Prevalence of Fossil Fuels for Transportation
Reducing Greenhouse Gas Emissions
The United States has a “Statement of Intent” to be carbon neutral by 2050,1 meaning carbon dioxide output is to have a net neutral impact to the environment. Since all fossil fuels are carbon based, they will always produce CO2 upon combustion and are therefore incompatible with this intent. Carbon capture and sequestration (CCS) can be used to reduce CO2 emissions at the source, and some producers are planting trees to offset some of the carbon emissions. However, to fully meet the intent, the U.S. will need to invest heavily in renewable energy.
Emissions are considered “well-to-wheel”, that is at every step along the way from sourcing the feedstock, processing it into transport fuel, and consumption in the vehicle. Oil and gas companies can become carbon neutral for direct emissions from company operations and indirect emissions from consumed energy.4 Carbon intensity (amount of carbon by weight emitted per unit of energy consumed5) of petroleum-based products can be reduced by mixing biologically made renewable fuels with the petroleum fuels. The feedstocks for renewable fuels include various plants and animal fats. Blue hydrogen (produced from petroleum-based sources, but the carbon is captured and sequestered) or green hydrogen (produced entirely from non-petroleum-based sources) can be used for refinery hydroprocessing.
Renewable fuels facilities can be incorporated into existing refinery facilities. A refiner may consider a retrofit to existing hydroprocessing facilities to process renewable feedstocks into renewable fuels. It is possible and economically advantageous with government credits to process the renewable fuels in a mixture with petroleum-based fuels. Incorporating the use of green sources of energy such as wind or solar or re use of waste gases for the production of the petroleum-based fuel uses renewable energy in the existing transportation fleet.
A knowledgeable engineering firm can work with owners and licensors to deliver process units capable of meeting the renewable fuels requirements. Ascent Engineering is ideally positioned to evaluate existing equipment for retrofit as well as new processes and to strike the balance between the licensor’s requirements and the refiner’s existing assets.
Gasoline, Octane, and the Open Road
Gasolines from different crudes along with blending of cracked gasolines led to wide variations in the performance of automobile and aviation engines. Since crude compositions vary widely, the quality of the straight run gasolines also varied widely. Early gasoline was rated based on Baume scale and volatility.
Abnormal combustion is a phenomenon where the gasoline vapor burns by heat and compression prior to the spark from the spark plug. This pre-ignition can lead to hot running engines with reduced power and potential damage due to “knock”. Different gasolines have different resistance to abnormal combustion. Aromatic and naphthenic gasolines, with their higher octanes, have higher resistance to knock than paraffinic gasolines.
Until 1929, there was no consistent standard for gasoline quality. In 1929, the octane rating scale was adopted. Octane is a measure of how much compression gasoline can withstand before igniting. A higher octane number can handle higher compression and is less likely to suffer pre-ignition. Octane of gasoline is measured against a mixture of iso octane (2,2,4-trimethylpentane) and n heptane. Iso octane is assigned an octane number of 100 while n heptane is assigned an octane number of 0. The octane of gasoline is measured by running it in a test engine with variable compression ratio. The test results are compared to mixtures of iso octane and n heptane. RON is the Research Octane Number and is determined by running the fuel in a test engine at idle conditions. MON is the Motor Octane Number and is determined by running the fuel in a test engine at higher speeds and temperatures. The octane number reported at the gas pump is the average of the two, or (R+M)/2.
EPA and the Clean Air Act
Tetraethyllead (TEL) was used for many years to increase the octane of gasoline. The increased octane using TEL allowed the development of more efficient engines with higher compression ratios. Unfortunately, TEL is toxic and the effects of lead poisoning in children and emissions to the environment were the primary reasons for the phase out. Worldwide, TEL phase out from road gasoline began in the 1970s. Japan was an early adopter of unleaded gasoline and stopped using leaded gasoline by 1980. Many other countries such as Canada and much of Europe had completed TEL phase out by the mid-1990s including the United States by 1996.8
MTBE (Methyl tertiary-butyl ether) was introduced as an oxygenate to improve combustion and reduce tail pipe emissions. The miscibility of MTBE with ground water has caused its use to be discontinued in the U.S. MTBE can be tasted in water at very low concentrations. Health risks associated with MTBE have not been quantified, but it is believed to be a human carcinogen.
Ethanol has been around for well over a hundred years as a fuel source and its use as a gasoline additive has waxed and waned over the years as driven by wartime needs and taxes.9 Ethanol is a high octane oxygenate as well as a renewable energy source. The production and consumption of ethanol is part of the renewable energy requirement in today’s regulatory environment and it is by far the largest volume of renewable fuel stock in the United States.
Automobile fuel economy requirements are driving improvements in engine efficiency. The current U.S. federal Corporate Average Fuel Economy (CAFE) requirement is that the industry fleet wide average mileage for cars and light duty trucks be 40.4 mpg by 2026.10 On the manufacturing side, the industry is trending towards smaller engines. The smaller displacement (as well as reduced weight) help improve fuel economy, while modern technology can exact as much or more power from the smaller displacement engines. On the fuel side, automobile manufacturers such as General Motors are asking for improvements in fuel performance in order to help maximize engine efficiency. This would include higher octane fuel with higher RON and higher sensitivity (RON-MON). In lay terms, higher sensitivity means more stability at low temperatures and faster reactions at high temperatures to allow for high compression engines.11
As mentioned above, ethanol is commonly blended into gasoline as an oxygenate to reduce emissions. It can be produced from any number of renewable feedstock sources. In the U.S., ethanol is commonly produced from corn. Because ethanol counts as renewable fuel and is already so readily available, there is incentive to use more of it in gasoline blends. The most common ethanol blend contains up to 10% ethanol (E10), although in 2011 the EPA allowed use of up to 15% ethanol (E15) in automobile models from 2001. Gasoline with 85% ethanol (E85) is also available for automobiles which are specifically designed for it (flex fuel). Because ethanol is such a good solvent, specially designed fuel injection systems are required to prevent corrosion. Additionally, because ethanol has an oxygen atom, therefore it is a partially oxidized hydrocarbon, it contains less energy upon combustion than a non-oxygenated hydrocarbon. E10 gasoline typically has a 3 to 4% lower fuel mileage than 100% gasoline. E15 gasoline mileage is typically 4 to 5% lower than 100% gasoline. E85 gasoline can have 51 to 83% ethanol and 15 to 27% lower mileage.12
Industrial and European Workhorse
Conventional Diesel, Biodiesel, Renewable Diesel, and the Future
It is important to note that there are a number of terms surrounding diesel fuel that oftentimes get confused. Conventional diesel is traditional, petroleum-based diesel that is made from crude oil in an oil refinery. Biodiesel is not sourced from fossil fuels; rather it comes from renewable sources such as vegetable oils or animal fats. It is produced by a process called transesterification, or reaction of a glyceride and an alcohol (usually methanol) to make biodiesel (fatty esters) and glycerol. Biodiesel properties differ from conventional diesel in that biodiesel solidifies at cold temperatures, may separate during storage, and most importantly, the chemical structure differs enough that biodiesel cannot be used as a stand-alone substitute for conventional diesel fuel – it must be blended prior to use in traditional diesel engines. Finally, while renewable diesel is sourced from the same feedstocks as biodiesel, the process to produce it is more like that of conventional diesel. Because renewable diesel sees the same hydrotreating processes as conventional diesel, it has the same chemical structure as conventional diesel and can be used without blending. Renewable diesel does not contain oxygen and thus does not have the same cold and storage issues as biodiesel.
Renewables Mandates and Impact to Markets
- The Renewable Fuel Standard (RFS) is set by the Environmental Protection Agency (EPA) on the national level.
- Any of a number of carbon fuels programs adopted on the state government level. Current programs in effect and other state progress as of Q2 2021 include the following:
- California – Low Carbon Fuels Standard (LCFS) – currently in effect
- Oregon – Clean Fuels Program (CFP) – currently in effect
- Colorado – GHG Reduction Roadmap has been established, but its feasibility study on carbon fuels program concluded not to adopt. Instead, a zero emission vehicle mandate is part of the roadmap.
- Utah – Air Quality Roadmap has been established, but acts as a loose guideline with no call out of a carbon fuels program. Zero emission vehicle focus is called out in the roadmap.
- New York – State Senate Bill S2962A establishes the Clean Fuel Standard and is in committee.
- Washington – State House Bill 1091 establishes the Clean Fuel Standard and State Senate Bill 5126 establishes a carbon cap-and-trade program and both have passed through voting committee. The programs will be in effect January 2023 once signed by the governor.
- Minnesota – State House Bill HF 2083 dubbed the “Future Fuels Act” was introduced in the Minnesota House of Representatives and referred to the House Committee on Commerce, Finance and Policy.
Unless otherwise noted, any reference to a low carbon fuels program in this text refers to the California LCFS program as they are the largest market for carbon credits.
