ARTICLE IN PRESS

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Energy 32 (2007) 1075–1092

www.elsevier.com/locate/energy

Fuel specification, energy consumption and CO2

emission in oil refineries

Alexandre Szklo, Roberto Schaeffer�

Energy Planning Program, Graduate School of Engineering, Federal University of Rio de Janeiro, 21.941-972 Cidade Universitaria,

Ilha do Fundao, Centro de Tecnologia, Bloco C, Sala C-211, Caixa Postal 68565, Rio de Janeiro, RJ, Brazil

Received 17 May 2006

Abstract

The more stringent environmental quality specifications for oil products worldwide are tending to step up energy use and,

consequently, CO2 emissions at refineries. In Brazil, for example, the stipulated reduction in the sulfur content of diesel and gasoline

between 2002 and 2009 should increase the energy use of Brazil’s refining industry by around 30%, with effects on its CO2 emissions.

Thus, the world refining industry must deal with trade-offs between emissions of pollutants with local impacts (due to fuel specifications)

and emissions of pollutants with global impacts (due to the increased energy use at refineries to remove contaminants from oil products).

Two promising technology options for refineries could ease this clash in the near-to-mid term: the reduction per se of the energy use at

the refinery; and the development of treatment processes using non-hydrogen consuming techniques. For instance, in Brazilian refineries,

the expanded energy use resulting from severe hydrotreatment to comply with the more stringent specifications of oil products may be

almost completely offset by energy saving options and alternative desulfurization techniques, if barriers to invest in technological

innovations are overcome.

r 2006 Elsevier Ltd. All rights reserved.

Keywords: Oil refining; Fuel specifications; Energy use; Treatment processes; Brazil

1. Introduction

Part of the technological development of the oil refiningindustry worldwide is justified by the fact that this is anindustrial activity with high fossil fuel consumption andconsequently high CO2 emissions. Oil refining processes areenergy-intensive, requiring considerable amounts of director indirect heat. Between 7% and 15% of the crude oilinput is used by the refinery processes.1

e front matter r 2006 Elsevier Ltd. All rights reserved.

ergy.2006.08.008

ing author. Tel.: +55 21 2562 8760; fax: +55 21 2562 8777.

ess: roberto@ppe.ufrj.br (R. Schaeffer).

, the two largest Dutch refineries in 1995 posted energy use

ude oil feedstock [1]. There are refineries in the USA with

almost 15% of the crude oil processed (EIA/DOE [2]).

ent years, energy use in US refineries has been virtually

between 9% and 10% of the crude oil processed [3,4]. In

l energy use was 3191PJ, and primary energy use was

he difference between primary and final electricity

s relatively low due to the small share of electricity

the refinery and relatively large amount of self-produced

This situation is worsened by the more restrictiveenvironmental quality requirements for oil products2 andthe shift towards low-grade crude oils in the world refiningindustry.3 These two factors increase the energy use atrefineries. This increase depends on the type of refinery, interms of conversion capacity, the feedstock processed andthe mix of products obtained. It also varies widely, with aconsiderable order of magnitude. For instance, it isestimated that the total amount of crude oil processed byUS refineries increased, on average, some 5%, merely tocomply with the diesel and gasoline stricterspecifications

2For a detailed discussion of fuel quality specifications worldwide and in

Brazil, see Faiz et al [5], Guru et al. [6], Yamaguchi et al. [7], Junior [8],

Carvalho [9], Tavares [10], Plantenga and Leliveld [11], Song [12] and

Brunet et al. [13].3Refineries are facing many challenges, e.g. increased fuel quality

demands, heavier crude feeds and changing product mix, increasing and

more volatile energy prices, need to reduce air pollutant emissions,

increased pressure on profitability, and increased safety demands. These

challenges will affect the industry and technology choice profoundly [14].

ARTICLE IN PRESS

6From the standpoint of Integrated Energy Planning, demand-side

A. Szklo, R. Schaeffer / Energy 32 (2007) 1075–10921076

imposed in the USA at the start of the 1990s [15]. Thisproblem is so worthwhile that Shell, for example, assignedthe 18MtC increase in its carbon emissions in 2003(compared to 2002) specifically to adapting its refineriesfor the production of oil products with lower sulfur content[16].

Moreover, stringent environmental quality specificationsstipulated for oil products, particularly diesel and gasoline,affect other specifications for these oil products, unrelatedto the environment, such as the diesel lubricity4 and thegasoline octane number. Actually, FCC gasoline is by farthe most important sulfur contributor in gasoline, up to85–95% [13]. However, FCC gasoline contains also a greatquantity of olefins (20–40wt%), which provides it with afairly good octane number. Therefore, the challenge is toeliminate a maximum of the sulfur impurities with aminimum olefin saturation [13]. Nevertheless, hydrotreat-ing FCC gasoline through a conventional process wouldlead to a significant octane loss.

In addition, stricter environmental quality requirementsfragment the oil products market, creating boutique fuels

[17], and reduce supply efficiency, associated with theshipment, storage and distribution of oil products (theability to combine, sequence, and ship batches of similarproducts together is a key contributor to the reliability ofthe oil products distribution system). As each refinery isunique in terms of feedstock, products and processes,stricter environmental constraints tend to curtail the supplyflexibility of oil products distribution systems. For in-stance, markets that are heavily dependent on imported oilproducts become less flexible, such as the US market forgasoline (and diesel, to an increasingly extent), as well asthe European diesel market.5

The world refining industry faces challenges associatedwith the trade-off between pollutant emissions with localimpacts and pollutant emissions with global impacts,derived from the production and use of oil products(including oil refinery emissions and oil products combus-tion). In practical terms, this trade-off consists of the factthat the production of diesel or gasoline with extremely lowsulfur contents normally requires more energy. Conse-quently, the production of ‘‘cleaner’’ gasoline and diesel, interms of sulfur content, results in higher energy consump-tion and higher emissions of carbon dioxide (CO2), agreenhouse gas, by refineries.

