A Perspective on Oxygenated Species in the Refinery Integration of Pyrolysis Oil

Green Chemistry

CRITICAL REVIEW

Cite this: Green Chem., 2014, 16,407

Received 18th September 2013,Accepted 25th November 2013

DOI: 10.1039/c3gc41951g

www.rsc.org/greenchem

A perspective on oxygenated species in therefinery integration of pyrolysis oil†

Michael S. Talmadge,a Robert M. Baldwin,a Mary J. Biddy,a Robert L. McCormick,b

Gregg T. Beckham,a,c Glen A. Ferguson,a Stefan Czernik,a Kimberly A. Magrini-Bair,a

Thomas D. Foust,a Peter D. Metelski,d Casey Hetrickd and Mark R. Nimlos*a

Pyrolysis offers a rapid and efficient means to depolymerize lignocellulosic biomass, resulting in gas,

liquid, and solid products with varying yields and compositions depending on the process conditions.

With respect to manufacture of “drop-in” liquid transportation fuels from biomass, a potential benefit

from pyrolysis arises from the production of a liquid or vapor that could possibly be integrated into exist-

ing refinery infrastructure, thus offsetting the capital-intensive investment needed for a smaller scale,

standalone biofuels production facility. However, pyrolysis typically yields a significant amount of reactive,

oxygenated species including organic acids, aldehydes, ketones, and oxygenated aromatics. These oxyge-

nated species present significant challenges that will undoubtedly require pre-processing of a pyrolysis-

derived stream before the pyrolysis oil can be integrated into the existing refinery infrastructure. Here we

present a perspective of how the overall chemistry of pyrolysis products must be modified to ensure

optimal integration in standard petroleum refineries, and we explore the various points of integration in

the refinery infrastructure. In addition, we identify several research and development needs that will

answer critical questions regarding the technical and economic feasibility of refinery integration of pyro-

lysis-derived products.

1. Introduction

There is significant, worldwide interest in converting renew-able biomass sources to liquid transportation fuels, with theoverall aim to develop a more sustainable and diverse trans-portation fuel economy. Lignocellulosic biomass, derived fromplant cell walls, offers a significant pool of renewable carbonthat can be upgraded to a wide range of fuels andchemicals.1–3 To date, there are multiple technologies beingconsidered for producing biofuels from lignocellulosicbiomass, which can quite broadly be categorized as biochemi-cal and thermochemical conversion routes. Standardbiochemical conversion routes typically include a mild ther-mochemical pretreatment step intended to make the plant cellwall more amenable to hydrolysis of the most recalcitrantbiomass fractions to soluble sugars by enzymes. The resulting

sugars can then be upgraded catalytically4,5 or biologically.6

Conversely, thermochemical conversion uses significantlyharsher conditions to depolymerize biomass, either via pyro-lysis (400 °C–600 °C)7 to a mixture of vapor, liquid, and solid,or to synthesis gas via gasification8,9 at much higher tempera-tures (750 °C–950 °C).

Ethanol can readily be produced from either biochemicalconversion through fermentation10 or via thermochemical con-version through gasification, followed by catalytic upgrading tomixed alcohols.11 In the current gasoline market, ethanol pro-duced by fermenting sugar from grains or sugarcane has beenwidely accepted as a gasoline blendstock in some parts of theworld. However, there are significant technical challenges toexpanding the use of ethanol, such as its incompatibility withexisting vehicles at higher blends and its inability to be trans-ported in the fungible fuel distribution system.

In contrast to ethanol, producing infrastructure-compatiblehydrocarbon fuels from biomass has distinct benefits in thatthese materials can be tailored to be chemically similar oridentical to existing gasoline, jet, and diesel fuels. Producinghydrocarbon fuels from lignocellulosic biomass will undoubt-edly require an even broader range of research and develop-ment activities far beyond the significant efforts todemonstrate ethanol production at scale, as the slate of hydro-carbon molecules to be produced for broader fuel pools is

†Electronic supplementary information (ESI) available. See DOI:10.1039/c3gc41951g

aNational Bioenergy Center, National Renewable Energy Laboratory,

15013 Denver West Parkway, Golden, CO 80401, USA. E-mail: [email protected] and Hydrogen Systems Center, National Renewable Energy

Laboratory, 15013 Denver West Parkway, Golden, CO 80401, USAcDepartment of Chemical Engineering, Colorado School of Mines, Golden, CO 80401,

USAdBP Refining and Marketing Research & Technology, Naperville, Illinois, USA

This journal is © The Royal Society of Chemistry 2014 Green Chem., 2014, 16, 407–453 | 407

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necessarily more expansive. To accomplish this goal, conver-sion pathways using biochemical, thermochemical, andhybrid thermochemical/biochemical processes are beingconsidered.12

A particularly attractive technology for producing hydro-carbon fuels from biomass is fast pyrolysis. Slow pyrolysis forthe production of charcoal has been utilized for centuries,while over the past 30 years the focus has been on fast pyro-lysis to produce both pyrolysis oils as well as chemicals andfuels.7,13 Fast pyrolysis can produce a liquid carbonaceousmaterial in high yield in a relatively inexpensive process.7

Because of the advantages of this technology, it has beenextensively studied for many decades and recently the processhas advanced to commercial scale.13 With the approval ofASTM D7544, which defines the required specifications forpyrolysis oil for use in fuel-burning combustors, and the estab-lishment of environmental policies and societal focus through-out the world to reduce utilization of fossil fuels, pyrolysis oilis being strongly considered as a fuel oil replacement. Thereare currently several demonstration plants being operatedworldwide producing pyrolysis oil as boiler feed for electricitygeneration.13 Hydroprocessing of pyrolysis oil is a newer areaof research focus with the goal of producing infrastructure-compatible hydrocarbon fuels and/or refinery intermediatesand blendstocks. While work was begun in the 1980s in theseefforts, there has been a resurgence in this research area overthe past 5 years with the bulk of the research focusing on pro-cessing at the bench and pilot scale.14 One advanced pyrolysisprocess for producing transportation fuels involves generatingfast pyrolysis oil, often called bio-oil, and upgrading the bio-oilinto hydrocarbon fuels using hydrotreating or hydroproces-sing. Converting pyrolysis oil directly to a fuel using this tech-nology requires a significant capital investment for astandalone biorefinery as well as an external, readily availablesource of hydrogen. Because of significant biomass transpor-tation costs, production capacity for a single biorefinery islimited, and thus cannot take full advantage of economies ofscale for capital equipment costs.

Though hydrotreating of pyrolysis oil has been extensivelyinvestigated, there are limited studies in the literature onusing pyrolysis oil in existing petroleum refineries, which isthe subject of this perspective. The advantages of using bio-oilin refineries are significant:• Integrating pyrolysis oil into the refinery could signifi-

cantly reduce the cost of producing fuels from biomass. Tril-lions of dollars have been invested in petroleum refineries,and if bio-oil can be upgraded in these facilities, many of thecapital expenses associated with building a new plant tohandle bio-oil alone could be avoided.• Processing bio-oil with petroleum in a refinery could

produce a fuel that is indistinguishable from existing gasoline,jet, and diesel fuels. As a result, there would not likely berequirements for extensive, time consuming, and expensiveengine and acceptance testing.• Biomass fast pyrolysis produces a suite of hundreds to

thousands of chemical compounds and modern refineries

have been optimized to use complex and varying feedstocks toproduce transportation fuels at a profit.

In this perspective, we discuss various options for integrat-ing pyrolysis oil into a standard petroleum refinery. Specifi-cally, we first review the pyrolysis process for lignocellulosicfeedstocks and the composition of resulting bio-oils in light ofphysical property requirements for petroleum refinery inte-gration. We then discuss options for upgrading pyrolysis oil tomeet these requirements. In section 4, we discuss standardpetroleum refinery unit operations and examine associatedquality metrics for each. Section 5 describes several options forintegrating pyrolysis oil into refinery unit operations. Lastly,section 6 outlines some potential fuel molecules and theirassociated physical and chemical properties that may resultfrom the oxygenated feedstocks in a refinery.

2. Pyrolysis and composition ofpyrolysis oil

Fast pyrolysis is an attractive process for deconstructingbiomass into smaller carbonaceous molecules that couldpotentially be used as intermediates in refinery unit oper-ations. Using typical heating rates of 1000 K s−1, carbon con-versions greater than 70% into a liquid product can beobtained. This high conversion is essential because of thehigh feedstock costs associated with the collection and deliveryof biomass. In addition, pyrolysis reactors are relatively smalland of low capital cost due to the short residence timerequired, and they are typically easy to operate. Reactor con-figurations such as fluidized bed, circulating bed, andentrained flow are ideally suited to fast pyrolysis; these havebeen widely used for more than 60 years in the refining andpetrochemical industry and are commercially available.Finally, the relatively low temperature required for biomasspyrolysis (400 °C–600 °C) means that inexpensive materialscan be used for reactor construction.

If the fast pyrolysis process is conceptually ideal for prepar-ing refinery intermediates, the reality is that the compositionof the resulting bio-oils is far from ideal from the perspectiveof the refining industry. Typically, biomass pyrolysis oil hasmany undesirable physical characteristics that make its use ina refinery problematic. These include thermal instability,immiscibility in hydrocarbons, high viscosity, high watercontent, and corrosivity. These properties are directly relatedto the chemical composition of the bio-oil and in particular,the oxygen content of the products formed from the pyrolysisof the biopolymers found in plant cell walls. In this section,the conversion of biomass into pyrolysis oil products and theeffects of the pyrolysis oil composition on physical propertieswill be discussed in detail.

2.1 Biomass composition and yields of oils

Biomass is composed of three main biopolymers, cellulose,hemicellulose, and lignin; and the decomposition of thesethree materials is largely responsible for the observed solid,

Critical Review Green Chemistry

408 | Green Chem., 2014, 16, 407–453 This journal is © The Royal Society of Chemistry 2014

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liquid, and gaseous products. As can be seen in Fig. 1, thesematerials contain a significant amount of oxygen, which trans-lates into 30 wt%–60 wt% oxygen in the oil. Cellulose is asimple linear polymer consisting of repeat units of cellobiosewith a degree of polymerization (dp) often exceeding 2000. Inplant cell walls, several chains of cellulose are held together inmicrofibrils that provide the strength to the plants. Hemicellu-lose is a branched biopolymer that contains a backbone poly-saccharide, which is commonly a repeat of xylobiose.

Other sugars, such as manose, arabinose, glucose andgalactose, and sugar acids branch off from this backbone; andthere is a high degree of acetylation. The anhydrosugars inthese biopolymers typically have the atomic formula ofC6H10O5 for hexoses and C5H8O4 for pentoses, which showsthe source of much of the oxygen in pyrolysis oil. Lignin is acomplex polymer of propylaromatic subunits originally con-structed from the lignol monomers, p-coumaryl, coniferyl, andsinapyl alcohol (shown below), which have molecular formulasof C9H10O2, C10H12O3, and C11H14O4. This polymer does notcontribute as much to the oxygen content of the pyrolysisoil due to its lower atomic oxygen-to-carbon ratio. The

organization of these polymers in cell walls is the subject ofintense research, but it is clear that cellulose microfibrils formwhat appears to be a mat that provides the structure andstrength for plant cell walls and the hemicellulose and ligninare arranged around the cellulose microfibrils. Although thesebiopolymers in biomass largely determine the yields and com-position of the observed products in biomass pyrolysis oil,small levels of inorganic constituents also affect the productyields.15–17

Lignols:

The composition of biomass varies significantly fromwoody to herbaceous materials. Data on the composition ofseveral feedstocks for biofuels manufacture is available at the

Fig. 1 Typical products formed from the pyrolysis of the biopolymers in plant cell walls.

Green Chemistry Critical Review


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U.S. Department of Energy’s Alternative Fuels Data Center(http://www.afdc.energy.gov/biomass/progs/search1.cgi). Typicalcompositions are shown in Table 1 for some important speciescovering hard and soft woods (poplar and pine), potentialenergy crops (switch grass), and agricultural residue (cornstover). Notice that the woody materials typically have lowerash, extractives, and hemicellulose and more lignin than theherbaceous species. The extractives, materials that can beremoved from the biomass using solvents, are fatty acids,lipids, fatty alcohols, terpenes, resin acids, and terpenoids18

for woody materials and free sugars, sugar oligomers, alditols,organic acids, and inorganic ions19,20 for herbaceous feed-stocks. Extractives can have a major influence the propertiesof pyrolysis oil18,21,22 and pretreatment of the biomass canoften affect these materials resulting in changes in bio-oilcomposition.

During fast pyrolysis, the biopolymers found in plant cellwalls are converted into non-condensable gasses, liquids, andsolid char. The gasses are primarily CO2, CO, CH4, H2, andsome light hydrocarbons. The liquids contain 15%–30% waterin an emulsion with hydrophobic and hydrophilic organiccompounds, some suspended solid material, and alkali andalkaline earth metal compounds that are present as inorganicmatter in the feed biomass. Depending upon the temperatureof pyrolysis, the char is primarily carbon, which can be usedfor process heat. Though the light gases may serve as a sourceof hydrogen, the liquids are most suitable for refinery oper-ations. The organic compounds in these liquids typicallycontain a wide variety of oxygen functional groups, whichimpart undesirable physical and chemical properties to bio-oil.

Determining the yields of char, gas, and liquid is veryimportant for assessing the viability of different feedstocks forproduction of bio-oil. An interesting hypothesis has beenoffered, which suggests that these yields can be estimatedfrom the biopolymer content of the biomass. Perhaps the mostcompelling work was conducted by Qu et al., who studiedproduct yields in a bench-scale tubular reactor in which thebiomass was heated to pyrolysis temperatures (350 °C–650 °C)within one second.27 They measured the product yields fromthe individual biopolymers as shown in Table 2 and usedthese data to predict the formation of products from biomasspyrolysis based upon the measured biopolymer content. Thereported compositions are consistent with other literaturevalues,28–31 and Fig. 2 shows a comparison of the predicted(“calculate”) product yields to experimental values for rice

straw pyrolysis. Similar results were obtained for corn-stalkand peanut vine, a woody biomass. If this hypothesis is true,the carbohydrates will be the dominant source of liquids. Asshown in Table 1, carbohydrates make up roughly 70% of thebiopolymers and have liquid yields of 50%–60%, while ligninmakes up 20%–30% of the biopolymers and only produces40% liquid. Thus, the carbohydrates contribute 3 to 4 times asmuch liquid as does lignin in biomass pyrolysis.

It should be pointed out that there are studies suggestingthat this component analysis hypothesis is incorrect.32,33 Ofparticular concern are the effects of inorganic materials. Forinstance, Oassma et al. measured the pyrolysis yields forseveral feedstocks and showed that the organic materials in

Table 2 Products from the fast pyrolysis of select biopolymers at500 °C24

Yields Cellulose Hemicellulose Lignin

Gas 20% 26% 13%Char 18% 23% 47%Liquid 62% 50% 40%

Products in gasCO2 48% 60% 32%CO 47% 30% 25%CH4 4% 7% 42%

Fig. 2 Predicted yields compared to measured yields for the productsfrom rice straw pyrolysis. Taken from ref. 27. Reprinted with permissionfrom T. Qu, W. Guo, L. Shen, J. Xiao, K. Zhao, Industrial & EngineeringChemistry Research, 2011, 50, 10424–10433. Copyright 2011 AmericanChemical Society.

Table 1 Typical biomass compositiona

Species Extractives Ash Lignin Hemi-cellulose Cellulose

Hybrid Poplarb 3.6 0.9 23.3 (24.6) 27.8 (29.3) 43.7 (46.1)Monterey Pinec 2.7 0.3 25.9 (28.6) 23.0 (25.4) 41.7 (46.0)Switchgrassd 17.0 5.8 17.4 (23.1) 27.3 (36.1) 30.8 (40.8)Corn Stovere 7.6 6.8 17.2 (21.1) 26.3 (32.5) 37.8 (46.4)

aGiven in weight percent. Values in parenthesis are ash and extractive free. b Ref. 23. cRef. 24. d Ref. 25. e Ref. 26.



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the liquids were directly related to the amount of ash in thefeedstock, as shown in Fig. 3. Alkali metals present in the ashare known to increase the yields of char, water, and gasesduring pyrolysis17,34–37 and this could lead to lower yields ofliquid organic compounds. Potassium is known to be particu-larly active.38–42 In the study of Qu et al., the ash (inorganics)were treated as inert materials that only add to the char

yields.27 This appears to be different from a significant body ofliterature, which shows that the presence of alkali metals dra-matically influences the yields and composition of pyrolysisoils.

2.2 Oxygen content

As mentioned above, oxygen in bio-oil is responsible for someof the physical and chemical properties that make it unsuita-ble for introduction into refineries. There are a significantnumber of studies that report on the elemental composition ofbiomass fast pyrolysis oils; some of these data are shown inTable 3. In this table, the elemental composition is reported inthe absence of water, which makes up roughly 20% of the oil.Another study of note is a round robin campaign43 conductedin 2000 for the IEA, in which four pyrolysis samples were ana-lyzed by twelve laboratories. The standard deviations of themeasurements were 1%–3% for carbon and 3%–5% for hydro-gen. Oxygen was determined by difference. The larger vari-ations shown in Table 3 may be because of variations in the oilpreparation and the feedstock composition. As can be seen,the amount of oxygen varies from 32 wt% to 48 wt%, and sig-nificant variations are found between each species. The table

Fig. 3 Organic compound yields in the condensable liquids from fastpyrolysis as a function of ash content of biomass. From ref. 16. Reprintedwith permission from A. Oasmaa, Y. Solantausta, V. Arpiainen,E. Kuoppala, K. Sipilä, Energy & Fuels, 2010, 24, 1380–1388. Copyright2010 American Chemical Society.

Table 3 Elemental composition of fast pyrolysis oil on a dry basis

Feedstock

Weight percent ppm

C H Oa N Sb K–Nab Clb

PineVTT44 55.8 5.8 38.2 0.1 0.02 20 30Dynamotive44 52.6 7.53 39.52 0.09 0.0197BTG44 53.7 6.0 40.0 0.3Fortum44 57.1 6.4 36.4 0.1PNNL45 51.2 7.5 41.1 0.1 10PNNL46 53.0 6.4 40.5 0.1 0.003

PoplarNREL47 57.3 6.3 36.2 0.18 0.02 10 8NREL47 60.5 6.7 32.6 0.23 0.02 12 8Waterloo48 54.7 6.7 38.3Waterloo49 51.8 6.7 41.3Waterloo50 57.3 6.29 36.4

OakDynamotive44 47.2 4.5 48.0 0.12 0.022PNNL45 56.0 6.8 37.2 57NREL51 59.6 6.0 34.2 0.11 0.01 100

Corn StoverUMinn52 60.66 7.70 2.2 0.15USDA53 53.97 6.92 37.94 1.18Iowa St54 58.4 5.2 30.9 0.5

StrawVTT44 55.3 6.6 37.7 0.4 0.05 2 330Waterloo50 55.55 6.39CHEC 37 7.7 52 1.1 0.1

SwitchgrassNREL44,50 55.8 6.9 36.3 0.79 0.03 128 1900PNNL45 46.6 8.0 45.4 165USDA55 46.0 6.7 42.6 0.3

a By difference. b Some of the studies did not report sulfur, alkali and chloride.



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also shows the nitrogen and sulfur levels, where determined.As discussed later in this paper, fuel standards require lowlevels of sulfur in finished fuels and both elements can becatalyst poisons. Also shown in this table are measurements ofpotassium, sodium, and chloride. These elements can also becatalyst poisons; chloride can also contribute to corrosion.

2.3 Molecular composition

Numerous studies16,43,44,56–62 have measured the products ofbiomass pyrolysis; and the list of measured compoundsincludes carboxylic acids, esters, ethers, alcohols, ketones,aldehydes, diols, hydroxylated ketones and aldehydes, furans,sugars and anhydrosugars, phenolic compounds, and hydrocar-bons. Oxygen is present in most of more than 300 compoundsthat have been identified by GC/MS.63 Typically, the concen-tration of any particular compound is less than 10 wt% thoughthere is a large variability in the measurements of individualmolecular species in the products. The IEA round robin study,43

where the same oils were measured by different laboratories,highlighted the difficulty in measuring these compounds.

To some degree, the observed molecular products can berelated to the plant cell biopolymers as shown in Fig. 1 whichhighlights the product distribution from the pyrolysis of thedifferent biopolymers. Most of the aliphatic and furanic oxyge-nated hydrocarbons are formed from cellulose and hemicellu-lose,64,65 while the phenolic compounds arise from pyrolysis ofthe lignin component.66 As with total organic yield, the mole-cular composition of pyrolysis oil is also affected by theamount of alkali and alkaline earth metals in the biomass.The products from cellulose and hemicellulose are particularlysensitive.17,64

The molecular composition and the concentration of theseindividual compounds also depend on process severity (temp-erature, residence time, and heating rate profiles). Elliott67 andEvans and Milne15 found that highly oxygenated aliphatic andaromatic primary pyrolysis vapors (oils) form at 400 °C. Manyof these compounds crack at temperatures above 550 °C andproduced pyrolysis vapors that are less oxygenated and morearomatic. As a result, oils produced at elevated temperaturesinclude more phenolic compounds.

