Development and Prospects of Biomass-Based Fuels for Heavy-Duty Truck Applications: A Case Study in Oregon

Abstract

Decarbonizing Oregon’s heavy-duty trucking sector, which accounts for 24% of the state’s transportation emissions, is essential for meeting carbon reduction targets. Drop-in fuels such as renewable diesel, biodiesel, and synthetic fuels provide an immediate and effective solution, reducing emissions by up to 80% while utilizing the existing diesel infrastructure. In 2023, Oregon’s heavy-duty trucks consumed 450 million gallons of diesel, with drop-in fuels making up 15% of the fuel mix. Renewable diesel, which is growing at a rate of 30% annually, accounted for 10% of this volume, thanks to incentives from Oregon’s Clean Fuels Program. By 2030, drop-in fuels could capture 40% of the market, reducing CO₂ emissions by 3.5 million metric tons annually, assuming continued policy support and advancements in feedstock sourcing. Meeting the projected demand of 200 million gallons annually and securing sustainable feedstock remain critical challenges. Advances in synthetic fuels, like Power-to-Liquids (PtL) from renewable energy, may further contribute to decarbonization, with costs expected to decrease by 20% over the next decade. Oregon aims for a 50% reduction in emissions from heavy-duty trucks by 2050, using a mix of drop-in fuels and emerging technologies. While hydrogen fuel cells and electric trucks face challenges, innovations in infrastructure and vehicle design will be key to the success of Oregon’s long-term decarbonization strategy.

1. Introduction

Global warming, mainly driven by human-induced carbon-di-oxide (CO₂) emissions from energy use, can be mitigated by replacing fossil fuels with renewable energy sources. The transportation sector is a major contributor to greenhouse gas (GHG) emissions, accounting for around 25% of global emissions [1,2]. Fossil fuel consumption in transportation is responsible for 65% of these emissions, with petroleum-based fuels, primarily gasoline and diesel, making up 95% of transportation energy [3]. The U.S. is a leading emitter of GHGs, with transportation responsible for 28% of its total emissions in 2021 [4]. Figure 1 shows the share of U.S. GHG Emissions by Economic Sector, U.S. Transportation Sector GHG Emissions by Source, and U.S. Transportation Sector GHG Emissions by Gas in 2022. Between 1990 and 2022, emissions from transportation increased by 19%, with light-duty vehicles contributing 57% of these emissions, and medium- and heavy-duty trucks contributing 23% [5,6]. In the U.S., transportation emissions have grown more than any other sector, driven by higher travel demand. These emissions include carbon dioxide (CO₂), methane (CH₄), nitrous oxide (N₂O), and hydrofluorocarbons (HFCs), which come from fuel combustion and air conditioning leaks [7].

In 2022, the United States consumed approximately 20 million barrels of petroleum per day, with the transportation sector alone accounting for 13 million barrels [8]. This resulted in the emission of about 1810 Tg of CO₂, reflecting an 18.7% increase from 1990 levels [6]. As part of its response to the escalating global climate crisis, the U.S. has committed to achieving a net-zero greenhouse gas (GHG) emissions economy by 2050, with the dual goals of reducing emissions and enhancing energy self-sufficiency. To address the climate challenges posed by fossil fuel consumption in the transport sector, the U.S. has been exploring renewable energy options since the end of the Cold War era [9]. In 2020, the U.S. became a net exporter of petroleum for the first time since 1949, marking a significant step toward energy independence. In 2022, petroleum exports totaled 9.52 million barrels per day, while imports were 8.33 million barrels per day, making the U.S. a net exporter for the third consecutive year [10,11]. A key factor in this achievement is the use of “drop-in fuels”—biofuels that can replace conventional fossil fuels without needing modifications to existing infrastructure [12]. Biofuels help reduce GHG emissions, support economic and energy security, and meet regulatory requirements, such as the U.S. Renewable Fuel Standard (RFS) and California’s Low Carbon Fuel Standard (LCFS) [13,14].

To comply with the U.S. federal government energy mandate and state legislation, Oregon is pursuing mandates and policies aimed at zero emissions to combat climate change and shift away from fossil fuel dependency [15,16,17]. Oregon has set ambitious goals to promote zero-emission vehicles (ZEVs) and reduce greenhouse gas emissions from the transportation sector [18]. In 2023, the Oregon Global Warming Commission recommended a package of goal updates as part of its Roadmap to 2030 under Executive Order 20-04 [19]. These goal updates include: by 2030 Oregon will achieve at least a 45% reduction below 1990 levels, and by 2040 Oregon will achieve at least a 70% reduction below 1990 levels. In addition to that, by 2050 Oregon will achieve at least a 95% reduction below 1990 levels, and by 2050, or as soon as practicable, Oregon will achieve net zero emissions and achieve and maintain net negative emissions thereafter [19,20].

Oregon is one of the few U.S. states with an active clean fuel program, which mandates reductions in fuel carbon intensity and incentivizes the adoption of renewable fuels. The state also participates in initiatives like the West Coast Clean Transit Corridor and hosts infrastructure pilots such as Electric Island, positioning it at the forefront of heavy-duty electric vehicle deployment. Transportation has been Oregon’s largest source of emissions, with levels remaining relatively stable over the past 30 years [21]. To meet Oregon’s Executive Order 20-04 and statutory goals (

Table 1. Proportionate share of tailpipe and total sector-based transportation emissions to meet Oregon’s Executive Order 20-04 and statutory GHG emissions reduction goals. Unit is in million metric tons (MMT) [20,22,23].

	EO 20-04		Statutory
Vehicle Class	2035 (45% Below 1990) (MMT CO2)	2050 (80% Below 1990) (MMT CO2)	2050 (75% Below 1990) (MMT CO2)
Light-Duty Vehicles (LDV)	6.3	2.3	2.9
Medium- and Heavy-Duty Vehicles (MHD)	3.5	1.3	1.6
Total LDV and MHD	9.8	3.6	4.5
Total Transportation	11.4	4.1	5.2

), emissions reductions in the transportation sector may need to exceed its proportional share, as other sectors may be harder to decarbonize [22,23]. For example, light-duty vehicles might need to achieve greater reductions compared to medium- or heavy-duty vehicles, especially in earlier years. In 2022, Oregon adopted California’s Advanced Clean Cars II standards, requiring automakers to gradually increase the proportion of zero-emission vehicles (ZEVs) in their sales, with all new passenger vehicles sold in the state needing to be ZEVs by 2035 [13,24]. Additionally, Oregon’s Clean Fuels Program (CFP) supports cleaner fuel alternatives, including renewable fuels and electricity, while expanding electric vehicle (EV) charging infrastructure and offering rebates to make EVs more accessible [16,18].