Therefore, more stringent sulfur specifications imposechallenges to oil refiners, but also drive technical innova-tion [11,19, 20]. Deep reduction of gasoline and dieselsulfur must be made without compromising their quality(e.g., gasoline octane number, diesel lubricity); losing dieseland gasoline yields must also be avoided by treating units

4Additives are often used (fatty acids or esters) to increase the lubricity

of diesel with extremely low sulfur contents (or severely hydrotreated, or

Ultra Low Sulfur Diesel). These additives contain a polar group attracted

by metal surfaces, forming a fine lubricating layer.5On this matter, see Hackworth and Shore [18].

[12]; and the treating units must not increase energy useand CO2 emissions of refineries.In order to deal with these challenges, through supply-

side actions,6 there are three promising technologicalalternatives for refineries:

(a)

actio

by t

but7O8I

affec

lubr

alternatives for saving energy at refineries;

(b) less severe or non-conventional treatment process

alternatives (replacing severe hydrotreating); and

(c) oil gasification and the removal of CO2 at the refinery.

The first two options could be implemented in the nearmedium terms, while the last option would require furthertechnology development and construction of new facilitiesbefore implementation would be possible.There is also a feasible alternative outside oil refining

processes, which is the formulation of the oil products withnon-oil products components (and/or additives) havinglow or even nil contaminant content levels. For sulfur andaromatics, this would involve the blending of refiningproducts with biofuel, particularly ethanol for gasoline7

and biodiesel for diesel8 and/or with synthetic fuelsproduced through the Fischer-Tropsch route—for in-stance, based on natural gas using the gas-to-liquids(GTL) route.However, this paper emphasizes alternatives directly

related to oil refining (or undertaken inside refineries). Theanalysis focuses also on the two first alternatives mentionedabove, for the near to medium terms (alternatives (a) and(b)), since a detailed discussion of the alternative (c) may befound in Szklo and Schaeffer [21].Section 2 of this paper describes the energy use in oil

refineries. Section 3 discusses the conventional options forspecifying oil products in oil refineries, highlighting thecase of diesel and gasoline. Section 4 estimates the increasein energy use and CO2 emissions at the Brazilian refiningsector, due to its actual sulfur reduction program for dieseland gasoline. Through the Brazilian example, this estimateshows the need to seek technological alternatives to thetrade-off between local emissions of atmospheric pollutants(due to fuel specifications) and emissions of greenhousegases by oil refineries (due to the expanded use of energyresulting from the operation of severe hydrotreatmentunits). Sections 5 (energy savings options) and 6 (alter-native desulfurization techniques) propose and estimate theimpact on energy savings (and consequently on CO2

emissions) of technical alternatives for saving energy orremoving sulfur in oil refineries. This analysis is carried outfor the near to medium terms, assuming that there will be

ns (energy policies associated with lower consumption of oil products

he transportation sector, for instance) will probably be effective here,

their analysis is outside the scope of this paper.

r ETBE, based on ethanol.

t is also possible to add ethanol to diesel. However, this significantly

ts important properties of the diesel, such as its cetane number,

icity, volatility, ignition temperature and stability.

ARTICLE IN PRESS

Table 1

Energy use by refining process units (MJ/b)

Minimum Maximum

Atmospheric distillation 90 200

Vacuum distillation 50 120

Visbreaking 100 150

Delayed coking 120 250

Fluidized catalytic cracking (FCC) 50 180

Hydrocracking (HCC) 170 340

Hydrotreating 60 180

Catalytic reform 220 360

Alkylation by H2SO4 350 360

Alkylation by HF 430 430

Etherification 310 600

Isomerization through isobutane 360 360

Isomerization through isopentane 100 250

Isomerization through Isobutylene 480 480

Lube-oils production 1500 1500

Notes: Average values based on Energetics [23]. This consumption

includes power generation losses, based on a heat rate of 10,500BTU/

kWh (or First Law Efficiency of 32.5%, which is compatible with the co-

generation power plants found at refineries).

A. Szklo, R. Schaeffer / Energy 32 (2007) 1075–1092 1077

no drastic changes in the finished products blending andrefining processes. Finally, Section 7 presents the finalremarks of the paper, focusing on the results of theBrazilian case and the barriers faced by refiners in Braziland worldwide to invest in the technical innovationsanalyzed in this paper.

2. Energy use at oil refineries

Heat and electricity are used by refineries, with heatoutstripping electricity. Heat is used directly (in thefurnaces) or indirectly (as steam). Meanwhile, electricitymay be supplied partially by co-generation plants.9

The fuel required to produce steam and electricity comesmainly from process wastes: refinery gas, residual fuel oils(fuel oil, vacuum wastes and asphalt wastes) and FCCcoke. However, the composition and quality of the energysources consumed by a refinery vary considerably. More-over, the set of fuels used by a refinery is the outcome of thebalance between the energy required by the processes, thetypes of crude processed, the current constraints onemissions and economic analyses.

In general, refinery processes are energy-intensive. Themost intensive process (in terms of energy demands perbarrel processed) is the production of lube-oils, which takesplace in only a few refineries (some 1500MJ/b).10 Otherprocesses with high specific energy use include etherifica-tion (production of MTBE and TAME), alkylation andisomerization (Table 1). However, once again, the produc-tion of MTBE and the alkylation and isomerization unitsare found merely at refineries focused on higher-gradegasoline. In other words, these energy-intensive processes(in terms of energy use by processed feed) are not the mainunits using energy in the world refining industry, becausetheir feed are not significant, in terms of volume processed.