The chemical composition of bio-oils produced fromprocess conditions that maximize liquid yields is very complex,and complete analysis of those oils requires the combined useof several analytical techniques. A precise description of bio-

oil composition has not yet been achieved and even with con-siderable analytical efforts, about 20% of the composition stillremains unknown. According to Meier,68 water is the singlemost abundant component of bio oil, accounting for 15 wt%–

30 wt% of the whole oil. Other major components include:40 wt% GC-detectable organic compounds; 15 wt% non-vola-tile HPLC detectable compounds; and 15 wt%–25 wt% of high-molecular-weight compounds. Major organic compoundsclasses identified in bio-oil are hydroxyaldehydes, hydroxy-ketones, sugars, carboxylic acids, and phenolics,69 with mostof the phenolic compounds present as oligomers with mole-cular weights ranging from 900 to 2500 AMU.66,70

A comprehensive approach to bio-oil analysis has been pro-posed by the VTT research group44 in which water content isdetermined by Karl-Fischer titration: the high-molecular-weight, water insoluble compounds collectively termed “pyro-lytic lignin” are precipitated by mixing small amounts of bio-oil with water and measuring the subsequent precipitateweight. The pyrolytic lignin is a fraction composed of many oli-gomeric fragments originating from the biomass lignin. Themost extensive studies on characterization and analysis of thismaterial were done by the Institute of Wood Chemistry inHamburg.71–74

GC/MS analysis has been used extensively to identify andquantify the volatile components of bio-oils. The most compre-hensive results are those published by Branca et al.,58 Garcìa-Pérez et al.,75 and Azeez et al.76 Azeez quantified 80 com-pounds that accounted for 36.3 wt% of beechwood bio-oil and44.0% of corn cob bio-oil. Piskorz et al.69 used HPLC analysisof water-soluble fractions to determine types and amounts ofvaried carboxylic acids, hydroxyaldehydes, ketones, and carbo-hydrates that were not quantified by gas chromatography. Themost abundant organic components of bio-oils that have beenreported in these studies are generally hydroxyacetaldehyde,acetic acid, formic acid, acetol, glyoxal, levoglucosan, andcellobiosan.

A simplified approach to bio-oil characterization uses func-tional group analysis. Radlein77 provided the results shown inTable 4 obtained by Nicolaides78 for the primary functionalgroup content of bio-oils produced from different feedstocksusing appropriate chemical analysis methods.

Interesting information on bio-oil composition was alsoobtained from 13C NMR analysis that provides data on bio-oilcarbon distribution between different types of functionalities.

Table 4 Group distribution in bio-oils produced from different feedstocks75

Feedstock

Moles functional groups per kg organic liquid

Carboxyl Carbonyl Hydroxyla Phenolic Methoxy

Maple 2.1 5.7 0.92 2.8 2.1Wheat straw 1.4 5.3 1.40 3.0 1.1Poplar-Aspen 2.1 6.2 0.77 2.8 1.6Peat moss 1.2 3.0 1.30 1.8 0.7

aHydroxyl contents may be underestimated as the phthalic anhydrate method used here is not very reliable for analyzing hydroxyl groupsattached to adjacent carbon atoms.



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Ingram et al.79 gathered the results in Table 5 for several bio-oils produced in an auger pyrolyzer. These data show a signifi-cant difference in the composition of bio-oil obtained fromwood and from bark, especially for carbonyl and aliphaticcompound content.

Because of the extensive variation in bio oil chemical pro-perties, several fractionation methods have been used to facili-tate the chemical analysis of these complex liquids. Onesuccessful approach is based first on solvent extraction usingwater followed by different polarity organic solvents such asether and dichloromethane. Oasmaa et al.22 analyzed bio-oilsproduced from forest residues using this method in whichseven distinct fractions were obtained consisting of:

1. High-molecular-weight lignin2. Low-molecular-weight lignin3. Extractives4. Sugars5. Water6. Aldehydes, ketones, and lignin monomers7. Acids, alcohols, other volatiles.Based on currently available analyses of bio-oils, Radlein77

presented the bio-oil composition considering both compoundclass and associated size of molecules as shown in Table 6.

Two-dimensional gas chromatography coupled with time offlight mass spectrometry (2D GCxGC/TOFMS) and two-dimen-sional flame ionization detection (2D GCxGC/FID) have beenrecently applied to more comprehensively characterize bio-oil.

The ability to spatially separate polar from nonpolar com-pounds with selective detection expands the range of volatileoil compounds that are analyzable with this technique.

Other recent work characterizes chemical changes via func-tional groups in raw bio-oils using both 2D GCxGC/TOFMSand 2D GCxGC/FID. As shown in Fig. 4,80 major functionalgroups can be identified using these techniques comprisingsugars, aromatics, phenols, aldehydes, ketones, furans andbenzenediols. The combined method provides both quantitat-ive (FID) and qualitative (TOFMS) information on raw andtreated oils for 150 discrete peaks that comprise more than80% of the total peak area. Further work on raw and hydro-deoxygenated (HDO) pyrolysis oils using 2D GCxGC/TOFMSidentified 250 and 350 analytes, respectively, for the raw andtreated oils that described greater than 75% of total peak area.These GC techniques give promise for the rapid determinationof the composition of both raw and upgraded pyrolysis oilsand are potentially very useful tools for exploratory catalystresearch and for reaction mechanism and kinetic studies.81

In summary, because of the chemically complex nature offast pyrolysis bio-oils, comprehensive compositional analysisremains a very challenging task that requires application ofmultiple analytical techniques. Despite significant progress,about 20% of the bio-oil composition is still unknown. Basedon the behavior of this material (non-volatile, water insoluble,ether insoluble), it is likely the unidentified fraction is mostlycomprised of polyols derived from the thermal decompositionof polymeric carbohydrates. However, no direct evidence cur-rently exists to confirm this hypothesis. The emerging two-dimensional GC techniques are rapidly changing how bio-oilsare characterized and, when used with other analytical tech-niques, may provide powerful new tools for comprehensivechemical characterization of these unique and complex renew-able materials.

2.4 Properties of oils

Several physical and physico-chemical properties of rawbiomass pyrolysis oil make it unsuitable for use in petroleumrefineries; for the most part these undesirable properties are aresult of the high oxygen content and the particular oxygenfunctionality present in bio-oil. In particular, many of the com-ponents of pyrolysis oil are not soluble in organic solvents,

Table 5 Distribution in bio-oils produced in an auger reactor

Type of carbon

Carbon content (% of all bio-oil carbon)

Pine woodoil

Pine barkoil

Oak woodoil

Oak barkoil

Carbonyl 11.8 0.5 18.1 2.4Aromatic 48.4 43.9 40.1 35.3Carbohydrate 5.8 1.4 10.3 2.1Methoxy/hydroxy 16.1 20.8 16.1 12.5Alkyl 17.9 33.4 15.5 47.7

Table 6 Compound classes in bio-oil

Compound Class

Composition rangeWt% of organicbio-oil fraction

C1 compounds (formic acid, methanol,formaldehyde)

5–10

C2–C4 linear hydroxyl and oxosubstituted aldehydes and ketones

15–35

C5–C6 hydroxyl, hydroxymethyl andoxo substituted furans, furanones,and pyranones

10–20

C6 anhydrosugars andanhydrooligosaccharides

6–10

Water soluble carbohydrate derivedoligomeric and polymeric materialof unknown composition

5–10

Monomeric methoxyl substitutedphenols

6–15

Pyrolytic lignin 15–30

Fig. 4 Group type analysis of the crude bio-oil.



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which is a potential barrier to co-processing with petroleum.Of additional concern are the following:

1. High water content.2. Pyrolysis oil contains a significant amount of particulate

matter that can foul catalysts.3. The pyrolysis oils are reactive, particularly at elevated

temperatures, which results in increased viscosity.4. Raw pyrolysis oils can have high viscosity, which as noted

can increase during storage and handling. This can lead topoor flow characteristics and plugging, particularly in distilla-tion units.

5. Pyrolysis oils have low volatility, leading to high amountsof residue upon fractional distillation.

6. Pyrolysis oils are more corrosive than petroleum feed-stocks and can damage the reactors and transfer lines.

Table 7 shows some of the specifics of pyrolysis oil propertiesthat are relevant to introduction into a refinery;16,18,43,44,81–90

these properties are discussed in more detail below.2.4.1 Water content. Water is the most abundant com-

pound in biomass pyrolysis oil with typical loadings of 15 wt%to 30 wt%. At these loading ranges, the pyrolysis oil does notseparate into aqueous and oil phases, but remains as a single-phase pseudo-emulsion. This emulsion is thought to be facili-tated by hydrogen bonding due to the oxygen content of mostof the organic species in pyrolysis oil. The oxygen-containingfunctional groups on these compounds can form hydrogenbonds to water molecules and facilitate the formation of astable emulsion. Imaging91 has shown that 5–10 μm aqueousdroplets are found in these emulsions. At weight loadingsgreater than 30%, separation of water and oil occurs and twophases are seen. The water in the bio-oil results from moisturein the biomass plus water formed by dehydration reactionsoccurring during pyrolysis. The impact of water content onrefinery integration is a key issue that needs to be investigated.Water in the pyrolysis oils will decrease the viscosity of bio-oil,but the presence of water can be damaging to some of the cata-lysts used in the downstream unit operations used for upgrad-ing bio-oil Phase separation and water extraction may be anapproach for reducing water in the oil phase, but will likelyremove a significant amount of the organic material and willincrease the waste water clean-up demands.

2.4.2 Solids. Particulate matter is generated by pyrolysisand in spite of attempts to filter this material with cyclones,

some of the solid material is carried into the pyrolysisoil.44,51,87,88,91,92 In addition, there is evidence that particulatematter is formed during bio-oil condensation66 and aging ofpyrolysis oil. Particles found in pyrolysis oil vary from nan-ometer to micrometer sizes. Fig. 5 shows three measurementsof size distribution in pyrolysis oil87 for particles greater than1 μm. The nanometer-sized particles have been observed inimaging studies of pyrolysis oil and are thought to be animportant component of the micro-emulsion. The solids couldbe from char formed during pyrolysis, sand or other heattransfer material, polymerized pyrolysis products, or inorganicmaterial from the biomass. The presence of these materials isproblematic because:

1. They can facilitate aging and polymerization of the pyrol-ysis oil.51

2. They increase viscosity.3. They can plug transfer lines and damage pumps.4. They can deactivate catalysts.A recent study by the National Renewable Energy Laboratory

has shown that application of hot gas filtration to pyrolysisvapors prior to condensation is effective for producing a bio-oil with very low particulate content, and with very low concen-trations of alkali and alkaline earth metals.48 The stability ofthe hot gas filtered oil was also found to be greatly improvedwhen compared to unfiltered oil as discussed in the followingsection.

2.4.3 Stability and aging. Bio-oil is not a product of ther-modynamic equilibrium during pyrolysis, but is producedwith short reactor times and rapid cooling or quenching fromthe pyrolysis temperatures. This produces a condensate that isalso not at thermodynamic equilibrium at storage tempera-tures. Bio-oil contains many oxygenated organic compoundswith a wide range of molecular weights, typically in small per-centages. During storage, the chemical composition of the bio-oil changes toward thermodynamic equilibrium, resulting inchanges in the viscosity, molecular weight, and co-solubility ofits many compounds.

Table 7 Properties of biomass pyrolysis oil

Property Notes

Water 15 wt%–30 wt%Viscosity 13–80 cSt @ 50 °CSolids content 0.01 wt%–1 wt%Miscibility inorganic solvents

Poor

Stability Oil components polymerize,particularly at elevated temperatures

Corrosivity pH 2.0–3.7, TAN ∼ 100Distillation 30%–50% residue81,89

Density 1.2 g cm−3

Fig. 5 Three measurements of particle sized greater than 1 mm fromthe pyrolysis of forest residue.87 Reprinted with permission fromA. Oasmaa, C. Peacocke, A guide to physical property characterisation ofbiomass – derived fast pyrolysis liquids, VTT Publications, 2001, vol. 450,pp. 1–102. Copyright 2001 VTT Publications.



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The aging of biomass pyrolysis oil has been extensivelystudied and has important implications for its use in refi-neries. These studies have shown that chemical reactions inthe oil lead to increased water content, the evolution of lightgasses, greater tendency towards phase separation, increasedmolecular weight, and increased viscosity. The rate of aging isstrongly dependent upon temperature,92–94 which also hasimportant implications for introduction into refinery unitoperations. Fig. 6 shows a plot of the viscosity and molecularweight of pyrolysis oil. As can be seen, the viscosity increasesby roughly 50% in 80 days at 37 °C, while the viscosity doublesin 15 hours at 90 °C. The concomitant increase in molecularweight shown in this plot suggests that polymerization reac-tions are occurring during aging. This type of increase in vis-cosity and molecular weight has been observed by severallaboratories95–97 and was the subject of a recent round robinstudy.98

Most projected uses of bio-oil require that it retain theseinitial physical properties during storage, shipment, and use.However, some bio-oils rapidly become more viscous duringstorage. Fig. 7 shows this increase for three bio-oils made fromthree hardwoods using different pyrolysis conditions afteraging 3 months at 35 °C to 37 °C. These three bio-oils exhibit

very different initial viscosities and rates of viscosity increase.The effect of aging on viscosity is greater at lower measure-ment temperatures.99

Because the viscosity change rates may be represented asArrhenius exponential functions of the inverse of absolutetemperature, chemical reactions appear to be involved. Fig. 8shows that the bio-oils must be cooled quickly after being pro-duced and then stored at low temperatures to maintain theirlow viscosity.

In addition to simple viscosity increases, the bio-oil emul-sion can separate into various tarry, sludgy, waxy, and thinaqueous phases during aging. Tarry sludges and waxes still insuspension have caused rapid plugging of fuel filters. They canform during storage in previously filtered bio-oils and inaqueous phases. Bio-oils seem to be more unstable duringstorage than are petroleum-derived fuel oils, although thereappear to be many similarities in their mechanisms.

The reactions that occur in pyrolysis oil largely involve theoxygen functionalities. Diebold discussed several types of reac-tions100 including:• Esterification: the reaction of organic acids with alcohols

to form esters and water.• Condensation reactions involving aldehydes and ketones

and water or alcohols.• Condensation reactions of aldehydes with phenols.• Condensation reactions involving furfurals.Many of these reactions can also be catalyzed by solid

material in the bio-oil, such as inorganic material from thebiomass. Studies where the solids are filtered out show muchslower changes in viscosity.51 These reactions reduce theamounts of carbonyls and alcohols; increase the molecularweight; and, with dehydration reactions, lead to water for-mation. An increase in water concentration has beenobserved,93 and although increased water has been shown toreduce viscosity,88 this effect is overwhelmed by an increase inmolecular weight. Fig. 9 shows a plot of the observed trends inpyrolysis oil,98 which are consistent with the reactions dis-cussed by Diebold100 and which show that most of the agingoccurs during the first 3 months.

The reactivity of pyrolysis oil can be particularly proble-matic for distillation operations. Polymerization and molecular

Fig. 8 Rate of viscosity increase with temperature during oil storage.

Fig. 6 Changes in the viscosity and molecular weight of pyrolysis oilgenerated from oak in a vortex reactor.93,94

Fig. 7 Aging of bio-oils at 35 °C to 37 °C.



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weight growth during distillation leads to the formation ofsolid residue, particularly as the distillation pot is heated todrive off different components. This eventually leads to the for-mation of nonvolatile solid materials that form a solid residue.This can result in up to 50% of the starting material remainingas solid residue.90

2.4.4 Viscosity. The viscosity of bio-oil as produced canvary from as low as 25 cP to as high as 1000 cP (measured at40 °C) or more depending on the feedstock, the water contentof the oil, the amount of light ends that have been collected,and the extent to which the oil has aged. Other researchershave found that polymerization reactions that lead to viscosityincreases are accelerated at higher storage temperatures, and ithas been shown that the rate of change in viscosity canincrease from 0.009 cP per day when stored at −20 °C to morethan 300 cP per day at 90 °C.101

Bio-oil is more viscous than crude oil at room temperature;however, its viscosity is very similar to that of crude oil in atemperature range of 35 °C–45 °C.102–105 To transport the bio-oil in pipelines, the temperature of the pipeline should bemaintained in the range of 35 °C–45 °C to keep the viscositysimilar to that of crude oil.104,105 Bio-oil produced from P.indicus and F. mandshurica had a kinetic viscosity of 70–350 cPand 10–70 cP separately. Bio-oil produced from rice straw hada minimum kinetic viscosity of about 5–10 cP, which is mainlydue to the rice straw’s high water content.106

The lignin content of the original feedstock has a positiveinfluence on the molecular weight and viscosity of bio-oil.34

Recently, Ertas and Alma107 compared the average molecularweight and molecular weight distribution of laurel extractionresidues bio-oil (664 g mol−1 and 1.52) and found they were

very close to those of switchgrass bio-oil of 658 g mol−1 and1.49, respectively.108

Simple methods such as adding polar solvents, diesel, orother fuels can address some of the undesired bio-oil charac-teristics described in this section. Polar solvents, such asmethanol or ethanol, can improve the volatility and heatingvalue and decrease the viscosity and acidity. Adding ethanolimproves the volatility, stability, and heating value anddecreases the viscosity, acidity, and corrosivity.109 Blendingdiesel or other fuels can positively impact oil viscosity.110

Finally, application of hot gas filtration prior to condensationoffers a relatively simple method to produce a bio-oil with lowparticulate content (essentially zero ash) and improved stabi-lity with respect to increases in viscosity.

2.4.5 Corrosivity. The corrosivity of pyrolysis oil is primar-ily due to its acidity, which is derived mainly (60%–70%) fromthe volatile acids and phenolic compounds. Measurements oftotal acid number (TAN) of bio-oil samples show that values inthe 90–100 range are fairly common, with a pH typically in therange 2–3; TAN values of 150–200 are not uncommon. The pKa

values for the acids are the lowest of all the compounds in theliquid, and this is the reason for the good correlation betweenthe TAN and the amount of acids as shown in Fig. 10. Thereare also other groups of compounds in fast pyrolysis liquidsthat influence acidity, like phenolics (5%–10%) and fatty andresin acids (<5%). The acidity of the “sugar” fraction, mainlydue to hydroxy acids, covers about 20% of the total acidity.111

This level of acidity has been shown to cause corrosion pro-blems for many materials. In particular, high corrosion ratesfor carbon steel (AISI01) have been observed,44,92 which wouldbe problematic for many refining operations. Further, the cor-rosivity increases significantly at higher temperatures.112

Several metal and polymer materials have been tested113–117

for resistance to corrosivity from pyrolysis oil and Table 8 col-lects the result from one of the studies.

Fig. 9 Observed trends in compound classes during the aging of pyro-lysis oil.98 Reprinted with permission from D. C. Elliott, A. Oasmaa,F. Preto, D. Meier, A. V. Bridgwater, Energy & Fuels, 2012, 26, 3769–3776.Copyright 2012 American Chemical Society.

Fig. 10 Correlation of TAN with volatile acids, determined by capillaryelectrophoresis (CE), in pyrolysis liquid.111 Reprinted with permissionfrom A. Oasmaa, D. C. Elliott, J. Korhonen, Energy & Fuels, 2010, 24,6548–6554. Copyright 2010 American Chemical Society.



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Keiser et al.118 reported corrosion rates of structuralmaterials obtained with pyrolysis oils from varied feedstocksand with varied TAN and carboxylic acid content. All threesamples contained significant concentrations of formic andacetic acids as well. Metallic specimens were immersed in theoil as well as in the vapor space above the oil with the oil at atemperature of 50 °C, which was considered to be themaximum temperature the bio-oil would reach during storageand transport. Weight change calculations showed significantweight loss occurred in carbon steel and the 214 Cr-1 Mosamples, and a hydrated iron formate corrosion product wasidentified on the surface of these specimens. Calculated cor-rosion rates for these alloys were much more than could be tol-erated in any system that was expected to last for years. Thestainless steel specimens showed minimal weight change.They also reported that stress corrosion was likely an activemechanism for the lower chrome content steels. This resultemphasizes the need to control bio-oil TAN as storage andpipeline material needs must be similar to materials currentlyin use.

Technologies like hydrogenation, hydro-deoxygenation, andother similar conventional processes address the high acidityproblem; however, they require large-scale plants and capital,and exhibit substantial yield losses (up to 50%) mainly due tothe use of hydrogen. Torrefying the biomass feedstock hasresulted in 25% less acetic acid in the produced oil althoughas mentioned previously torrefaction results in a loss ofcarbon efficiency.119

Modifying raw bio-oils to reduce TAN and acid content hasbeen demonstrated by deoxygenating fast pyrolysis oilsvia reaction with recycled product gas120 in which a two-foldreduction in oil oxygen content was achieved. These types ofrecent improvements in reducing bio-oil acidity are neededto reduce corrosivity and ensure infrastructure compatibilityas potential renewable hydrocarbon fuels and fuelintermediates.