The subtle difference between the federal RFS program and the California LCFS program is that the RFS program is aimed at directly setting renewable fuel volumes, driving the demand for the national bulk production and use of renewable fuels, with concomitant reduction in greenhouse gas (GHG) emissions. The LCFS program is aimed at directly setting carbon volumes, as opposed to renewable fuel volumes, and requires a more stringent carbon accounting in the life cycle of the final fuel product.
The RFS and LCFS programs financially impact refiners and importers of gasoline and/or diesel sourced from petroleum. Both of these programs are designed to incentivize renewable fuel production and carbon emission reduction. Both programs introduce a supply-and-demand market of credits. Both programs put petroleum-based refiners and importers into a deficit position, creating the “demand” of renewable fuel and carbon credits. The “supply” of the credits comes from entities that generate a renewable fuel with a proven pathway of reduced GHG emissions compared to petroleum-based fuels.
In the RFS program, refiners must either purchase credits (referred to as Renewable Identification Numbers, or RINs) or physically blend renewable fuels into their gasoline and diesel fuel pool to meet compliance. Furthermore, the RFS program requires four different categories of renewable fuels to blend as part of meeting compliance. These four categories include fuels derived from cellulosic, biomass, advanced, and renewable feedstocks.
In the LCFS program, the main focus is carbon emissions attributed to the life cycle pathway to generate gasoline and diesel. Every year, the California Air Resources Board (CARB) updates the CI (carbon intensity) scores of California fuels (CARBOB, or California Reformulated Gasoline Blendstock for Oxygenate Blending, and ULSD) and this sets the emissions life cycle of gasoline and diesel fuel sold in California, and for all obligated parties to which it is subject. The CI scores of these fuels are relatively high due to being sourced from carbon emitting intensive processes. The LCFS program sets a CI benchmark reduction target for these fuels, for which a delta in CI score between the higher CI fuel and lower CI benchmark exists, creating the deficit position and “demand” for credits. Entities that provide alternative fuels with a proven life cycle pathway CI score lower than the benchmark is the “supply” of credits to which obligated parties in a deficit position can purchase. CARB offers programs for obligated parties to consider in order to offset their deficit position.
Renewable Fuel Standard (RFS)
The RFS program is a national policy that requires a certain volume of renewable fuel to replace or reduce the quantity of petroleum-based transportation fuel. The Energy Independence and Security Act of 2007 (EISA) specifies the total RFS volume requirements through the year 2022. The long-term goal is 36 billion gallons annually (2.35 million BPCD or 11.2 million m3/m) of total renewable fuel by 2022. The law requires EPA to set RFS volumes for 2023 and beyond, according to certain criteria defined in the statute. Figure 1 below shows the RFS EPA congressional volume targets.18 The detailed tabulated values can be found on the EPA website. Obligated parties under the RFS program are refiners or importers of gasoline and/or diesel fuel. Based on the renewable fuels volume targets in the graph above, this sets a regulated party’s Renewable Volume Obligation (RVO), the deficit position. Compliance is achieved by blending renewable fuels into transportation fuel or by obtaining credits called Renewable Identification Numbers (RINs) to meet the EPA-specified RVO. To be explicit, the regulated party is obligated to blend and meet each of the four different types of renewable fuel targets into their fuel pool. The EPA sets the RVO requirement and refiners or importers must demonstrate compliance annually. For example, a transportation fuel sourced from 100% fossil fuel will not meet compliance. The refiner or importer must purchase a renewable fuel source under the RFS program with RINs attached and blend it into the transportation fuel to meet the annual RVO. It is also possible to purchase RINs as credits to meet compliance.
There are four different categories of renewable fuels that the RFS program mandates for obligated parties to blend into their fuel pool. The RVO for each of these four categories must be met for each compliance year. The four categories are essentially categorized by a combination of the feedstock and minimum GHG emission reduction requirement. The four categories and their accompanying RIN codes are as follows, arranged from more advanced RINs to less advanced RINs:
- Cellulosic Biofuel (D3) / Cellulosic Diesel (D7) – 60%+ GHG Reduction
Example Feedstock: Corn stover, wood chips, miscanthus, biogas
- Biomass-based Diesel (D4) – 50%+ GHG Reduction
Example Feedstock: Soybean oil, canola oil, waste oil, animal fats
- Advanced Biofuel (D5) – 50%+ GHG Reduction
Example Feedstock: Sugarcane, biobutanol, bionaphtha
- Renewable Fuel (D6) – 20%+ GHG Reduction
Example Feedstock: Corn starch
- RIN codes D3 Cellulosic Biofuel and D7 Cellulosic Diesel can count for Advanced Biofuel and Renewable Fuel
- RIN code D4 Biomass-based Diesel can count for Advanced Biofuel and Renewable Fuel
- RIN code D5 Advanced Biofuel can count for Renewable Fuel
More RINs can be generated from higher energy content fuel compared to ethanol as the base fuel. A single RIN has the energy equivalency as 1 gallon of ethanol, hence renewable fuels with higher energy content than ethanol can generate more than 1 RIN per gallon. For example, biodiesel can generate 1.5 RIN, renewable diesel can generate 1.7 RIN, and butanol can generate 1.3 RIN.
Table 1: D-Code Compliance to the Four Fuel Categories
|D-Code||Cellulosic Biofuel||Biomass-Based Diesel||Advanced Biofuel||Total Renewable Fuel|
- Feedstock production and transportation
- Fuel production and distribution
- Use of the finished fuel
Electricity Emission Factors – eGRID
Specific only to the RFS program, the lifecycle GHG analysis uses the EPA Emissions & Generation Resource Integrated Database (eGRID), where the U.S. is divided into electrical grid regions. Electricity emission factors are an average grid basis that includes the mix of various electricity generation sources. The eGRID is a comprehensive source of data on the environmental characteristics of almost all electric power generated in the United States and is updated periodically. Figure 3 below depicts the eGRID subregions of the U.S. and provides the corresponding CO2 emitted based on the source profile mix. The following Figure 4 and Figure 5 depict a breakdown of the electricity source profile of each region and the corresponding average CO2 emissions.
The eGRID data presented here highlight the fact that the majority of the U.S. electrical grids are currently powered by carbon based sources. California is typically touted to be the green initiative state, and with nearly 50% of the electricity generation powered by natural gas, it has one of the lowest carbon emission rates in the nation. A majority of other U.S. regions have electricity generation portfolios with higher exposure to fossil fuels. From the standpoint of achieving nationwide net zero carbon emissions, a significant overhaul in the U.S. electrical infrastructure is required to support lower CO2 emissions for general electrical use and for transportation use in electric vehicles. Renewable fuels are an interim pathway to achieve lower CO2 emissions for the existing internal combustion engine fleet.
Low Carbon Fuel Standard (LCFS)
The carbon intensity is a metric used to measure the carbon emitted per unit of energy consumed throughout the life cycle pathway of a fuel source. Note that the CI score referenced under LCFS program (typically in units of gCO2e/MJ) can be loosely compared to the RFS lifecycle GHG analysis results (typically in units of kgCO2e/MMBtu), but both are calculated by different methodologies.
Carbon intensity is important to regulated parties because CARB establishes annual CI benchmarks for the transportation fuel pool, specifically gasoline and diesel. There is a planned schedule of CI reduction of California’s transportation fuel pool to 2030 and beyond. Regulated parties include fuel importers, refiners, and wholesalers who are required to reduce CI score across their transportation fuel product line. To ensure that the overall California transportation fuel pool meets the annual LCFS CI benchmark target, a regulated entity must lower the CI of its fuel pool (by substituting cleaner fuels) and/or purchase LCFS credits from other regulated entities. LCFS credits do not expire and any surplus of LCFS credits can be banked for future compliance.5
Figure 6 below depicts the overall reduction of the CI benchmark through 2030 and beyond and simplifies the supply/demand interaction of LCFS credits. A regulated party of transportation fuels with deficits must generate or acquire enough credits to be in annual compliance with the standard. Other entities, such as biofuel refiners, electricity, and natural gas suppliers can opt into the program to generate valuable credits so long as the CI pathway for those fuels are lower than the standard.
The annual California CI benchmarks through 2030 and beyond can be found in Table 2 and Table 3 below, copied from the CARB website effective July 2020.
Conventional Jet fuel is currently an exemption to the LCFS program and does not generate deficit to the transportation fuel pool. However, CI benchmarks are established by CARB to determine the credits that can be generated for alternative jet fuel producers.
CARB may update the CI score of California fuels periodically based on energy and emission updates along the life cycle pathway. California gasoline and diesel produced from the average efficiencies of California refineries are 100.82 and 100.45 gCO2e/MJ respectively as of 2020. CARB also assigns each alternative fuel an Energy Economy Ratio (EER). An alternative fuel’s CI score divided by its EER results in the EER adjusted CI score, which represents emissions produced from the alternative fuel per MJ of conventional fuel displaced. Refer to Table 5 below for established lookup table by CARB19 and Figure 7 for various EER-adjusted CI scores of common alternative fuels.