This article investigates the potential role of drop-in fuels in advancing Oregon’s climate change mitigation efforts, with a particular focus on their application in the heavy-duty vehicle sector. The study aims to evaluate how these fuels can support the state’s environmental and energy objectives, especially within the framework of the Oregon Clean Fuels Program (CFP), which mandates reductions in the carbon intensity (CI) of transportation fuels. The analysis begins by outlining the current fuel mix for Oregon’s heavy-duty fleet, including diesel, biodiesel, natural gas, and electric powertrains, and identifies key barriers to decarbonization, such as infrastructure limitations, high capital costs, technology readiness, and scalability challenges. These issues are assessed within the context of Oregon’s unique economic conditions and regulatory landscape.

A central research gap addressed by this study is the limited exploration of drop-in fuels as a viable near-term decarbonization strategy, despite their compatibility with existing engines and fueling infrastructure. Current decarbonization pathways in Oregon tend to emphasize long-term investments in battery-electric and hydrogen technologies, both of which face considerable deployment obstacles. In contrast, drop-in fuels, such as hydrotreated renewable diesel, biomass-based synthetic fuels, and other advanced biofuels, offer the potential for immediate emissions reductions with minimal infrastructure disruption. However, their role in meeting interim climate targets remains under-analyzed at the state level. This study seeks to fill that gap by assessing Oregon-specific production technologies, technical feasibility, and the alignment of drop-in fuel pathways with state policies and sustainability goals. The findings aim to inform a more balanced and pragmatic approach to decarbonizing Oregon’s heavy-duty transportation sector.

2. Current Energy Production Scenarios in Oregon

2.1. Electricity

Hydroelectric power constitutes more than 50% of Oregon’s domestic electricity production, positioning it among the top four hydroelectric producers in the United States [25]. In 2022, the state produced 51% of its electricity from hydropower, utilizing 105 plants, so securing the second position nationally, following Washington [26]. Natural gas is the second most significant energy source, accounting for 30% of electricity production [27]. In 2022, non-hydro renewable sources—wind, solar, biomass, and geothermal—constituted 19% of Oregon’s power generation. Coal, previously accounting for 10% of Oregon’s electricity, was eliminated following the closure of the state’s final coal plant in 2021. Oregon lacks commercial nuclear power reactors, as its sole facility was deactivated in 2006 after being shut down in 1992 [27].

Figure 2 shows energy resources used to generate electricity that is sold to Oregon’s utility customers. In 2020, Oregon utilized 53.7 million megawatt hours (MWh) of electricity from both domestic and external sources, an increase from 47 million MWh in 2012, attributed to economic and demographic expansion [25,27]. From 2012 to 2020, coal’s consumption share decreased from 32% to 26%, whilst natural gas’s share rose from 12% to 21.5%. Hydropower’s contribution varied with precipitation, reaching a maximum of 46% in 2012 and declining to 37% in 2019 [27,28].

2.2. Renewable Energy

In 2022, renewable energy sources, mainly hydroelectric power, accounted for about 70% of Oregon’s total in-state electricity generation [27]. Hydropower alone contributed nearly 70% of the state’s renewable electricity production. Non-hydro renewable generation has more than doubled since 2011, with wind energy leading the growth. Wind power made up 14% of Oregon’s electricity generation in 2022, with most wind farms located along the Columbia Gorge and in the Blue Mountains [20,28]. By December 2022, Oregon had approximately 4203 MW of wind capacity. A 200 MW wind farm began operations in northern Oregon in 2022, and a 600 MW wind-solar hybrid project is set to launch in 2025 [27].

Solar energy, including small-scale systems under 1 MW, contributed about 3% of Oregon’s electricity in 2022, surpassing biomass for the second consecutive year. Large-scale solar projects began in 2011, and most solar power from 2014 to 2016 came from rooftop and small-scale installations. A 56 MW solar photovoltaic (PV) facility became operational in 2017, followed by the state’s first 70+ MW solar PV plant in 2021. Nearly 2000 MW of new solar capacity is expected by 2025 [20,25].

Biomass contributed over 2% of Oregon’s renewable electricity in 2022, primarily from wood and wood waste. Industrial facilities in western Oregon use woody biomass for power, and about 5% of households rely on wood heating. The state has six wood pellet plants producing 370,000 tons annually, around 3% of the national total [27,29]. Geothermal energy, while making up less than 1% of Oregon’s power, has significant potential. The U.S. Department of Energy ranks Oregon third in geothermal capacity, following Nevada and California. The Cascade Mountains, an active volcanic region, contain an estimated 2200 MW of geothermal electricity potential [27,28].

2.3. Natural Gas

Oregon possesses the sole natural gas field in the Pacific Northwest, namely, the Mist Field in northwestern Oregon, identified in 1979. The Mist Field’s production, while constituting only a minor percentage of the total U.S. output, peaked at 4.6 billion cubic feet of natural gas annually in the mid-1980s [30]. In 2021, annual natural gas production from the field decreased to 205 million cubic feet [18]. The field is devoid of substantial natural gas reserves or production and is utilized mostly for natural gas storage. The Mist Field has multiple subterranean natural gas storage reservoirs. The cumulative capacity of Oregon’s natural gas storage reservoirs is approximately 36 billion cubic feet [18,20]. Natural gas is generally stored during warmer months, when prices and demand are low, and extracted from storage reservoirs during colder months to provide peak heating demand [20].

2.4. Petroleum

Oregon possesses no crude oil reserves or production, and its sole crude oil refinery ceased operations in 2008. The refineries in Puget Sound, Washington, supply over 90% of the refined petroleum products, including motor gasoline, distillate fuel oil (diesel), and jet fuel, utilized in Oregon [31]. Petroleum products are delivered to the state via the Olympic Pipeline and by barge at seven terminals in the Portland area. Utah refineries distribute refined petroleum products to Oregon, while certain petroleum products are transported via tanker or rail from California and Canada. Canadian and North Dakota crude oil exports transit through the Portland port for international transport [31].