3. Upgrading biomass pyrolysis oil

As detailed in the previous section, biomass pyrolysis oil (bio-oil) has many undesirable properties that make it unsuitablefor direct use as a fuel or as a feedstock for fuel manufacture.Technologies and technical pathways for upgrading biomassbio-oil into a more useful material can generally be brokendown into two categories:

1. Vapor-phase processes operating at low (atmospheric)pressure using crystalline aluminosilicate catalysts.

2. High pressure catalytic hydrotreating.Research on these two processing options is reviewed in the

following sections.

3.1 Ex-situ vapor-phase catalytic upgrading of whole bio-oil

Vapor-phase upgrading of whole bio-oil can be carried out viaeither in situ or ex-situ processes. Catalytic fast pyrolysis, whererelease of the primary pyrolysis vapors is accomplished in abed of catalytic material, is an example of the in situ upgradingmode, while contacting of pyrolysis vapors resulting fromthermal fast pyrolysis with catalysts in a separate reactor is anexample of the ex-situ upgrading mode. This latter mode ofoperation has several advantages, including the potential foroperating the upgrading reactor at different reaction con-ditions (temperature, space time, reactive gases, etc.) than thepyrolysis reactor. It also affords the opportunity to protect theupgrading catalysts from deleterious alkali and alkaline earthmetals by using a solids separation step such as hot gas fil-tration.51 The ex-situ mode gives more flexibility in operationand provides opportunities to optimize the process by tuningthe reaction conditions and improving thermal efficiencies byclose-coupling of the pyrolysis and upgrading steps. Theremainder of this section will examine results of investigationsconcerning ex-situ upgrading.

At temperatures of 350 °C to 500 °C with zeolite catalysts,oxygenated organic compounds undergo cracking, dehy-dration, decarboxylation, aromatization, alkylation, conden-sation, and polymerization reactions. Dehydration is thedominant mechanism when using acidic catalysts such asZSM-5; the product obtained while the catalyst is active is amixture of aromatic hydrocarbons and low molecular weightolefins. The general scheme for upgrading bio-oil using cata-lysts like ZSM-5 is shown in Fig. 11.

Ex-situ vapor-phase catalytic upgrading of whole oil andmodel compounds representing the major oxygenated moi-eties present in bio-oil produced by thermal pyrolysis has beenstudied by several investigators.121–128 In a series of seminalstudies, Adjaye and Bakshi investigated bio-oil cracking in afixed-bed microreactor in a range of temperatures from 290 °Cto 410 °C121–123 over several different catalysts includingHZSM-5, H-Y zeolite, H-mordenite, silicalite, and amorphoussilica-alumina. These studies showed that hydrocarbon yieldsranged from a high of 27.9 wt% with HZSM-5 to only 5 wt%with silicalite. At the higher temperatures studied, coke oncatalyst was significant ranging from a low of 15 wt% forHZSM-5 to as much as 29 wt% for amorphous Si–Al catalyst.

Table 8 Weight loss for materials stored in pyrolysis oil90

Material Weight loss (wt%)

PolymersTeflon 0.000

SteelsAISI01 0.823AISI316 0.000AISI420 0.191HASTELLOY X 0.012NIMONIC 80A 0.002HAYNES 188 0.000ARCLOK 0.006

MetalsCopper 0.000Chromium 0.000Nickel 0.004

AlloysNIKROTAL 0.005



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These high levels of coke-make severely impact the carbonefficiency of ex-situ cracking strategies. Other studies have con-firmed that zeolites such as ZSM-5 are moderately effective intransforming model compounds representative of biomasspyrolysis vapors to hydrocarbons.122,129 Chang et al.130 showedthat adding hydrogen-rich compounds with a high effectivehydrogen index‡ could radically reduce the coke-makeobserved during ex-situ catalytic upgrading while simul-taneously improving the hydrocarbon yield over crystalline alu-minosilicate catalysts. A different approach to vapor-phasecatalytic upgrading of bio-oil was reported by Vispute et al.,who describe an integrated hydroprocessing plus ex-situ cata-lytic upgrading scheme.128 Their approach involves increasingthe effective hydrogen index of bio-oil by hydroprocessing firstfollowed by subsequent catalytic upgrading over zeolites.

Several studies have been conducted on model compoundsto elucidate which of the oxygenated molecules in bio-oil arechallenging to upgrade using this technical pathway. Using afixed bed of HZSM-5 catalyst, high conversions (>90%) wereobtained for alcohols, aldehydes, ketones, acids, and esterswhile phenols and ethers remained mostly unchanged. Alco-hols and ketones reacted to produce high yields of aromatichydrocarbons.124–127,131 Acids and esters were mostly con-verted to gas, water, and coke with low hydrocarbon yield. Thehydrocarbon production was the lowest and coke formationthe highest for oxygenated organic compounds with a loweffective hydrogen index.

3.2 Catalysts for ex-situ vapor-phase upgrading of bio-oil

When zeolites are used to deoxygenate biomass pyrolysis oils,hydrocarbon yields of 10 wt% to 30 wt% have generally beenreported; however, high coke production and rapid catalyst de-activation were also observed,131–133 which is consistent withthe hydrogen deficiency of bio-oil (effective hydrogen index ofca. 0.3). Results of laboratory investigations for upgradingwhole bio-oil on a suite of catalysts with varying acidity includ-ing HZSM-5, H-Y zeolite, mordenite, silicalite, and amorphoussilica–alumina have been reported by a number of investi-gators.122,134,135 NREL pioneered an integrated process inwhich vapors from a biomass pyrolyzer were fed to a catalyticreactor containing HZSM-5 and converted to aromatic and ole-finic hydrocarbons.136,137 Using a pilot-scale vortex reactor inseries with a fixed bed of commercial Mobil MCSG-2 catalyst at450 °C, a total hydrocarbon yield of 12.7 wt% based on woodfeedstock was achieved, which is about one third of the theore-tical yield. Excessive coking was observed due to the highacidity of the HZSM-5 catalyst, which enhanced dehydrationreactions. The presence of transition metals has been shownto affect the mode of oxygen rejection by producing morecarbon oxides and less water, thus making more hydrogenavailable for incorporation into hydrocarbons.138

3.3 Hydroprocessing

Bio-oil can be converted to a gasoline- or diesel-like liquid bycatalytic hydroprocessing using catalysts and conditions thatare similar to those used in petroleum hydrodesulfurization,hydrotreating, and hydrocracking processes.139 Several

Fig. 11 Pyrolysis of biomass and upgrading of bio-oil using ZSM-5.

‡Defined as (H/C)eff = (H − 2·O)/C, where H, C, and O represent the number ofmoles of hydrogen, carbon, and oxygen per unit mass sample.



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excellent reviews highlight the history, current status, andtechnical challenges associated with hydroprocessing bio-oil.139–143 Elliott reported that hydroprocessing whole bio-oilin a single-stage hydrotreater gave rise to severe product lossdue to coking; hence, a two-stage process was developed. Inthis improved process, the oil was stabilized at a lower tempera-ture (150 °C–280 °C) before it was fed to a high temperaturereactor (350 °C–400 °C) where the majority of the oxygen removaltook place. Standard petroleum industry hydrotreating catalystswere used including both nickel-molybdenum (NiMo) and cobalt-molybdenum (CoMo) on a γ-alumina support; the upgradedproduct represented 30 wt%–50 wt% of the crude bio-oil.144

Several, detailed economic studies have been published forthis process145–148 assumed the bio-oil was produced in a cir-culating fluidized bed at a feed rate of 2000 bone-dry metrictons per day of wood chips at a cost of $50.7 per ton. The oilwas then upgraded in two stages at temperatures of 240 °C–370 °C and 2015–2500 psig pressure to produce 44 wt% hydro-treated oil containing 1.5 wt% oxygen. Hydrogen consumptionwas assumed to be 5 wt% of the feed. This product oil wasthen hydrocracked as necessary and separated into gasolineand diesel streams. The projected minimum fuel-selling pricewas $2.04 per gal ($1.34 per gal ethanol equivalent). Thiscould be reduced to $1.74 per gal ($1.14 per gallon ethanolequivalent) by co-locating the plant with a petroleum refineryto take advantage of the refinery’s low-cost hydrogen andlarge-scale hydrocracking capacity. While these projections arepromising, other studies have concluded that the process wastoo expensive to compete with conventional crude oil because ofthe large amount of hydrogen consumed, low product yields,low quality products that would require further upgrading in arefinery, and the corrosivity of the raw oil.149 A recent technoeco-nomic analysis for hydroprocessing of bio-oil produced by mildcatalytic pyrolysis146 suggested that the “most probable fuelprice” for transportation fuels was $3.03 per gal for this pathway.

Another recent study was carried out to obtain an assess-ment of the process economics in light of incrementalimprovements to the bio-oil catalytic hydrodeoxygenationprocess, changes in refining requirements (particularlyincreased hydrodesulfurization requirements), and changes inpetroleum prices. This report suggested that costs could be sig-nificantly reduced by mildly hydrotreating the bio-oil and thenco-processing the partially deoxygenated products with pet-roleum-derived material in a refinery.150 The authors rec-ommended reducing the severity of HDO to leave about 7 wt%oxygen in the bio-oil, thus avoiding hydrogenating aromaticswhile reducing hydrogen consumption, catalyst costs, andhydrotreater capital costs. The residual acidity of the oil couldthen be accommodated by diluting with crude oil or aninternal refinery stream (naphtha, gas oil, etc.).

Various blending strategies could be employed, withmaterial derived from mild hydroprocessing of bio-oil blendedand co-processed with petroleum-derived material using exist-ing refinery unit operations to carry out additional deoxygena-tion required to maintain acceptable product quality for thefinal fuels. For this strategy to work, a number of important

criteria must be met by the products from mild hydrotreating:(1) the acidity of the bio-oil must be reduced from the typicalTAN value of over 100 to about 15, assuming that hydrotreatedbio-oil would be blended in a 1 : 8 ratio (acidity of blend lessthan 2 mg KOH per g oil150). (2) The hydrotreated bio-oil mustbe completely miscible with hydrocarbons. (3) The hydro-treated bio-oil must be sufficiently volatile so that it is amen-able to fractional distillation (some high-boiling residue isacceptable). If hydrotreated bio-oil is to be co-processed in therefinery, information on the composition and concentration ofoxygenates in the bio-oil-derived hydrotreated products is criti-cal to ensure that product quality is maintained.

Other studies have highlighted the relationship betweentotal oxygen, oxygen functional groups, acidity (TAN), hydro-carbon miscibility, and hydroprocessing severity for a bio-oilthat had been hydroprocessed to various levels of oxygencontent;151,152 these results are reviewed in section 5 of thisdocument. Co-processing bio-oil with petroleum in refinery unitoperations such as the FCC and hydrotreaters is also reviewed insection 5 (below). Mild hydrotreating and mild HDO of bio-oilhas also been investigated by Venderbosch et al., who rec-ommend a multi-stage reaction scheme for upgrading bio-oil.153

3.4 Bio-oil hydroprocessing catalysts

Many studies have been carried out concerning the impact ofcatalyst formulation on hydroprocessing and hydrodeoxygena-tion of whole bio-oil and model compounds representative ofthe major oxygenated moieties in bio-oil. Mortensen et al.139

have recently summarized the important findings for a broadrange of standard and novel hydroprocessing catalysts. Severalinvestigations have been carried out using industrial pet-roleum hydroprocessing catalysts such as Co-MoS2 and Ni-MoS2 on a γ-alumina support.154–156 Wildschut et al.157

reported that catalyst formulations containing Pt, Ru, and Pdsupported on carbon gave superior results for HDO of wholebio-oil, while maintaining high yields of upgraded productswhen compared to standard cobalt- and nickel-moly sulfidecatalysts. Other novel catalytic materials have been recentlyreported for hydroprocessing bio-oil and HDO of representa-tive oxygenated model compounds including WO3, NiCu/CeO2,and phosphides of nickel, cobalt, iron, tungsten, and molyb-denum supported on SiO2.

158–160

The impact of the support on bio-oil hydroprocessing cata-lysts has also been investigated. Standard petroleum refiningcatalysts normally utilize alumina (Al2O3) as the supportmaterial, but this is unsuitable for bio-oil upgrading asalumina is unstable in high water environments. As alterna-tives to alumina, zirconia (ZrO2), silica (SiO2), and ceria (CeO2)have been identified as promising stable carriers for transitionmetals used in hydroprocessing bio-oil.161,162 Other investi-gations have focused on the use of carbon as a supportmaterial.163,164 Since carbon is relatively neutral (in compari-son to the more acidic alumina, zirconia, or ceria materials),the tendency to promote coke-on-catalyst is reduced whencarbon is used as the support. However, regeneration ofcarbon-supported catalysts can be problematic as techniques



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based on oxidation of poisons cannot be used for thesematerials.

3.5 Problems and issues associated with upgrading bio-oil

Upgrading bio-oil produced by thermal fast pyrolysis ofbiomass to a more useful hydrocarbon-like product essentiallyinvolves removing organic oxygen, reducing the average mole-cular weight, and increasing the atomic hydrogen-to-carbonratio. Water produced by dehydration reactions occurringduring pyrolysis also needs to be removed. Reducing organicoxygen will lower the acidity of the upgraded bio-oil and willalso improve the volatility of the product towards fractionaldistillation. When oxygen is removed by catalytic cracking, theprimary oxygen rejection mechanisms are dehydrationaccompanied by significant decarboxylation and decarbonyla-tion (loss of oxygen as CO2 and CO, respectively). These reac-tions result in poor carbon efficiency with respect to carbon inthe feed being translated into carbon in the upgraded productand a hydrogen-deficient product with low quality (low H/Cratio). Typical carbon efficiencies for catalytic cracking ofwhole oil are approximately 15 wt%–20 wt% for upgraded oil,with 20 wt%–30 wt% of the feed carbon going to light gasesand the remainder to coke. Hydroprocessing removes organicoxygen primarily as water, giving better carbon efficiencies butat the expense of the necessity of providing gas-phase mole-cular hydrogen. Carbon efficiencies for hydroprocessing areapproximately 30 wt% to 50 wt% for converting carbon in thefeed to carbon in the upgraded oils. Approximately 10 wt%–

30 wt% of the carbon in the bio-oil is converted to gaseousproducts during hydrotreating, with the remainder lost ascoke.

While carbon efficiencies are important metrics for bio-oilupgrading processes, capital and operating costs for theupgrading operation must also be considered. Catalytic vapor-phase upgrading of bio-oil is typically carried out at ambientpressure, at relatively low temperatures (300 °C–500 °C), and inthe absence of added gas-phase molecular hydrogen. Someresearchers have suggested that adding hydrogen-rich and/orhydrogen transfer molecules can improve the carbon efficiencyof catalytic vapor-phase upgrading,130 but this will increasecost and add additional complexity to the operation due toconsumption of added chemicals and/or the need to recoverand re-use the hydrogen shuttlers. Hydroprocessing, on theother hand, is done at moderate temperatures (350 °C–450 °C)but at high pressure (>100 atm.) and in the presence of gas-phase molecular hydrogen. Hydrogen consumption duringbio-oil hydroprocessing varies widely with operating severityand the source of the bio-oil; a comparison of hydroprocessingparameters for bio-oil and various petroleum fractions isshown in Table 9. Reported hydrogen consumptions for hydro-treating bio-oil vary widely and will depend largely on thedegree of deoxygenation required for the final product.153

All of these factors result in significant additional costs forhydroprocessing due to high capital costs associated with theupgrading reactors and (especially) hydrogen manufacture. Arecent study150 by the Global Energy Management Institute on

upgrading bio-oil concluded that upgrading costs for hydro-processing would be in the range of $25 to $40 per BBL –

depending on the oxygen content for the final product – for asingle stand-alone upgrading facility processing the output ofone pyrolysis plant (Fig. 12). Finally, upgrading by eithervapor-phase or hydroprocessing technologies will involverapidly deactivating catalysts, which must be regenerated fre-quently to maintain activity. Regeneration of vapor-phaseupgrading catalysts can be accomplished readily using recircu-lating reactor/regenerator technology as is currently practicedin the fluid catalytic cracking of gas oil in the petroleum refin-ery. Costs associated with regenerating fixed-bed bio-oil hydro-treaters would be expected to be particularly high; moving-bedreactor technology may have to be applied to maintain accepta-ble hydrotreating activity.150

4. Standard refinery needs andquality metrics and impact of bio-oil4.1 Petroleum hydrocarbon chemistry

A brief introduction to petroleum hydrocarbon chemistry ishelpful before initiating discussions on crude oil and pet-roleum refinery operations. This section of the report focuseson165 identifying the various types of hydrocarbons present inpetroleum refineries and166 general trends of hydrocarbonbulk properties. This section also includes a discussion of theeffects of bio-oil constituents on these bulk properties.

There are four major types of hydrocarbons present in thefeedstocks to or intermediate streams found in a petroleumrefinery, following the acronym PONA as follows:

Table 9 Hydroprocessing conditions for different feedstocks153

FeedSeverity T (°C) : P (bar) :LHSV (h−1)

H2 Consumption(Nm3 m−3 feed)

Naphtha 260–350 : 15–35 : 2–5 2–10Light oil 290–400 : 17–35 : 2–5 15–50Heavy oil 350–425 : 70–140 : 1–3 70–170Residuum 350–425 : 70–140 : 0.15–1 100–200Bio-oil 350–450 : 100–170 : 0.1–1 200–800

Fig. 12 Effect of plant size on hydrotreating cost.



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Paraffins: normal and iso-paraffins (or alkanes) are naturallyoccurring molecules in crude oil.

Olefins: olefins (or alkenes) are not naturally occurring incrude oil, but they are formed in several conversion processesof a typical petroleum refinery.

Naphthenes: naphthenes (or cyclo-paraffins/cyclo-alkanes)are naturally occurring molecules in crude oil.

Aromatics: aromatic compounds do not naturally occur inpetroleum, but are formed during processing.

In addition to the major categories of chemical speciesfound in the petroleum refinery, it is also important to under-stand the major trends in physical properties among thesespecies as functions of carbon number, the number of carbonatoms present in a particular molecule.

The first of these trends is boiling point, which is presentedin Fig. 13 for a wide range of hydrocarbon compounds includ-ing normal paraffins, naphthenes, and aromatics, as a func-tion of carbon numbers. The trend clearly shows that boilingpoint closely correlates with a carbon number. The scatterassociated with the data, around C10 single-ring aromatics forexample, represents the impact of structural variationsbetween molecules of the same carbon number on the boilingpoints. For example, the boiling point of isobutylbenzene(173 °C) is lower than its isomer with the same molecularformula, 1,2,3,4-tetramethylbenzene, which boils at 205 °C.

As will be discussed below, much of the processing in arefinery is based upon the boiling point of the cut that isbeing processed. As Fig. 13 shows, the hydrocarbon moleculesin a particular boiling range have essentially the same numberof carbon atoms. However, the boiling points for oxygen-con-taining organic molecules that are typical of those found inpyrolysis oil are considerably higher than the hydrocarbons.Therefore, a boiling point cut containing oxygenated com-pounds from pyrolysis oil will necessarily contain moleculeswith shorter carbon chains than is typical for hydrocarbons.

Another important trend to identify is that between carbonnumber (or boiling point) and density for the various types ofhydrocarbons present in the refinery. Fig. 14 presents densitytrends (as API gravity§) for n-paraffins, naphthenes and singlering aromatics. The two most important observations fromFig. 14 are that density increases with (1) increasing carbonnumber for similar chemical structures, and (2) decreasinghydrogen to carbon ratio.

The trend of increased hydrocarbon density with decreasinghydrogen-to-carbon ratio is also shown with the C6 compoundsbelow. The lowest density compound, n-hexane, contains thehighest H/C ratio, while the highest density compound,benzene, has the lowest H/C ratio. Understanding thisphenomenon is critical to the refining industry as productsales are on a volumetric basis (barrels or gallons). Equalmasses of n-hexane and benzene will represent significantlydifferent volumes of the respective compounds. For example,1 kilogram of n-hexane equals approximately 1.5 liters ofproduct while 1 kilogram of benzene equals only 1.1 liters ofproduct.

Fig. 13 Boiling points of hydrocarbons versus carbon number.167 Theplot also contains the boiling points of 57 oxygen-containing organicmolecules that are typical of those found in biomass pyrolysis oil. A listof these molecules and their properties is provided in the supplementalmaterial.

Fig. 14 API gravities of hydrocarbons versus carbon number.167 Thegravity for the 57 representative oxygen-containing compounds areshown in the black squares. Several of these oxygenated compounds aswell the compound classes are called out. DME = dimethyl ether, MEE =methylethyl ether, DEE = diethyl ether, MTBE = methyl tert-butyl ether,FA = formic acid, AA = acetic acid, PA = propionic acid, Fur = furfural,DEGly = diethylene glycol, TEGly = tetraethylene glycol, PGly = propy-lene glycol, PhOH = phenol.

§API gravity or °API = 141.5/specific gravity – 131.5.