Thus, in absolute terms, the energy use of a refinery isconcentrated in a few processes that are not the mostenergy-intensive (in terms of energy use per barrel), butinstead process large volumes of feedstock. The Vacuumand Atmospheric Distillation plants usually total 35–45%of the energy use of a refinery [24], because any barrel of oilentering a refinery runs through the topping separationunits. This same reasoning explains why, in advancedrefining industries having considerable conversion capacityand focused on fuels with low contaminant content levels,hydrotreatment units post considerable energy use, inabsolute terms.11 These plants pre-treat catalytic processfeeds and enhance the quality of the finished products.

In addition, more complex refineries tend to be larger(processing more crude oil) with more energy-intensive

9This is the case with some Brazilian refineries such as REDUC, which

generated 373 GWh in 2003, with an installed capacity of 63.3 MW, with

natural gas accounting for 49% of this power generation, while refinery

gas accounted for 15%, fuel oil for 23% and FCC coke for 13% [22].10Particularly in view of the energy use associated with solvent recycling.11For example, these plants accounted for 19% of energy use in US

refineries in 1996 [24]. In 2001, this proportion rose to 24% [3].

units. However, there are small low-complexity re-fineries with high CO2 emissions, because they operatewith less-efficient processes in terms of energy use andselectiveness.An analysis of European refineries is quite explanatory,

showing that there are refineries with the same NelsonIndex,12 but with very different specific CO2 emissions(emissions per feedstock processed). For instance, thespecific CO2 emissions of European refineries with lowconversion capacities (Nelson Index equal to 2) vary from250 to 550 ktCO2/Mt of crude, while, for refineries withhigher conversion capacities (Nelson Index equal to 8),there is a range between 200 and 350 ktCO2/Mt of crude[25].Nevertheless, it is possible to infer from the European

refining data that the more complex refineries have higherspecific CO2 emissions on average than the less complexones. However, the standard deviation in the specific CO2

emissions by less complex refineries is higher. Thus, theincrease in energy use (and consequently specific CO2

emissions) by more complex refineries is due solely to theirhigher conversion and treatment capacities. For the lesscomplex refineries, higher energy use and CO2 emissionsmay also be associated with inefficiencies in their produc-tion processes.

12The Nelson Complexity Index is a measure of secondary conversion

capacity in comparison to the primary distillation capacity of any refinery.

This index was originally developed by Wilbur L. Nelson in 1960 to

quantify the relative costs of the components that constitute the refinery.

Nelson assigned a factor of one to the primary distillation unit. All other

units are rated in terms of their costs relative to the primary distillation

unit also known as the atmospheric distillation unit.

ARTICLE IN PRESSA. Szklo, R. Schaeffer / Energy 32 (2007) 1075–10921078

3. Hydrotreatment and blending for diesel and gasoline

specifications

The quality specifications for oil products at a refineryare conventionally achieved through hydrotreatment(HDT) units for intermediate and finished products andthrough blending for finished products. The severity levelsof the HDT process determine the final product specifica-tion. Mild HDT is normally used to remove sulfur andolefins. More severe HDT additionally removes nitrogencompounds, higher sulfur compound content and aromaticrings. The HDT process catalysts are selective for removingsulfur and nitrogen compounds, and metals and or othercontaminants [26]. For example, diesel hydrotreatmentinvolves the desulfurization and hydrogenation of insatu-rates (olefins and aromatics), in order to increase the dieselcetane number [27]. Severe hydrodesulfurization of thediesel aims at obtaining low sulfur content levels (8 ppm),in addition to fuel stabilization (operation at low pressuresof around 45 bar).

The blending operation is complex. It is designed tocomply with technical and economic refining constraints,which encompass different and not always harmoniousfinished products specifications. Actually, the diesel andgasoline specifications13 have different attributes, whosevalues are nationally or regionally defined, according tothe regulations stipulated for each marketplace, but thattend to converge to some extent in major consumermarkets (particularly Western Europe and North Amer-ica). This convergence affects the global oil productsmarket, because Western Europe is the main diesel importzone and USA is the main import zone for gasoline andgasoline blending components [14]. Thus, diesel andgasoline specifications tend to converge in the globalrefining segment as follows:

1. Impose constraints on the sulfur content of both oil

products: This initially involves the challenge of boostingdesulfurization capacity (HDS), which steps up the energyuse at refineries. Depending on its severity, the hydrotreat-ment process energy use varies between 60 and 180MJ/b[23]. These processes also require hydrogen, between 50and 350Nm3/m3, depending on the HDS feed [25], whichresults in a higher hydrogen production at the refinery, andconsequently another energy use increase. For example,steam reform of natural gas to produce hydrogen requires aconsumption of around 50GJ/tH2 [29]. An alternative (orsometimes complementary) option to HDS is to blend thefeedstock entering the refinery, favoring sweeter crudes.However, these crudes have a price-premium compared tothe sourer crudes, requiring a balance between the fixedcosts (represented by the increase in the HDS capacity) andthe variable costs (represented by the sweet oil price-premium), in order to define the best possible strategy forreducing the sulfur content of the oil products.

13This Section focuses on the analysis of gasoline and diesel, which are

the main products of the world refining industry [14].

2. Increase gasoline octane number: The technologicaloptions most commonly used include boosting the capacityof the following processing units: catalytic reform (how-ever, to the detriment of increasing the aromatics contentsof the gasoline), FCC, alkylation and isomerization.Additives may also be used, such as ethers (for example,MTBE) and organic alcohols (ethanol).