3. Energy Consumption Scenarios in Oregon

Oregon’s per capita energy use is lower than in most U.S. states. In 2020, transportation accounted for 30% of the state’s energy consumption (Figure 3), followed closely by the industrial sector [27]. Despite energy-intensive industries like agriculture, food processing, and forestry, most of Oregon’s GDP comes from less energy-intensive service industries. Computers and electronics made up 40% of manufacturing GDP, yet industrial energy use per capita remained lower than in most states. Residential energy use was 25%, while businesses used 20%. Transportation made up 28.6% of consumption but 47% of expenditure due to high fuel costs, whereas, industry accounted for 27.4% of consumption but only 14% of costs [27,32].

4. Opportunity for Powering Trucks

4.1. Heavy Duty EVs/Battery Electric Trucks

Registrations of medium- and heavy-duty electric vehicles in Oregon nearly doubled by January 2023 compared to 2021, driven by the National EV Infrastructure (NEVI) program [16,33]. Transit buses (37%) and delivery vans (44%) make up a significant share of these vehicles. Anticipating further growth [20], Oregon companies are advancing charging infrastructure for medium- and heavy-duty vehicles. Portland General Electric (PGE) and Daimler Truck North America (DTNA) launched the first public charging network for electric heavy-duty trucks [34]. TITAN Freight Systems, in partnership with DTNA, added three Freightliner eCascadia Class 8 battery-electric trucks to its fleet. PGE and DTNA use the “Electric Island” site near DTNA’s Portland manufacturing plant to study high-power charging and grid impact. While MW-level charging is not yet available, the site has a 5 MW capacity for future upgrades [35,36].

Electric Island supports the West Coast Clean Transit Corridor Initiative (WCCTI), which aims to place charging stations every 50–100 miles along major freight routes, such as Interstate 5 [37]. Oregon is set to manage 8 of the 27 planned medium-duty truck charging stations by 2025. The Transportation Electrification Infrastructure Needs Analysis (TEINA) predicts that between 10 and 690 new DC fast-charging stations could be built by 2035, depending on economic conditions [33,38]. Since one third of Oregon’s long-haul trucking miles come from out-of-state, particularly California, long-haul charging infrastructure is crucial. The national medium- and heavy-duty EV market remains in early development, with many vehicles used in demonstration projects [39]. However, sales are expected to grow, influenced by federal regulations mandating a 75% reduction in nitrogen oxide emissions by 2024 and a 90% reduction by 2027 [16,29].

Electric vehicles can regenerate energy while braking, enhancing fuel efficiency, especially in downhill scenarios like mountainous terrain [40]. Simulations by the National Renewable Energy Laboratory (NREL) indicate that the hybrid electric vehicle (HEV) possesses the lowest overall cost powertrain (USD/km) [41]. Figure 4 illustrates the total cost of ownership (TCO) for several vehicle powertrains (Diesel, CNG, HEV, PHEV, BEV, and FCEV) throughout three temporal intervals: 2018, 2025, and “Ultimate”. The “Ultimate” future scenario indicates a further decrease in total cost of ownership (TCO) for battery electric vehicles (BEVs) and fuel cell electric vehicles (FCEVs), potentially rendering them comparable to or less expensive than diesel and compressed natural gas (CNG). This scenario predicts advancements in battery technology, fuel cells, and infrastructure, leading to decreased fuel, maintenance, and operational expenses for all powertrains [41]. The HEV enables a smaller diesel engine to charge a more compact, lightweight, and cost-effective battery. Regenerative brakes on the HEV facilitate the recovery of braking energy, enhancing power efficiency. Multiple Class 8 hybrid electric concepts are undergoing testing in 2024.

4.2. Hydrogen Fuel Cell Electric (FCEV) Trucks

Hydrogen is used as a transportation fuel for fuel cell electric vehicles (FCEVs), however, FCEV ownership remains significantly lower than other electric vehicle types, particularly battery electric vehicles (BEVs). Since 2014, only 18,102 FCEVs have been sold nationwide [42]. BEVs and plug-in hybrid electric vehicles were commercialized earlier, giving them a substantial advantage in market share. Additionally, electric vehicle charging infrastructure has developed much faster than hydrogen fueling networks [43]. As of July 2023, Oregon has no hydrogen fueling stations, whereas, 695 DC fast charging stations exist at 234 locations, with more planned [33,38].

Only three light-duty FCEV models are available for purchase in the U.S., and they are limited to states with hydrogen fueling stations: California, New York, and Hawaii [20]. However, FCEVs are expected to see greater adoption in the medium and heavy-duty (MHD) sector. Electrifying long-haul freight vehicles is challenging due to battery weight, which reduces cargo capacity [20,38]. A battery for an electric semi-truck weighs approximately 16,000 pounds, or 20% of the total truck weight [30]. Hydrogen presents a viable alternative, as FCEVs are lighter and offer advantages such as shorter refueling times (17 min), longer ranges (300 miles), and improved efficiency [44,45]. However, hydrogen remains costly, with most production still reliant on natural gas [46].

4.3. Liquified Natural Gas (LNG) Trucks

As diesel prices continue to rise due to the Middle East crisis and the Russia-Ukraine conflict, natural gas remains a stable and cost-effective alternative [32,47,48]. In addition to cost advantages, quality reduces lifecycle greenhouse gas emissions relative to diesel, improves public health, boosts environmental quality, and offers safety benefits while bolstering a robust transportation system [49]. In 2014, Fred Meyer, a Kroger Co. subsidiary, launched Oregon’s first heavy-duty liquefied natural gas (LNG) truck fleet with 11 vehicles. Later, they expanded their fleet by 40 additional LNG trucks, expected to cut greenhouse gas emissions by 755 metric tons annually equivalent to removing 159 passenger cars from the road each year [50]. In 2016, Republic Services replaced older diesel trucks with 16 compressed natural gas (CNG) garbage trucks in the greater Portland area, increasing their Oregon-based natural gas fleet to 35 vehicles [51]. In 2021, NW Natural (Portland) and Hyliion (Austin) partnered to provide a CNG-electric hybrid Cascadia day cab tractor at no cost to three fleet operators—Baker Rock Resources, Tillamook County Creamery Association, and CalPortland—seeking low-emission alternatives. Hyliion’s e-axle adds 120 horsepower to a Class 8, 12-L CNG semi-truck, enabling it to haul 100,000+ pounds uphill, rivaling diesel performance. Onboard Dynamics supplied a mobile CNG fueling station for on-site refueling [52,53].