Table 5: Lookup Table for Gasoline and Diesel and Fuels that Substitute for Gasoline and Diesel
(Table was recreated for this article, refer to CARB website for current information)
|Fuel||Fuel Pathway Code||Fuel Pathway Description||Carbon Intensity Values (gCO2e/MJ)|
|CARBOB||CBOB||CARBOB - based on the average crude oil supplied to California refineries and average California refinery efficiencies||100.82|
|Diesel||ULSD||ULSD - based on the average crude oil supplied to California refineries and average California refinery efficiencies||100.45|
|Compressed Natural Gas||CNGF||Compressed Natural Gas from Pipeline Average North American Fossil Natural Gas||79.21|
|Propane||PRPF||Fossil LPG from crude oil refining and natural gas processing used as a transport fuel||83.19|
|Electricity||ELCG||California average grid electricity used as a transportation fuel in California||93.75 (and subject to annual updates)|
|ELCR||Electricity that is generated from 100 percent zero-CI sources used as a transportation fuel in California||0.00|
|ELCT||Electricity supplied under the smart charging or smart electrolysis provision||Refer to CARB Current Regulation|
|Hydrogen||HYF||Compressed H2 produced in California from central SMR of North American fossil-based NG||117.67|
|HYFL||Liquefied H2 produced in California from central SMR of North American fossil-based NG||150.94|
|HYB||Compressed H2 produced in California from central SMR of biomethane (renewable feedstock) from North American landfills||99.48|
|HYBL||Liquefied H2 produced in California from central SMR of biomethane (renewable feedstock) from North American landfills||129.09|
|HYEG||Compressed H2 produced in California from electrolysis using California average grid electricity||164.46|
|HYER||Compressed H2 produced in California from electrolysis using zero-CI electricity||10.51|
An example deficit calculation for 2020: a California refiner is subject to gasoline and diesel deficits on the order of 100.82 – 91.98 = 8.84 gCO2e/MJ for CARBOB gasoline and 100.45 – 92.92 = 7.53 gCO2e/MJ for ULSD. The impact to refiners in this deficit position is economics. The larger the spread of the CI fuel produced and the benchmark, the larger the credit deficit position.
The price of an LCFS credit hovered just below $200/MT (metric ton) at the end of Q1 2021. Current prices of an LCFS credit can be found on the CARB website, and a weekly snapshot as of end of April 2021 is shown in Table 6 below.
Table 6: LCFS Credit $/MT of CO2
|LCFS Weekly Snapshot||Fuel Pathway Code|
|Transfer Type||All Non Zero||Type 1|
|Average Price (1) ($/MT)||$190||$175|
|Price Range ($/MT)||$168 - $213||$168 - $193|
|Total Volume (MT)||470,789||214,909|
|Total Value ($)||$89,353,572||$37,506,772|
- Volume weighted average
- Fuel Pathway-based Crediting – All transportation fuels need a carbon intensity score to participate in the LCFS to generate credits, and the fuel type dictates which process is used to determine that CI. This option will be the most capital-intensive for a petroleum refiner. This is essentially only an option when considering a new renewable feedstock to either replace the petroleum feed or co-process, as this constitutes a new fuel pathway with a lower CI score. Being a petroleum refiner will still be in a deficit position, but a co generation of renewable fuels will generate credits.
- Project-based Crediting – Projects include actions to reduce GHG emissions in the petroleum supply chain. This may include innovative crude – crude oil produced using methods like solar-generated electricity, refinery investment credits, renewable hydrogen used in refining, and carbon capture and sequestration (CCS) using direct air capture. Crediting for projects is based on life cycle emission reductions and credits are issued after the reported reductions are verified. This option can be leveraged to replace utility usage such as electricity and hydrogen from high CI sources to low CI sources. There are currently projects in California Kern county that are installing photovoltaic solar panels and battery storage to replace the electricity usage by oil refineries. For electricity, this reduces the GHG emissions from the grid source of 93.75 gCO2e/MJ to 100% zero-CI source solar electricity of 0 gCO2e/MJ. These projects are economically viable with the government credits and are a way of reducing the carbon intensity of existing facilities and essentially partially electrifying the existing fuel system and fleet.
- Zero Emission Vehicle (ZEV) infrastructure (Capacity-based) Crediting – Introduced in 2018, crediting for ZEV infrastructure is based on the capacity of the hydrogen station or electric vehicle (EV) fast charging station less the actual fuel dispensed. This option is an “infrastructure credit” aimed at promoting building out ZEV infrastructure while providing an incentive to receive credits.
- LCFS Reporting Tool (LRT) and Credit Bank & Transfer System (CBTS). This portal serves the function of credit management system and annual reporting.
- Alternative Fuel Portal (AFP). This portal serves the function of alternative fuel registration and CI pathway application & evaluation process.
- Look up table pathway applications is the simplest of the three and is limited to conventional fuels and simple electricity and hydrogen generation.
- Tier 1 pathway applications involve processes that are more rigorous than the above, but the technology is generally industry adopted and CARB board has experience in evaluating the technology.
- Tier 2 pathway applications involve processes that are upcoming technologies, and the CARB board has limited experience in evaluating. More rigorous review and documentation is generally associated with this pathway.
RFS RIN Market
The Renewable Fuels Association reports that some refiners did in fact take steps to increase their renewable fuel blending capacity and capture RINs internally. Meanwhile, other refiners refused to invest in biofuel blending capacity, choosing instead to purchase RINs from parties who blended more than required.
The RVO to regulated parties will increase annually per the RFS EPA Volumes that can be found on the EPA website. The deficit incurred by obligated parties is set to increase until 2023 and possibly beyond 2023 subject to EPA’s decision.
LCFS Credit Market
An article published by Stillwater Associates in 2020 notes the following:
“Stillwater estimates that nearly 75% of all credits generated in both states [California and Oregon] are from fuels brought in from other states or countries. The value of these credits from fuels produced out-of-state in 2019 was more than $2.1 billion in California and nearly $140 million in Oregon.”
U.S. Government and Armed Forces Fleets
The U.S. Navy's objective is centered around energy security, energy efficiency, and sustainability while remaining a power on the seas. In 2014, renewable fuels were included in the U.S. Navy’s fuel procurement request for the first time in history. The U.S. Navy's interest in renewable fuels was part of its goal to generate 50% of its energy from alternative sources by 2020. In particular, the Navy’s interest is in renewable fuels that can be used as direct replacements for petroleum-based gasoline and distillate fuels, also known as drop-in biofuels. The Navy also sailed the Great Green Fleet in 2016 to demonstrate the sea service’s efforts to transform its energy use. Deployed on alternative fuels, this fleet brought awareness to the Navy’s initiative to usher in the next generation of energy innovation. The Great Green Fleet was fueled by nuclear power for the carrier and a blend of renewable fuel made from beef fat and traditional petroleum.
The U.S. Air Force uses over 2.4 billion gallons of jet fuel annually (0.16 million BPCD as compared to total U.S. commercial airline demand of 1.2 million BPCD) and they are the largest energy consumer in the Department of Defense. Since 2012, the Air Force had approximately 256 renewable energy projects, but appears limited to installation of near zero emission electricity generation. The projects include solar, wind, geothermal, and waste to energy. With a 1.2 million BPCD of annual commercial jet fuel consumption, a government mandate in the jet fuel industry would further drive the demand for renewable fuels in addition to the current diesel and gasoline renewable fuels.
Feedstocks such as yard waste or other woody plant material contain cellulosic content that provides structure to plants (cellulose, hemicellulose, or lignin). These are more difficult to process and have much lower yields than the glyceride-based biomass. In this case, producing any biofuel requires a two step process, first to break down the rigid outer structure of the plant cell wall, then upgrading to finished product.20 The deconstruction step can be achieved by way of pyrolysis, gasification, or by use of enzymes or catalysts.
Chemical Structure and Molecular Weight
The molecular weight (MW) of triglycerides is high, 800 to 900, many with boiling points >1,000°F (538°C). On the other hand, the single chain fatty acids have MWs of 200 to 250.21 The molecular weight is calculated by understanding the molecular structure of each of the glycerides. Each glyceride is a unique molecular composition of repeating chains. The MW of individual glycerides of composition XX:Y is calculated by carbon number.21 The glycerides are a series of increasing carbon numbers and chain combinations. For example, corn has three glyceride chains each typically consisting of 54 w% linoleic, 28 w% oleic,13 w% palmitic, 2 w% steric, and 3 w% others. The chains are linked together by 3 carbons, 5 hydrogens. The calculated MW of corn ranges between 865 to 880 depending on the concentration of the glyceride distribution. The average corn molecular structure is shown in Figure 8 below:
Table 7: Typical Renewable Feedstock Physical Properties
|Feed||UOM||Technical or Distillers Corn Oil||Soybean||Animal Fat||Rapeseed|
|Reference||23, 26||22, 23,24, 26||22, 23,24, 26||22, 23,24, 26|
|Nitrogen, est (2)||wppm||95||3.9||600||16|
|Chloride, est (2)||wppm||20||20||20||20|
|Moisture, est (2)||wt%||4||2||2||2|
|Free Fatty Acid||wt%||12||2||15|
|Sulfur, est (2)||wppm||100||100||100||100|
|Glycerides distribution||3 chains||3 chains||1 chain||3 chains|
- Calculated from glycerides distribution
- Typical value used for design; actual values may vary
Virgin vegetable oil feedstocks provide a more consistent feedstock versus used cooking oil, which will have greater variation in contaminants. Vegetables have high concentrations of unsaturated fatty acids such as linolenic (18:03), linoleic (18:02), and oleic (18:01), whereas animal fats have more saturated fatty acids than vegetable oils, such as stearic (18:00) and palmitic (16:00). This has implication with respect to processing requirements for conversion to fuels. In general, more preprocessing will be required for higher contaminant feedstocks. Higher concentrations of unsaturated fatty acids will have higher hydrogen consumption for processing when compared to feedstocks with lower fatty acid content. Consideration of feedstock pretreatment should be a major focus of any renewable project.