3. Reduce the Reid vapor pressure (RVP) of the gasoline

(reduction of evaporative emissions): The usual procedure isto adjust the final gasoline blending through its compo-nents and additives. For example, the debutanization of thegasoline reduces its vapor pressure. However, the removalof butane from the gasoline also lowers its octane numberand steps up its sulfur content (per barrel o gasoline). Theaddition of ethanol to gasoline affects its Reid vaporpressure, compared to the increase that occurs with MTBE.This may impose constraints on the amount of ethanol thatmay be added to gasoline [30].

4. Increase the cetane number of the diesel: The cetanenumber of the diesel may be increased through boostingthe HDT capacity, including HDA, and the hydrocracking(HCC) capacity, depending on the characteristics of thefeedstock. There are additives that boost the cetanenumber [6]. These compounds, frequently organic nitrates,improve cold-start performance, reduce combustion noise,and may reduce particulate matter (PM) emissions.However, at the same time, cetane boosters increase theflammability of the fuel, are potentially more hazardousdue to ultrafine particle emissions, and degrade the storagestability of the fuel [27]. Finally, the cetane number mayalso be increased through redefining the diesel blending, forinstance, by removing the FCC cycle oil from it (mainlydue to its high aromatic content). However, this poses atrade-off between the diesel refining yield (quantity) andthe specifications of this oil product (quality). Ceteris

paribus, by limiting the diesel pool to higher-gradecomponents, the refinery will produce smaller amounts ofdiesel.

5. Reduce diesel smoke and the emission of particulates:This reduction may be achieved through careful blendingof the diesel, for instance by lowering the T9514 andremoving the FCC cycle oil from the diesel pool. Onceagain, this requires a trade-off between the quantitativeoutput and the grade of the diesel produced by the refinery.

6. Lower the aromatics content of gasoline and diesel:Normally, it involves the reduction in the use of catalyticreform units [21], increasing, for example, the use of thealkylation process to produce high-octane gasoline. Fordiesel, and even for gasoline, this may also be achievedthrough wider use of HCC units, which, in the case ofdiesel, also increase the cetane number, while lowering theoctane number of gasoline. For treatment, the hydrodear-omatization units (HDA) are particularly noteworthy.In sum, the use of HCC and HDT units and modifica-

tions of the gasoline and diesel blends are the most

14Temperature at which 95% of diesel is distilled.

ARTICLE IN PRESS

Table 2

Gasoline components and quality specifications

High octane rating? Low RVP? Low olefins content? Low benzene? Low aromatics? Low sulfur content?

(RON+MON)/2489.5 (o7) (o14% vol) (o1% vol) (o35%vol) (o150 ppm)

Basic blend

Butanes YES NO YES YES YES YES

Alkylates YES YES YES YES YES YES

Isopentane YES NO YES YES YES YES

Isomers NO YES YES YES YES YES

Light FCC Naphtha YES NO NO NO NO DEPENDS(2)

Heavy FCC Naphtha NO YES DEPENDS YES NO DEPENDS

Reformed YES YES YES NO NO YES

HCC Naphtha NO NO YES YES YES YES

Straight-run gasoline NO DEPENDS YES YES YES DEPENDS

Additives

MTBE YES NO YES YES YES YES

Ethanol YES NO(1) YES YES YES YES

Notes: (1) the effect of the ethanol on the gasoline RVP is greater than that of the MTBE. (2) ‘‘DEPENDS’’ means that it ‘‘DEPENDS on the feedstock of

the unit. Source: Based on Yamaguchi et al. [7].

Table 3

Diesel components and quality specifications

High cetane number? Low sulfur content? Ultra low sulfur diesel? Low aromatics?

(450) (o0.05% weight) (o0.005% weight) (o20% vol)

HCC diesel YES YES YES YES

Light cycle oil (LCO) NO NO NO NO

Straight-run diesel DEPENDS on the load

Diesel HDS mild YES YES DEPENDS on the load

Severe HDS Diesel YES YES NORMALLY NORMALLY

HDA diesel (1) YES YES YES YES

Notes: (1) Hydrodearomatization (HDA) is a high-energy-intensive process that, in addition to removing sulfur from low-reactive compounds, saturates

the aromatics and consequently increases the diesel cetane number. Source: Based on Yamaguchi et al. [7].

A. Szklo, R. Schaeffer / Energy 32 (2007) 1075–1092 1079

conventional ways for meeting oil products specifications.For the blending process, the gasoline pool has moreoptional components and additives than the diesel pool(Tables 2 and 3). Nevertheless, since FCC gasolinerepresents 30–40% of the total gasoline pool, and is byfar the most important sulfur contributor in gasoline, up to85–95% [13],15 merely altering the blend of the gasolinepool does not solve the issue of deeply removing sulfurfrom it.16

15The most important class of sulfur compounds present in FCC

gasoline is made of thiophene and its light alkyl derivatives in addition to

benzothiophene. Most of the sulfur impurities present in FCC gasoline

(mainly thiophene and short alkyl chain thiophenes) are not present in the

FCC feedstocks. Therefore, several possibilities (in fact two main routes a

priori) have to be considered to account for the formation of the ‘‘organic

sulfur compounds’’ of the gasoline boiling range during the FCC process.16Commercial gasoline is made up of different fractions coming from

reforming, isomerization and FCC units. Those coming from the

reforming and isomerization units are produced from distillation cuts,

and consequently contain little or no sulfur because the sulfur containing

compounds present in crude petroleum have high boiling points and the

feedstocks used in the isomerization and reforming units are hydrotreated.

On the opposite, the atmospheric residues or the vacuum distillates which

constitute FCC feedstocks contain significant amounts of sulfur,

0.5–1.5wt% [13].