5. Limitations on Powering Trucks

5.1. Heavy Duty EVs/Battery Electric Trucks

Heavy-duty electric vehicles (EVs) offer significant potential, but they also face limitations, including lower payload capacity, longer refueling times, higher costs, and restricted driving range [44,54,55]. Battery-electric heavy-duty trucks have the shortest range (62–500 miles) compared to hydrogen fuel cell trucks (660–1104 miles) and diesel trucks (975–1950 miles). Typically, battery-electric trucks can travel 150–300 miles per charge, with the Tesla Semi achieving a maximum of 500 miles—far less than diesel trucks’ 2000-mile range per refill [44,56,57,58]. Battery type and capacity impact range, but increasing battery size reduces payload capacity, affecting profits for trucking companies. A typical electric semi-truck battery weighs about 9 metric tons (25% of total weight). Charging times range from 3–20 h, whereas hydrogen fuel cell trucks refuel in 10–17 min, and diesel trucks take just 6–12 min [44]. Cost remains a major barrier. A diesel heavy-duty truck with a 150-mile range typically costs around USD 119,000, while hydrogen fuel cell trucks range from USD 135,503 to USD 202,112, and battery-electric trucks are priced even higher—ranging from USD 164,641 to USD 335,349, depending on battery size, manufacturer, and features [41,59]. Battery swapping, tested in China, offers a potential solution, with swap times of 3–6 min [60]. However, standardization and adoption remain challenges. Consumer concerns, such as high costs and limited charging infrastructure, also hinder EV adoption.

5.2. Hydrogen Fuel Cell Electric (FCEV) Trucks

The lack of planned or existing fueling infrastructure in Oregon continues to be a major obstacle to the widespread use of hydrogen vehicles. Furthermore, natural gas is used to produce more than 95% of the hydrogen that is now accessible, which means that vehicles that use this fuel have carbon emissions related to the fuel’s manufacture [61]. Although there are technologies available to create green hydrogen from clean electricity, producing hydrogen for use as a transportation fuel is less effective than using that electricity to power a battery directly [62,63]. Because they have not yet reached the 150,000-mile projected lifetime to compete with conventional vehicles, hydrogen fuel cell vehicles are also more expensive than electric vehicles and have reliability and durability issues [44,46,64]. Because of the low level of public awareness, comprehension, and acceptability, fuel cell technology also requires public education. It will take some time for the public to accept this technology as a competitive substitute for traditional automobiles [45]. Because hydrogen is a lighter fuel with greater range, it can help transition transportation sectors including long-haul freight, aviation, and marine that are difficult to decarbonize, despite the infrastructure, efficiency, cost, and durability issues [65].

5.3. LNG Trucks

The liquefaction of natural gas to produce Liquefied Natural Gas (LNG) renders its initial cost prohibitive. Small-scale liquefaction is costly and less efficient compared to larger-scale operations, presenting a challenge for smaller operators [66]. The extremely low temperature characteristics of LNG hamper its processing and handling, as it can freeze any touch surfaces it immediately encounters [67]. The price of LNG is subject to volatility and is significantly affected by weather conditions, market trends, and geopolitical factors [66]. LNG is mostly transported via pipelines; hence, the disparity in pipeline capacity between production and consumption regions necessitates alternative or supplementary transportation methods. The surface transit of LNG entails trucking. Federal law forbids the transportation of LNG by rail, a potentially more economical option than trucks [66]. Furthermore, pipelines incur elevated costs for modifications and repairs. The cost of LNG production and shipment is approximately two to three times greater than that of natural gas [68]. Cambridge Systematics (2019) discovered LNG transit by truck for the year 2016 and found that Oregon exhibited negligible LNG transportation, suggesting a diminished demand for LNG in the state [66]. LNG truck engines have inferior power compared to diesel engines and are incapable of matching their performance when transporting substantial loads on steep inclines [69]. Moreover, LNG vehicles exhibit inferior fuel efficiency, and a reduced driving range compared to diesel trucks.

6. Why Is Liquid Fuel Still Required in Oregon?

Oregon’s economy relies heavily on freight trucks, which transport goods across long distances, often in rural and mountainous areas with limited EV charging infrastructure [38]. Diesel fuel, with its high energy density, allows trucks to travel long distances without frequent refueling [70]. Current electric truck technology, though improving, still lacks the range and refueling speed needed for this sector. Gasoline and diesel have much higher energy densities than current batteries, making them ideal for vehicles that need to operate continuously without frequent stops for recharging [71,72]. This characteristic of liquid fuels supports Oregon’s varied landscape, where distances between destinations and infrastructure are significant, especially in rural areas. Oregon experiences harsh winters and unpredictable weather, particularly in mountainous and coastal areas [73]. Emergency and rescue vehicles, such as snowplows, ambulances, and fire trucks, rely on liquid fuels for their power and dependability in extreme conditions [74]. Diesel engines perform reliably in colder weather, and liquid fuels can be easily stored for emergencies or outages [75].

The average age of a class 8 truck in the U.S. in 2008 was 11.1 years, and by 2018 it had increased to 12.8 years [76]. Therefore, in the near future, there will be a high need for a drop-in fuel substitute. Additionally, there will be a high demand for diesel fuel for off-road and stationary uses including long-lasting forestry and agricultural. The current fleet of diesel trucks will probably get older due to policies like California’s that forbid sales of new diesel trucks beyond a certain date. NREL simulations suggest the hybrid electric vehicle will be the lowest cost class 8 powertrain [41,77]. A renewable diesel drop-in fuel would support both older diesel powertrains as well as the hybrid electric powertrain [78].

Many commercial fleets are holding off on switching to electric vehicles until infrastructure and technology are ready to meet their demands. For practical and financial reasons, many businesses still employ gasoline and diesel due to the upfront expenses, range restrictions, and lengthy recharging times of EVs [79]. Although Oregon’s EV infrastructure is growing, it will take time for the transportation industry to completely transform. Liquid fuels are still necessary until charging stations are widely available, particularly in high-demand locations like rural areas and roads.

7. Thermochemical Processes of Liquid Fuel Production

Lignocellulosic biomass is an abundant and economically viable resource for producing carbon-based materials, playing a crucial role in the transition to a more sustainable energy matrix [80,81]. Currently, it contributes 14% of primary energy in the U.S. and holds significant potential to reduce the country’s dependence on fossil fuels by offering a wide array of bioproducts that can partially replace petrochemicals [82,83,84,85].