Looking to the Future
From a cultivation standpoint, microalgae are a potential source for renewable fuels; however, the technology has significant hurdles to make it economically feasible. On the plus side, algae have a high oil level and farming it does not require arable land. However, in addition to harvesting and transport logistics which require consideration, the product fuels depend heavily on the composition of the algal biomass, which in turn varies based on the type of algae, the nutrients they consume, and the environment in which they are grown. Various U.S. federal agencies such as the DOE, USDA, NOAA, and NSF are invested in researching increased algal biomass productivity and product yield.30
Perhaps the biggest hurdle for microalgae as a viable biofuels feedstock is the amount of nitrogen and phosphorus required for sufficient algae production. The amount of fertilizer required to meet a mere 5% of U.S. fuel demand would amount to more than double what’s used domestically to grow food.32 Since fertilizer components (nitrogen, phosphorous, and potassium mainly) are undesirable in finished fuels, they are generally removed by the refining process. The current focus on recycling these nutrients means the algae feedstocks of the future would require only a fraction of the fertilizer that conventional wisdom tends to quote. In addition, marine macroalgae would not require any man-made fertilizers.
The rapid growth rate (2-3 ft or 0.6-0.9 m per day) of marine macroalgae, commonly referred to as kelp or seaweed, and relative ease of cultivation as compared to microalgae may result in an overall lower production cost per barrel of biocrude produced despite lower yield results from preliminary studies. Biocrude is a mixture of hydrocarbons, fatty acids, esters, phenolics, and oxygenates that results from the conversion of biomass via chemical processes to liquid biofuel. Though the term is sometimes specific to the liquefaction process products, it is often used interchangeably with bio-oil, which is more often associated with the product of biomass pyrolysis. Marine macroalgae requires no fertilization, as cold ocean water provides the nutrients required for growth. The west coast of the United States in particular is well suited for macroalgae cultivation, as water conditions suitable for growth exist from Alaska to Southern California.33 While most of the global aquaculture production for macroalgae occurs in Asian waters,34 the United States has recently invested in research into offshore macroalgae production.
Several technologies are in development for converting biomass to renewable fuels. The DOE’s BETO office has placed emphasis on technologies that can process or co-process multiple different feedstocks to ensure a continuous source of biofuels. This minimizes the impact of variables such as growing seasons. Besides hydroprocessing of biomass to make renewable diesel, other technologies for the production of various biofuels include systems that require dry feedstocks (pyrolysis, gasification, trans-esterification) and systems that utilize the wet feedstock (hydrothermal liquefaction, fermentation, anaerobic digestion).35 Whichever method is utilized, post processing of the biofuel product is likely required. For instance, continuous hydrothermal liquefaction has been advanced to pilot-scale by the Pacific Northwest National Laboratory,36 and has been shown to produce biocrudes for both micro and macroalgal feedstocks. The biocrude product is high in nitrogen and Total Acid Number (TAN),37 which is logical considering the feedstocks require nitrogen for growth (fertilizer). Work in these areas is evolving rapidly and they could become future renewable energy feedstock sources.
Mixed Use Plastics- Considered Renewable?
Government programs (both EPA RFS and California LCFS) are set up so that credit opportunity exists for renewable gasoline production. As of 2021, the RFS program includes approved pathways for producing renewable gasoline from cellulosic feedstock and renewable naphtha from limited plant oil feedstock, such as distillers corn oil and distillers sorghum oil. The California LCFS program is set up such that lower carbon intensity pathways generate more credit. That means a process producing renewable gasoline with a low CI score from all forms of technology may be considered for credit generation.
The renewable fuels industry has shown much interest in renewable gasoline in different forms of production. Studies have been conducted for using a Fluid Catalytic Cracker (FCC) to take feed of plant oils or co-processing pyrolysis oil with vacuum gas oil, allowing for re-use of a refinery asset for renewable gasoline production. Projects with Fisher-Tropsch technology are currently in operation, in construction, and planned for future construction. Shell’s Pearl gas-to-liquids plant in Qatar was built and operating since 2011, while Nacero announced in Q2 2021 that they are planning a gas-to-liquids plant in Texas using several other technologies to reduce carbon footprint.
Some momentum has started for 100% renewable gasoline into commercialization as of 2021, but is dwarfed by the current government program for ethanol production. The future of commercialized mass renewable gasoline production may depend on government incentives beyond that of the existing RFS.
Ethanol and the Blend Wall
While synthetic (non-renewable) ethanol exists, the vast majority of ethanol is sourced from a variety of agricultural feedstocks, primarily corn in the U.S. and sugarcane or sugarbeets elsewhere in the world40 and is thus considered a renewable fuel additive. Ethanol from renewable sources has been mainly driven by the RFS program. Recall that the RFS program requires a minimum amount of renewable fuels to be blended into transportation fuels, with that minimum increasing each year. Ethanol is an obvious choice to meet this requirement due to its high octane properties and renewable feedstock sources. The RFS plan was based on the idea that as gasoline consumption increased alongside the increasing minimum renewables requirement, the national fuel supply could stay at or below the E10 blend wall, or the maximum ethanol blend to avoid engine or fuel system damage in vehicles not designed for fuel past E10 grade,41 which includes most vehicles on the road today. EPA suggests that gasoline consumption in recent years has been close to the E10 blend wall level. From 2015 through 2019, fuel ethanol consumption equaled about 10% of total U.S. motor gasoline consumption.
As gasoline consumption is likely to decline as a result of increasing remote work options and increasing popularity of electric vehicles, the U.S. is on track to hit the ethanol blend wall. Possible solutions to the blend wall problem include adjusting the RFS rules, which would require a change to government regulations, changes to the way engines and fuel systems are made, increased production of E15 and E85 gasoline, neither of which helps cars already on the road, or finding another renewable oxygenate to use instead of ethanol.
Future of Existing Ethanol Plants
The demand for gasoline as a transportation fuel is seen on a path of decline with increasing policies and interest to adopt zero emission vehicle (ZEV) powertrains. This decline in gasoline demand is expected to be seen in the near-term, affecting light and medium-duty vehicles. While the U.S. has some states that have adopted ZEV and low-emission vehicle regulations, no federal legislation is currently in place. However, California has recently announced executive orders that will aggressively push the market into ZEV. California will require all new passenger cars and trucks sold in the state to be emission free by 2035. In addition, California will also require all semi-trucks sold in the state to be emission free by 2045.
Ethanol producing plants may face business decisions in a changing market where ethanol demand in gasoline diminishes. This leaves ethanol producers to consider unconventional market opportunities such as other transportation fuels or chemicals. As light and medium duty passenger vehicles are the primary focus of ZEV powertrains, ethanol could be a feedstock to produce renewable diesel and SAF while capturing government incentive programs in transportation fuel. There are several companies that recognize this opportunity in the current market landscape and have positioned themselves as technology owners.
- Gevo, a Colorado based company, has a commercial facility making isobutanol alongside ethanol and produces it using a genetically modified yeast. They have also been producing alcohol-to-jet (ATJ) derived from isobutanol since 2011 at South Hampton Resources located in Silsbee, TX. Gevo’s ATJ fuel was used in certification tests, including test flights with the U.S. Air Force, U.S. Army, and U.S. Navy. Since receiving its ASTM certification in 2016, Gevo’s ATJ fuel has been used in commercial flights around the world and working towards commercialization.
- Vertimass, a California based company, is developing a proprietary catalyst for converting ethanol into renewable diesel, SAF, and renewable chemicals. As of 2017 they have several pilot plants as proof-of-concept and continuing improvements and development with a target to commercialization.
- Other opportunity exists in the chemical industry. Axens has a dehydration technology of converting renewable ethanol into bio-ethylene. The bio-ethylene produced can be integrated in existing downstream polymerization installations such as polyethylene (PE), polystyrene (PS), polyethyleneteraphthalate (PET), polyvinylchloride (PVC) and acrylonitrile- butadiene-styrene (ABS) without need for modifications.