Therefore, Ceteris paribus, there is an even balancebetween the oil product grade and quantity at the refinery.A more tightly specified pool of an oil product is made upof fewer refinery streams. For example, if the purpose ofthe refiner is to produce lower grade diesel (in largerquantities) the pool of this oil product may be equal to thesum of the following intermediate streams: straight-rundiesel, HCC diesel (if HCC installed), HDT diesel (mild orsevere), FCC LCO,17 and a fraction of the kerosene cut.However, if the purpose is instead to produce ultra lowsulfur diesel (ULSD),18 the pool should be based on HCCdiesel, diesel severely hydrotreated, and a kerosene fractionspecified for the diesel pool and hydrotreated [7].

4. Trade-off between sulfur content and CO2 emissions—

Brazil’s refining case study

Having analyzed the energy use by refineries (Section 2)and the conventional specification alternatives for key oilproducts (diesel and gasoline) in Section 3, it is possiblenow to move on to the problem of the trade-off between

17Light cycle oil.18Diesel with a sulfur content of below 15ppm.

ARTICLE IN PRESS

Table 4

Quality specifications requirements for Brazilian diesel (2002–2009)

2002 2005 2009

Metropolitan diesel Rural diesel Metropolitan diesel Rural diesel Diesel

Density 20/4 1C 0.820–0.865 0.820–0.880 o0.860 o0.870 o0.845

Sulfur content (ppm) 2000 3500 500 2000 50

Centane number 42 42 43 42 45

%T360 (ASTM D86) 85 85 90 85 95

Table 5

Expansion of hydrotreating (HDT) and hydrocracking (HCC) units in the

Brazilian Refining Segment—2004–2011

Expansion 1000 barrels per calendar-day

Hydrotreating 704.4

Diesel 317.6

Gasoline 320.8

Naphta, petcoke and other oil products 66.0

Hydrocracking 99.0

Lube oils 35.0

Diesel (fuels) 64.0

Source: Assayag [32] for HDT and Petrobras [33] for HCC.

A. Szklo, R. Schaeffer / Energy 32 (2007) 1075–10921080

the quality specifications of oil products and the energy useby refineries (CO2 emissions) in a more objective manner.This means the quantification of this trade off for a casestudy.

The case study presented here is that for which moredetailed data was available for our estimates: the Brazilianrefining industry. We do recognize that the Brazilianrefining industry is not subject to explicit greenhouse gases(GHG) emission reduction targets, as Brazil is not part ofAnnex 1 countries of the Kyoto Protocol [31]. In addition,the country’s regulations have defined rising diesel andgasoline quality requirements. Nevertheless, these require-ments are still less restrictive than the targets set for theUSA and Western Europe over the same period.

But even though the purpose of the Brazilian refiningindustry is not to formulate a ULSD diesel or a premiumgasoline, and even though Brazil has no GHG emissionstargets, the case of Brazil per se clearly exemplifies thetrade-off between fuel specification and energy use (CO2

emissions) by refineries. For Brazil, as of today, this trade-off is perhaps more easily perceived by the refiners as abalance between energy use and oil product specifications.

As listed in Table 4, there are currently two dieselspecifications in Brazil (metropolitan diesel and ruraldiesel), depending on the area of consumption (metropo-litan areas with stricter specification). However, by 2009,there will be only a single diesel specification, with morestringent requirements especially for sulfur content. Thus,between 2002 and 2009, Brazil’s refining industry shouldstrive to lower the sulfur content of its diesel by around3000 ppm, due to the proportion between rural andmetropolitan diesel on the Brazilian market (at around70% and 30% of the diesel market, respectively).Additionally, the Brazilian refining industry should complywith a reduction in the gasoline sulfur content, currentlyspecified at 1000 ppm and dropping to 80 ppm in 2009,according to the proposal presented by Brazilian refiners[6]—i.e., a reduction of 920 ppm.

In order to comply with these specification targets andprocess increasingly heavier crude oils from the Brazilianoil production, with no loss of light and medium pro-ducts yields,19 Petrobras allocated 43% of some US$ 6

19For the type of crude oil produced and processed in Brazil, see

Tavares et al. [34] and Szklo et al. [35].

billion through its Refining Investment Plan between2004 and 2008 to upgrading diesel and gasoline quality.The rest of these investments are channeled to con-version (30%); maintenance (11%); expansion (6%); andothers. Basically, these investments are earmarked forthe HDT and HCC units (Table 5) that will boostHDT capacity from 222,000 bpd (12.5% of AtmosphericDistillation) to 926,000 bpd (51.1% of AtmosphericDistillation), and HCC from zero to 99,000 bpd(5.5% of Atmospheric Distillation) between 2002 and2009 [32, 33].These units will operate in compliance with the typical

conditions presented in Table 6. Particularly for diesel,compared to HDT, HCC will result in high-grade products(except for the naphtha octane number), with highhomogeneity (Tables 7 and 8). However, although versa-tile, an HCC plant has high costs, particularly whenprocessing Brazilian crude oils to produce lubricants. It isestimated that a plant with a capacity of 5500m3/year ofHDT for diesel costs some US$ 200 million, while an HCCunit with the same capacity producing medium distillatescosts some US$ 500 million, and finally an HCC unit withthe same capacity focused on lube oils costs US$ 650million [22].Based on these data and the average specific consump-

tion of the HDT and HCC units under consideration, ahuge increase in energy use may be foreseen for theBrazilian refining industry, owning to the introduction ofHDT and HCC units and the production of H2 that they

ARTICLE IN PRESS

Table 6

Typical HDT and HCC operating conditions tested for Brazilian crudes

Diesel HDT Full HCC Partial HCC

Purpose Fuel Fuel Fuel+lube-oils

Rated capacity (m3/d) 5500

Operating pressure (bar) 85 165 200

Operating temperature (oC) 365 380 390

Catalyst volume (m3) 235 825 980

Number of reactors 2 3 4

Wall thickness (mm) 144 244 3444

Source: Petrobras [33].