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Fig. 14 also shows the API gravity for the 57 compoundsthat are representative of oxygenates in biomass pyrolysis oil.As can be seen, the ethers have gravities similar tonaphthenes; aldehydes, ketones and alcohols have gravitiesbetween aromatic compounds and naphthenes; and the gravi-ties for esters and acids are smaller than aromatic compounds.Several of the compounds, such as polyols, phenols, and fur-fural are significantly lower than hydrocarbons. This showsthat the oxygenates will require significant upgrading (hydro-treating) to reach the gravities of paraffinic fuels.

Another important aspect of hydrocarbon chemistry is theincreasing number of existing isomers, different hydrocarbonstructures with the same molecular formula, as a function ofcarbon number. For example, the number of C5 paraffinisomers is 3, the number of C8 paraffin isomers is 18, thenumber of C11 paraffin isomers is 159, and so on. Crude oiland petroleum refinery streams contain compounds up to theC40 range, representing a very large number of different hydro-carbon compounds.

This ability to profitably process complex mixtures oforganic molecules suggests that refineries are well suited tohandle bio-oil mixtures. However, the oxygen content of thebio-oil will introduce uncertainty into existing refiner oper-ations. The existing oxygenated compounds in petroleum aretypically furans, quinone, phenols, and some carboxylic acidsand are present in concentrations under 1 wt%. The oxygen inpetroleum crude is treated as a contaminant that is removedduring hydrotreating.

4.2 Refinery overview

The simplified process flow diagram presented in Fig. 15 rep-resents a typical, high-conversion U.S. petroleum refinery to bereferenced throughout the following discussions. The term“high-conversion,” applied to the configuration in Fig. 15,refers to the presence of all major conversion processes – fluidcatalytic cracker or FCC, coker, and hydrocracker. Not all refi-neries possess each of these process units and a refinery’s con-version capabilities are measured on the processing capacitiesof these conversion units relative to the crude fractionationcapacity of the refinery. The fact that the refinery is noted as a“U.S.” refinery is also important. A refinery is designed to meeta specific product market distribution based on demand andavailable crude oils in that region. The European productdemand is very different than that of the United States and,therefore, typical refinery configurations are different as well.

As shown in Fig. 15, the major processing steps of a typicalU.S. petroleum refinery are as follows:

4.2.1 Fractionation. The first major processing step in thepetroleum refinery is the fractionation of the crude oil intovarious petroleum fractions or cuts. Fractionating the crude oilis accomplished by distillation in the Atmospheric Distillationand Vacuum Distillation columns as shown in Fig. 15. In thesetwo distillation columns, the crude oil is fractionated into fivemajor cuts as follows:

(1) Butanes and lighter: the stream labeled “Gas” from theAtmospheric Distillation column in Fig. 15 represents the

butanes and lighter materials from the crude oil. This fractionof the crude oil includes a mixture of C4 hydrocarbons(butanes, butenes), C3 hydrocarbons (propane, propene), andany other light ends (ethane, methane). The C3s and C4s areoften recovered and are referred to as LPG, or liquefied pet-roleum gas.

(2) Naphthas: represented by the “Light Naphtha” and“Heavy Naphtha” streams from the Atmospheric Distillationcolumn, the naphtha materials include C5 hydrocarbonsthrough boiling points of approximately 165 °C, correspondingroughly to C10 hydrocarbons. Light Naphtha includes C5 hydro-carbons up to boiling point of 75 °C while Heavy Naphthaincludes hydrocarbons in the 75 °C to 165 °C boiling range.Naphtha materials typically contribute to gasoline productsafter processing in the refinery.

(3) Middle distillates: the middle distillate materials fromthe crude oil include the “Jet Fuel Kerosene” and “Diesel Oil”fractions from the Atmospheric Distillation column.

Kerosene: the kerosene cut includes hydrocarbons in theboiling range of 165 °C to 250 °C, corresponding roughly tohydrocarbons in the C10 to C14 range. The kerosene cut fromthe crude unit can contribute to jet fuel, gasoline, and dieselfuel products after refinery processing.

Diesel: the diesel cut includes hydrocarbons in the boilingrange of 250 °C to 340 °C, corresponding roughly to hydrocar-bons in the C14 to C20 range. The diesel cut from the crudeunit can contribute to diesel fuel or heating oil products afterrefinery processing.

(4) Gas oils: the term “Gas Oil” applies to hydrocarbons inthe boiling range of 340 °C and 540 °C. The gas oil fraction asdefined for this discussion includes the “Atmospheric GasOil,” “Light Vacuum Gas Oil,” and “Heavy Vacuum Gas Oil”streams from Fig. 15.

(5) Residue: the term “Resid” applies to hydrocarbonsboiling above 540 °C. This stream is identified as “VacuumResid” in Fig. 15.

Gas oils and resids contain materials that are too heavy(high molecular weight, high boiling points) to contribute tothe typical refinery products like gasoline and diesel. Thesematerials must be processed in the refinery to reduce themolecular weights in order to produce intermediates that boilin the range of streams used for production of fuels.

The term “cut point” refers to the distillation temperatureat which one petroleum fraction ends and another begins. Forexample, the cut point between heavy naphtha and kerosenein this discussion is 165 °C. The cut points between thevarious petroleum fractions vary from one refinery to the nextdepending on product slate and refinery capabilities.

After crude oil fractionation, each fraction or cut is sent toan appropriate destination for further processing.

4.2.2 Treating/finishing processes. Treating and finishingprocesses are generally designed to improve a specific physicalproperty of a stream or remove impurities from a stream. Thelight fractions from the crude oil – butanes and lighter,naphthas, and middle distillates – are the streams that typi-cally enter the treating and finishing steps after fractionation.



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The treating and finishing processes of a typical petroleumrefinery are described briefly as follows:

Gas processing: these processing steps include light hydro-carbon separation and product recovery through multiple dis-tillations (deethanizer, depropanizer, debutanizer, butanesplitter, etc.). Typically, the C4 (butanes and butenes) andlighter streams are separated into several saleable productslike propane, propylene, iso-butane, mixed butanes andbutenes (C4 olefins), and LPG. The light gases C2 and lightergenerally contribute to refinery fuel gas.

Hydrotreating: hydrotreating operations fall into a broadercategory of hydroprocessing, which will be described in detailin later sections of the report. The major objective of a hydro-treating process is to remove impurities in hydrocarbonstreams like sulfur, nitrogen, and oxygen. These impuritiesmust be removed from the hydrocarbons to meet product

blending specifications and to minimize undesired catalystpoisoning in various locations of the refinery.

4.2.3 Conversion processes. The hydrocarbons present inthe heavy petroleum fractions like gas oils and residue aremuch too high in molecular weight to contribute to high-valueproducts like gasoline and diesel fuel. These heavy petroleumfractions are also typically hydrogen-deficient relative to thehydrogen-to-carbon ratios of gasoline and diesel. Therefore,the conversion processes in the refinery are designed to165

reduce the molecular weight of the feedstocks and166 increasethe hydrogen-to-carbon ratio of the feedstocks by carbon rejec-tion (coking) or hydrogen addition (hydrogenation). The majorconversion processes in a typical petroleum refinery are asfollows:

Fluid catalytic cracking: fluid catalytic cracking (FCC) is a keyconversion technology for the U.S. refining industry as it

Fig. 15 Overview of typical U.S. petroleum refinery configuration. https://upload.wikimedia.org/wikipedia/commons/6/60/RefineryFlow.png.



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produces a significant yield of high-octane gasoline blendstockfrom high molecular weight feedstocks like gas oils fromcrude oil fractionation. The FCC reduces molecular weight bycatalytic cracking of carbon–carbon bonds and increases thehydrogen-to-carbon ratio by coke extraction.

Coking or visbreaking (thermal cracking): the coking and vis-breaking processes utilize thermal energy (heat) to non-cata-lytically crack heavy hydrocarbons in the vacuum residuumstream to lighter molecules and increase hydrogen-to-carbonratio by coke extraction.

Hydrocracking: hydrocracking falls into the broader categoryof hydroprocessing, which will be described in detail in latersections of the report. The major objective of hydrocrackingprocesses is to catalytically crack carbon–carbon bonds andincrease hydrocarbon-to-carbon ratio by hydrogenation underhigh hydrogen partial pressures. Typical feedstocks for thehydrocracker are virgin gas oils from the atmospheric andvacuum columns and heavy cracked intermediates from theFCC and thermal cracking processes.

Table 10 summarizes the total U.S. operating capacities forcrude oil distillation/fractionation and the major conversionprocesses including FCC, thermal cracking (coking and vis-breaking), and hydrocracking.

4.2.4 Other catalytic processes. Several other processes inthe refinery are designed for catalytic conversion of specificrefinery streams for maximizing gasoline production andimproving the properties of gasoline streams – specifically theoctane number. These catalytic processes are as follows:

Catalytic reforming: the two major purposes of catalyticreforming processes are (1) to convert virgin naphtha streams,containing high concentrations of paraffins and naphthenes,into higher octane products by ‘reforming’ paraffins intonaphthenes and aromatics and naphthenes into aromatics;and (2) to generate a hydrogen supply for hydroprocessing unitoperations in the refinery. A simple example of a reformingreaction is shown below in the conversion of methylcyclo-hexane to toluene and hydrogen.

Depending on product market pricing, a refiner may alsorecover valuable aromatic compounds from the reformer

product stream (reformate) like benzene, toluene, and xylenesfor sale as individual products prior to blending the reformatestream into gasoline. Catalysts used in catalytic reforming pro-cesses are typically highly promoted precious metals (i.e. plati-num, rhenium) on a silica–alumina support.

Isomerization: another means of increasing octane values ofrefinery streams is through an isomerization process. Theobjective of isomerization in petroleum refining is to convertstraight-chain paraffins into branched paraffins, which arehigher-octane molecules relative to their straight-chain equi-valents. Isomerization for gasoline blending is commonlyapplied to light naphtha streams from crude fractionation,which contains high concentrations of C5 and C6 paraffins.

Alkylation: alkylation processes in the U.S. petroleum refin-ery context are typically closely coupled with the FCC andthermal cracking processes, which yield substantial volumesof light olefins (butenes) and branched paraffins (e.g. iso-butane). The alkylation reaction example below shows theconversion of isobutene and isobutane to form 2,2,4-trimethyl-pentane or isooctane, a high-value gasoline blending com-pound (blending octane number of 100).

Refinery alkylation units are typically designed to utilize acirculating inventory of acid solution, either sulfuric acid(H2SO4) or hydrofluoric (HF), which serves as the acid catalystfor alkylation reactions.

4.2.5 Ancillary processes. There are several ancillary pro-cesses in the petroleum refinery that are designed to minimizeenvironmental emissions. These environmental control unitoperations are as follows:

Wastewater treatment: the wastewater treatment plant isanother environmental set of operations focused on minimi-zing emissions of hydrocarbons, salts, solids, and other impu-rities from water streams emitted from the refinery.

4.3 Crude oil

Typical refinery feedstocks consist of various blends of pet-roleum crude oils. Crude oils are raw and complex mixtures ofhydrocarbons with constituents ranging from light gases likemethane and ethane to long-chained hydrocarbons like thosefound in asphalt. The types and concentrations of differenthydrocarbon species in crude oils can vary significantlydepending on the source/location of the material. Simple com-positional examples of two different crude oils – Brent Crudeand Cold Lake Crude – are presented in Fig. 16 relative toaverage European and United States product market demandsfor major crude-derived products.

Fig. 16 demonstrates two very important facts. First,different crude oils can have very different compositions, pro-perties, and qualities. Second, typical compositions of crudeoil are not consistent with the distribution of productsdemanded. The fraction of heavy hydrocarbons (gas oil and

Table 10 U.S. capacities for crude distillation and major conversionprocesses168

Refinery operationTotal U.S. operatingcapacity (106 Bbl per day)

Atmospheric distillation 17.86Vacuum distillation 8.94Fluid catalytic cracking (FCC) 6.17Thermal cracking 2.88Hydrocracking 2.08



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resid) generally present in crude oils are significantly higherthan the demand for these materials. This discrepancybetween crude supply compositions and product demanddefines the need for petroleum refining. The two major objec-tives of petroleum refining are to165 recover the naturally occur-ring hydrocarbons that can be blended with minimalprocessing from the crude oil (naphtha, kerosene/jet fuel,diesel/heating oil) and166 convert the heavy, less-valuablehydrocarbon compounds like gas oil and resid throughvarious refinery conversion processes to increase the yields ofhigher-value products.

Crude oils are characterized through compilations ofanalytical results called assays. Simplified assays for severalcrude oils of varying qualities are presented in Table 11, andthe corresponding complete assays are provided in the ESI.†165

The analytical data from the assays provides a refiner withessential information to assess the suitability of a particularcrude oil for a refinery or various refineries with different con-figurations. The major categories of information provided inthe crude oil assays are discussed below. The discussions referto the simplified process flow diagrams of a typical U.S. pet-roleum refinery configuration in Fig. 15.

Theoretical fractionation volumes: the first process step in apetroleum refinery is to fractionate the crude oil by distillationinto multiple “cuts” based on boiling point. The volume frac-tion breakdowns for five different crude oils of varying qual-ities are provided in Table 11 and displayed graphically inFig. 17. As the data in the table and figure shows, differentcrude oils can have widely varying contents of the major hydro-carbon fractions. The heavy crude (Cold Lake Blend) possessesmuch less light material (diesel and lighter) and much moreheavy material (gas oil and residue) relative to the lightercrudes like Gippsland Blend and Brent Blend.

Another method for refiners to identify the volumes ofeach fractionation range present in crude oils or refinery

intermediates is to plot the cumulative fractionated volume ofthe material as a function of the distillation temperature, ananalysis known as a crude oil distillation or boiling pointcurve. An example of this type of analysis is presented inFig. 18 for two different crude oil types. The color schemes onthe plot represent each of the major petroleum fractionsdefined previously – naphtha and lighter, kerosene and diesel,gas oil and resid. A refiner can look at the distillation curvesfor the whole crude oils and quickly identify the differences incut volumes. For example, the Gippsland Blend distillationcurve crosses the naphtha/kerosene cut-point of 165 °C atapproximately 43 vol% of the distilled crude oil, while theHungo Blend distillation curve crosses the same cut-point atonly 18 vol% of the crude oil. These values correspond to thesums of the butane and lighter, light naphtha, and heavynaphtha volumes presented in Table 11 for Gippsland Blendand Hungo Blend crudes, the sums equating to 42.56 vol%(0.44 + 6.32 + 35.80) and 17.86 vol% (1.33 + 4.24 + 12.29),respectively.

Data provided by crude oil assays also provide refiners withvery useful information regarding impurities in the variouscuts of petroleum fractions. For example, Fig. 19 presents thesulfur contents of each crude oil cut from kerosene to residuefor five different crude oils. Most product blends like gasoline,jet fuel, heating oil, and diesel fuel have a maximum sulfurcontent specification, which means that refiners must reducesulfur contents of applicable blending components to meetthe fuel sulfur specifications. The information presented inFig. 19 can provide a refiner with insight on how much proces-sing is required to meet such specifications and if the refineryhas the capabilities to meet them. For example, a refiner mustconsider available SRU capacity if a high-sulfur crude is beingevaluated. Note that the sulfur contents of these crudes aretypically higher than 0.1 wt% and are significantly higher thanbiomass pyrolysis oils as shown in Table 3. Thus, bio-oil willnot adversely contribute to the sulfur content of the fuel andin fact may be used to reduce sulfur with an appropriate blend-ing strategy.

Other important specifications for refiners to consider inevaluating crude oils are Conradson carbon (Concarbon) andmetals contents, which are typically concentrated in the heavyfractions like gas oils and resid. Conradson carbon is ameasurement of the tendency of the hydrocarbon stream toleave carbon deposits (coke) when processed at elevated temp-eratures. Metals like nickel and vanadium are present in manyrefinery feedstocks as organometallic compounds; thesematerials are severe poisons for refinery catalysts like those inthe FCC and hydroprocessing units and will contribute toaccelerated reduction of catalyst activity. Concarbon andmetals contents of the gas oil and resid fractions for each ofthe crude oils are presented in Fig. 20a (gas oils) and Fig. 20b(resids). A refiner must consider the impact of Concarbon andmetals contents of petroleum fractions when determining theappropriate processing unit. As the figures below clearly show,Concarbon and metals contents can vary drastically from onecrude oil to another. The potential contribution of bio-oils to

Fig. 16 Benchmark crude oil compositions compared with majormarket demands.



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Table 11 Simplified crude oil assays165

Crude oil name Gippsland blend Brent blend Alaskan North slope Hungo blend Cold Lake blendOrigin Bass Strait, Australia North Sea Alaska, USA Angola Alberta, Canada

Whole crude oil (−200 F to 1499 F)API gravity 49.00 38.50 31.40 28.30 19.71Sulfur (wt%) 0.0140 0.4060 0.9580 0.6410 3.8177Concarbon (wt%) 0.2200 2.1800 4.8600 5.6400 11.6900Total nitrogen (ppmw) 57.0 970.0 1800.0 2640.0 0.0Total acid number (TAN), mg/g 0.050 0.090 0.200 0.470 1.018ASTM distillation type D-1160 D-1160 D-1160 D-1160 Est. from Cut D-86Initial boiling point (F) 118.1 9.0 32.0 17.8 33.55 vol% (F) 173.8 102.0 98.8 151.5 98.910 vol% (F) 207.4 157.4 158.3 228.2 124.130 vol% (F) 277.7 316.3 377.8 457.3 552.250 vol% (F) 371.7 508.4 582.1 666.5 836.270 vol% (F) 476.4 716.7 814.4 882.1 1088.690 vol% (F) 613.9 970.3 1085.9 1135.7 1342.495 vol% (F) 692.6 1107.3 1216.2 1258.2 1400.8End boiling point (F) 958.2 1389.2 1398.6 1414.4 1,423.0

Butane & lighter (−200 F to 60 F)Total cut liquid volume% 0.44 2.55 2.53 1.33 0.65API gravity 117.28 118.54 113.65 121.03 113.01Carbon (wt%) 82.6 82.5 82.6 82.4 82.7Hydrogen (wt%) 17.4 17.5 17.4 17.6 17.4

Light naphtha (60 F to 165 F)Total cut liquid volume% 6.32 8.95 7.98 4.24 11.19API gravity 79.57 82.04 83.77 79.73 89.21Paraffins (volume%) 93.8 85.6 84.7 83.9 93.8Naphthenes (volume%) 6.2 12.9 14.3 15.9 5.9

Heavy naphtha (165 F to 330 F)Total cut liquid volume% 35.80 19.39 14.08 12.29 6.91API gravity 60.34 56.07 55.02 55.05 57.80Paraffins (volume%) 64.9 47.1 43.3 42.5 52.9Naphthenes (volume%) 34.1 38.5 43.0 49.8 35.6Aromatics (volume%) 1.0 14.5 13.7 7.7 11.5

Kerosene (330 F to 480 F)Total cut liquid volume% 27.68 14.97 14.06 13.11 5.92API gravity 47.73 42.88 41.10 41.02 37.88Sulfur (wt%) 0.0006 0.0327 0.0929 0.0781 0.6814Aromatics (volume%) 6.28 14.92 21.24 15.53 12.87Freeze point (F) −39.1 −48.0 −52.1 −58.9 −96.9Smoke point (mm) 29.4 20.7 21.5 24.0 20.1

Diesel (480 F to 650 F)Total cut liquid volume% 20.07 17.20 16.01 15.96 11.02API gravity 35.53 34.80 31.39 32.65 26.07Sulfur (wt%) 0.0185 0.2585 0.5304 0.3126 1.9316Cloud point (F) 20.0 20.0 7.0 12.0 −42.0Pour point (F) 13.0 10.0 −2.0 4.0 −51.0Cetane index 1990 (D4737) 55.6 55.8 48.1 51.0 37.8

Gas oil (650 F to 1000 F)Total cut liquid volume% 9.19 25.48 27.07 31.23 28.66API gravity 25.39 24.86 21.24 21.20 15.27Sulfur (wt%) 0.1054 0.6079 1.2117 0.7550 3.2888Pour point (F) 88.0 100.0 88.0 89.0 34.0Concarbon (wt%) 0.0600 0.2300 0.5200 0.4700 0.8500Nickel (ppmw) 0.30 0.00 0.00 0.10 0.10Vanadium (ppmw) 0.00 0.00 0.00 0.00 0.40

Residue (1000 F to 1499 F)Total cut liquid volume% 0.50 11.46 18.27 21.84 35.65API gravity −0.08 10.81 6.87 7.77 1.14Sulfur (wt%) 0.4991 1.3673 2.3438 1.3325 6.0816Pour point (F) 109.0 97.0 121.0 108.0 124.0Concarbon (wt%) 33.63 15.50 21.76 21.82 27.88Nickel (ppmw) 76.50 9.50 51.50 71.50 155.80Vanadium (ppmw) 12.00 43.10 118.70 59.60 384.30Asphaltene (wt%) 7.60 2.30 7.30 3.60 19.90



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the Concarbon content is unclear. As discussed in section 2,crude pyrolysis oils are reactive and will coke when heated.Though this has not been quantified, coke formation fromheating pyrolysis oil is likely to be significant.