There are various methods to process lignocellulosic biomass, with the most common being biochemical and thermochemical routes [86,87,88]. While biological processing has been extensively studied and standardized, it is often selective, producing only a few high-yield products using biological catalysts [89,90,91]. Thermochemical processing, on the other hand, involves chemical changes induced by heat and can produce a wide range of valuable products and byproducts. These processes include pyrolysis, combustion, and gasification, each with distinct operating conditions. Gasification of lignocellulosic material generates syngas, a mixture of carbon monoxide, hydrogen, and methane, which can be converted into olefins or hydrocarbons via processes like Fischer–Tropsch synthesis [92,93]. Syngas can also be converted into methanol, a key energy carrier, using catalytic synthesis in reactors like fluidized bed, entrained bed, circulating bed, and fixed bed gasifiers [90,94,95].

Pyrolysis, the thermal cracking of biomass without oxygen, yields liquids, solids, and gases in varying proportions depending on the pyrolysis type (slow or fast). Fast pyrolysis, conducted at moderate temperatures, has gained attention due to its high liquid yields, reaching up to 80% by weight, making it an attractive option for energy production. Auger and fixed bed reactors are commonly used for fast pyrolysis [95].

While combustion is widely used in industry for heat and electricity generation, its limited product range and pollutant emissions make it less sustainable long-term [96,97,98]. Gasification, closely related to combustion, has seen many demonstration projects but fewer commercially stable units [65,99,100,101]. In contrast, pyrolysis offers a broader product matrix and is expected to contribute significantly to the energy revolution, providing a versatile, efficient, and environmentally acceptable method for biomass conversion [102].

7.1. Pyrolysis Process

Pyrolysis has been used in distilling coal tar and other processes related to obtaining chemical products and fuels [103,104], and in terms of systematic study and application, modern research on pyrolysis began in the 19th century. In an inert atmosphere or with low amounts of oxygen, this thermochemical process can produce liquid, solid, and gaseous fuels simultaneously [105,106,107]. Solid fuels like biochar have an energy use and, due to their carbon structure, allow for the absorption of pollutants and the desorption of beneficial compounds for soil recovery [108,109]. On the other hand, pyrolysis bio-oil (tar or pyroligneous water) is a mixture of chemicals released in the vapor phase and typically condensed for later use [110,111,112]. Some of the substances are water-soluble (aqueous). In contrast, others are not (organic) depending on the processing conditions (fast or slow pyrolysis), the oil can be formed by a single phase or multiple phases [103]. For example, slow pyrolysis is characterized by generating more solids, with biochar being its main product [102]. On the other hand, fast pyrolysis generates more liquid bio-oil [113].

Table 2. Comparison between slow pyrolysis vs. fast pyrolysis.

Features	Slow Pyrolysis	Fast Pyrolysis	References
Temperature (°C)	300–600	500–1000	[103]
Heating rates (°C/s)	0.1–10	10–10,000	[103]
Aeration	Oxygen-free or limited (N2)	Oxygen-free (N2)	[103]
Particle size (mm)	>2 mm	<2 mm	[103]
Residence time (s)	Minutes-hours	Seconds	[103]
Yields	Liquids 30–50 wt.%, biochar 35–25 wt.%, gases 15–25 wt.%	Liquids 60–80 wt.%, biochar 10–20 wt.%, gases 10–20	[103,106]
Target products	Biochar	Bio-oil	[103,106]
Reactors	Fixed bed, auger, rotary kiln	Fluidized bed, ablative, rotary cone, auger	[103,106]
Advantages	The highest yield of biochar can accept a wide range of particle size	A higher yield of bio-oil	[103,106]
Disadvantages	Further treatment of gases is needed due to high CO concentrations	Low biochar yield, fine particle size, biomass with low moisture content (<10%)	[103,106]

shows the comparison between slow and fast pyrolysis.

Several studies reported that fast pyrolysis can produce between 60% and 75%, even 80%, by weight of bio-oil, which can be used directly in many applications or as an energy carrier after upgrading [103,114,115,116]. Likewise, studies have reported that various conditions, such as raw material, reactor type, temperature, additives, catalysts, residence time, and pressure, greatly influence the yield and quality of the product [113,117]. The bio-oil obtained by fast pyrolysis contains oxygen-rich compounds and water, making it unstable and hindering its direct use. It is necessary to improve deoxygenation to make it compatible with refined fuels [118]. This is why a subsequent refining stage through catalysis is required to convert wood into liquid fuels through pyrolysis. The kinetics and mechanisms of pyrolysis have been extensively studied [119,120,121,122,123]. For decades academic and industrial research has worked to better understand the underlying mechanisms of pyrolysis and develop efficient technical processes, however, there is less focus on catalytic upgrading to generate fuels or chemicals. Fast pyrolysis remains less understood regarding the resulting products. Fast pyrolysis produces a complex yet versatile mixture that is available for use in a variety of industrial applications. Numerous efforts are being carried out worldwide to find new processing routes and synthesize new components to replace derivatives of the current petrochemical industry [124], being the main goals to achieve high yields of desired products, especially quality bio-oil and identification of new compounds [114,125].

7.2. Challenges of Processing Pyrolysis Oil

The bio-oil produced through biomass pyrolysis presents some differences and challenges compared to conventional heavy oil or heavy crude derived from petroleum. Unlike conventional heavy crude oil, bio-oil contains a complex mixture of organic compounds with various boiling points and variable physicochemical properties [105,126,127]. This can make its processing and refining challenging and its direct use in applications requiring a homogeneous and high-quality fuel or lubricant [128]. Another significant difficulty is the stability and degradation of bio-oil. Due to its diverse composition and the presence of less stable compounds, bio-oil may experience storage and transportation issues, as well as a higher propensity for chemical degradation and the formation of unwanted products during prolonged storage or processing [129,130]. Despite these challenges, bio-oils are fuels that, once ignited, burn with a stable and self-sustaining flame. Although their viscosity can be reduced by moderate preheating or the addition of polar solvents, storing them at elevated temperatures can increase viscosity over time due to chemical reactions among the compounds in the oil [126]. Additionally, the corrosiveness of bio-oil can affect common construction materials [131], although they are generally non-corrosive to stainless steels [132,133]. These characteristics significantly affect their behavior during combustion and their applicability in energy production in standard equipment, and further research is required to address these challenges and maximize the potential of bio-oils as a renewable alternative to fossil fuels [134,135].

