-7
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Potential and risks of hydrogen-based e-fuels in climate change mitigation
Ueckerdt, Falko; Bauer, Christian; Dirnaichner, Alois; Everall, Jordan; Sacchi, Romain; Luderer, Gunnar
Nature Climate Change (2021), 11 (5), 384-393CODEN: NCCACZ; ISSN:1758-6798. (Nature Portfolio)
Abstr.: E-fuels promise to replace fossil fuels with renewable electricity without the demand-side transformations required for a direct electrification. However, e-fuels' versatility is counterbalanced by their fragile climate effectiveness, high costs and uncertain availability. E-fuel mitigation costs are euro800-1,200 per tCO2. Large-scale deployment could reduce costs to euro20-270 per tCO2 until 2050, yet it is unlikely that e-fuels will become cheap and abundant early enough. Neglecting demand-side transformations threatens to lock in a fossil-fuel dependency if e-fuels fall short of expectations. Sensible climate policy supports e-fuel deployment while hedging against the risk of their unavailability at large scale. Policies should be guided by a 'merit order of end uses' that prioritizes hydrogen and e-fuels for sectors that are inaccessible to direct electrification.
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Gudmundsson, O.; Thorsen, J. E. Source-to-Sink Efficiency of Blue and Green District Heating and Hydrogen-Based Heat Supply Systems. Smart Energy 2022, 6, 100071 DOI: 10.1016/j.segy.2022.100071
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Source-to-sink efficiency of blue and green district heating and hydrogen-based heat supply systems
Gudmundsson, Oddgeir; Thorsen, Jan Eric
Smart Energy (2022), 6 (), 100071CODEN: SEMNBM; ISSN:2666-9552. (Elsevier Ltd.)
Hydrogen is commonly mentioned as a future proof energy carrier. Hydrogen supporters advocate for repurposing existing natural gas grids for a sustainable hydrogen supply. While the long-term vision of the hydrogen community is green hydrogen the community acknowledges that in the short term it will be to large extent manufd. from natural gas, but in a decarbonized way, giving it the name blue hydrogen. While hydrogen has a role to play in hard to decarbonize sectors its role for building heating demands is doubtful, as mature and more energy efficient alternatives exist. As building heat supply infrastructures built today will operate for the decades to come it is of highest importance to ensure that the most efficient and sustainable infrastructures are chosen. This paper compares the source to sink efficiencies of hydrogen-based heat supply system to a district heating system operating on the same primary energy source. The results show that a natural gas-based district heating could be 267% more efficient, and consequently have significantly lower global warming potential, than a blue hydrogen-based heat supply A renewable power-based district heating could achieve above 440% higher efficiency than green hydrogen-based heat supply system.
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de Kleijne, K.; de Coninck, H.; van Zelm, R.; Huijbregts, M. A. J.; Hanssen, S. V. The Many Greenhouse Gas Footprints of Green Hydrogen. Sustainable Energy Fuels 2022, 6, 4383– 4387, DOI: 10.1039/D2SE00444E
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The many greenhouse gas footprints of green hydrogen
de Kleijne, Kiane; de Coninck, Heleen; van Zelm, Rosalie; Huijbregts, Mark A. J.; Hanssen, Steef V.
Sustainable Energy & Fuels (2022), 6 (19), 4383-4387CODEN: SEFUA7; ISSN:2398-4902. (Royal Society of Chemistry)
Green hydrogen could contribute to climate change mitigation, but its greenhouse gas footprint varies with electricity source and allocation choices. Using life-cycle assessment we conclude that if electricity comes from addnl. renewable capacity, green hydrogen outperforms fossil-based hydrogen. In the short run, alternative uses of renewable electricity likely achieve greater emission redns.
https://chemport.cas.org/services/resolver?origin=ACS&resolution=options&coi=1%3ACAS%3A528%3ADC%252BB38XitlSntLzM&md5=673e7a3fe7231c64681c4da1b8476c8b
Pototschnig, A. Renewable Hydrogen and the “Additionality” Requirement: Why Making It More Complex than Is Needed?. European University Institute 2021, 1– 6, DOI: 10.2870/201657
There is no corresponding record for this reference.
Ocko, I. B.; Hamburg, S. P.; Jacob, D. J.; Keith, D. W.; Keohane, N. O.; Oppenheimer, M.; Roy-Mayhew, J. D.; Schrag, D. P.; Pacala, S. W. Unmask Temporal Trade-Offs in Climate Policy Debates. Science 2017, 356 (6337), 492– 493, DOI: 10.1126/science.aaj2350
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Unmask temporal trade-offs in climate policy debates
Ocko, Ilissa B.; Hamburg, Steven P.; Jacob, Daniel J.; Keith, David W.; Keohabne, Nathaniel O.; Oppenheimer, Michael; Roy-Mayhew, Joseph D.; Schrag, Daniel P.; Pacala, Stephen W.
Science (Washington, DC, United States) (2017), 356 (6337), 492-493CODEN: SCIEAS; ISSN:0036-8075. (American Association for the Advancement of Science)
There is no expanded citation for this reference.
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Deng, H.; Bielicki, J. M.; Oppenheimer, M.; Fitts, J. P.; Peters, C. A. Leakage Risks of Geologic CO2 Storage and the Impacts on the Global Energy System and Climate Change Mitigation. Clim. Chang. 2017, 144 (2), 151– 163, DOI: 10.1007/s10584-017-2035-8
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Leakage risks of geologic CO2 storage and the impacts on the global energy system and climate change mitigation
Deng, Hang; Bielicki, Jeffrey M.; Oppenheimer, Michael; Fitts, Jeffrey P.; Peters, Catherine A.
Climatic Change (2017), 144 (2), 151-163CODEN: CLCHDX; ISSN:0165-0009. (Springer)
This study investigated how subsurface and atm. leakage from geol. CO2 storage reservoirs could impact the deployment of Carbon Capture and Storage (CCS) in the global energy system. The Leakage Risk Monetization Model was used to est. the costs of leakage for representative CO2 injection scenarios, and these costs were incorporated into the Global Change Assessment Model. Worst-case scenarios of CO2 leakage risk, which assume that all leakage pathway permeabilities are extremely high, were simulated. Even with this extreme assumption, the assocd. costs of monitoring, treatment, containment, and remediation resulted in minor shifts in the global energy system. For example, the redn. in CCS deployment in the electricity sector was 3% for the "high" leakage scenario, with replacement coming from fossil fuel and biomass without CCS, nuclear power, and renewable energy. In other words, the impact on CCS deployment under a realistic leakage scenario is likely to be negligible. We also quantified how the resulting shifts will impact atm. CO2 concns. Under a carbon tax that achieves an atm. CO2 concn. of 480 ppm in 2100, technol. shifts due to leakage costs would increase this concn. by less than 5 ppm. It is important to emphasize that this increase does not result from leaked CO2 that reaches the land surface, which is minimal due to secondary trapping in geol. strata above the storage reservoir. The overall conclusion is that leakage risks and assocd. costs will likely not interfere with the effectiveness of policies for climate change mitigation.
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Vinca, A.; Emmerling, J.; Tavoni, M. Bearing the Cost of Stored Carbon Leakage. Front. Energy Res. 2018, 6, 40, DOI: 10.3389/fenrg.2018.00040
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Supporting Information
Supporting Information
The Supporting Information is available free of charge at https://pubs.acs.org/doi/10.1021/acs.est.3c09030.
More detailed information about methods and data used in this study as well as additional figures that show the climate impact of hydrogen pathways relative to other alternatives under the 2030 condition (PDF)
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