The final crude oil quality metric presented in this discus-sion is the TAN, which is a measure of a crude oil’s acidity asdetermined by titration with potassium hydroxide. Theamount of potassium hydroxide required to neutralize theacids present in the crude oil (typically naphthenic acid) servesas the metric for TAN. The TAN values are used to determinethe relative corrosivity of crude oils on equipment encounteredby the crude oil (tankage, piping, preheat, and crude oil frac-tionation). TAN values for various crude oils are presented inFig. 21, which shows that ranges of TAN values vary signifi-cantly between crude oils. A refiner must consider the impactof TAN on the refinery’s impacted metallurgy. If a crude oil hasa TAN value that is deemed too high for a refinery’s currentmetallurgy (materials of construction), the refiner is faced withthe decision to avoid purchasing and processing that particu-lar crude oil or invest in a capital project to upgrade the metal-lurgy of the impacted equipment. The impact of bio-oil onTAN will clearly be significant. As discussed in section 2,

Fig. 17 Theoretical fractionations based on crude oil assay cutvolumes.

Fig. 18 Theoretical fractionations based on crude oil distillation curves.

Fig. 19 Sulfur contents of crude oil fractions based on crude oil assay.

Fig. 20 (a) Concarbon and metals contents of gas oil fraction of crudeoil. (b) Concarbon and metals contents of residue fraction of crude oil.



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bio-oil can have TAN values in excess of 100 mg g−1, oftenranging to as much as 200.

4.4 Refinery unit operations and refinery intermediates

The following discussions focus on more detailed informationon (1) the major unit operations found in a typical petroleumrefinery, and (2) the refinery intermediates that are producedfrom these processes. The major unit operations discussed inthe following sections are crude fractionation, FCC, thermalcracking (coking and visbreaking), and hydroprocessing(hydrotreating and hydrocracking) units.

4.4.1 Crude oil fractionation unit. The overall objective ofthis process unit is to fractionate the crude oil entering therefinery into major petroleum distillation cuts while achievingsatisfactory product quality (cut-point overlap), maximizingproduct recovery, and minimizing energy consumption.

A simplified process flow diagram for crude fractionation isprovided in Fig. 22. The processing steps typically included inthe crude fractionation unit in a petroleum refinery are listedand discussed below. Typical ranges for operating parameters(temperature and pressure) for each processing step in thecrude fractionation unit are summarized in Table 12.

Desalting raw crude oil: the first major processing stepwithin a typical crude fractionation unit is the desalter, whichutilizes a water wash to remove inorganic salts from the crudeoil that may negatively impact downstream systems such aspoisoning catalyst systems in conversion reactors. The desalteris also effective at removing suspended solids such as sand,clay, and particulates from metallurgical corrosion from thecrude oil. The crude oil is first pumped to an operatingpressure above the crude oil vapor pressure, typically in therange of 100 psig–150 psig, and pre-heated to an operatingtemperature range of 95 °C–150 °C. The crude oil is then con-tacted with wash water at a volumetric flow rate of approxi-mately 3% to 10% of the crude oil volumetric flow;170 the saltsenter the aqueous phase. The washed oil and aqueous solutionthen enter an electrostatic charged liquid/liquid separationvessel where electric current assists in the phase separationbetween the aqueous phase and the crude oil. The brine wash-

water is sent to the wastewater treatment plant and thedesalted crude oil is sent to the next processing step, the crudeoil preheat system.

Crude preheat: after the desalter, the crude oil enters thecrude preheat system, which consists of a series of heatexchangers and a fired-furnace to vaporize the gas oil andlighter fractions and a portion of the resid fraction (10%–

20%).170 These unit operations provide heat required for frac-tionation in the atmospheric distillation column. The heatexchangers increase the crude temperature from desalter con-ditions to approximately 290 °C and the fired-furnace heatsthe crude oil up to the optimal inlet temperature for theatmospheric distillation column, typically in the range of400 °C–410 °C.

Atmospheric distillation: the preheated crude oil then entersthe flash zone of the atmospheric distillation column. Thevapor (gas oil and lighter plus a portion of the resid) travels upthe column and is contacted with internally condensed andrefluxed resid, commonly referred to as “overflash.” Steam isalso added to the column in the flash zone to assist in strip-ping gas oil molecules from the heavy resid. Throughout thecolumn, liquid circulation and cooling loops called “pump-arounds” draw liquid from an internal collection tray and rein-troduces the cooled liquid to the column as reflux forimproved efficiency. A portion of the liquid can be drawn fromthe pumparound as a crude oil cut. The atmospheric distilla-tion column and associated equipment separate the crude oil

Fig. 21 Total acid number (TAN) of crude oil (mg g−1).

Fig. 22 Simplified process flow diagram for crude oil fractionationunit.169

Table 12 Typical operating conditions for processing steps in crude oilfractionation170–173

Processing stepTemperature(°C)

Pressure(barga)

Desalter 95–150 6.9–10.3Crude preheat 400–410 1.7–2.1Atmospheric distillation Overhead 150–200 1.7–2.1

Bottoms 340–400 Overhead P + DPAtmosphericbottoms preheat

400–430 0.03–0.10

Vacuum distillation Overhead 65–120 0.03–0.10Bottoms 400–410 Overhead P + DP

a Represents gauge pressure in bar (100 kPa). Gauge P = Absolute P −Atmospheric P.



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into multiple cuts ranging from the C4 and lighter stream tothe atmospheric tower bottoms (ATB). The ATB streams arefurther fractionated in the vacuum distillation column whilethe other fractionated crude oil streams proceed to the appro-priate processing steps in downstream refinery units. Atmos-pheric bottoms preheat: the ATB stream from atmosphericdistillation enters the vacuum preheat system, which includes asecond fired-heater to increase the temperature of the ATB totemperatures near 430 °C. Similar to the atmospheric column,the fired-heater provides heat for fractionation in the vacuumdistillation column. Adding steam to the ATB stream in thefired-heater helps control thermal decomposition and coking inthe heater tubes by reducing the hydrocarbon partial pressure.

Vacuum distillation: the preheated ATB enters the vacuumdistillation column, which operates at pressure below atmos-pheric to prevent the heavy fractions of crude oil from under-going undesired decomposition by thermal cracking andcoking. Stripping steam is added to the bottom of the columnto assist in feed vaporization and to minimize coking. Typicaloperating pressures in the vacuum tower range from 10 to40 mmHg, depending on the crude and desired intermediateproducts. The vacuum distillation column and associatedequipment separate the ATB stream into light vacuum gas oil,heavy vacuum gas oil, and resid.

The various intermediate streams produced through crudeoil fractionation are sent to different areas of the refinery forfurther processing prior to product blending. The followingdiscussion summarizes the common destinations for eachfractionated stream from the crude unit.

Butanes and lighter: this mixture of light hydrocarbons ismost commonly sent to a gas processing plant where it isfurther split into C4 hydrocarbons, C3 hydrocarbons and otherlight ends (ethane, methane). After amine scrubbing to removethe H2S, the light ends are generally burned as refinery fuelgas for heat and power. After mercaptan removal, the C3

stream is blended into a propane product or LPG. The C4

stream is also treated for mercaptan removal and thenblended into a mixed butanes product or sent as feed to thealkylation unit.

Light naphtha: the light naphtha stream is sent to a mildhydrotreating unit if necessary to meet gasoline product sulfurspecifications. The stream can then serve as a direct gasolineblendstock or as isomerization unit feed to increase the octanevalue prior to gasoline blending.

Heavy naphtha: the heavy naphtha stream is sent to thecatalytic reformer hydrotreating unit to reduce sulfur andnitrogen contents to protect the catalytic reformer catalystfrom nitrogen poisoning and to meet gasoline product sulfurspecifications. After hydrotreating, the stream then serves as adirect gasoline blendstock or as catalytic reformer unit feed toincrease the octane value prior to gasoline blending. Thedecision on whether or not to catalytically reform the heavynaphtha is an economic one, which depends on the marketvalue of high octane gasoline versus low octane blends and therefinery’s hydrogen balance (since the reformer is a net produ-cer of hydrogen).

Kerosene: the kerosene cut is sent to a sulfur reductionprocess like mercaptan treating or hydrotreating. The streamthen serves as a blendstock for jet fuel or ultra-low-sulfurdiesel (ULSD). Kerosene blending strategy is another economicdecision that depends on the relative market values of jet fueland ULSD.

Diesel oil: the diesel oil cut is sent to a hydrotreating unit toreduce the sulfur content to levels consistent with product spe-cifications. Most refiners reduce the sulfur content of thediesel oil for ULSD blending (<15 ppmw sulfur), however refi-ners can also produce marine diesel (<500 ppmw sulfur) andhome heating oil (<2000 ppmw sulfur).

Atmospheric gas oil and light vacuum gas oil: the atmosphericgas oil and light vacuum gas oil streams most commonly serveas FCC feedstock. The FCC converts the gas oil range hydrocar-bons to light gases, naphtha, and diesel range products. FCCunits normally have a hydrotreater upstream which impactsthe FCC product quality and yield structures as a function ofdegree of hydrotreating.

Heavy vacuum gas oil: this stream can either be sent to theFCC, coker, or hydrocracker. The appropriate destination forthis stream depends on product quality (metals content), avail-able unit operations and capacities at the refinery, and relativeyield structures for the stream in each of the possible unitoperations.

Residue: the resid material from the crude fractionationunit is most commonly sent to the coker unit to yield naphthaand diesel range hydrocarbons by thermal cracking. Some refi-ners co-feed resid in low concentrations (<5%) to the FCC asthe yields of fuel-range products are more favorable relative tothe coker. Refiners have also constructed grass-roots FCC unitsdesigned to process high concentrations of resid feedstocks.Resid materials can also be sold as asphalt if the economicsand market demand are favorable.

4.4.2 Fluid catalytic cracking (FCC) unit. The overall objec-tive of the FCC process is to catalytically convert heavier pet-roleum molecules, primarily from the gas oil fractions, tosalable products like gasoline and diesel blendingcomponents.

A simplified process flow diagram for a fluid catalytic crack-ing unit is provided in Fig. 23. The processing steps includedin the FCC unit are listed and discussed below.

Fig. 23 Simplified process flow diagram for fluid catalytic crackingunit.169



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Feed preheat: the FCC feed enters the crude preheat system,which consists of a series of heat exchangers similar to theconfiguration in the crude fractionation unit to increase thegas oil temperature to approximately 290 °C through heattransfer with process streams being cooled from the down-stream main fractionator.

Catalytic cracking in reactor: the preheated feed is injectedinto the reactor where it meets hot regenerated catalyst fromthe regenerator. The hot catalyst vaporizes the oil, and crack-ing reactions take place in the riser reactor at temperaturesranging from 510 °C–565 °C and at a residence times generallyranging from 0.1 to 1 s. The principal reactions in FCC unitsare presented in Fig. 24. Carbon (coke) from the cracking reac-tions is deposited on the catalyst surface lowering its conver-sion activity; catalyst exiting the riser typically contains about1 wt% carbon. However, this value can vary depending onfeedstock quality and operating conditions. The deactivated orspent catalyst is recovered through the vapor/solids disenga-ging equipment (rough cut separator and cyclones) and flowsthrough the stripping section where residual hydrocarbons arestripped from the catalyst surface with steam. The fluidizedspent catalyst then flows from the reactor to the regenerator.The cracked vapor products are separated from the circulatingcatalyst through the vapor/solids disengaging equipment andsent to the main fractionator.

Coke combustion in regenerator: coke is burned from thespent catalyst at temperatures ranging from 650 °C–760 °C. Airis supplied to the regenerator from the air blower through theair distributor (air grid). The combustion of coke in the regen-erator provides the heat required in the reactor for feed vapori-zation and catalytic cracking reactions (overall endothermicreactions). The cracking reactor and catalyst regenerator aretypically operated in heat balance where the energy required

for the reactor to vaporize feed plus endothermic crackingreactions equals the energy supplied by coke combustion inthe regenerator (sensible heat to catalyst).

Flue gas is separated from the catalyst through disengagingsystems similar to the FCC reactor. The flue gas from theregenerator enters a power recovery turbine to generate powerand/or a series of heat exchangers to recover heat energy.

Product fractionation: the product vapors from the FCC aresent to the main fractionator for distillation into cuts, similarto the fractionation of crude oil in the atmospheric distillationoperation.

Gas oil crackers are the most common types of FCCs in theUnited States. These units are generally straightforward tokeep in heat balance. Resid crackers are less common butattractive for the United States as FCCs provide better yieldstructures over thermal cracking processes like cokers. It ismore challenging to maintain heat balance due to excessivecoke make from Concarbon and regenerator design limit-ations. Specific design aspects are required for resid FCCs tocontrol the heat balance such as catalyst coolers to reduce thetemperature of regenerated catalyst and control the catalyst-to-oil ratio.

The major refinery intermediates produced by the FCC unitare fuel gas, C3s, C4s, cracked naphthas, light cycle oil, heavycycle oil, slurry oil, and coke, which is not recovered as it isburned in the regenerator. Typical yield structures are primar-ily a function of feed conversion, which is calculated as 100%− (LCO vol% + HCO vol%). The major unit operating para-meters that impact feed conversion are catalyst type andactivity, reactor operating temperature, contact time/reactorresidence time, and catalyst-to-oil ratio. A simple example ofhow the yield structure is impacted by conversion is presentedin Fig. 25.

The various intermediate streams produced through theFCC unit operation are sent to different areas of the refineryfor further processing prior to product blending. The followingdiscussion summarizes the common destinations for eachFCC intermediate stream.

Butanes and lighter: this mixture of light hydrocarbons issent to the FCC gas processing plant where it is further splitinto C4 hydrocarbons, C3 hydrocarbons, and other light ends(ethane, methane). After amine scrubbing to remove the H2S,

Fig. 24 Summary of fluid catalytic cracking reactions.174 Fig. 25 Typical yield structure for FCC.



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the light ends are generally burned as refinery fuel gas for heatand power. The C3 stream is typically blended into a propane/propylene product. The C4 stream, which is high in olefincontent, is sent to the alkylation unit for conversion to a highoctane gasoline blendstock through reaction with isobutanemolecules from other refinery processes.

FCC cracked naphtha(s): the FCC naphtha streams are highlyaromatic and represent high octane materials that are desir-able as gasoline blendstocks. These intermediates are typicallysent to a hydrotreating unit that uses a catalyst specificallydesigned to selectively reduce sulfur while minimizing aro-matic saturation, which will minimize the octane loss associ-ated with saturation of aromatics to cycloparaffins. Afterdesulfurization in the FCC naphtha hydrotreater, the streamserves as a direct gasoline blendstock.

FCC light cycle oil (LCO): the FCC LCO stream is a highlyaromatic diesel range intermediate. Raw LCO from the FCC isa low-quality diesel blendstock because its high aromaticcontent makes its cetane number very low. Therefore, toimprove the diesel blending properties of the LCO intermedi-ate, it is typically sent to a high-pressure hydrotreater to satu-rate the aromatics and improve the cetane value, whilesimultaneously reducing the sulfur content to levels appropri-ate for ultra-low sulfur diesel (ULSD), marine diesel, or homeheating oil. If a refinery produces ULSD and higher sulfur pro-ducts (marine diesel and heating oil), the LCO will be prefer-entially blended in the higher sulfur blends due to the highhydrogen consumptions associated with removing sulfur downto ULSD specifications. The LCO can also serve as a hydro-cracker feed to produce C3s, C4s, naphtha, and ULSD blend-stocks, depending on the relative economics of gasoline anddiesel and refinery processing capabilities and capacities.

Heavy cycle oil (HCO): depending on available processingunits in the refinery, the FCC may yield a heavy cycle oil (HCO)intermediate, consistent with the boiling range of light atmos-pheric gas oil. This stream is also highly aromatic. If a refinerhas the available hydrocracker capacity to process HCO, it canbe converted to C3, C4, naphtha, and diesel products in thehydrocracker.

FCC slurry oil: the heavy residual material from the FCC iscalled slurry oil because, in addition to the highly aromaticand high boiling point molecules present in the stream, sus-pended catalyst fines from reactor carry-over may also bepresent in the liquid. The slurry oil is sometimes sent to thecoker if the material does not negatively impact the quality ofcoke product. The stream can also be blended as lower valuebunker fuel or blended as asphalt.

FCC catalysts: FCC catalysts have evolved over the past 70years to allow for flexibility in terms of variations in processconfigurations and conditions as well as changes in FCC feedcharacteristics. Modern FCC catalysts are amorphous silica–aluminas or rare earth exchanged Y-zeolites; desirable catalystproperties include high thermal and hydrothermal stability(>850 °C), high attrition resistance, high activity, high activityfor the desired selectivity to C5–C10 fractions and low cokeyield.175–177 A major driver associated with the economics of

an FCC unit is the required make-up rate for replacing thespent catalyst, with current rates being cited at <1 wt%.175 Themake-up rate also effects the composition of the catalyst suchthat the circulating FCC catalyst is a mixture of newer, highlyactive catalyst and older catalyst with reduced activity. Inindustrial terms, this mixture is often referred to as equili-brium catalyst or E-Cat.178 Additives to the FCC catalyst arealso included to improve overall yields and fuel properties aswell as to help control emissions from the FCC unit. ZSM-5 isoften included either by incorporating it into the FCC catalystmatrix or as a separate catalyst to boost the octane of the gaso-line product and promote light olefin production.175,178 Theaddition of ZSM-5 reduces gasoline yields; a 1-unit increase inoctane roughly results in a 2 vol% reduction in gasoline yieldsdue to cracking losses.175 Additives are also utilized to reducesulfur content in the gasoline fraction. Metal passivators, suchas antimony or bismuth help to improve catalyst lifetimes andreduce coke formation, specifically when processing heavierresids that may contain significant amounts of metal por-phyrins.175,177 Additives in the catalysts are also often employedto help control emissions from regeneration, particularly SOx

and NOx, as well as promote the oxidation of CO.175–177

4.4.3 Thermal cracking unit(s). The overall objective ofthermal cracking processes is to thermally convert heavy pet-roleum molecules, primarily from the resid fraction, intosalable products or blendstocks like gasoline and diesel blend-ing components. A comparison of thermal reaction types rela-tive to catalytic cracking reaction types is presented inTable 13. Simplified process flow diagrams for three types ofthermal crackers – visbreaker, delayed coker, and fluid coker –are presented in Fig. 26–28. Although the process configur-ations differ in each of the thermal processes, the major pro-cessing steps are similar. The major steps for each processconfiguration are discussed below.

Table 13 Comparison of thermal cracking and catalytic crackingreactions179

Hydrocarbontype Thermal cracking Catalytic cracking

Normalparaffins

High gas production(C3 and lighter)

High yield of LPG andnaphtha range compounds

High yield of normalα-olefins

Low yield of normalα-olefins above C4

Low yield of branchedaliphatics (non-aromatics)

High yield of branchedaliphatics (non-aromatics)

Low yield of aromatics High yield of aromaticsOlefins Low degree of skeletal

isomerizationHigh degree of skeletalisomerization

H-transfer is minimal H-transfer is extensiveRate of cracking isroughly equal to thatof paraffins

Rate of cracking is muchhigher than that ofparaffins

Naphthenes Rate of cracking is lessthan that of paraffins

Rate of cracking is roughlyequal to that of paraffins(with equivalent structuralgroups)

Alkylaromatics

Cracked within alkylside-chain

Cracked alkyl side-chain atring



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VisbreakerFeed preheat: the first process step in visbreaking is feed

preheat, which consists of a series of heat exchangers andfired furnaces to increase the resid temperature to above430 °C. The thermal cracking and viscosity reduction reactionsinitiate in the process heater and continue in the downstreamoperations.

Thermal cracking: the preheated feed is injected into anoptional soaking drum, which provides residence time for thethermal reactions to take place.

Product fractionation: the hot liquid from the fired-heater/soaking drum is quenched with recycled fractionator bottomsand enters the atmospheric fractionator. The products from

the visbreaker include C4 and lighter gases, naphtha, gas oil,and bottoms/tar.

Delayed cokerFeed fractionation: the delayed coker process configuration

is unique in that the heavy oil (resid) feed enters the fractiona-tor prior to the reactor system to remove any light productsthat may be present in the resid. The fractionator bottomsstream is recycled to extinction through the downstream fired-furnace and reactor system.

Bottoms preheat: from the fractionator, the heavy bottomsstream is preheated in a series of heat exchangers and a fired-furnace to increase the resid temperature to above 480 °C. Thethermal cracking and coking reactions initiate in the processheater and continue to the downstream coke drum. Steam istypically added to the process side of the furnace to control thebuildup of coke deposits in the heater tubes.

Thermal cracking: the thermal cracking reactions continuefrom the furnace to the coke drum where coke is collecteduntil the drum is filled to a controlled level. As coke depositsin the drum, the cracked vapor products exit the top of thedrum and enter the fractionator for product recovery and sep-aration. Once the operating coke drum is full, it is taken out ofservice and the second coke drum takes its place. The full cokedrum is then decoked (the coke is removed from the drum)through a labor intensive series of coke cutting and coolingsteps. Once the coke is cooled and broken into small pieces,the coke is dumped from the bottom of the drum and sold asproduct or burned as fuel. The empty coke drum is then pre-pared to enter operating service again.