Several studies related to bio-oil production composition show that bio-oil can contain more than 400 compounds [136,137,138,139]. However, it remains a challenge to identify each compound in a bio-oil sample. From a chemical perspective, bio-oil is a highly complex mixture of organic components derived from cellulose, hemicellulose, and biomass components from lignin pyrolyzes, such as organic acids, esters, alcohols, aldehydes, ketones, furans, phenols, and dehydrated carbohydrates [103]. Pyrolysis oil obtained from this complex mixture of organic compounds has inferior characteristics for direct use in existing combustion and utilization equipment due to its high oxygen and moisture content, high viscosity, and acidity, as well as low stability and calorific value compared to conventional oil [139]. Therefore, finding the best working conditions in lignocellulosic biomass pyrolysis and the most suitable pretreatment is crucial for process implementation [94].

7.3. Pyrolysis Conversion Technologies for Fuel Production

Many reactors have been designed for pyrolytic formation of high-quality bio-oil and gas [140]. There are many types of reactors, such as fixed-bed reactors, fluidized bed reactors, ablative, vacuum, rotary cone, and screw or auger, and numerous variations of these that operate under the same principle in the quest to optimize production and reduce costs [103,140]. Several authors have classified this type of reactor according to heating rates, particle residence time, and vapor residence time within the reactor. Fast pyrolysis reactors promote high heating rates (>100 °C/s) with particle sizes <2 mm and vapor residence times of 1–2 s. These reactors, such as fluidized bed reactors, are designed to maximize bio-oil yield [103,115,130].

Table 3. Yields for different wood waste feedstock pyrolysis conversion technologies.

Biomass	T °C	Yield (wt.%)			References
		Char	Bio-Oil	Gas
Rotary kilns
Pinon-juniper wood	500	30	59	11	[145]
Fir pellets	500	23	62	16	[146]
Shredded pine	500	30	58	12	[147]
Pine bark	500	34	36	30	[148]
Auger pyrolysis
Oak	450	20	50	30	[149]
Pinewood chips	500	30	58	12	[95]
Douglas fir wood	400	12	48	40	[150]
Oak bark	450	27.8	49.6	-	[149]
Fluidized bed reactors
Pine wood chips and pellets	530	10	59	28	[141]
Pitch pine	500	16	64	21	[151]
Pine sawdust	525		67–71		[152]
Spruce sawdust	500	12	78	8	[153]
Japanese cedar	500	13	66	22	[151]
Red oak	400	21	67	13	[154]
Poplar sawdust	504	12	77	11	[155]
Beech	510	13	72	9	[156]
Eucalyptus loxophleba wood	450	14	71	14	[157]
Fixed beds
Pine chips	500	31	50	18	[158]
Douglas Fir	500	22	66	8	[159]
Red oak	500	24	67	8	[159]

shows the yields for different pyrolysis conversion technologies. Although all these technologies have great potential for liquid production, some require specific control and are still in development or at pilot scales. Fluidized bed reactors have received the most attention from researchers due to their proven ability to produce high-quality bio-oil due to the excellent surface contact between biomass and the bed under fluidization conditions [94,141]. Additionally, fluidization theory has been consolidated over the years [142,143,144], and this type of reactor is commercially available and installed in a wide range of industries, from petrochemicals to pharmaceuticals. Comparisons of different reactors in fast pyrolysis, including auger, batch, and fluidized bed, have been conducted, concluding that fluidized bed reactors yield more bio-oil [142]. Therefore, although numerous fast pyrolysis technologies exist, fluidized bed reactors offer the best overall performance guarantees for obtaining high-quality bio-oil, and their flexibility can be applied to other thermochemical processes, such as coprocessing with household or industrial waste and gasification [143].

According to these yields, several technologies can be used for bio-oil production. Nevertheless, as shown in

Table 4. Pyrolysis technologies for different types of bio-fuels production.

Feedstock (Dry Ton per Year-DTPY)	Pyrolysis Reactor	Upgrading Technology	Products	References
Blended woody, 2000	Dual fixed bed	Hydrotreating, hydrocracking, catalysis	Gasoline and diesel range products	[160]
Blended (45% pulpwood, 32% woody residues, 20% construction, and demolition waste), 2000	Circulating Fluidized bed	Hydrotreating, hydrocracking, catalysis Zeolite-HZSM5	Gasoline and diesel range products	[161]
Corn stover, 2000	Fluidized bed reactor	Hydrotreating using molybdenum-cobalt catalysis, hydrocracking using nickel-molybdenum catalyst	Naphtha and diesel range products	[162]
Hybrid poplar 2000	Circulating Fluidized bed	Dual stage hydrotreating using cobalt molybdenum catalyst	Gasoline and diesel range products	[163]
Hybrid poplar 2000	Circulating fluidized bed reactor	Dual stage hydrotreating using cobalt molybdenum catalyst	Gasoline and diesel range products	[164]
Corn stover, 2000	fluidized bed reactor	Two-stage hydrotreating (Ru/C and Pt/C catalysts) followed by fluid catalytic cracking (HZSM-5 zeolite)	Olefins and aromatics	[165]
		One-stage hydrotreating (Ru/C catalyst)	Gasoline and diesel range products
Mixed wood 2000	fluidized bed reactor	Multistage catalytic upgrading and zeolite cracking	Olefins and aromatics (benzene, toluene, ethylene, propylene, butylene, xylene)	[166]
Woodchips, 550	fluidized bed reactor	None	Pyrolysis oil, gas, and char	[140]
Norwegian spruce, 2000	Circulating fluidized bed reactor	Integrated hydrotreating (Mo and Ni nano sulphide catalysts) and hydrothermal liquefaction/H2 production from water-soluble bio-oil	Gasoline and diesel range products	[167]
Pine chips, 2000	Circulating fluidized bed reactor	None	Pyrolysis oil, gas, and char	[168]
Pinewood, 72	fluidized bed reactor	Two-stage hydrotreating (Ru/C and Pt/C catalysts) followed by fluid catalytic cracking-HZSM-5 zeolite)	Gasoline and diesel range products	[169]
Equine waste, 6–15	Combustion Reduction Integrated Pyrolysis	None	Diesel range products	[170]
Corn stover, 2000	fluidized bed reactor	Hydrotreating (cobalt-molybdenum catalyst) Hydrocracking	Gasoline and diesel range products	[166]
Hybrid poplar 2000	Circulating fluidized bed reactor	Multistage catalytic upgrading and zeolite cracking.	Olefins and aromatics	[171]

regarding bio-oil production, fluidized bed reactors maintain a prominent position due to their confluence of advantageous attributes. In addition, Table 4 relates to different studies to produce biofuels from other feedstock, and it is not causal that most of these studies involve fluidized bed reactors.

