Ammonia is a promising energy and hydrogen carrier due to its ease of liquification, high hydrogen content, and potential to be synthesized without carbon feedstocks. Despite its widespread use in agriculture, the utilization of ammonia to deliver hydrogen or for direct power generation is still under development. Sometimes referred to as “cracking”, the standard approach for recovering hydrogen from ammonia relies on harsh reaction conditions that limit its suitability for low-carbon transitions. This work investigates the technology development status and potential cost of plasma and electrolysis-based ammonia decomposition, benchmarks them with thermal-chemical decomposition, and further compares them with direct ammonia-to-power solid oxide fuel cell systems. Results suggest that in order to reach cost parity with cracking technologies, plasma-based decomposition must achieve one order of magnitude improvement in energy efficiency (to 10 kWh/kg or lower), while electrolysis decomposition must achieve enhanced durability using cheap electrolytes.

Substantial upscaling of carbon dioxide capture is possible in the coming decades but existing solutions for storage are projected to be limited in annual capacity by as much as 2-10 GtCO2 per year until mid-century. Temporary storage of CO2 in a solid or liquid state could prove useful for filling this gap in capacity, until more permanent and ideally lucrative CO2 sequestration options come online. There are several concepts for reversible solid-state and chemical CO2 storage, but their advantages and limitations have yet to be reviewed in this context. This article focuses on the physical and chemical aspects of CO2 storage via liquid and solid chemical carriers and sorbents, and gives an overview of the energetics around their use, as well as prospects for their future development. Exciting opportunities for coupling capture and medium to high maturity multi-year storage technologies could support carbon removal in the coming decades. Highlights of the analysis are the remarkable storage capacity of oxalic acid and formic acid (CO2-density of 1857 kg m−3 and 1152 kg m−3, compared with condensed liquid CO2 at 993-1096 kg m−3, respectively), the relative scalability and compatibility of carbonate salts for stationary storage with direct air capture, and the potential promise of multiple carriers for CO2 transportation. Solid sorbents do not achieve such ultra-high storage capacities, but could improve storage over compressed gas tanks on a capacity and energetics basis.

Food waste makes up approximately 15% of municipal solid waste generated in the United States, and 95% of food waste is ultimately landfilled. Its bioavailable carbon and nutrient content makes it a major contributor to landfill methane emissions, but also presents an important opportunity for energy recovery. This paper presents the first detailed analysis of monthly food waste generation in California at a county level, and its potential contribution to the state's energy production. Scenarios that rely on excess capacity at existing anaerobic digester (AD) and solid biomass combustion facilities, and alternatives that allow for new facility construction, are developed and modeled. Potential monthly electricity generation from the conversion of gross food waste using a combination of AD and combustion varies from 420 to 700 MW, averaging 530 MW. At least 66% of gross high moisture solids and 23% of gross low moisture solids can be treated using existing county infrastructure, and this fraction increases to 99% of high moisture solids and 55% of low moisture solids if waste can be shipped anywhere within the state. Biogas flaring practices at AD facilities can reduce potential energy production by 10 to 40%.

Digestate and biochar can be land applied to sequester carbon and improve net primary productivity, but the achievable scale is tied to expected growth in bioenergy production and land available for application. We use an attributional life-cycle assessment approach to estimate the greenhouse gas (GHG) emissions and carbon storage potential of biochar, digested solids, and composted digested solids generated from organic waste in California as a test case. Our scenarios characterize changes in organic waste production, bioenergy facility build-out, bioenergy byproduct quality, and soil response. Moderate to upper bound growth in the bioenergy sector with annual byproduct disposal over 100 years could provide a cumulative GHG offset of 50-400 MMTCO2 equiv, with an additional 80-300 MMTC sequestered in soils. This corresponds to net GHG mitigation over 100 years equivalent to 340-1500 MMTCO2 equiv (80-350% of California's annual emissions). In most scenarios, there is sufficient working land to apply all available biochar and digestate, although land becomes a constraint if the soil's rest time between applications increases from 5 to 15 years.

Gaseous streams in biorefineries have been undervalued and underutilized. In cellulosic biorefineries, coproduced biogas is assumed to be combusted alongside lignin to generate process heat and electricity. Biogas can instead be upgraded to compressed biomethane and used as a transportation fuel. Capturing CO₂-rich streams generated in biorefineries can also contribute to greenhouse gas (GHG) mitigation goals. We explore the economic and life-cycle GHG impacts of biogas upgrading and CO₂ capture and storage (CCS) at ionic liquid-based cellulosic ethanol biorefineries using biomass sorghum. Without policy incentives, biorefineries with biogas upgrading systems can achieve a comparable minimum ethanol selling price (MESP) and reduced GHG footprint ($1.38/liter gasoline equivalent (LGE) and 12.9 gCO_2e/MJ) relative to facilities that combust biogas onsite ($1.34/LGE and 24.3 gCO_2e/MJ). Incorporating renewable identification number (RIN) values advantages facilities that upgrade biogas relative to other options (MESP of $0.72/LGE). Incorporating CCS increases the MESP but dramatically decreases the GHG footprint (-21.3 gCO_2e/MJ for partial, -110.7 gCO_2e/MJ for full CCS). The addition of CCS also decreases the cost of carbon mitigation to as low as $52-$78/t CO₂, depending on the assumed fuel selling price, and is the lowest-cost option if both RIN and California's Low Carbon Fuel Standard credits are incorporated.

California's dairy sector accounts for ∼50% of anthropogenic CH₄ emissions in the state's greenhouse gas (GHG) emission inventory. Although California dairy facilities' location and herd size vary over time, atmospheric inverse modeling studies rely on decade-old facility-scale geospatial information. For the first time, we apply artificial intelligence (AI) to aerial imagery to estimate dairy CH₄ emissions from California's San Joaquin Valley (SJV), a region with ∼90% of the state's dairy population. Using an AI method, we process 316,882 images to estimate the facility-scale herd size across the SJV. The AI approach predicts herd size that strongly (>95%) correlates with that made by human visual inspection, providing a low-cost alternative to the labor-intensive inventory development process. We estimate SJV's dairy enteric and manure CH₄ emissions for 2018 to be 496-763 Gg/yr (mean = 624; 95% confidence) using the predicted herd size. We also apply our AI approach to estimate CH₄ emission reduction from anaerobic digester deployment. We identify 162 large (90th percentile) farms and estimate a CH₄ reduction potential of 83 Gg CH₄/yr for these large facilities from anaerobic digester adoption. The results indicate that our AI approach can be applied to characterize the manure system (e.g., use of an anaerobic lagoon) and estimate GHG emissions for other sectors.

Herein we present a concept of a high-temperature, thermal energy storage (HT-TES) system for large-scale long-duration energy storage (>10-hour discharge) applications. The system relies on tunable composite ceramic materials with high electrical conductivity and can output the stored energy flexibly as heat at 1100 degrees C or higher, and as electricity. We model the performance and cost of the system in a techno-economic analysis to identify key material and system properties influencing viability. For applications with daily operation (12-hour storage duration), we find achieving levelized storage costs below US Department of Energy’s 5 ₵/kWhe (1-2.5 ₵/kWhth equivalent) target by 2030 is possible. Candidate materials should have above 600-900 high-temperature cycle stability while offering at least 104 S/m of electrical conductivity. Our results suggest this system can economically store energy for weeks to months, or a longer discharge duration (96 hours) when coupled with intermittent charging using surplus renewable energy sources.