Table 7

HCC units yields tested for Brazilian crudes

Product Total conversion Partial conversion

Naphtha (wt%)—yield 23 11

Sulfur (ppm) o10 o10

MON/RON 55/65 55/65

Jet fuel (wt%)—yield 26 18

Sulfur (ppm) o10 o10

Nitrogen (ppm) o1 o1

Diesel (wt%)—yield 46 27

Sulfur (ppm) o10 o10

Nitrogen (ppm) o1 o1

IC 55 53

Fuel oil residues (wt%)—yield 4 43

Sulfur (ppm) o5 o5

Nitrogen (ppm) o1 o1

Source: Petrobras [33].

Table 8

Diesel HDT—crude oil feedstock: Cabiunas

Load 50% vol: heavy straight-run diesel

29% light cycle oil (LCO)

21% light coke gas oil

Load Liquid wastes

Density at 20/4 1C 0.8988 0.8772

T90 (1C) 395 388

Total sulfur (% mass) 0.570 0.005

Total nitrogen (mg/kg) 1760 80

Cetane number 36.1 42.0

Source: Petrobras [33].

21This consumption is based on data from Brazilian plants compared to

the values range for similar units installed in European refineries [25, 36,

A. Szklo, R. Schaeffer / Energy 32 (2007) 1075–1092 1081

require (Table 9).20 This increase tops 30%, according toour estimates, which assumed:

37] and in the USA [23, 28]. See also Dusse et al. [38] and Almeida et al.

�

2

pro

use

the

[39].22This has been the typical production process for producing ultra-pure

A usage factor of 97% for the treatment and hydro-conversion plants, according to the HDS, HDA and

0The estimate does not include HCC for lube-oils, as this is not a plant

ducing fuels. For H2 production, the average specific consumption was

d for a steam reform plant, which is the technology mainly adopted for

expansions planned by Petrobras [33].

H2

pro

2002

typ

HDT units already in operation in the country [33]. Theaverage distillation capacity usage factor of 90% wasbased on Tavares et al. [34].

� The following average specific consumption levels for

the HDT and HCC units under analysis, which are givenin MJ/b:21 Diesel HDT (100); Gasoline HDT (150);naphtha HDT (135); total conversion HCC (240).

� The hydrogen demands from the units listed above (in

Nm3/b): Diesel HDT (28); Gasoline HDT (15); naphthaHDT (15); total conversion HCC (58).

� The energy use of a typical H2 production unit based on

natural gas steam reform,22 at 57 GJ of fuel/t H2

(Rostrop-Nielsen [29];23 EIPCCB [25]).

� The main energy source for the HDT and HCC units

consist of process wastes and residual fuel oils, inaddition to petcoke. The data from Brazilian refineriessuch as REDUC justifies this assumption (Schaeffer etal. [40]). According to MCT [41], the CO2 emissionfactor of the petcoke is 27.5 tC/TJ. For the steam reformto produce H2, by definition the energy source is naturalgas (emission factor of 15.3 tC/TJ). For the total CO2

emissions derived from the production and use of energyin Brazil, the methodology of the Ministry of Scienceand Technology [41] was applied by Cima [42] to 2002.

As presented in Table 10, stricter diesel and gasolinequality specifications in 2009 increase CO2 emissions inBrazil by around 1.5MtC. Overall, the units intended tomeet the diesel and gasoline sulfur specifications boostenergy use of Brazil’s refining industry by around 30%.These units account for some 2% of the total CO2

emissions derived from the Brazilian energy system.This estimate should not lead to the conclusion that

stricter oil product quality specifications in Brazil are notappropriate. The positive impacts of these specificationsare significant, for sulfur emissions as well as emissions ofother pollutants such as CO and NOx, whose catalystremoval system is poisoned by sulfur. What is presentedhere is the trade-off between the quality specifications forthe oil products and the increase in energy use (and CO2

emissions) by refineries, in order to comply with thesespecifications.This trade-off has objective implications for the strate-

gies of the countries covered by Annex I of the KyotoProtocol but is also significant for countries such as Brazil,China and India, in view of current discussions over thepertinence of establishing greenhouse gases reduction

(99.999%) in Brazilian refineries, although the solid wastes gasification

cess may also be analyzed for a period beyond 2009 (Szklo & Schaeffer,

5).3According to Rostrop-Nielsen [29], the thermodynamic yield of a

ical H2 production unit is around 3.5Gcal/1000Nm3.

ARTICLE IN PRESS

Table 9

Estimated energy consumption by the Brazilian refining segment after the introduction of new HDT and HCC units

Total energy use—Brazilian Refining Segment—2002 (1)—(TJ) 228,141

Energy use by new HDT, HCC and H2 production plants (TJ) 70,438

Increase in energy use due to more stringent fuel specifications (%)(2) 31.0

Total energy use of HDT/HCC (TJ)(3) 82,050

Proportion of HDT/HCC in total energy use (%) 27.5

Note: (1) Based on the specific consumption data for Brazilian refineries [40]. In 2002, it is estimated that energy use represented 6.6% of the feedstock

crude-oil entering the Brazilian refining park. (2) After the introduction of the HDT, HCC and H2 production plants, energy use accounted for 8.6% of the

feedstock crude oil entering the Brazilian refining park. The increase of 31% in final energy consumption is due only to the above-mentioned plants. This

analysis is carried out on a Ceteris paribus basis—i.e., possible energy conservation measures were not taken into consideration, which might be

implemented by the Brazilian refining industry, and no marked changes were assumed in the average feedstock of the refineries (API, sulfur content,

acidity, etc.). (3) Units existing in 2002 and installed after 2002, in order to comply with the new quality specifications. Consumption by all the existing and

new HDT and HCC units and the H2 production plants accounts for 27.5% of the final energy consumption of the Brazilian refining segments.