The current U.S. government mandates on renewable gasoline are limited to the RFS and LCFS programs. Even though ethanol blending began with the Clean Air Act for the purpose of reducing smog and harmful toxins, it is the RFS program that mandates blending 10% ethanol into conventional gasoline pool, which coincides with the program’s Renewable Volume Obligations (RVO) to refiners. Technology exists to produce renewable gasoline, and complies with the RFS program, but is not widely industry adopted as of 2021. The state level LCFS program mandates a carbon reduction via a credit market, putting lower carbon intensity score produced gasoline in favorable position for selling credits to deficit producers. This program is designed to incentivize lower intensity score renewable fuel processes. Ethanol producers can generate credits in this market to sell, but the program does not necessarily drive the mandate for ethanol nor any other type of sustainable process.
Biodiesel cannot be used directly in most vehicles and typically has to be blended with petroleum diesel. Up to 5% FAME (B5 biodiesel) is allowed by many vehicle manufacturers with some that can accommodate up to 20% FAME (B20 biodiesel). Biodiesel has different solvent properties from petroleum-based diesel. Impurities such as methanol, free fatty acids, water, catalyst and glycerol left in the biodiesel may increase corrosion,43 causing degradation of rubber gaskets and hoses in vehicles. The cold flow properties of biodiesel vary depending on the feedstock but are generally worse than both petroleum based and renewable diesel. These cold flow properties make biodiesel unusable in cold climates without blending with petroleum diesel or additives. Table 8 below shows a comparison of cold flow properties of biodiesel from various feedstocks and No. 2 petroleum diesel.44
Table 8: Biodiesel Cold Flow Properties
|Soy||Canola||Lard||Edible Tallow||Inedible Tallow||LFFA (1)
|Cloud Point, °F (°C)||36 (2)||27 (-3)||57 (14)||68 (20)||73 (23)||108 (42)||46 (8)||0 (-18)|
|CFPP, °F (°C)||28 (-2)||24 (-4)||52 (11)||58 (14)||50 (10)||52 (11)||34 (1)||-4 (-20)|
|Pour Point, °F (°C)||30 (-1)||25 (-4)||52 (11)||56 (13)||46 (8)||54 (12)||46 (8)||-17 (-27)|
- LFFA – Low Free Fatty Acid
- HFFA – High Free Fatty Acid
Table 9: Biodiesel Cold Flow Properties
|Generic Yields from the Chemistry Basis: the entering triglyceride as a wt%|
|Hydrogen consumption||3 to 4||Most of hydrogen consumed in deoxidation reactor|
|Water||11 to 13||Water produced in deoxidation reactor|
|Methane||3 to 6||Can be higher, depending on severity of isom reactor|
|Diesel + Jet + Gasoline||75 to 80||Selectivity to diesel is a function of reactor and catalyst|
There are other technologies available for renewable diesel from biomass. Gasification of feedstocks is another path for producing renewable diesel. The biomass can be gasified by microbial digestion or pyrolysis. The gas can then be processed using Fischer-Tropsch synthesis to convert the gas to diesel and naphtha. Fast pyrolysis uses heat in an air free environment to decompose the large biomass molecules to diesel and naphtha boiling range materials. These can be processed to diesel or other fuels.45
Co-products in the production of renewable diesel include naphtha, jet fuel, and fuel gas. The naphtha is a low-octane gasoline and is of less value than the diesel or jet fuel, though it is considered a “green” fuel and has potential for credit capture. Renewable jet fuel has no U.S. federal mandates at this time, but renewable jet producers can sell RIN credits in the RFS program or carbon credits in the LCFS program. Fuel gas that is produced from renewable feeds can also be considered “green” fuel.
The current U.S. government mandates on renewable diesel are limited to the RFS and LCFS programs. Some states offer a diesel tax credit and the federal government offers a Blenders Tax Credit (BTC), but it is subject to periodic review and renewal and should not be relied on for long term credit incentive. The RFS program mandates a Renewable Volume Obligation (RVO) on several types of renewable diesel produced from sustainable sources into the nation’s diesel pool. The state level LCFS program mandates a carbon reduction via a credit market, putting lower carbon intensity score produced diesel in favorable position for selling credits to deficit producers.
Sustainable Aviation Fuel, SAF
HEFA, Hydroprocessed Esters and Fatty Acids:
In the HEFA-SPK (Hydroprocessed Esters and Fatty Acids, Synthetic Paraffinic Kerosene) process, approved in 2011, lipid-based feedstocks are deoxygenated using hydrogen and then hydroprocessed into hydrocarbon products. In 2020, the similar HC-HEFA (Hydroprocessed Hydrocarbons, Hydroprocessed Esters and Fatty Acids) process was approved to use lipids from algae as a feedstock. These are the most like traditional crude refining.
This was the first approved pathway for a straight paraffinic SAF and is produced by gasification of solid biomass feedstock into a syngas, which is converted to liquid hydrocarbon by the FT process. Later, a second FT process was approved that produces SAF with aromatic compounds.
SIP, Synthesized Isoparaffins:
This is a fermentation based process that utilizes sugars as a feedstock, converts it to farnesene, and is then hydrotreated to produce SAF.
This process upgrades isobutanol or ethanol to SAF by oligomerization. The source of alcohol feedstock is not specified, but the pathway commonly starts fermentation of a sugary feedstock to the intermediate alcohol.
CHJ, Catalytic Hydrothermolysis:
The CHJ process, also called Hydrothermal Liquefaction, combines fatty acid with water and passes them into a high temperature and high pressure reactor to create a single phase that is then hydroprocessed to produce SAF.
The two HEFA pathways noted above are the most similar to traditional refinery hydroprocesses in that they take a renewably sourced oil-based feed and process it in ways that are familiar to a conventional refinery. This makes it a good starting place for a refiner to make the leap from producing petroleum based jet fuel to renewable jet fuel. The other pathways likewise include some level of traditional hydroprocessing, but also include an early processing step that may require heavier investment on the part of the refiner in order to achieve.
Renewables Projects and Technologies
As new technologies are proven successful on the laboratory scale, one of the most common hurdles to mass production is scale-up of the technology into pilot plant and commercialization. These new technologies will have the opportunity to advance into commercialization as the net zero carbon initiative garners momentum. Ascent has experience and is an excellent partner in these transitions from pilot plant to commercial scale facilities.
Current and Planned Renewable Projects
The following is a list of renewable fuels plants around the world that are currently in operation or in planning stages for future construction. There is a mix of commercial projects planned, which include hydroprocessing, gasification, pyrolysis, gas-to- liquids, biogenic, or combinations of these technologies. In addition, many of these projects are incorporating utility generation from solar and other carbon net negative sources.
Renewable Process Technologies
There are two main reactions that convert the feed into renewable diesel. The first reactor beds ideally perform the selective hydrodeoxygenation reaction to break down triglycerides into water and straight hydrocarbon chains. The next reactor beds or reactor perform the hydrocracking/hydroisomerization reaction to convert the straight chain hydrocarbons into isomers of smaller chains to improve physical properties, mainly pour point. The reactor effluent is then separated of recycle gas and fractionated to produce offgas, naphtha, and diesel.
There are various licensors available providing the catalyst and technology for the production of renewable diesel via hydroprocessing. Some companies have developed their own proprietary catalyst to use internally. The most widely available licensors are Axens, Haldor Topsoe, and Honeywell UOP.
Fischer-Tropsch / Gas-to-Liquids
There are projects that utilize Fischer-Tropsch technology with a carbon capture CO2 feed gas discussed below. Other projects that take synthesis gas from a gasification process are discussed in the next section.
- Porsche, being known as a high-performance automaker, is investing and collaborating with several energy companies to produce a carbon-neutral synthetic fuel and dubbing it “eFuel”. The pilot plant project Haru Oni is slated to be built in Chile, planned for production in 2022, and will convert methanol to gasoline. The methanol will be produced by combining CO2 and H2 and will be sustainably sourced. CO2 direct air capture will be utilized, and Siemens Energy’s PEM electrolysis powered by wind power will produce the H2.
- Nacero, a Texas based company, is planning a 100,000 barrels per day (1.5 billion gallons/year or 484,000 m3/month) renewable gasoline facility in Penwell, TX. The facility will utilize a myriad of technology to minimize its carbon footprint. They will utilize Haldor Topsoe TIGAS technology to convert natural gas, captured bio-methane, and flare gas into methanol, followed by conversion into renewable gasoline and hydrogen.
Gasification technology has been proven commercially and is deployed around the world by the chemical, refining, fertilizer, and electric power industries. Besides the traditional non-carbon-neutral coke and coal feedstocks, most of these gasifiers are also able to use biomass or solid waste feedstocks, which is important to a renewable fuel producer because cellulosic feeds offer the highest reduction GHG emissions and a high value in government credit programs.
There are several companies with planned commercial scale productions employing a combination of gasification, Fischer-Tropsch, and hydroprocessing to produce fuels.
- Fulcrum Bioenergy, a California based company, developed a process that combines gasification technology with Fischer-Tropsch fuel process to produce renewable synthetic crude. They are completing construction of their first facility planned for operation in 2021. The Sierra BioFuels Plant is located in Storey County, NV and expected to process 175,000 tons of municipal solid waste feed stock annually to produce 11 million gallons (700 barrels/day or 3,500 m3/month) of renewable synthetic crude. Fulcrum has an offtake agreement with Marathon Petroleum Corporation (MPC) to sell all of the synthetic crude to MPC’s refinery in Martinez, CA. Included in the project is a feedstock processing facility located near a large waste landfill, which has been commissioned and started-up and is producing gasification feed from sorted municipal solid waste.