The use of fluidized bed reactors for bio-oil production is driven by heat and mass transfer dynamics. Inert particles, such as sand, ensure uniform temperature distribution and efficient interaction between biomass and the heat-transfer gas, optimizing pyrolysis and minimizing charcoal and gas output. Fluidized beds’ scalability allows them to process a wide range of feedstocks, from woody biomass to agricultural residues, across various scales, from pilot plants to industrial facilities. This scalability is essential for biomass conversion projects. NREL’s studies highlight fluidized bed reactors, demonstrating their cost-effectiveness and commercial viability in bio-oil production across different reactor designs, as shown in

Table 5. Bio-oil production cost and investment costs for different plant sizes.

Plant Size (ton/d)	Feed Cost (USD/dry ton)	Bio-Oil Cost (USD/gal)	Total Capital Investment	Reactor Type	References
2.4	USD 22	USD 1.73	USD 97,000	Fluidized bed	[172]
24	USD 22	USD 0.82	USD 389,000	Fluidized bed	[172]
100	USD 36	USD 1.21	USD 6.6 million	Fluidized bed/Circulating fluid beds	[173]
200	USD 36	USD 0.99	USD 8.8 million	Fluidized bed/Circulating fluid beds	[173]
400	USD 36	USD 0.89	USD 14 million	Fluidized bed/Circulating fluid beds	[173]
1000	USD 44	USD 0.50	USD 46 million	Vortex pyrolizer	[174]
250	USD 44	USD 0.50	USD 14 million	-	[162]
1000	USD 20–USD 42.50	USD 0.59	USD 44–143 million	Thermal liquefaction	[175]
		USD 2.46
250	USD 11	USD 0.46	USD 14 million	Fluidized bed	[176]
1000	USD 44	USD 0.41	USD 37 million	Fluidized bed	[176]

.

Pyrolysis in a fluidized bed is an excellent alternative to produce bio-oil. Fluid dynamics within the bed promote self-cleaning, mitigating fouling and agglomeration, and notorious problems in other technologies. This extends the operational lifespan and maintains product quality by preventing unwanted soot contamination. Additionally, fluidized beds offer inherent safety due to excellent temperature control achieved by manipulating the fluidizing gas flow. This controlled environment minimizes uncontrolled reactions and thermal decomposition, which is crucial for safe and stable operation. Finally, the co-production of heat from coal combustion within the bed offers an energy-efficient solution. This internal heat generation reduces external energy demands, contributing to the sustainability and economic viability of the bio-oil production process. The research will focus on the pre-processing of biomass and the exploration of new operating conditions that include the use of novel catalysts for the in-situ removal of pollutants or oxygen to promote higher yield and better quality of bio-oil.

8. Oregon Legislation

8.1. Oregon Clean Fuel Program (CFP)

In 2016, Oregon’s Clean Fuels Program (CFP) was introduced as a component of the Pacific Coast Collaborative Climate Plan and its plan to reduce greenhouse gas emissions [16]. Within ten years, the CFP seeks to reduce the greenhouse gas intensity of transportation fuels by 10%, based on California’s Low Carbon Fuel Standard (LCFS) [13]. The program encourages the creation and use of automobiles and alternative fuels that produce fewer greenhouse gas emissions than conventional petroleum-based technologies [177]. For transportation fuels, it creates a standard for carbon intensity (CI), which is expressed in grams of CO₂ equivalent per megajoule (gCO₂e/MJ). New targets to lower CI from 2015 levels by 20% by 2030 and 37% by 2035 were established in 2022 [16,24,178]. Fuel lifecycle emissions are evaluated from production to combustion, taking into account effects from the extraction and refinement of raw materials. Fuels below the CI target receive credits, while those beyond it suffer deficits. By allowing for credit trading, a market for carbon credits is established, bringing in money for manufacturers of low-carbon fuel.

8.2. Climate Protection Program (CPP)

In 2021, Oregon launched its Climate Protection Program (CPP) to diminish greenhouse gas emissions, alleviate air pollutants, and enhance public health, especially in communities facing environmental injustices, including communities of color, low-income populations, tribal groups, and rural areas [179]. The CPP mandates that covered entities diminish greenhouse gas emissions and mitigate other detrimental pollutants. This initiative is integral to Oregon’s comprehensive policies designed to combat climate change. CPP utilizes two primary strategies: establishing enforceable, diminishing emission restrictions on fossil fuel consumption and implementing optimal emissions reduction methods at designated sites, including industrial operations [22]. Suppliers of natural gas, gasoline, diesel, kerosene, and propane are required to adhere to emission limits if they surpass certain criteria. Eventually, these caps will collect over 99% of combustion emissions from liquid fuels including propane in Oregon. Furthermore, facilities that release 25,000 metric tons of CO₂ equivalent (MT CO₂e) per year are incorporated into the program [21]. In December 2023, the Oregon Court of Appeals annulled the CPP on account of procedural deficiencies. The state intends to introduce new legislation in 2024, designed to reintroduce climate mitigation measures and diminish emissions from stationary sources and transportation fuels, commencing in 2025 [23].

8.3. Advanced Clean Trucks (ACT) Rule

The Advanced Clean Trucks (ACT) Rule represents a pivotal regulatory measure aimed at transitioning medium- and heavy-duty truck fleets from conventional internal combustion engine (ICE) technology to zero-emission vehicle (ZEV) alternatives, including battery-electric and hydrogen fuel cell-powered trucks [180]. Implemented by the Oregon Department of Environmental Quality (DEQ) in alignment with broader decarbonization goals, this rule mandates that manufacturers progressively increase their zero emission vehicle (ZEV) sales beginning with the 2025 model year [181]. The regulation applies to newly manufactured on-road vehicles exceeding a gross vehicle weight rating (GVWR) of 8500 pounds, with annual sales requirements that escalate over time [180,181]. The ACT Rule establishes a structured trajectory for fleet electrification, with sales targets differentiated by vehicle class and model year, culminating in 75% ZEV adoption for specific truck categories (Class 4–8 rigid) by 2035 [181]. This regulatory framework is designed to significantly reduce greenhouse gas (GHG) emissions and mitigate air pollution from diesel exhaust, which has been linked to adverse environmental and human health impacts [22,182]. However, given the persistence of legacy ICE fleets, the policy anticipates a gradual integration of ZEVs into existing transportation networks, necessitating advancements in charging and hydrogen refueling infrastructure to support widescale adoption [20,64].