Interestingly, this is compatible with the figure presented by the US refining industry [24].

Table 10

Estimated CO2 emissions by the Brazilian refining segment after the

introduction of the treatment plants

Energy system emissions – 2002 (MtC)—A(1) 79.2

Emissions by the HDT, HCC and H2 production plants (MtC)—B 1.8

Expansion to comply with specifications in 2009 (MtC) 1.5

Existing plants in 2002 (MtC) 0.3

(B/A) % 2.2

Notes: (1) Emissions from fossil fuel consumption in Brazil, according to

Cima [42].

A. Szklo, R. Schaeffer / Energy 32 (2007) 1075–10921082

targets for non-Annex I countries, after the periodstipulated in the Kyoto Protocol [43]. In this case, theproblem of carbon emissions may become significant inBrazil, in the near future.

In brief, technological alternatives should be sought forquality specifications with no considerable increase inenergy use by refineries. The next sections of this paperdiscuss some alternatives.

5. Energy savings potential in refineries

According to Petrick and Pelegrino [15], in the mediumto long terms a target reduction of 15–20% in energy use(and consequently in CO2 emissions) from US refiningsector is achievable. Waste heat recovery seems to be one ofthe most important options in the short to medium terms,while fouling mitigation, and new refining processes arepromising technologies in the medium to long terms.24 Asthis section will discuss, a similar energy savings potentialcan be achieved in Brazilian refineries, offsetting a least50% of the increase in energy use estimated in the previoussection. Clearly, there remain barriers to invest in the set ofenergy savings options identified in this section. The final

24API [24] indicates, however, fouling mitigation as an alternative to the

near-to-mid term. Brazilian experiences on this issue lead to the same

conclusion [44].

remarks of this paper highlight some of them, while thissection focuses mainly on the technical alternatives.

5.1. Improvement of heat integration and waste heat

recovery

In the short to medium terms, the improvement of heatintegration and waste heat recovery appears as one of themain options for saving fuel in Brazilian refineries. There isno substantial R&D development related to this option,and chemical plants in Brazil and worldwide are alreadyaware about the techniques that might be applied forimplementing this option. Moreover, chemical plants [45]and oil refineries [46] in Brazil have experiences inoptimizing heat networks for saving fuels.Especially for oil refineries, large temperature differences

indicate the possibility of managing heat and cold flows toreduce energy use. For instance, heat integration of processsystems can ensure that a substantial proportion of theheat required will be provided by exchanging heat betweenstreams to be heated and streams to be cooled, and not byexternal sources for heating and cooling. A positive side-effect of that is the simultaneous reduction of waste water(used for quench) and make-up water (used for steamgeneration). In brief, to improve heat management andwaste heat recovery in refineries includes:

�

2

pro

use of waste heat in absorption refrigeration systems[46];

� use of waste heat to pre-heat feeds (e.g., through the

installation of waste heat boilers or heat recovery steamgenerators);25

�

heat and/or mass (water and hydrogen) integrationusing basically Pinch techniques [47, 48]; � improvement of furnaces efficiencies combined with

computer controlled combustion [24];

� direct feed of ‘‘intermediary products’’ to processes

without cooling and storage, aiming at recovering the

5For instance, waste heat boilers can recuperate some of the heat

duced during the coking process.

ARTICLE IN PRESS

2

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A. Szklo, R. Schaeffer / Energy 32 (2007) 1075–1092 1083

waste heat of these hot products. For instance, the wasteheat of the products of the crude distillation unit can berecovered by later feeding them directly to the down-stream units, rather then cooling them for storage andlater feeding the downstream units from tankage [25];

� use of heat pumps [49]; � decreased film temperature and increased turbulence on

heat transfer surfaces;

� insulation of buildings and process units [25]; � adoption of steam management [49]. Steam used for

stripping,26 vacuum generation, atomization and tracingis usually lost to waste water and to the atmosphere. Inorder to reduce the sour water loads to strippers and, assuch, reduce chemical treatments in the overheadsystem, and option could be to strip sidedraw products,particularly the lighter cuts, using reboiled sidestrippersinstead of steamed strippers [25].

Overall, through the use of Pinch techniques,27 reduc-tions in energy consumption around 20% have beenreported by Petrick and Pellegrino [15]. This figure agreeswith estimates from EIPCCB [25]. However, according toHallalle [47] and CTEC [48], typical savings resulting fromenergy pinch hover between 10% and 25% in oil refineries(as a percentage of total fuel consumption). Finally,Alsema [1] estimates that 2% savings on fuel can berealized by improved waste heat recovery; and, in the caseof process integration and energy pinch, the fuel savingpotential ranges between 2% and 6%. Beer [52] agrees withthese numbers, estimating an average fuel saving of 5% inDutch refineries, at low costs (less than 10$/GJ).

In turn, two studies performed at the Brazilian refineryReplan28 [53,46], and one study performed at the Brazilianrefinery Reduc29 [54], analyzed the potential application ofwater and energy pinch in these plants. According to them,making better use of residual heat in the process streams isa major option for saving fuels in Brazilian refineries.