- Northwest Advanced Bio-Fuels, an Arizona based company, has a technology to convert woody biomass into SAF. The process combines a front-end gasification process and a back-end Fischer-Tropsch process. They are planning to build a commercial plant at the Port of Grays Harbor, WA and have secured $600 million in funding commitment. The project will produce 60 million gallons per year of SAF (3,900 barrels/day or 19,000 m3/month) and reported a 10-year offtake agreement with Delta Airlines.
- Velocys, a United Kingdom company, provides a complete end-to-end process from waste feed to fuel, and their technology has been proven extensively in pilot scale. Velocys process technology employs gasification, Fischer-Tropsch, and hydrocracking to produce SAF and renewable diesel. Velocys is currently involved in two projects that will bring the technology to commercial scale. A collaboration of Velocys and British Airways have joined in the name of Altalto to bring the process technology to Immingham, United Kingdom. A similar partnership of Velocys and Oxy Low Carbon Ventures is planning a Bayou Fuels project to bring the process technology to Natchez, Mississippi. Oxy Low Carbon Ventures expertise in carbon capture and sequestration will take the renewable process a step further by reducing CO2 emissions into the atmosphere.
- USA BioEnergy, an Arizona based company, is in early stages of developing three project sites to bring their technology to commercial scale. The company provides a design that includes gasification, Fischer-Tropsch, and hydroprocessing to produce SAF and renewable diesel. As of 2018, the company has entered into a Letter of Intent to develop the project in Yell County, AR, Maricopa County, AZ, and Lane County, OR.
- Red Rock Biofuels, a Colorado based company, is constructing a renewable fuels facility utilizing gasification, Fischer-Tropsch, and hydrocracking in Lakeview, OR. The facility will take waste biomass from sawmills and forests. Red Rock Biofuels has partnered with TCG Global for the gasification technology. Emerging Fuels Technology is the licensor for the Fischer-Tropsch process and Velocys has manufactured and completed delivery of four reactors in Q1 2021.
Biomass pyrolysis systems have been built in small scale but have yet to be adopted in large scale to serve the energy markets.
There are a couple of well-known pyrolysis technology providers that have small scale plants built.
- BTG Bioliquids, a Netherlands based company, has a fast pyrolysis technology and with two small scale plants in operation. The Empyro plant in Hengelo, Netherlands takes in a feed of wood residues to convert into bio-oil and has an offtake agreement with a nearby dairy farm. The Green Fuels Nordic Oy plant in Lieksa, Finland takes in saw-mill byproducts and biostem to convert into bio-oil and has an offtake agreement with a heating plant in Joensuu, Finland. A third installment of BTG Bioliquids technology is planned with Pyrocell, a joint venture between a wood industry company Setra and oil company Preem. The Pyrocell project is located Gävle, Sweden and construction commenced in Q1 2021.
- Ensyn, a Canadian based company, holds a patented fast pyrolysis technology and with two small scale plants in operation producing bio-oil. The bio-oil from both the Ontario and Quebec facilities is supplied to heating oil customers.
Fluid Catalytic Cracker (FCC) Utilization
W.R. Grace & Company (GRACE) developed a modular pilot plant FCC unit and licensed 26 pilot plant FCC units around the world as of 2013. A test study conducted in 2013 by GRACE compared 100% soybean oil feed to conventional vacuum gas oil, and preliminary results suggested that soybean oil could likely be processed in a commercial FCC. It is unclear if there are recent developments to processing soybean oil in an FCC.
More recent study work in this area has focused on co-processing of pyrolysis oil with vacuum gas oil. Researchers are examining catalysts, product properties, and overall feasibility of this process. Overall, these studies highlight challenges even with a small amount of mixed pyrolysis oil processed in an FCC, but are optimistic in the general feasibility of the process. It is unclear if there are recent developments to processing pyrolysis oil in an FCC.
Sugar Feedstock Conversion Technologies
Virent, a Wisconsin based company and a subsidiary of Marathon Petroleum Corporation, owns a technology that converts plant-based sugars into a full range of hydrocarbon products identical to those made from petroleum. This includes gasoline, diesel, jet fuel, and chemicals for plastics and fibers. They are not yet commercialized but have key strategic relationships with energy companies that can support their commercialization.
LanzaTech, an Illinois based company, uses an engineered microbe to convert CO2 into ethanol in gas phase fermentation. They have 6 demonstration plants installed globally since 2008 and have commercial facilities in operation attached to industrial facilities capturing the carbon offgas streams. LanzaTech subsidiary LanzaJet provides an alcohol-to-jet technology to produce SAF and renewable diesel which has been proven on commercial scale. The primary steps to this process include dehydration of the ethanol, oligomerization, hydrogenation, and fractionation.
The profitability of renewable fuel production can be defined as the incentive minus the investment. The investment part of this equation will be different for each producer and should be determined on a case by case basis. For the refiner, this includes feedstock and production costs as well as payments on capital investments and other inputs.
In the United States, the incentive for renewables is similar in general for all producers and can be defined as the energy value (ULSD rack price, for instance) plus various government based incentives previously detailed. These include the Biodiesel Mixture Excise Tax Credit (BTC) and Renewable Fuel Standard Program (RINs value) on the national level, and the Low Carbon Fuel Standard (LCFS in California, Oregon, and British Columbia), plus other states currently considering LCFS programs in review or legislative process.
Several points that should be considered when calculating the renewable incentive. First, the BTC is a short-term program that requires government annual renewal. According to the U.S. Department of Energy:
“This incentive originally expired on December 31, 2017, but was retroactively extended through December 31, 2022, by Public Law 116-94.”48
It should not be taken for granted that this program will continue past 2022. Second, the federal and state credits are shared between the feedstock supplier, renewable fuel producer, and retail sellers.
A simplified sample calculation for the production of renewable diesel compared to the conventional counterparts is included in Table 11 below.
Table 11: Sample Renewables Incentive Calculation
|Sample Overall Incentive Calculation Comparison for Renewable Diesel Generation|
|Conventional Diesel||Renewable Diesel; US General||Renewable Diesel; State Incentive; Chicago (1)||Renewable Diesel; CA LCFS State; Los Angeles (2)|
|Rack Price (3)||$/Gal||$1.27||$1.27||$1.20||$1.65|
|State Incentive (4)||$/Gal||$0.00||$0.00||$0.98||$0.00|
- Illinois, Iowa, and Minnesota all have individual state incentives that are independent of LCFS. For illustrative purposes, the value utilized here is for Illinois.
- LCFS value shown is for California.
- Rack price is the national average for October 2020 for Conventional and General Renewable Diesel. Local prices shown for Chicago and Los Angeles.
- Biodiesel Mixture excise Tax Credit, Renewable Fuel Standard Program RIN, State Incentive, and Low Carbon Fuel Standard values are all for October 2020.
A rough order of magnitude cost of a plant can be calculated from knowing the total capital cost and capacity of existing plants and projects. The cost of a desired plant depends on many variables to consider such as greenfield/brownfield scope, capacity, feedstock pretreating, types of products, integration with existing refinery, rails, and offsites. A more precise comparable cost estimate can be made if the breakdown of major costs are known for existing projects. Typical economic capacity scaling formulas can be applied and using cost indices to calculate capital costs to today’s dollars.
The following is an example comparison calculation for a desired 10,000 barrels per day (BPD) renewable diesel plant. The project cost for Diamond Green Diesel Train 1 initial build and Holly Frontier can be used as comparable.
- Diamond Green Diesel's initial build of its current Train 1 renewable diesel plant in Norco, LA had a total cost of $370 MM in 2011. They installed a new pretreatment unit, new renewable diesel unit, new rails, and new offsites. A majority of utilities, including hydrogen, used in the renewable diesel unit are obtained and purchased from the nearby refinery. Applying cost indices to 2021, the total cost is $443 MM which equates to ~$2.81/gal/yr (~$43,000/BPD, ~$0.74/liter/yr) for a 10,000 BPD capacity plant.
- HollyFrontier is installing a new greenfield renewable diesel unit and pretreatment unit at their Artesia, NM refinery announced in 2019. In addition, HollyFrontier is converting their Cheyenne, WY refinery into renewable diesel production announced in 2020. The pretreatment unit will process 80% of the renewable diesel capacity for both Artesia, NM and Cheyenne, WY. They installed a new pretreatment unit, new renewable diesel unit, new rails, and new offsites at their Artesia, NM location. A majority of utilities, including hydrogen, used in the renewable diesel unit will be brought in from the nearby refinery. Applying cost indices to 2021, the total cost is $629 MM which equates to ~$4.10/gal/yr (~$62,900/BPD, ~$1.08/liter/yr) for a 10,000 BPD capacity plant.
Grassroots or Existing Refinery Retrofit?
