Dimitri M. Saad

The industrial sector in the U.S, contributes to 23% of the nation's annual emissions from the combustion of fossil fuels, generated for process heat end-use, and process emissions, produced as a byproduct of industrial processes. The demand for industrial process heat is not well quantified, as it varies across industries, processes, fluid media (steam/combustion gases), temperature requirements, and over time. Decisions regarding future technologies, processes, and fuels that can meet industrial heat demand in an economically viable manner while minimizing the environmental and social negative consequences associated with industrial heat require such information. In this work, we develop a method to estimate heat demand for industrial facilities and apply it to 120 facilities (representing 39 manufacturing industries) in California. We find that 27 out of 46 million metric tons of CO2 emitted by California's manufacturing industries originate from the production of heat. Petroleum refining and oil/gas extraction sites account for 72% of these emissions. Over 85% of California's industrial heat demand requires temperatures below 600°C, thus holding some potential for electrification.

Understanding greenhouse gas (GHG) emissions from natural gas systems is essential for transitioning to a low-carbon economy. This work estimates well-through-transmission GHG emissions of the US natural gas from one million wells covering 91% production in 2023. A high-resolution US oil and gas production area map is developed to harmonize spatial and tabular data from the oil and natural gas (O&NG) supply chain. We systematically integrate latest aerial campaign measurement into natural gas life cycle GHG emission estimates, capturing methane fugitives with better characterization of superemitter events. More than ten public and commercial data sets are integrated with an engineering-based unit process life cycle assessment (LCA) model. The estimated total GHG emissions from the US gas sector are 719 MMT CO₂eq, more than twice the estimates of the US Environmental Protection Agency. The average well-through-transmission carbon intensity (CI) for US natural gas is 15.99 [15.14, 16.90] gCO₂eq/MJ, with an upstream (exploration through processing) CI of 12.27 [11.84, 12.68] gCO₂eq/MJ and a midstream (transmission) CI of 3.72 [3.30, 4.22] gCO₂eq/MJ (bracketed values indicate uncertainty ranges). Methane fugitive and venting account for 61% and 21% of the upstream CI, an order of magnitude higher than flaring contributions (2.1%). Reducing methane fugitive and venting loss rates by 75% would reduce the upstream CI by half.

We forecasted 82 GW of total geothermal capacity by 2045, reducing system capacity and costs by 40% and 8.6%, respectively.

Methane pyrolysis has been proposed as a cost-competitive route to produce low CO₂ -emissions hydrogen that can utilize today’s infrastructure to supply feedstock and manage waste, and thereby be rapidly scalable. However, this process faces challenges such as catalyst deactivation and carbon build-up that hinder its large-scale implementation. Pyrolysis is usually conducted in the absence of oxidizers to avoid combustion products such as CO₂ . Here, however, we demonstrate that the addition of small concentrations of an oxidant to a methane pyrolysis reaction on Fe-based catalysts prevented catalyst deactivation and increased the net production of carbon and hydrogen. Methane pyrolysis in the presence of a small amount of CO₂ demonstrated a twofold increase in carbon yield and a 7.5-fold increase in hydrogen concentration in the effluent compared to that of a pure methane feed during 1 h operation in a fluidized bed reactor at 750 °C. A similar beneficial effect was observed by adding small amounts of H₂O in the feed. We provide evidence that the cyclic formation and decomposition of an iron carbide catalyst phase allowed for increased methane decomposition and significant carbon removal from the catalyst surface, thus increasing carbon and hydrogen yields. It was also shown that a similar result was obtained for Ni- and Co-based catalysts.

The aviation industry is responsible for over 2% of global CO₂ emissions. Synthetic jet fuels generated from biogenic feedstocks could help reduce life cycle greenhouse gas (GHG) emissions compared to petroleum-based fuels. This study assesses three processes for producing synthetic jet fuel via the synthesis of methanol using water and atmospheric CO₂ or biomass. A life cycle assessment and cost analysis are conducted to determine GHG emissions, energy demand, land occupation, water depletion, and the cost of producing synthetic jet fuel in Switzerland. The results reveal that the pathway that directly hydrogenates CO₂ to methanol exhibits the largest reductions in terms of GHG emission (almost 50%) compared to conventional jet fuel and the lowest production cost (7.86 EUR kg_JF^-1); however, its production cost is currently around 7 times higher than the petroleum-based counterpart. Electrical energy was found to be crucial in capturing CO₂ and converting water into hydrogen, with the sourcing and processing of the feedstocks contributing to 79% of the electric energy demand. Furthermore, significant variations in synthetic jet fuel cost and GHG emissions were shown when the electricity source varies, such as utilizing grid electricity pertaining to different countries with distinct electricity mixes. Thus, upscaling synthetic jet fuels requires energy-efficient supply chains, sufficient feedstock, large amounts of additional (very) low-carbon energy capacity, suitable climate policy, and comprehensive environmental analyses.