Product fractionation: the hot product vapors from the cokedrum enter the fractionator column where they are separatedinto C4 and lighter gases, naphtha, and gas oil intermediatestreams.

Fluid cokerThe fluid coker process configuration is similar to the FCC

process in that a circulating fluidized solid material serves asthe heat transfer media between the reactor and burnervessels. Coke produced from the reactor is sent to the burnerfor combustion. The coke combustion in the burner providesheat to the reactor for heating the feed and for the endother-mic coking reactions. However, instead of the catalyst used forFCC unit operations, the fluid coker utilizes coke particles asthe heat transfer media.

Feed pre-heat/scrubbing: in the fluid coker process configur-ation, the feed is pumped into the vapor scrubber section ontop of the reactor. The vapor scrubber serves several purposesincluding preheating the feed by direct contact with the hotreactor vapors from the coker reactor and flashing any lightproducts present in the feed. The heavy resid feed flows downthrough the contacting media and reaches a liquid draw tray atthe bottom of the scrubber. The liquid then flows from thescrubber section to the reactor through one or several injectionpoints.

Thermal cracking: the preheated feed from the scrubber isinjected into the reactor where it meets hot circulating cokeparticles. The hot coke particles heat the residual oil and

Fig. 26 Simplified process flow diagram for visbreaker unit.170

Fig. 27 Simplified process flow diagram for delayed coker unit.170

Fig. 28 Simplified process flow diagram for fluid coker unit.170



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thermal cracking reactions take place in the reactor at tempera-tures in the range of 510 °C–540 °C. Carbon (coke) from thecracking reaction mechanisms is deposited on the surface ofthe circulating coke particles. The coke particles from thereactor are recovered through the vapor/solids disengagingequipment (cyclones) and flows from the reactor to the regen-erator. The cracked vapor products are separated from the cir-culating catalyst through vapor/solids disengaging equipmentand sent to the vapor scrubber and fractionator.

Coke combustion in burner: coke accumulated on the circu-lating coke particles is burned by partial oxidation in theburner. Air is supplied to the burner from an air blowerthrough the air distributor (air grid). Coke combustion pro-vides the heat required in the reactor for feed vaporization andthe endothermic thermal cracking reactions. The flue gas isseparated from the catalyst through disengaging systemssimilar to the reactor. The partially oxidized vapor from theburner typically serves as fuel for a downstream CO boiler,where the CO is combusted to CO2. The flue gas from the COboiler can then enter a power recovery turbine to generatepower and/or a series of heat exchangers to recover heatenergy.

Vapor scrubber and product fractionation: the reactor vaporsflow from the reactor, through the cyclones where residualsolids are removed, and enter the vapor scrubber. The scrub-ber cools the vapors through direct contact with cold feed andknocks out residual solids or heavy hydrocarbon dropletscarried over from the reactor. The vapors then flow from thevapor scrubber to the fractionator for distillation into cuts,similar to the fractionation of crude oil in the atmospheric dis-tillation operation. The cuts typically obtained from the fluidcoker are C4 and lighter gases, naphtha, and gas oil intermedi-ate streams. The heavy bottoms stream is recycled toextinction.

The major refinery intermediates from the thermal crackingprocesses include fuel gas, C3s, C4s, cracked naphthas, andcracked gas oil. The coker also yields a coke product while thevisbreaker yields a heavy unconverted bottoms/tar stream.Typical yield structures are primarily a function of feed quality,specifically the Conradson carbon content. A simple exampleof how the yield structure from the coker is impacted by feedquality is presented in Fig. 29.

The various intermediate streams produced through thethermal cracking unit operations are sent to different areas ofthe refinery for further processing prior to product blending assummarized below.

Butanes and lighter: this mixture of light hydrocarbons istypically sent to a gas processing plant where it is further splitinto C4 hydrocarbons, C3 hydrocarbons, and other light ends(ethane, methane). After amine scrubbing to remove H2S, thelight ends are generally burned as refinery fuel gas for heatand power. The C3 stream is typically blended into a propane/propylene product. The C4 stream, which is high in olefincontent, is sent to the alkylation unit for conversion to a highoctane gasoline blendstock through reaction with isobutanemolecules from other refinery processes.

Thermally cracked naphtha(s): these naphtha streams arehigh in olefins and possess moderate octane values. Sincethese naphthas can also be high in sulfur content, the inter-mediates are typically sent to the cracked naphtha hydrotreat-ing unit with the FCC naphtha streams. After desulfurizationin the cracked naphtha hydrotreater, the stream serves as adirect gasoline blendstock.

Thermally cracked gas oil: the gas oil streams from thermalcracking processes are lower quality intermediates relative toraw gas oils recovered from crude fractionation due to theirhigh aromatic and olefin content. However, the cracked gasoils can serve as feedstocks for other process units wherefurther conversion can yield high-value products like naphthaand middle distillates for product blending. The mostcommon destinations for the thermally cracked gas oils arethe FCC (typically one with a feed hydrotreating unit upstream)or a high pressure hydrocracker.

Bottoms/tar oil: the heavy residual material from visbreakingprocesses is blended as lower value bunker fuel or as asphalt.

Coke: coke recovered from the delayed coker process can besold into various markets including carbon anode production(needle coke). The coke from the delayed coker and purgedcoke particles from the fluid coker can also be used as feed-stocks for gasification processes to produce synthesis gas fordownstream conversion or to produce heat and power.

4.4.4 Hydroprocessing units. The term “hydroprocessing”as it relates to the petroleum refining industry represents adiverse variety of chemical processes in which catalytic hydro-genation is used to manipulate the molecular composition ofa petroleum-derived refinery intermediate. The overall purposeof hydroprocessing is to maximize the value of products fromthe petroleum refinery (finished fuel sales) relative to the costof the hydrogen (purchased or manufactured on-site) con-sumed in the hydroprocessing unit operations.

A simplified process flow diagram representing the mostcommon configuration of a hydroprocessing unit found in aU.S. refinery is provided in Fig. 30. The major processing stepsincluded in the configuration are listed and discussed below.

Feed pre-heat: the feed to the hydroprocessing unit is heatedin a series of feed/effluent exchangers and a fired-furnace up

Fig. 29 Typical yield structure for coker units.



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to the appropriate reactor inlet temperature, which is specificto the service/purpose of the hydroprocessing unit operation.

Reactor(s): the preheated feed from the pre-heat system ismixed with fresh and recycled hydrogen streams and entersthe reactor system, which can consist of a single vessel or amulti-reactor configuration. The ratio of hydrogen to feed,operating pressure, and operating temperature in the reactorsystem depends on the hydroprocessing service. There are twomajor categories of reactions that take place in hydroproces-sing units; hydrotreating reactions, which are summarized inFig. 31a, and hydrocracking reactions, summarized inFig. 31b. The unit purpose and design, operating conditions,and catalyst dictate the types of reactions that take place in thereactor(s). Typically, sulfur and nitrogen removal (hydrotreat-ing) reactors will utilize supported cobalt-molybdenum(CoMo) or nickel-molybdenum (NiMo) catalysts while hydro-cracking reactors will possess an acidic zeolite catalyst to favormolecular weight reduction reactions. The reactor effluentstream leaves the reactor system and enters the effluentcooling section of the unit.

Effluent cooling and vapor/liquid separation: the hot reactoreffluent stream enters the feed/effluent heat exchangers anddownstream coolers to reduce the temperature and condensethe hydrocarbon products. Once cooled, the hydrogen-richrecycle gas is removed from the effluent mixture in the first-stage separator vessel. The hydrogen-rich recycle gas is com-pressed and sent back to the reactor inlet while the liquid issent to the second-stage separator, which typically operates ata lower pressure relative to upstream operations, allowing lighthydrocarbons to flash and exit in the vapor stream. The lighthydrocarbons from the second-stage separator generally serveas fuel gas for heat and power. The liquid from the second-stage separator enters the product stripper or fractionator forproduct recovery/separation.

Product fractionation: the liquid from the vapor/liquid separ-ation system flows to the product stripper or fractionator vesselfor product separation and recovery. A product stripper isusually present for hydrotreating operations where molecularweight reduction reactions are minimal. A product fractionatoris required in hydrocracking services where significant

conversion reactions result in a diverse product distribution.The product slates for hydroprocessing units vary widelydepending on the feed and function of the unit.

As Fig. 15 shows, a typical U.S. refinery possesses manydifferent hydroprocessing unit operations that serve differentroles in processing a diverse array of refinery intermediatestreams. The most common hydroprocessing unit operationsfound in U.S. petroleum refineries are summarized in thedescriptions below. The operations are grouped together inthree major categories – Naphtha Hydroprocessing, DistillateHydroprocessing, and Gas Oil and Resid Hydroprocessing. Thedescriptions include typical feedstock(s), processing objectives,and ranges of typical operating parameters associated witheach respective hydroprocessing unit operation.

Naphtha hydroprocessing. The two major sources of thenaphtha intermediates that feed hydroprocessing units in therefinery are (1) the crude fractionation units and (2) the FCCand coker. The unprocessed or virgin naphthas from crude

Fig. 30 Simplified process flow diagram for hydroprocessing unit.170

Fig. 31 (a) Summary of metal catalyzed hydrotreating reactions. (b)Summary of acid catalyzed hydrocracking reactions.180



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fractionation units are generally high in paraffin (alkane) andnaphthene (cycloalkane) contents. The cracked naphthas fromthe FCC and coker units are generally high in olefin (alkene)and aromatic contents. Since virgin naphthas possess highlevels of hydrogen saturation relative to cracked naphthas, thevirgin materials generally consume significantly less hydrogenthan cracked naphthas in hydroprocessing units. Table 14 pre-sents a comparison of operating conditions for typicalnaphtha hydrotreating services found in U.S. refineries.Virgin naphtha/reformer feed hydrotreating

This relatively mild hydrotreating operation processesvirgin (previously unprocessed) naphtha streams recoveredfrom the raw crude oil during crude fractionation. Hydro-treated products from virgin naphtha units either serve asgasoline blendstock or feed to the naphtha reformer unit,which increases octane value by yielding single-ring aromaticsand hydrogen for use in other hydroprocessing units in therefinery. The primary processing objectives for naphtha hydro-treating units are (1) desulfurization, if the product is used forgasoline blending, to meet gasoline blending specifications;and (2) denitrogenation, if the product feeds a reformer unit,as nitrogen is a poison for the reformer catalyst. Cobalt-molyb-denum catalysts are most commonly employed in these units.Cracked naphtha hydrotreating

The primary feeds to this higher-severity naphtha hydro-treating service are cracked naphthas from the FCC and cokerunits. These cracked materials generally possess higher octanevalues relative to virgin materials due to higher olefin and aro-matic contents. The major objective of hydrotreating thesematerials is desulfurization to meet finished fuels specifica-tions while minimizing (1) octane loss by hydrogen saturation

of carbon chains and rings and (2) minimizing naphtha lossesto light ends by cracking reactions. Cobalt-molybdenum andnickel-molybdenum catalysts are most common in these units.

Distillate hydroprocessing. Similar to the naphtha intermedi-ates, the two major sources of distillate (kerosene/jet fuel anddiesel) intermediates feeding hydroprocessing units are (1) thecrude fractionation units and (2) products from the FCC andcoker. The unprocessed or virgin distillates from crude frac-tionation units include the kerosene/jet fuel and virgin distil-late. The cracked distillates from FCC, light cycle oil (LCO) andcoker distillates contain molecules that are significantly lesssaturated in hydrogen relative to their virgin boiling-rangeequivalents. Therefore, virgin distillates generally consume sig-nificantly less hydrogen than cracked distillates in hydropro-cessing units. Table 15 presents a comparison of operatingconditions for typical distillate hydroprocessing services foundin U.S refineries.

Deep desulfurization distillate hydrotreating capacity in theUnited States has increased significantly in recent years due toincreasingly challenging sulfur specifications for on-roadULSD diesel (S < 15 wppm).Kerosene/jet fuel hydrotreating

This relatively low-severity hydrotreating unit operation per-forms desulfurization on the virgin kerosene/jet fuel cut fromthe crude oil fractionation units. The treated product will typi-cally serve as a blendstock for either jet fuel or ULSD. The des-tination for the product depends on a refinery’s ability toproduce jet fuel and the relative economics of jet fuel versusULSD. Cobalt-molybdenum catalysts are most common inthese units.Virgin distillate hydrotreating

This processing unit performs desulfurization on the virgindistillate cuts from the crude oil fractionation units. Thetreated product will serve as a blendstock for ULSD, marinediesel, or heating oil depending on the refinery’s capabilitiesand market demands for each product. Product from this unitwill preferentially enter the lower-sulfur finished fuel blendssince the virgin distillates are less challenging for deep desul-furization relative to the cracked distillates. Cobalt-molyb-denum catalysts are most common in these units.Cracked distillate hydrotreating

This processing unit performs desulfurization on thecracked distillate materials from the FCC (FCC LCO) and coker(coker distillate). Like the virgin distillate unit, the treatedproduct will serve as a blendstock for ULSD, marine diesel, or

Table 14 Typical operating conditions for naphtha hydrotreatingunits153,169,170,173,180

Process parameter

Virgin naphtha/reformerfeed hydrotreating

Crackednaphthahydrotreating

Feed gravity (API) 50–65 30–50Temperature (°C) 230–340 230–340Pressure (psia) 300–450 650–1000H2 partial pressure (psia) 100–150 200–650LHSV (h−1) 3–10 1–5H2 consumption (SCF/Bbl) 40–200 200–500H2 to oil ratio (SCF/Bbl) 300–600 1500–3000

Table 15 Typical operating conditions for distillate hydrotreating units153,169,170,173,180

Process parameterKerosene/jethydrotreating

Virgin distillatehydrotreating

Cracked distillatehydrotreating

Distillatehydrocracking

Feed gravity (API) 40–50 30–45 15–30 15–30Temperature (°C) 290–370 310–400 340–7400 340–450Pressure (psia) 700–1000 700–1500 1000–2500 1000–2500H2 partial pressure (psia) 500–900 500–1200 800–1800 800–2300LHSV (h−1) 3–6 1–4 1–2 0.5–2H2 Consumption (SCF/Bbl) 150–500 300–700 700–1700 500–2000H2 to oil ratio (SCF/Bbl) 600–2500 1200–3000 2000–7000 2000–8000



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heating oil. However, product from this unit will preferentiallyenter the higher-sulfur finished fuel blends since the crackeddistillates are significantly more challenging for deep desulfur-ization relative to the virgin distillates. Most of the recenthydroprocessing investments in the United States havefocused on desulfurization of cracked distillates to maximizeULSD production. Cobalt-molybdenum and nickel-molyb-denum catalysts are most common in these units.Distillate hydrocracking

Hydrocracking processes add another objectivebeyond desulfurization and denitrogenation namely molecularweight reduction or cracking. A distillate hydrocracker iscapable of processing both virgin and cracked distillatematerials, yielding a product slate that commonly favorsnaphtha-range compounds. Hydrocracking units typically areaccompanied by upstream hydrotreating units that utilizecobalt-molybdenum and/or nickel-molybdenum catalysts forsulfur and nitrogen removal to protect the zeolite hydrocrack-ing catalysts.

As demand for diesel fuel increases relative to gasoline, dis-tillate hydrocracking economics become less attractive com-pared to desulfurization-only units, which yield highervolumes of USLD blendstock relative to naphtha. Units orig-inally designed for distillate hydrocracking can often be modi-fied by catalyst-loading strategies and operating conditions tofavor higher distillate yields.

Gas oil and resid hydroprocessing. The sources of gas oil andresid intermediates feeding hydroprocessing units are (1) thecrude fractionation units and (2) the FCC and the coker. Theunprocessed or virgin cuts from crude fractionation units typi-cally include the atmospheric gas oil (AGO), light vacuum gasoil (LVGO), heavy vacuum gas oil (HVGO) and resid from thevacuum tower bottoms. The cracked gas oils and resids thatare candidates for hydroprocessing are the FCC heavy cycle oil(FCC HCO), coker light gas oil (CLGO) and coker heavy gas oil(CHGO). Table 16 compares operating conditions for typicalgas oil and resid hydroprocessing units in U.S. refineries.Gas oil/FCC feed hydrotreating

This unit operation provides desulfurization, denitrogena-tion, and mild hydrogen saturation to FCC feedstocks, whichcan include AGO, LVGO, HVGO, and, in some cases, smallvolumes of resid. The gas oil/FCC feed hydrotreating serviceprovides significant yield benefits in FCC products and alsoreduces the required desulfurization severities for hydrotreat-ing FCC products like FCC naphtha, LCO, and HCO. Cobalt-molybdenum and nickel-molybdenum catalysts are mostcommon in these units.Cracked gas oil hydrocracking

An alternative and often economically preferred processingstrategy for upgrading coker gas oils is high-severity hydro-cracking to produce high distillate yields for ULSD blending.In addition, challenging FCC products like HCO (and LCO dis-tillate) can be processed in the hydrocracker to produce dieseland gasoline blendstocks. The penalty for converting thesehydrogen-deficient intermediates in the hydrocracker is thatthey consume significant amounts of hydrogen.

Resid hydrocrackingThis high severity hydrocracker is designed to process

heavy virgin fractions like HVGO and resid to produce higher-value products for product blending or further downstreamprocessing. Based on literature,173 these heavy oil hydrocrack-ers are typically designed as ebullated catalyst bed systemswith supported nickel-molybdenum or zeolite hydrocrackingcatalysts. Like cracked gas oil hydrocrackers, these units alsoconsume significant amounts of hydrogen.

4.5 Refinery products

The typical U.S. petroleum refinery markets a variety of fin-ished products ranging from propane (LPG) to asphalt. Someof the common refinery products and associated specificationsare discussed below.

Liquefied petroleum gas (LPG): LPG products consist of mix-tures of the C3 and C4 hydrocarbon streams. Some commonLPG products are described below.• Propane products are commonly comprised of the C3

hydrocarbons from the crude fractionation unit and varioushydroprocessing unit operations due to the low propylenecontent of the streams. Propane products normally have speci-fications on the amounts of other materials present in themixture. For example, “HD5 consumer grade” propane musthave a minimum propane content of 90% and a maximumpropylene content of 5%.• Propylene products can also be sold from a refinery. Typi-

cally, propylene is sold as a polymer precursor for polypro-pylene production. The specifications on propylene typicallyvary depending on agreements established with the purchas-ing company, however, commodity specifications exist for pro-pylene materials as well. For example, “polymer grade”propylene must have a minimum purity of 99.5%.• Butanes can be sold as products if the refinery has excess

material that is not being utilized in the alkylation unit, the C4

isomerization unit, or blended into gasoline products to adjustthe vapor pressure (Reid vapor pressure, Table 17). Minimumpurity specifications of 95% on isobutane and normal butaneproducts are common.

Gasoline: gasoline products are created by blending thevarious naphtha streams from the refinery into a mixture

Table 16 Typical operating conditions for gas oil and resid hydrotreat-ing units153,169,170,173,180

Process parameter

Gas oil orFCC feedhydrotreating

Cracked gas oilhydrocracking

Residhydrocracking

Feed gravity (API) 15–25 0–20 (10)–15Temperature (°C) 340–430 340–450 400–450Pressure (psia) 800–1200 1500–3000 2400–3000H2 partial pressure(psia)

600–1000 1200–2700 1900–2700

LHSV (h−1) 0.5–1 0.5–2 0.5–1H2 consumption(SCF/Bbl)

500–1000 1200–3500 1200–3500

H2 to oil ratio(SCF/Bbl)

1500–4000 4000–10 000 4000–10 000



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meeting all applicable fuel specifications. A refinery typicallyproduces several gasoline products with varying average octanenumbers. Specifications for gasoline products can varydepending on location, ambient temperature, and specific cus-tomer requirements. An example of how individual naphthablending components compare to properties of a typical fin-ished gasoline fuel blend is presented in Table 17.

Jet fuel: the most significant contributor to jet fuel pro-duced by a refinery is the straight-run kerosene stream fromthe crude fractionation unit. However, hydrotreated and hydro-cracked refinery intermediates with comparable boiling rangesmay also contribute to jet fuel products. The straight-run kero-sene is normally upgraded by mercaptan treating, clay treating,or hydrotreating before it can be sold as jet fuel.181 Specifica-tions for jet fuel products vary depending on the requirements

of the service and customer. Table 18 presents a summary ofmajor fuel property specifications for civilian jet fuels.181 If arefiner does not produce jet fuel products, the kerosene-rangeblendstocks can be used to contribute to USLD, another highlyvalued product.• Diesel fuels and heating oil: diesel fuel products are

created by blending the various middle-distillate streams(virgin and cracked kerosenes and diesel oils) from the refineryinto a mixture meeting all applicable fuel specifications. Anexample of how individual middle-distillate blending com-ponents compare to properties of a typical finished diesel fuelblend is presented in Table 19.