Once a refiner has decided to pursue the production of renewables, they must decide whether to retrofit an existing plant or build a grassroots facility. A grassroots facility has the advantage of incorporating new technologies and leaves open the greatest opportunity for optimization for the selected feedstock and desired product. On the downside, grassroots requires a larger, up-front capital investment. Retrofit of an existing plant is also a faster route to get into the renewables production market. It allows a refiner to leverage current assets, but requires thoughtful planning for how to best optimize these assets for renewable feedstocks. The switch to renewables is associated with reduced throughput as compared to crude oil feed. Another option for retrofit is to co-process renewable feedstocks alongside petroleum based crude oil.29 Even a small amount of renewably sourced product can benefit from the incentives for low carbon steps in the fuel producing process. A simple summary plan for existing refiners to evaluate current assets and options is outlined below.
- Inventory of existing equipment to maximize existing asset value
- Impacts on gasoline blending
- Impacts on G/D ratio, light ends production, petrochemical feedstocks, aromatics, lubes, and asphalt
- Refinery impacts on fuel gas balance
- Other projects to support future configuration
- Safety aspects as compared to conventional refinery
- Environmental considerations such as fired heater duty and NOx implications compared to conventional plant
The biggest advantage to a grassroots facility is the chance to optimize the unit to renewable fuels production. The capital investment is high, but the long term plant reliability and operability would reflect the fit for purpose design. Additionally, there is more flexibility regarding what can be built and where. For example, deciding the plant location should consider accessible and available feed source and the ability to deliver to the product market. The producer also will want to consider being able to capitalize on LCFS credits by participating in the California and Oregon LCFS program, and other states ready to adopt an LCFS program.
Existing Refinery Retrofit
Stand-alone vs Co-processing
The decision is ultimately be driven by the refinery’s objectives and more importantly the economics. While making this decision, a refiner may consider:
- Do I want to expand my business line?
- Where can I source a sustainable feed?
- Do I want to produce a specific renewable fuel?
- How can I meet finished product specifications?
- Do I want to claim or purchase RIN credits?
- How can I increase margins?
- How can I extend the useful life of my facility?
- How can I best utilize my existing hardware with new renewables feedstocks?
However, several of these traditional feedstocks already have established markets in the food, chemicals, and biofuels industry, which can result in a premium price point to meet the higher demand. This has also led to more research to find new (non-edible) feed sources such as jatropha, camelina, and pennycress.49 Additionally, as the industry moves away from edible feedstocks, waste oils and other dirty feeds require additional pretreatment, which also factors into overall cost and feedstock selection.
One way to overcome this initial challenge is to form a partnership with the feedstock supplier. Another way is to evaluate the processing of a blend of feed oils, similar to what is done with crude oil. This can provide the advantage of more control over feedstock purity, for example with a blend of high and low contaminant feeds, thereby reducing pretreatment investment.50 Another purity/quality feed pretreatment consideration is whether the plant will require upgrades to the metallurgy of the existing systems (feed storage and preheat systems) as well as establishing hydrogen requirements.
In addition to feedstock availability, a refiner should consider the plant’s proximity to the feedstock market. The typical method of transporting of renewables feeds is via rail. Some refineries may have the existing railway infrastructure to support this, but this is not to deter the refineries that do not. Options can include expansion of an existing railway system to a remote location and include the necessary loading/unloading/blending facilities and pump systems to send to the refinery via pipeline.
Glycerides, by nature, are acidic and can contain a certain concentration of free fatty acids. One challenge with renewable feeds is that glycerides can break down into more free fatty acids under heated conditions. Considering the amount of water byproduct that results from renewables hydroprocessing, there is a very real concern for corrosion issues in the piping and equipment in the reactor circuit. Metallurgy should be checked and may limit either the type of feedstocks that can be processed or the pretreatment types required, or metallurgical upgrades may be required.
Glyceride feedstocks also contain impurities such as:
- Alkali Metals
Sulfur in particular has additional options for treatment. This compound is not foreign to refiners and most have units on the back end of their plant for sulfur removal.50
Finally, the treated feed oil may be removed of solids, but many vegetable oils and animal fats are waxy or even solid at ambient temperatures. Heat tracing, either steam or electric, is required to keep piping and vessels warm enough to maintain the oils in liquid form.
One key difference between hydroprocessing crude oil versus hydroprocessing renewable feedstocks is that the HDO and DCO/DCO2 reactions are much more exothermic for renewable feedstocks, requiring multiple beds and/or multiple reactors.52 Evaluation of the existing quench system is critical to avoid runaway, to ensure proper heat balance across the reactor to maintain high yield, and to mitigate loss of product due to undesired side reactions, cracking, and coke formation. This applies even when co-processing a small percentage of renewable feedstocks.53 The higher hydrogen consumption and associated heat of reaction associated with renewables requires more intensive quenching requirements. Ascent has reviewed and designed multiple systems for increased heat removal including:
- Speeding up of recycle gas compressor
- Addition of a liquid product recycle to obtain a higher heat sink
- Combination of recycle gas and liquid product recycle
- Lowering of cold low pressure separator temperature
The reactor effluent will have a much higher mass enthalpy due to the higher quench rates which will require evaluation of the existing heat integration. Ascent can provide the experience required to review such systems to ensure maximum heat recovery and minimization of utility consumption.
The amount of additional hydrogen required will be dependent on the amount and type of renewable feedstock processed as well as reaction conditions favoring either hydrodeoxygenation or decarbonylation/decarboxylation pathways. Options for obtaining the additional hydrogen include installation of an additional hydrogen plant, replacement of the existing hydrogen plant with larger equipment, importing hydrogen, or retrofits to debottleneck the existing hydrogen plant. For example, opportunities to retrofit an existing steam methane reformer (SMR) hydrogen plant for additional hydrogen needs of up to 30% include reactor modifications, reformer upgrade, or installation of pre- or post-reformer. When considering which option to pursue, the refiner should consider how much additional hydrogen is required.55 Opportunities for renewable hydrogen should also be considered as discussed below.
One way to reduce the CI score for hydrogen production is to find a sustainable source for SMR feed. This can range from re-use of the offgas that results from hydroprocessing the renewable diesel to capturing methane from livestock farms as feed. Recall that one of the side reactions to the primary hydrodeoxygenation, decarbonylation, and decarboxylation reactions is methanation. While the production of methane is not preferred, there is a potential home for the methane in the SMR to produce hydrogen. Use of the methane in this manner would result in a lower CI score of the finished fuel product.
Use of blue (petroleum based with carbon capture and sequestration, CCS) or green (entirely non-petroleum based) hydrogen is another consideration for reducing the overall carbon footprint. Blue hydrogen, like the grey hydrogen described above, is also typically produced by a SMR, but in this case, the product CO2 is captured, transported to a storage site (typically via pipeline), and deposited deep under the surface of the earth in porous rock formations. The rock above the storage site is impermeable and does not allow the CO2 to escape. Because CCS does not capture 100% of the CO2, production of blue hydrogen is considered a low carbon emitting process as opposed to truly carbon neutral. As of 2021, there is no official standard for defining how much CO2 must be captured in order to qualify as blue as opposed to grey hydrogen. However, CertifHy is a consortium of companies aiming to develop the first such standard for the EU to define green and blue hydrogen. In 2019, CertifHy proposed a threshold greenhouse gas footprint of 36.4 gCO2eq/MJ for blue hydrogen, which is 60% lower than the benchmark 91 gCO2eq/MJ greenhouse gas footprint.56,57
Green hydrogen is produced without CO2 as a byproduct and is a truly carbon neutral process. This is achieved by electrolysis of water, splitting it into hydrogen and oxygen, where the hydrogen is captured and the oxygen may be vented to atmosphere with no negative impact on emissions. Electrolysis requires an electrical current, which must be sustainably sourced for the hydrogen to be considered “green”. Such green power sources may include using solar, wind, or hydro energy, but these technologies themselves have limitations based on location and weather conditions that vary throughout the year. One option for location of a green hydrogen plant is to integrate it with a dedicated solar, wind, or hydropower plant, though this would require additional infrastructure to collect and transport the hydrogen to the renewable refinery.
There are many factors for a refiner to consider in the decision to source either blue or green hydrogen. The cost to produce green hydrogen is high, estimated at 2-3 times the cost of blue hydrogen, according to the International Renewable Energy Agency (IRENA).58 That being said, green hydrogen would offer the biggest reduction in CI score. The biggest advantage to blue hydrogen over green hydrogen is that it can take advantage of existing refinery infrastructure, i.e. the SMR, and only the CCS infrastructure is required new. Because blue hydrogen may be faster for a refiner to implement and at a lower cost than a green hydrogen plant, blue hydrogen can serve as an interim means to a lower CI score while the world waits for green hydrogen technology to evolve. Regardless of green or blue, both options represent a means to achieving a lower CI score than grey hydrogen (see Table 5), which warrants consideration if the economics demonstrate viability.
Whether a refiner currently imports hydrogen or produces hydrogen on site, Ascent can help determine the options best suited for the plant to start producing renewable fuels.