9. Discussion and Conclusions

The heavy-duty trucking industry in Oregon is seeing a significant shift, with electrification becoming a primary answer. The increasing utilization of battery electric trucks (EVs), bolstered by programs such as the National EV Infrastructure (NEVI) program, underscores substantial advancement in this area. Initiatives like Portland General Electric and Daimler Truck North America’s “Electric Island” highlight the possibility for developing a comprehensive charging infrastructure crucial for expanding medium- and heavy-duty electric vehicle deployment. Nonetheless, obstacles remain, such as restricted driving ranges, prolonged charge durations, diminished payload capacities attributable to battery weight, and substantial initial expenses. Although these constraints constrain the feasibility of electric vehicles for long-distance travel, infrastructure projects such as the West Coast Clean Transit Corridor Initiative seek to alleviate these challenges and expedite Oregon’s shift to zero-emission freight transportation.

Hydrogen fuel cell electric vehicles (FCEVs) offer a promising alternative for long-haul trucking due to their longer range, lighter weight, and faster refueling capabilities compared to battery-electric trucks. However, the current lack of hydrogen fueling infrastructure in Oregon, combined with high vehicle and fuel costs, presents substantial barriers. Additional challenges include environmental concerns over hydrogen production and limited public awareness. In parallel, liquefied natural gas (LNG) trucks provide a lower-emission interim solution but face hurdles such as higher fuel costs, lower engine performance, and logistical complexities in LNG distribution. Oregon’s clean trucking future will likely require coordinated investments in both electric and hydrogen infrastructure, with LNG serving as a transitional technology.

Thermochemical processes, particularly pyrolysis, play a central role in advancing the production of sustainable liquid fuels from lignocellulosic biomass. Biomass is becoming an increasingly valuable resource for reducing reliance on fossil fuels and lowering greenhouse gas (GHG) emissions. Among thermochemical methods, fast pyrolysis holds significant potential, producing bio-oil in yields as high as 80%. However, bio-oil requires further refinement to address challenges such as instability, high oxygen content, and compatibility with conventional fuel systems. Continued research on deoxygenation processes and catalytic upgrading is essential to enhance its viability as a drop-in fuel option.

While Oregon’s Clean Fuels Program (CFP) and Climate Protection Program (CPP) are foundational to the state’s transportation decarbonization strategy, their implementation in the heavy-duty trucking sector is not without significant challenges. These challenges arise from a combination of market limitations, regulatory uncertainty, infrastructure readiness, and stakeholder constraints, particularly among small and mid-sized fleets. One of the key barriers to CFP implementation is the limited in-state production and availability of low-carbon fuels, particularly renewable diesel and biomass-based drop-in fuels. Although the CFP incentivizes fuels with lower carbon intensity (CI), Oregon currently relies heavily on renewable diesel imported from California, exposing the market to regional supply disruptions and price volatility. This dependency hinders fuel security and limits the scalability of CFP incentives in rural areas and long-haul freight corridors where fuel switching is most needed.

Furthermore, fleet fragmentation poses a structural challenge. Many trucking companies operating in Oregon are small, independently owned businesses that lack the capital to invest in alternative fuel infrastructure or to navigate the CFP credit market. Accessing credits, monetizing them, and ensuring compliance requires administrative resources that many smaller operators do not possess. These risks exacerbate inequities and limit the policy’s reach. The Climate Protection Program (CPP)—designed to impose declining caps on GHG emissions—has encountered legal and political resistance since its introduction. In 2022, legal action temporarily halted the implementation of the program, creating uncertainty for regulated parties. For fleet operators and fuel suppliers, such instability undermines investment planning and weakens confidence in long-term regulatory support for low-carbon alternatives. In addition, the lack of strong integration between CPP emission caps and the CFP’s market-based credit system may lead to duplicative compliance burdens or conflicting incentives.

Finally, drop-in fuels represent a vital transitional solution for Oregon’s existing and future technologies. These fuels can complement the electrification and hydrogen-based strategies, particularly in extending the life of existing heavy diesel trucks and stationary equipment in remote areas. Hybrid electric Class 8 trucks, as suggested by NREL, may serve as the lowest total cost option for the coming decades, bridging the gap between current systems and a fully sustainable future.

While Oregon has made commendable progress in electrifying its heavy-duty trucking sector, particularly through programs like the National EV Infrastructure (NEVI) initiative and demonstration projects such as Electric Island, the current transition strategy is heavily reliant on long-term zero-emission technologies. Battery electric trucks (BEVs) and hydrogen fuel cell electric vehicles (FCEVs) face considerable deployment barriers, including limited driving range, high capital costs, inadequate infrastructure, payload penalties, and charging or refueling delays. These limitations hinder their immediate scalability, especially for long-haul freight applications and rural operations where electrification is less feasible. At the same time, the potential of drop-in low-carbon fuels—such as renewable diesel, biodiesel, and synthetic fuels—remains underutilized. These fuels can be integrated seamlessly into existing diesel engines and fueling networks, providing an effective near-term solution for reducing greenhouse gas (GHG) emissions by up to 80%. However, despite these advantages, drop-in fuels represented only 15% of Oregon’s heavy-duty diesel consumption in 2023. The lack of focus on these fuels in current research and policy frameworks creates a gap in Oregon’s decarbonization strategy.

Specifically, there is limited analysis on how drop-in fuels can bridge the emissions gap between now and 2035, while BEV and FCEV adoption scales. Furthermore, challenges such as sustainable feedstock supply, fuel production scalability, and long-term policy support are not comprehensively addressed. A deeper investigation into the feasibility, barriers, and strategic role of drop-in fuels is essential to ensure Oregon meets its interim climate goals without relying solely on technologies that may take decades to fully mature.