Other products: products including heavy fuel oils, asphalt,lubricant oils, waxes, coke (carbon), elemental sulfur, aro-matics (benzene, toluene and xylenes), specialty chemicals,

Table 17 Comparison of gasoline blend component properties to finished gasoline producta 173,182

PropertyFinished gasolinespecification

Light crackednaphtha

Heavy crackednaphtha

Straight runnaphtha Alkylate Reformate

API gravity Report 70.6 57.2 76.6 71.4 47.6Distillation (ASTM D86)10 vol% BP (°C) 70 Max 46 57 44 78 6650 vol% BP (°C) 77 Min/121 Max 79 116 70 103 10190 vol% BP (°C) 190 Max 126 146 106 119 180Final BP (°C) 221 Max 150 155 117 188 191

Reid vapor pressure (psia) 7.0 9.1 2.6 9.7 4.5 6.7Aromatics (vol%) 50 6.6 13.3 3.5 0.7 52.9Olefins (vol%) 25 44.6 39.0 0.1 0.6Research octane no. Report 89.6 84.0 55.2 96.0 97.2Motor octane no. Report 78.5 75.9 55.0 94.0 87.1Ave. octane no. (R + M)/2 90.0 84.1 80.0 55.1 95.0 92.2

aNote: the summary presented in the table does not represent a complete set of gasoline specifications.

Table 18 Summary of property specifications for major jet fuel products181

Fuel Jet A Jet A-1 TS-1 Jet B

Specification ASTM D 1655 DEF STAN 91-91 GOST 10227 CGSB-3.22Acidity (mg KOH g−1) 0.10 0.015 0.7 (mg KOH per 100 ml) 0.10Aromatics, % vol. max 25 25.0 22 (% mass) 25.0Sulfur (mass%) 0.30 0.30 0.25 0.40Sulfur, mercaptan (mass%) 0.003 0.003 0.005 0.003Distillation, °C: initial boiling point — Report 150 Report10% recovered, max 205 205 165 Report50% recovered, max Report Report 195 min 125; max 19090% recovered, max Report Report 230 ReportEnd point 300 300 250 270

Vapor pressure, kPa, max — — — 21Flash point, °C, min 38 38 28 —Density, 15 °C, kg m−3 775–840 775–840 min 774 @ 20 °C 750–801Freezing point, °C, max −40 −47.0 −50 (Chilling point) −51Viscosity, −20 °C, mm2 s−1, max 8 8.0 8.0 @ −40 °C —Net heat of combustion, MJ kg−1, min 42.8 42.8 42.9 42.8Smoke point, mm, min 18 19.0 25 20Naphthalenes, vol%, max 3.0 3.00 — 3.0Copper corrosion, 2 h @ 100 °C, max rating No. 1 No. 1 Pass (3 h @ 100 °C) No. 1Thermal stabilityFilter pressure drop, mm Hg, max 25 25 — 25Visual tube rating, max <3 <3 — <3Static test 4 h @ 150 °C, mg per 100 ml, max — — 18 —

Existent gum, mg per 100 ml, max 7 7 5 —



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and many others can be produced by petroleum refineries andother integrated petrochemical facilities.

5. Integrating pyrolysis oil intostandard refineries5.1 Introduction

As mentioned earlier, a potentially very attractive option forintroducing biomass-derived materials into the fuels market-place would be to use bio-oil as a feedstock and/or blendstockin a standard petroleum refinery, either replacing or supple-menting fossil-derived materials with biomass-derivedmaterials. This would, in principle, facilitate the introductionof renewable carbon into the fuels infrastructure and wouldeconomically advantage the biofuels industry by using themulti-trillion dollar refining and distribution infrastructurealready in place. As detailed in section 4, from the refiner’sperspective when evaluating potential refinery feedstocks,important properties include the boiling range distributionobtained from the main crude oil fractionator and the hydro-carbon types (PONA) and heteroatom (sulfur, nitrogen, oxygen)contents of each of the resulting primary distillation andprocess-derived intermediate fractions. The boiling range dis-tribution from the main fractionator impacts all of the majordownstream unit operations, which are in turn designed tooptimize the refinery product slate to produce the most profitper barrel of feedstock.

Using bio-oil as a blendstock and/or feedstock in a conven-tional petroleum refinery introduces several potential pro-blems and pitfalls associated with the differences in physico-chemical properties of bio-oil relative to petroleum crude oil.Important properties of bio-oil as they related to refinery feed-stocks have been reviewed in detail in section 2.5 of this docu-ment. In addition to these issues, the following pointsrepresent significant barriers to utilization of bio-oil in aconventional petroleum refinery.

(1) Miscibility: due to its high organic oxygen content and thepresence of highly polar oxygenates, raw or non-upgraded bio-

oil is largely immiscible in aliphatic and aromatic hydrocarbonstypical of petroleum-derived crude oil and crude oil fractions.This problem can be mitigated by catalytic upgrading of thebio-oil to reduce oxygen and improve miscibility.145,146

(2) Acidity: as mentioned previously the acidity of petroleumcrude oil is generally very low (Fig. 21). Acidic componentspresent in crude oil generally represent naphthenic acids asmeasured using copper and silver strip tests (ASTM D130-12,ASTM D7671). These components are corrosive to mild steel athigh temperatures. The refining industry has long since deter-mined mechanisms for mitigating the impact of corrosionimparted by naphthenic acids [http://www.setlaboratories.com/nac/tabid/79/Default.aspx] including blending (industry stan-dard is that the TAN of the blend must be <0.6183), use of cor-rosion inhibitors, and upgraded materials of construction. Fora discussion of the impact of TAN of bio-oil on corrosion, seesection 2.5.5.

(3) Presence of organic oxygenates: as outlined in section 4,most crude oils contain very small amounts of organic oxygen;in general less than 1 wt% and often less than 0.1 wt%.184

Accordingly, catalysts and processes used in the refinery unitoperations for hydroprocessing intermediates and upgradingfossil petroleum to finished fuels are not designed to accom-modate these materials. The presence of organic oxygenatesand oxygen functional groups can impart very different pro-perties to feedstocks in the refinery when compared to streamsthat are predominately hydrocarbon. Physical properties suchas density, viscosity (section 2.5.4), and storage stability(section 2.5.3) can be altered and oxygenates can also degradeelastomers used in engine parts. The presence of organicoxygen leads to changes in volatility, which impacts unit oper-ations used for separating intermediates or producing finalproducts. Chemical properties are also altered by the presenceof organic oxygen, which can influence the reaction chemistryof important conversion and fuels synthesis processes. Cata-lysts, which are effective for converting crude fractions in theabsence of oxygenates, may function entirely differently whenoxygenated compounds are present, leading to changes inactivity and selectivity.

Table 19 Comparison of diesel blend component properties to finished diesel producta 173,182

PropertyFinished dieselspecification

Hydrotreatedstraight run diesel

Hydrotreatedcracked diesel

Hydrocrackerkerosene

Hydrocrackerdiesel

API gravity 33.5 Min/39.0 Max 33.8 35.0 38.0 34.0Distillation (ASTM D86)Initial BP (°C) 171 Min 267 223 191 28550 vol% BP (°C) 238 Min 291 261 229 32190 vol% BP (°C) 282 Min/338 Max 334 319 267 363

Cetane index 40 MinFlash point (°C) 60 MinCloud point (°C) −12 MaxPour point (°C) −7 MaxViscosity (cSt at 40 °C) 1.9 Min/4.1 MaxSulfur (ppmw) 15 Max

aNote: the summary presented in the table does not represent a complete set of diesel fuel specifications.



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(4) Presence of alkali and alkaline earth metals in the oil:crude oil has a very small inorganic content, which is generallycomprised of salt and porphyrins of vanadium and nickel.Salts and suspended solids in crude oil are readily removed ina de-salting unit operation prior to the initial fractionation(section 4.4.1). Refiners have developed strategies to mitigateand/or passivate the impact of vanadium and nickel contami-nation on refining catalysts, but introducing bio-oil brings anew suite of potential catalyst poisons from silicon, calcium,potassium, and other alkali and alkaline earth metals. Thesemetals could act as poisons for cracking and hydrotreatingcatalysts. The effect of these contaminants can be greatlyreduced by using hot gas filtration during the pyrolysisprocess,51 but trace quantities of these metals could still windup in downstream unit operations.

5.2 Refinery integration studies

In a comprehensive investigation into incorporating bio-renew-ables into the petroleum refinery, Marker183 examined severalopportunities for including bio-oil into standard petroleumrefinery unit operations. In addition to an examination of uti-lizing waste fats and greases as refinery feedstocks and hydro-gen production from the aqueous fraction of bio-oil, this studylooked at:• Hydroprocessing pyrolytic lignin to produce aromatics

and gasoline.• Co-processing bio-oil with vacuum gas oil (VGO) in the

fluid catalytic cracker (FCC).Using a two-step process46 consisting of catalytic hydrotreat-

ing over a Ru/C catalyst followed by catalytic hydrocrackingover a NiMo/alumina catalyst, hydroprocessing of pyrolyticlignin was reported by Marker to be successful in producing ahydrocarbon-like liquid product that represented 32 wt% ofthe starting material at 96 wt% oxygen removal. Approximately80 wt% of the hydrotreated liquid was found to be materialboiling in the naphtha range. Co-processing whole raw bio-oiland pyrolytic lignin in a laboratory ACE system was carried outfor blends of up to 20 wt% raw bio-oil and/or pyrolytic lignin.These experiments were accompanied by tests on the catalyticcracking of a hydrotreated whole bio-oil and for VGO alone.Results showed that all three biomass-derived oils gave greatlyincreased yields of coke (16 wt% and 27 wt% for the bio-oil/VGO blends) when compared to catalytic cracking of VGOalone. The bio-oil/VGO blends were found to increase the‘crackability’ of the feedstock when compared to VGO aloneand to increase the yields for light-end products, which ispotentially an economically attractive outcome.

A comprehensive investigation of opportunities for incor-porating biomass-derived materials in the petroleum refinerywas carried out under the auspices of the BIOCOUP project.This study concluded that the best insertion point forbio-oil was the FCC using a partially deoxygenated bio-oil con-taining up to 20% organic oxygen as the feedstock.

More recently, a team with members from NREL, PNNL,GEMI, and Valero185 conducted an investigation on the impactof upgrading with hydrogen on several of the important

refinery-relevant properties of bio-oil. The objective of thisstudy was to develop information on changes in acidity,boiling range distribution, elemental composition (includingtotal oxygen), and hydrocarbon and oxygenate types in streamsthat represent important refinery intermediates, and to corre-late this information with hydroprocessing severity (principallytemperature, pressure, liquid hourly space velocity or LHSV)and total oxygen content of the upgraded oil. Three levels ofhydroprocessing severity were analyzed, consisting of reactionconditions required to produce an oil with low oxygen content(LOC; organic oxygen = 0.4 wt% on a water-free basis),medium oxygen content (MOC; organic oxygen = 4.9 wt% on awater-free basis), and high oxygen content (HOC; organicoxygen = 8.2 wt% on a water-free basis). Fig. 32 shows the defi-nitions that were used in this study for the various boilingrange fractions for the upgraded bio-oils (as determined bysimulated distillation) related to the definitions normallyemployed in the refining industry for these same fractions. Ascan be seen, the upgraded bio-oil fractions from this study areconsiderably wider in boiling range than their petroleum-derived counterparts; in several cases the T90 point¶ for thebiomass-derived fraction falls outside of the range normallyused for petroleum-derived fractions.

Information on the distillate fractions and elemental analy-sis of the upgraded bio-oil fractions (as defined in Fig. 32) areshown in Table 20. As can be seen, hydrotreating results in agradual shift of the distillate product slate towards lighter frac-tions (naphtha + light ends) with a reduction primarily in thegas oil fraction as hydroprocessing severity increases. For theHOC and MOC oils, an additional 10 wt% of the starting oilcomprised a non-volatile residue. These data also show thatorganic oxygen is concentrated in the lighter distillate frac-tions for the HOC oil, while the opposite trend is found for theMOC oil with organic oxygen concentrated in the heavier

Fig. 32 Actual fraction distillation range in comparison to targets (bysimulated distillation).185 LOC (low oxygen content) = 0.4 wt%. MOC(medium oxygen content) = 4.9 wt%. HOC (high oxygen content) =8.2%.

¶T90 is the temperature at which 90% (by volume) of the fraction has been dis-tilled into overhead products, and is an important characteristic of refineryintermediates.



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fractions. For the LOC oil, the organic carbon content of allfractions was basically the same.

In addition to elemental composition and boiling fractiondistribution, the acidity of the fractions is extremely importantto the refiner. Table 21 presents data on the relationshipbetween acidity and hydroprocessing severity for each distillatefraction obtained from this study.

These acidity data are presented in terms of total acidnumber (TAN) and carboxylic acid number (CAN). The intenthere was to indicate the relative proportion of strong acids (car-boxylic acids) in the TAN, as corrosion issues associated withcarboxylic acids are anticipated to be quite problematic. Asshown in the table, for the HOC oil TAN is still very high andmost of the total acids consist of carboxylic acids, indicatingthat the weak acids (phenolics) have been removed by hydro-treating. At higher hydrotreating severities, the TAN and CANare both significantly reduced.

Data on the chemical compound classifications and hydro-carbon types (PONA) of the lighter distillate fractions as a func-tion of hydrotreating severity are shown in Fig. 33 andTable 22, respectively.

Oxygenated compounds were present in all of the HOC frac-tions represented in Fig. 33. In the light ends and naphthafractions, these were primarily C5, C6 and C7 cyclic and noncyc-lic ketones, esters of C6 and shorter carboxylic acids, methylsubstituted tetrahydrofurans, and aliphatic alcohols. Someacetic acid was present in these fractions. In the jet fraction,oxygenates were primarily methyl- and ethyl-substitutedphenols, with some methoxy phenols and C6 and C7 cyclicketones. Ketones in the jet fraction were less than in thelighter fractions, but phenols were much greater in this frac-tion. The MOC fractions contained much lower levels of oxyge-nates compared to the HOC fractions; detected compoundsconsisted primarily of alkyl phenols and aryl ethers. Fractionsfrom the LOC oil contained no oxygenates in the lights andnaphtha (below detection limits), with a small amount ofalkyl-substitute phenols in the jet fraction.

Table 21 Acidity185 TAN for untreated (raw) oil was approximately 185

HOC MOC LOC

mg KOH g−1 CANa TANb CAN TAN CAN TANLights 102 102 BDc 14 BD BDNaphtha 123 123 BD 100 BD 2Jet 67 154 BD 199 BD 14Diesel 20 20 BD 0.3 0.1 0.1Gasoil 9 9 BD BD 0.4 0.4

a Carboxylic acid number. b Total acid number. c BD = below detectionlimit.

Fig. 33 Chemical composition of the distillate fractions as a function ofhydrotreating severity.185

Table 20 Elemental analysis of boiling range fractions185

Oilsample Fraction

Distillatefraction C H N S O

% w/w % w/w % w/w % w/w ppm % w/w

HOC Lights 5.3 72.8 11.9 0.01 25 14.2Naphtha 19.7 73.7 11.5 0.01 19 14.4Jet 18.7 77.8 11.0 0.03 23 11.9Diesel 17.2 82.4 10.7 0.09 101 7.5Gasoil 30.3 84.6 10.4 0.14 354 5.3

MOC Lights 4.6 85.6 13.6 0.02 8 0.5Naphtha 17.7 84.5 11.9 0.05 8 3.9Jet 23.1 83.9 10.1 0.14 12 6.6Diesel 18.3 85.7 10.2 0.32 21 4.4Gasoil 32.6 87.8 9.9 0.40 116 2.5

LOC Lights 13.9 85.9 14.6 0.01 2 0.3Naphtha 30.2 86.3 13.3 0.02 2 0.3Jet 22.0 87.0 12.3 0.02 12 0.7Diesel 20.6 88.4 11.4 0.02 310 0.5Gasoil 13.5 88.6 11.5 0.03 243 0.4



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Results for the PONA analysis were determined using theaccepted GC method for petroleum, where the content oforganic oxygen is low. The impact of oxygenates on thisanalytical procedure is unknown; accordingly, results for theHOC and MOC fractions should be treated as approximate. Ingeneral, increasing hydroprocessing severity is found todecrease aromatics and increase the amount of paraffins andnaphthenes in the light and naphtha fractions. For the LOCfraction, the data indicate low aromatic content and moderateisoparaffin content leading to the relatively low research (RON)and motor octane numbers (MON) for these fractions.Benzene content in the light and naphtha fractions was foundto be below the limits set by the EPA for motor gasoline in allfractions analyzed.

5.3 Integration of bio-oil in the FCC

The FCC is the single most important unit operation in themodern petroleum refinery that has been optimized for produ-cing motor gasoline; accordingly, a great deal of interest hasbeen focused on investigating production of transportationfuels by processing bio-oil in the FCC – either by itself or as ablend with petroleum-derived gas oil/vacuum gas oil (usuallyknown as co-processing). It has been speculated that decarboxy-lation via FCC could provide a more cost-effective route forproducing transportation fuels from biomass when comparedto deoxygenation by hydroprocessing.186 Further, the FCC is aflexible refinery unit operation that can, in principle, bereadily tuned to accommodate different feedstocks by modify-ing catalysts and/or operating conditions. Several potentiallyviable strategies exist for integrating bio-oil into the fluid cata-lytic cracking unit of an existing petroleum refinery. The workat UOP on co-processing bio-oil in the FCC has been reviewedabove;183 additional co-processing investigations are reviewedbelow.

5.3.1 Co-processing whole bio-oil in the FCC. A simpleand straightforward method for integrating bio-oil into anexisting refinery would be to use whole bio-oil without pre-treatment or fractionation as a blendstock with petroleum-derived GO or VGO and direct feed the blend to the FCC. Inone study, mixtures of model oxygenates (acetone, acetic acid,2-propanol) and iso-octane as a surrogate for gas oil werecracked over an industrial equilibrium catalyst (E-cat) in a

fixed-bed laboratory reactor.187 In general, selectivity to lightgases and olefins was reduced and coke dramatically increasedby adding oxygenates. Blends of model oxygenates such asacetic acid, hydroxyacetone, and phenol with petroleum-derived gas oil were processed under standard FCC conditionsin a lab-scale reactor using both an E-cat and a mixture ofE-cat and ZSM-5.188 In general, adding the model oxygenatesincreased overall conversion; reduced the coke yield; andincreased the yield of fuel gas, LPG, and gasoline. Conversionof the gas oil was not significantly altered. It is worth noting,however, that the model compounds used in many of thesestudies are not within the boiling point range that is typicalfor upgrading in an FCC. A simulated distillation curve for pet-roleum-derived gas oil is shown in Fig. 34, along with boilingpoints for some of the model compounds that have beenemployed. Accordingly, conclusions from model compoundstudies may not be completely relevant when applied to co-processing in the refinery.

Fluid Catalytic Cracking mixtures of petroleum-derived gasoil with whole bio-oil has been reported. Fogassy et al. investi-gated co-processing VGO and whole bio-oil over a standardFCC catalyst, H-Y zeolite, and HZSM-5 in a laboratory reactorand found that introducing bio-oil resulted in lower rates forformation of cracked products except for coke and aro-matics.189 In a laboratory cracking reactor (ACE system), Agble-vor et al.190 were able to produce fuel-range products by co-processing bio-oil with gas oil in a ratio of 15/85 (wt/wt). Theproduct yields were almost identical to that for cracking gas oilalone, and the products were found to contain negligibleamounts of oxygen. Similar results were reported for co-proces-sing a mixture of 10 wt% bio-oil and 90 wt% vacuum gas oilusing an E-Cat in a laboratory ACE system.191 Up to 1500 ppmphenols were found in the liquid products. However, co-pro-cessing 10 wt% bio-oil and 90 wt% vacuum gas oil in a pilot-scale reactor system at Petrobras showed substantial differ-ences in the yields of coke and liquid products and theproducts contained significant organic oxygen content.192

Similar findings were reported by these same researchers

Table 22 PONA analysis of the distillate fractions as a function ofhydrotreating severity185

Vol%

LOC MOC HOC

Lights Naphtha Lights Lights Naphtha

Paraffins 28.3 15.4 13.6 7.9 5.9Isoparaffins 14.9 26.8 25.9 32.8 38.8Naphthenes 51.3 46 47.8 31.8 20.3Aromatics 5.6 11.8 5.2 10.9 27.0Olefins 0.07 0.01 7.54 16.7 8.3Benzene 0.5 0.4 0.6 0.3 0.8RON 64 71 73 79 88MON 61 68 72 77 87

Fig. 34 Example simulated distillation of petroleum gas oil fraction(343–538 °C) compared to model oxygenated compounds used inrecent upgrading studies.165,167



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when cracking a feedstock containing 100% bio-oil in a labora-tory ACE unit.