Excess CH4 and CO can lead to a lower recycle gas purity which can affect the hydrogen partial pressure in the reactor. Increasing the purge gas rate may be one solution, but understanding the impacts of the excess CO on the downstream units is just as important as the impacts to the hydrotreating unit. The production of these by-products and subsequent additional purging may require additional make-up hydrogen to maintain purity.
The higher amounts of CO2 may form carbonic acid in the reactor effluent cooling system where free water is typically present via a combination of water injection points and condensation. Review of this system should include the sour water system to ensure adequate handling of the additional water generated by these reactions as well as the additional dissolved CO2 that it may have.
In addition, if the gas byproducts that are sourced from renewable feedstocks are re-used in a process (e.g. fuel gas, producing electricity, producing hydrogen, etc.), it can be considered a new-negative carbon emission. This can be further compounded by capturing methane from cattle livestock farms if possible. This will assist in lowering the overall CI score of the produced transportation fuel.
Emergency Depressurization and Flare
Catalytic Processing Operations
The reactions occur inside thick-walled pressure vessels of allow steel, and require precise temperature, pressure, and composition monitoring and testing. The manufacturing process is a sequence of steps that rely upon each other to obtain product that meets final specifications. Normal process control includes sophisticated digital control system that is designed and maintained to support plant operations.
Catalyst operations run in over a multi-year cycle where the activity and performance of the catalyst gradually degrades. Good feedstock quality monitoring is essential to obtain the optimal catalyst use. Catalyst materials are highly specialized and are procured from chemical vendors that also support the petroleum refining industry. The loading and initial activation of the catalysts in the renewable fuels reactors is a separate batch process that requires expert monitoring and supervision often provided by a representative of the catalyst supply company.
Contingency operations for the high pressure, highly flammable process operations are essential. These typically include provision of a safety release system that is used in emergencies to de-pressure the reaction environments to safe location and flared to prevent impact beyond the plant boundary.
The yield of the renewable diesel is monitored by plant staff to maximize the value of the process. Adjustments can be made to the catalytic operation conditions to keep plant yields inside a target specification.
Auxiliary processing of the byproducts may require add-on facilities in the areas of water processing, gas processing, and carbon oxides conversion.
Some byproducts may be suitable for recycle via the hydrogen generation facility and thereby reduce the amount of purchased hydrogen plant feedstock.
Existing petroleum refiners and emerging renewable fuel startup technologies alike have an opportunity to capitalize in the path to zero emission energy consumerism. The outlook of the petroleum-based transportation fuel market is facing headwinds driven by demand for GHG reductions and sustainable energy future. Current government programs are affecting business decisions to shift into renewables due to renewable volume and carbon obligations levied on the transportation fuel industry. In the consumer automobile market, the cost of electric cars is projected to reach price parity with internal combustion engines (ICE), which would drive increasing consumer demand on the alternative technology and reduce liquid fuel demand.
Liquid transportation fuel is still expected to be relevant and in demand in the long path to carbon neutrality. In the transportation sector, the full realization of zero emission energy consumerism sees two major hurdles: consumer adoption of electric vehicles and a zero emission U.S. electricity grid. The public sentiment for electric vehicles is stronger today than it was ten years ago. An increasing consumer adoption of electric vehicles is expected within the decade, with expectations of significantly taking market share from ICE vehicles. Increased adoption of electric vehicles in the near future will eliminate tail pipe emissions, but it will not eliminate electric generation emissions until the majority of the U.S. electric grid is powered by non-carbon emitting processes. Even if both the consumer automobile market and electric grid were zero emission, there currently exists approximately 280 million ICE vehicles in the United States that would need to be replaced before their emissions could be eliminated.
Petroleum refiners are in an ideal position to use existing assets and infrastructure to economically renew themselves for the renewable age. The large installed assets such as hydrotreater units, reformers, rails, ports, and control rooms can be effectively revamped into renewable processing facilities at a cheaper cost than grassroots. There are numerous refiners today that are transitioning their existing plants into renewable fuels, both full refinery conversion and co-processing petroleum/renewables conversion. Ascent can help refiners evaluate their options, from selecting and working with a licensor to assessing existing assets, feedstock, and product options.
Emerging renewable fuels and energy startup technologies also have an opportunity to commercialize in the renewable age. As new technologies are proven successful on the laboratory scale, one of the most common hurdles to mass production is scale-up of the technology into pilot plant and commercialization. Ascent can help startup companies develop the industrial equipment required to grow from lab to mass production flow rates, evaluate and optimize the processing options, and design full scale production facilities.
- Renewable diesel: hydrotreated product of vegetable or fatty acid oils
- Biodiesel: product of transesterification of vegetable or fatty acid oils, also known as Fatty Acid Methyl Ester or FAME
- Glycerol: byproduct of transesterification of vegetable or fatty acid oils
- Green diesel: colloquialism
- Fatty acids: aliphatic monocarboxylic acids in an animal or vegetable fat, oil, or wax. Natural fatty acids are linear chains of 4 to 28 carbons and contain a range of 0 to 2 unsaturated bonds.
- Glycerides: naturally occurring glycerol esters from fatty acids. Glycerides are subdivided into triglycerides by the number and positions of the acyl groups:
- 1,2- or 1,3-diglycerides
- 1- or 2- monoglycerides
- Glycerides distribution of carbons and double bounds is defined as XX:Y
- XX is the number of carbons in the fatty acid chain
- Y is the number of double bonds
- For example, XX:Y for oleic acid is 18:01 (18 carbons, 1 double bond, and 2 oxygens)
- The distribution is used to calculate the MW and physical properties
- Hydrodeoxygenation Reaction (HDO): Reaction step in the hydroprocessing of renewable diesel in which oxygen is removed from a glyceride to produce H2O
- Decarbonylation Reaction (DCO): Reaction step in the hydroprocessing of renewable diesel in which oxygen is removed from a glyceride to produce CO
- Decarboxylation Reaction (DCO2): Reaction step in the hydroprocessing of renewable diesel in which oxygen is removed from a glyceride to produce CO2
- E10 Gasoline: Petroleum gasoline blended with up to 10% ethanol
- E15 Gasoline: Petroleum gasoline blended with up to 15% ethanol
- E85 Gasoline: Petroleum gasoline blended with up to 85% ethanol
- B5 Biodiesel: Petroleum diesel blended with up to 5% FAME
- B20 Biodiesel: Petroleum diesel blended with up to 20% FAME
Acronyms and Abbreviations
- AFP: Alternative Fuel Portal
- ATJ: Alcohol-to-Jet
- ASTM: American Society for Testing and Materials
- BETO: Bioenergy Technologies Office
- BPD: Barrels Per Day
- BTC: Biodiesel Tax Credit
- CAFE: Corporate Average Fuel Economy
- CARB: California Air Resources Board
- CARBOB: California Reformulated Gasoline Blendstock for Oxygenate Blending
- CBTS: Credit Bank & Transfer System
- CCS: Carbon Capture and Sequestration
- CHJ: Catalytic Hydrothermolysis
- CI: Carbon Intensity
- CORSIA: Carbon Offsetting and Reduction Scheme for International Aviation
- DCO: Decarbonylation
- DCO2: Decarboxylation
- DOE: Department of Energy
- eGRID: Emissions & Generation Resource Integrated Database
- EER: Energy Economy Ratio
- EIA: Energy Information Administration
- EISA: Energy Independence and Security Act
- EPA: Environmental Protection Agency
- EV: Electric Vehicle
- FAME: Fatty Acid Methyl Ester
- FCC: Fluid Catalytic Cracker
- FT: Fischer-Tropsch
- GGE: Gasoline Gallon Equivalent
- GHG: Greenhouse Gas
- GREET: Greenhouse gases, Regulated Emissions, and Energy use in Technologies
- HEFA: Hydroprocessed Esters and Fatty Acids
- HDO: Hydrodeoxygenation
- HDRD: Hydrogenation Derived Renewable Diesel
- ICAO: International Civil Aviation Organization
- ICE: Internal Combustion Engine
- IRENA: International Renewable Energy Agency
- LCFS: Low Carbon Fuel Standard
- LHSV: Liquid Hourly Space Velocity
- LRT: LCFS Reporting Tool
- MON: Motor Octane Number
- MTBE: Methyl Tert-Butyl Ether
- MTG: Methanol-to-Gasoline
- MW: Molecular Weight
- NOAA: National Oceanic and Atmospheric Administration
- NOx: Nitrogen Oxides
- NREL: National Renewable Energy Laboratory
- NSF: National Science Foundation
- PSA: Pressure Swing Adsorption
- RFG: Reformulated Gasoline
- RFS: Renewable Fuel Standard
- RIN: Renewable Identification Number
- RON: Research Octane Number
- RVO: Renewable Volume Obligation
- SAF: Sustainable Aviation Fuel
- SIP: Synthesized Isoparaffins
- SMR: Steam Methane Reforming
- TAN: Total Acid Number
- TEL: Tetraethyllead
- ULSD: Ultra Low Sulfur Diesel
- USDA: United States Department of Agriculture
- VOC: Volatile Organic Compound
- ZEV: Zero Emission Vehicle
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