In an important study, Fogassy et al. investigated partition-ing fossil carbon and biomass-derived carbon in productsfrom co-processing bio-oil with petroleum gas oil. Usingcarbon-14, they were able to determine that both coke andlight gases were richer in 14C than the gasoline from the FCC,suggesting that biomass-derived components react preferen-tially to undesirable products under cat crackingconditions.193

Co-processing whole bio-oil with hydrogen-rich materialsother than petroleum has been studied by Chen et al.194 andChang et al.130 These investigators found that mixing bio-oil (ahydrogen-deficient material with a low EHI) with a hydrogen-rich material (such as methanol) dramatically improved theconversion of bio-oil to hydrocarbons during catalytic crackingin the vapor phase over HZSM-5. They reported that a mixturewith a combined EHI of 1.0 or greater resulted in a greaterthan 300% increase in C5+ hydrocarbon yield accompanied bya 32 wt% reduction in coke-on-catalyst (water-free basis) whencompared to vapor phase cracking of whole bio-oil alone.Petrobras has applied this concept to the catalytic cracking ofpetroleum-derived hydrocarbons with ethanol to produceethylene in high yields.195

Findings from these studies show that whole bio-oil andmodel compounds representing the major oxygenated com-pounds in whole bio-oil produce large amounts of coke andlight gases when processed over acid catalysts typical of thoseused in a conventional FCC unit. Catalyst deactivation wasfound to be rapid, and alkali and alkaline earth metals presentin the whole oil caused severe and irreversible poisoning ofthe catalysts. Other factors, including the acidity and highwater content of whole bio-oil, make whole bio-oil a particu-larly difficult feedstock for the cat cracker. FCC units are gener-ally not made from high alloy steel, and the corrosivity ofwhole bio-oil would present severe operational difficulties.Similarly, the high water content of whole bio-oil is deleteriousto catalyst integrity in the FCC unit. Finally, it is unlikely thatproduction facilities for bio-oil will be able to supply sufficientquantities of product. Typical modern petroleum refineriesprocess upwards of 200 000 barrels per day of crude; a signifi-cant fraction of that amount is fed to the FCC. Single bio-refi-neries based on pyrolysis will initially produce bio-oils at a rateof only about 8000 BBL per D,k which is insufficient to satisfythe demand for the FCC in even one small- to medium-sizedrefinery. Accordingly, integration strategies based on proces-sing whole bio-oil without blending with refinery feedstocksand/or intermediates do not appear to be technically or com-mercially feasible.142 A blend of up to 10 wt% whole(untreated) bio-oil was suggested to be a suitable feed for theFCC unit in a conventional petroleum refinery.188

5.3.2 Co-processing hydrotreated/HDO bio-oil with VGO inthe FCC. Problems associated with co-processing whole bio-oil can be partially addressed by upgrading the whole oil priorto blending with gas oil. Thermal and catalytic hydrotreatingand catalytic hydrodeoxygenation (HDO) of thermal pyrolysisoil have all been investigated as upgrading strategies to reduceacidity and improve properties with respect to co-processing ofbio-oil in the FCC. Both low-severity thermal (e.g., non-cata-lytic) hydrotreating and catalytic hydrotreating have beeninvestigated by Samolada et al.,196 who found that the heavyfraction from thermal hydrotreating could be successfully co-processed with light cycle oil in the FCC. Coke formation wasless than 1%, and gasoline yields of up to 25% were obtainedusing this strategy. Co-processing hydrotreated bio-oil in theFCC has been studied by several investigators.197–199 Using alaboratory FCC system, Mercader et al. found that co-proces-sing HDO bio-oil in the FCC with long residue and light cycleoil produced products that were almost free of organic oxygenwithout excessive coke formation. Fogassy et al. found thatblending HDO bio-oil and VGO at a level as high as 20% gavecomparable yields for the gasoline fraction when compared tocracking VGO alone. A common thread in many of thesestudies is that removing oxygen in the FCC consumes hydro-gen from the hydrocarbon feedstock, resulting in the pro-duction of more olefins and aromatics in the products.

5.4 Other strategies

Co-processing partially upgraded bio-oil produced by catalyticfast pyrolysis (CFP) has been compared to co-processing anHDO bio-oil by Thegarid et al.200 This study showed thatproduct distributions were similar, but that the CFP oil couldeliminate the need for upstream hydrodeoxygenation. Organiccarbon efficiency of the CFP/FCC strategy was found to be sig-nificantly better than the HDO/FCC strategy.

Co-processing upgraded bio-oil in the FCC provides a tech-nical solution to some of the more problematic issues associ-ated with using biomass-derived liquids in the refinery.However, the economics of these strategies are dominated bythe high capital and operating costs associated with hydropro-cessing and hydrodeoxygenation. These costs are present, inpart, because the strategies being employed involve high-sever-ity hydrodeoxygenation and then co-processing the whole bio-oil. This results in high capital costs due to large reactorvolumes and high operating costs due to the high hydrogendemand for hydroprocessing/deoxygenation of the whole oil.A different strategy, which in principle could circumvent someof these problems, is shown below. This scheme involves firstmildly hydrotreating the whole bio-oil to the point where theoil can be distilled followed by fractionation. Hydrotreatingconditions could be adjusted to allow for water removal as aseparate phase during this initial step as mild hydrotreatinghas been shown to be effective in facilitating this separ-ation.150 Depending on their distillation characteristics andboiling range, the bio-derived fractions could then be sent tothe appropriate unit operation in the refinery (e.g., bio-naphtha to the reformer hydrotreater, bio-diesel to the diesel

kAssuming a single bio-refinery processing 2000 metric tons per day ligno-cellulosic biomass.



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hydrotreater) for blending with petroleum-derived materialand further processing into finished fuels (Fig. 35).

In this scheme, high severity hydroprocessing associatedwith the HDO step would be reserved for that fraction of thebio-oil that requires more severe processing to reduce acidityand improve miscibility. This would result in improved hydro-gen utilization efficiency and savings in both capital and oper-ating costs when compared to the whole-oil strategiesdiscussed above.

This strategy of selective hydrotreating also applies whenthe bio-oil is available from CFP. In the context of the schemeshown above, CFP is used to provide a partially upgraded bio-oil that can be fractionated, removing the need for hydrotreat-ing the whole oil prior to fractionation and improving theoverall economics and carbon efficiency accordingly. Con-ditions and catalysts for CFP required to produce a bio-oil thatcan be fractionated have not been widely investigated to date.

5.5 Co-processing in hydrotreaters

Co-processing bio-oil with petroleum-derived materials inhydrotreaters has not been extensively investigated to date. Buiet al.201 investigated co-processing straight-run gas oil withguaiacol as the surrogate for bio-oil in a laboratory hydrode-sulfurization (HDS) reactor using a standard CoMo/Al2O3 HDScatalyst. Their results indicated a competition between HDSand HDO with a decrease in HDS activity under certain con-ditions. Pinheiro et al.202 used model oxygenates blended withstraight-run gas oil (SRGO) to investigate the impact of bio-oilon HDS, HDN, and aromatic ring saturation. These studiesshowed no impact of 2-propanol, cyclopentanone, anisole, andguaiacol on HDS, HDN, or ring saturation; propanoic acid andethyldecanoate were found to inhibit all three hydrotreatingfunctions. In a separate study,203 these same investigatorsfound that CO and CO2 formed during hydroprocessing alsoinhibited HDS and HDN for hydrotreating SRGO. One of thefew studies of co-processing authentic bio-oil with petroleum-derived material in a hydrotreater was conducted by Mercaderet al.204 These investigators processed HDO bio-oil with SRGOunder typical HDS conditions and also found competitionbetween HDS and HDO; the product from co-processing con-tained substantially higher levels of sulfur when compared toHDS of the SRGO alone. However, catalyst activity for HDS wasnot reduced by co-processing with bio-oil as indicated by a

return to the original low sulfur levels in the product when thebio-derived material was removed from the feed. Productyields were the same for SRGO and when SRGO was co-processed with bio-oil.

5.6 Co-processing in other refinery unit operations

While the literature for co-processing in the FCC is substantial,there is limited information in the open literature on co-pro-cessing biomass-derived materials with petroleum-derivedmaterials in other standard refinery unit operations. Studieson co-processing in the FCC and FCC hydrotreater are citedabove, but similar investigations for co-processing bio-naphthawith petroleum naphtha in the naphtha hydrotreater (forexample) are missing. Fully integrating bio-oil in the refinerywill require an understanding of the impact of bio-derivedmaterials on all refining unit operations and the productsfrom these unit operations including the naphtha hydro-treater/reformer, the diesel hydrotreater, the hydrocracker, andthe coker. This information needs to be developed and disse-minated to fully inform efforts to integrate bio-oil into conven-tional petroleum refineries.

6. Biomass-derived oxygenates infinished fuels

Because of the high oxygen content of bio-oils, there is astrong economic incentive to leave much of this oxygen in thefinished fuel product to the extent that government regulationsand product quality standards will allow. As shown150 by Arbo-gast, hydrotreating costs are significant for reducing oxygencontent to the 2 wt% to 3 wt% range. These costs increaseexponentially as the oxygen content goes below approximately2 wt%. Here we examine what is known about the potential foroxygenates in bio-oil to be components of drop-in-fuels.

As described above, the three components of biomass(cellulose, hemicellulose, and lignin) produce different oxyge-nated products during pyrolysis. Cellulose and hemicelluloseform low molecular weight (C4 and smaller) ketones, alde-hydes, acids, esters, ethers, and alcohols that cannot easily bedirectly incorporated into gasoline. Hydrogenation of thesecompounds leads to low molecular weight hydrocarbons,suggesting that some form of oligomerization to increasemolecular weight is necessary if this bio-derived carbon is tobe incorporated into fuel. Cellulose and hemicellulose canalso produce furanic compounds such as furfural, furfurylalcohol, and furoic acid that, upon hydrogenation, can yieldmethyl furans because of the relative recalcitrance of the furanring structure.205 Sugars and anhydrosugars have also beenobserved in the pyrolysis products, with hydrogenation produ-cing 5- and 6-carbon alcohols. Pyrolysis of lignin, on the otherhand, produces phenols and alkyl phenols, methyl aryl ethers,and guiacols. Ethers are generally converted to phenolics byhydrotreating at adequately severe conditions.

The actual oxygenate composition of an upgraded pyrolysisoil is highly dependent upon the degree of

Fig. 35 Alternate hydroprocessing schemes.



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hydroprocessing.152,185 Hydroprocessing to 8 wt% to 10 wt%oxygen yields distillate fractions containing carboxylic acids,carbonyls, phenols, and ethers. Increasing the hydroproces-sing severity eliminates carbonyl and carboxyl compounds andconverts aryl ethers to phenols, consistent with model com-pound studies.205 The oxygen present also varies with distillatefraction. At roughly 8 wt% to 10 wt% oxygen the light andnaphtha fractions will primarily contain carbonyl, carboxyl,and ether groups. The jet and diesel fractions will containthese functional groups at lower levels, but will also containphenolic compounds. Upgrading further, under more severeconditions, to roughly 5% oxygen leads to fractions containingalmost exclusively phenolic compounds.

6.1 Properties of biomass-derived oxygenates

Certain oxygen functional groups present in pyrolysis oils areunlikely to be acceptable in fuel products. While carboxylicacids are used in fuels as corrosion inhibitors at very lowlevels,206 at higher levels they cause corrosion and are poten-tially poorly soluble in hydrocarbons at cold temperatures.Aldehydes and ketones may undergo condensation reactionsleading to the formation of gums, although there do notappear to be published studies showing this occurring. Esters,ethers, and alcohols have all been used successfully in fuels(biodiesel, MTBE, and ethanol, respectively) – with the caveatthat MTBE’s poor biodegradability in ground water ultimatelyled to its removal from the US market.207

Table 23 shows property data for a number of oxygenatedcompounds that have been observed in raw and upgradedpyrolysis oils. For gasoline, the boiling point must be betweenabout 25 °C and the 225 °C end point limit in standard specifi-cations (ASTM D4814). Additionally, the 90% volume boilingpoint is limited to 185 °C or 190 °C, depending on volatilityclass (time of year). Therefore, only limited amounts of com-pounds boiling above about 185 °C can be blended. Examin-ation of the data in Table 23 indicates that the furans, as wellas anisole and methyl anisole boil in the acceptable range,and also have high octane number and very low water solubi-lity. Christensen and coworkers208 describe the properties ofdimethyl furan and 2-methyl furan blends with gasoline; andthese oxygenates have many desirable properties, includinglittle effect on vapor pressure. Singerman described the use ofmethyl aryl ethers as gasoline blend components in the early1980s.209 Methyl aryl ethers improved octane number withoutdegrading other gasoline properties. These molecules may beviable gasoline blending components if all regulatory require-ments described below can be met. An important caveat is thatgasoline aromatics have been linked to fine particle emissionsfor emerging gasoline direct-injection engines210 and to theformation of secondary organic aerosol in the atmosphere.211

Both types of fine particles have been shown to have negativehealth effects, suggesting that environmental regulators couldlimit the allowable levels of aromatics in gasoline in thefuture. For example, the United States Environmental Protec-tion Agency currently limits benzene in gasoline to an averageof 0.62 vol%, not to exceed a maximum of 1.30 vol%.212 It is

unknown if furans or aryl ethers show the same effect onatmospheric fine particles.

Phenol also has a boiling point just in the acceptable range;however, it also has high water solubility, poor solubility inhydrocarbon at cold temperatures, and is corrosive. Otherethers and phenols have boiling points too high to be used ingasoline as blend components, although low residual levels(below roughly 1000 ppm oxygen) may be tolerable.

Diesel fuels boil between either 200 °C and 350 °C (no.2 grade) or 145 °C to 300 °C (no. 1 grade). No. 1 grade orblends of no. 1 and no. 2 are used predominantly in coldclimate, wintertime environments. Thus, the oxygenates inTable 23 that boil at too high a temperature for use in gasolinecould be used in diesel fuels based on boiling point. Addition-ally, as C/O ratio increases, the phenolics become less solublein water and more soluble in hydrocarbon. However, becausethese oxygenates are all aromatic compounds, they have a verylow cetane number, significantly limiting the amount thatcould be economically blended. Their impact on precipitateformation at cold temperatures is also unknown. Potentially,these oxygenates could be tolerated in diesel fuels as residualcomponents up to an oxygen content of roughly 1000 ppm.Very little research has been published on the potential forbiomass-derived oxygenates to be present in fuels at these lowlevels.

Jet engine fuels boil between 180 °C and 300 °C, and have afreezing point below −40 °C. However, quality standards andregulatory requirements for jet engine fuels are necessarilymore strict. Jet engines require clean, low soot formation com-bustion and so the sooting tendency of jet fuels (measured assmoke number) is limited in ASTM standard D1655. The pres-ence of aromatic compounds can lead to high sooting ten-dency, and so the standard also limits aromatics to 25 vol%.Oxygenated compounds other than specifically approved fueladditives are not permitted. Given these requirements, pyro-lysis oil components will need to be fully hydrogenated toalkanes before their use in jet fuel could be considered.

6.2 Regulatory and commercial requirements

New transportation fuels cannot simply be produced and thenintroduced into the fuel market place. In the United Statesthere are many federal and state regulatory, commercial, andconsequent testing requirements that must be met. The exactrequirements will depend on the chemical makeup of the newfuel. If it is demonstrably hydrocarbon (primarily hydrogenand carbon with less than perhaps 1000 ppm of sulfur, nitro-gen, and oxygen), then requirements for market introductionare likely to be less than if the fuel is an oxygenate (such asethanol, butanol, or biodiesel).

Clean air act. Compliance with the Act is mandatory andhas two aspects. First, the new fuel must meet the require-ments for gasoline or diesel fuel that the EPA has already putin place through rulemaking, such as limits on sulfur contentof diesel and gasoline, or vapor pressure of gasoline. Second,and more importantly, new fuels have to meet the fuel



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Table 23 Properties of model biomass derived oxygenates

Compound class/name Molecular structureResearch and motoroctane numbers

Boilingpoint (°C)

Solubility in waterat 20 °C (wt%)

Solubility inhydrocarbon

Furans2,5-Dimethylfuran 153, 109 94 0.26 Miscible

2-Methylfuran 155, 92 65 0.3 Miscible

EthersAnisole Unknown 154 Insoluble Miscible

4-Methylanisole 166, 148 174 Insoluble Miscible

1,2 dimethoxybenzene(veratrole)

Unknown 206 Insoluble Miscible

Propylanisole Unknown 215 Insoluble Miscible

PhenolsPhenol Unknown 181.7 8.3 Soluble,

not miscible

p-Cresol 153, 149 202 1.9 Miscible

2,4-Xylenol 140, 113 211 0.5 Miscible

Guaiacol Unknown 205 1.7 Soluble,not miscible

Syringol Unknown 261 1.7 Soluble,not miscible

4-Propylphenol Unknown 232 Insoluble Miscible

4-Propylguiacol Unknown 250 Insoluble Miscible



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registration requirements of Section 211b of the Clean Air Act,as implemented in CFR 40 Part 79. These consist of formalregistration with EPA, which includes divulging the compo-sition of the new fuel, and different levels of emission andanimal exposure testing, depending on the fuel. Additionally,if new fuels are to be used in existing engines designed forgasoline or diesel, the EPA will require demonstration that theemissions performance of existing engines/vehicles is notdegraded for the full useful life of the engine/vehicle(190 000 km for a car, as much as 700 000 km for a heavy dutytruck). Potentially, this could involve testing many vehicles (forexample, testing to support EPA in dealing with the E15 waiverpetition involved testing of at least 80 vehicles).

Commercial acceptance (ASTM standard ). Because most, ifnot all, new fuels will be blended with petroleum fuels and uti-lized in existing engines, acceptance of the new fuel by the pet-roleum and auto/engine industries is critical. If the petroleumdistribution industry refuses to distribute the blended fuelbecause they are uncomfortable handling it for safety orenvironmental reasons, because it cannot be obtained withconsistent quality, or because they feel they accept too muchliability for engine operating problems, then the new fuel willnot be distributed. While these requirements are not directlylegislated, they are an important aspect of consumer protec-tion. Primarily, this involves developing data to show that thenew material can be safely handled and that it is compatiblewith existing engines and vehicles. This compatibility isdifferent than the emission performance mandated by theClean Air Act. The primary way that this is accomplished isthrough development of an ASTM specification for the newfuel, which may take the form of a blendstock specification(such as exists for ethanol and biodiesel), adding the new fuelto existing specifications (such as those for gasoline or dieselfuel), or a new specification for a blended fuel (such as that forB6 to B20 blends). ASTM specification development requiresdata on a variety of issues, and what testing must be done ulti-mately depends on the properties of the new fuel. But itshould be clear that this is a non-trivial requirement and maytake 2 to 5 years to complete.

Approval of tanks and dispensers for use with new fuel. In theUnited States, underground storage tanks are regulated by theEPA, which requires tanks to be compatible with the liquidbeing stored. This can be demonstrated via testing at a third-party laboratory such as Underwriters Laboratories (UL) or bywarranty approval from the tank manufacturer. Local officials,such as fire marshals, regulate the dispensing and handling offuels. These officials are known as Authorities Having Jurisdic-tion or AHJs. These officials require that equipment (fueltanks, piping, pumps, fuel dispensers, hoses, and nozzles) belisted by a third party organization as being safe for use withthe fluid being handled or be covered under warranty for usewith the new fuel. In most cases this means that the equip-ment has been listed by UL for use with the fuel in question.UL develops test methods and aggressive test fluids to ensurethat equipment passing their tests will be safe for use with thedesignated fluid. For a new fuel a UL test fluid will likely not

exist. Development of test methods, fluids, and performancetesting of equipment can take several years.

7. Summary

Introducing biomass pyrolysis oils into existing petroleum refi-neries offers an opportunity facilitate the introduction of ligno-cellulosic bio-oils for production of renewable biofuels. Asdescribed in this perspective, raw pyrolysis oils have physicaland chemical properties that make direct insertion into refin-ery unit operations difficult. Dilution with petroleum streamsis not feasible because of the poor miscibility of pyrolysis oiland distillation is not practical because of its reactivity. Thus,it is highly likely that upgrading will be necessary before theoils can be introduced.

There are several options available for upgrading pyrolysisoils, some of which are described above. Generally, theseapproaches involve upgrading the condensed oil or the pyro-lysis vapors before they are condensed. In this context, theappropriate upgrading strategy will depend upon the chemicaland physical properties of the resulting oil, where the oil isintroduced and ultimately the profitability for the refinery.

As shown in this perspective, there is great need for furtherresearch in this area. While some studies have been publishedin this area more work is needed to evaluate and comparedifferent upgrading and integration strategies. Any researchprogram in this area should also include a fundamental under-standing of the how the upgrading process affects the physico-chemical properties of the resulting oil and how this in turninfluences how the material can be inserted into the pet-roleum refinery with minimal impact on existing unit oper-ations. Research should also include a detailed understandingof ultimate cost of the upgraded oil and the effects on refineryprofitability.

Acknowledgements

We acknowledge funding from the National Advanced BiofuelsConsortium, funded by the US Department of Energy (DOE)BioEnergy Technologies Office (BETO) through Recovery ActFunds and the US DOE BETO program that supported thiseffort. We would like to thank researchers at BP for stimulatingconversations in this area.

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2 T. Werpy and G. Petersen, Top Value Added Chemicals fromBiomass: Volume I–Results of Screening for Potential Candi-dates from Sugars and Synthesis Gas, U.S. Department ofEnergy, 2004, 1–76.



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A Perspective on Oxygenated Species in the Refinery Integration of Pyrolysis Oil

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