6Normally, stripping steam is used to meet flash point specification and

improve front-end fractionation and yield distribution.7Energy optimization, through heat exchanger networks using the

ch Analysis, seeks integration between cold streams (that need

rming) and hot streams (that need cooling), considering the tempera-

e and enthalpy of each stream. As mentioned before, simultaneously,

reducing external heating and cooling demands, Pinch Energy Analysis

s not result only in fuel savings but also water savings (used as steam in

ustrial processes or as work fluid in cooling towers). For more details

ut this technique, see Hallale [47] and Linnhoff [50,51].8Replan is the largest Brazilian refinery, in terms of topping units

acity (352 million barrels per calendar-day). It is located in the state of

Paulo, and it focuses mainly on fuels, particularly on diesel

duction (around 40–45% of its historical oil products yield). It also

duces significant volumes of naphtha for petrochemicals production.9Reduc is the Brazilian refinery with the largest Nelson Index of

plexity, being focused on fuels (mainly, diesel, jet fuel, premium

oline, and LPG), petrochemicals and lube oils (80% of total lube oils

duction in Brazil). Its primary capacity is 239 million barrels per

endar-day. A detailed analysis of Brazilian oil refineries can be found in

lo [22].

However, the analysis of the Brazilian refinery Replanshows that not all hot streams may be used by an energyintegration network. Initially, volatile products that must becooled rapidly through direct contact with water (quench)cannot be used. Neither can intermittent streams [46].Processes with high specificity levels (such as HDT) shouldalso be discarded, as well as hot streams containing solids insuspension (such as catalyst streams). Finally, high exergystreams (such as FCC outlet gases) are hard to recycle, as theyare found in inaccessible parts of the refinery [46].Therefore, the high-energy use of the atmospheric distilla-

tion column and the fact that this column processes largevolumes of feedstock make it the first option for heatintegration in oil refineries. For instance, at the distillationcolumn of the Brazilian refinery Replan, the variation oftemperature is from 124 to 35 1C for diesel (mass flow of80.5kg/s), from 165 to 35 1C for jet fuel (mass flow of 16.6kg/s), and from 304 to 35 1C for light gasoil (mass flow of 8.3 kg/s).30 The first two oil products leave the atmospheric columnto be hydrotreated, while the latter one follows to a FCC unit.Therefore, to optimize heat recovery from Replan’s refineryatmospheric distillation column, two or three reflux streamscould be kept in continuous circulation at several points.In addition, besides the introduction of optimized heat

networks in Brazilian refineries, the use of waste heat toprovide cooling is also an attractive option. Again, theanalysis of Replan is elucidative. Given the variations oftemperature of the streams leaving its distillation column,the regenerator of the absorption refrigeration system(single-stage absorption system) can be easily kept at100 1C, with the coefficient of performance (COP) of 0.80.In this case, the cold stream produced can be used as thelast stage of the vacuum production system of the vacuumdistillation column. As such, it reduces the temperature ofthe water used by this system, lowering also the pressure ofthe column, and, as such, increasing its performance.31

In sum, considering mainly heat integration and wasteheat recovery for Brazilian refineries and according to theoptions described before and tested in two major Brazilianrefineries, this study estimates a fuel savings potential ofaround 10% (percentage of total fuel consumption).

5.2. Fouling mitigation

The definition of the Pinch Point32 is highly affected bythe control of fouling. In heat networks where foulingreadily occurs, this may reach 40 1C [48], when the typical

30These variations of temperature are generated by the heat rejected to

the water refrigeration system, after the distillation column.31Petrick and Pellegrino [15] describe the application of an absorption

refrigeration unit, using waste heat, to recover additional LPG from a

reformer reactor. The implementation of this alternative at a refinery in

Denver, Colorado, had a payback period of 1.5 years [3]. Petrick and

Pellegrino [15] also report on using a similar technology for the CDU,

estimating energy savings ranging from 10% to 20%.32The Pinch Point is determined as the minimum temperature difference

that is accepted by the heat exchangers in the heat network.

ARTICLE IN PRESSA. Szklo, R. Schaeffer / Energy 32 (2007) 1075–10921084

figures range between 10 and 20 1C. Fouling reducesthermal efficiency and heat transfer capacity, resulting inincreases in energy use. It is difficult to prevent, as themechanisms, which lead to fouling, are not yet wellunderstood [24].

Therefore, an important measure for lowering energy useby refineries is the control of fouling in heat exchangers,which, in addition to lessening the heat exchange area, alsocause maintenance halts and accident risks at industrialplants.33

In addition, the desalter unit plays an important role inreducing energy use by the refinery, through removing saltsand contaminants from its feedstock. Interestingly enough,this may be a win–win situation, because better heatexchanges have positive effects on the desalter efficiency, asthis efficiency is associated with operations within arestricted optimum temperature range. Heat exchangerswith losses of heat exchange areas due to fouling cannotguarantee that this optimum range will be reached,lessening the salts and metals removal capacity of thedesalter [55]. This results in oil losses that pollute the liquidwastes discharged by the plant and relatively highcontaminant levels in the feedstock.

It was estimated that a typical refinery, ca. 1980, with aprimary processing capacity of 100Mbpd, could decreasethe energy use by its Atmospheric Distillation unit by 30%by controlling heat exchanger fouling [56]. However, amore recent study indicated a lower energy potentialthrough fouling control, which remains significant at10% [57]. According to Bailey [58], the oil refining industryin the US alone spends US$ 2 billion a year on crustingproblems.

However, the steadily increasing diversity of the crudeoils processed in the world refining industry hampers thedevelopment of fouling prevention techniques. Heatstability studies are needed, as well as analyses of thesolubility of asphaltenes and naphthenic acids, in additionto the development of anti-fouling chemical compoundsthat also remove scale without adversely affecting thequality of the refinery products. The challenges areexplained by the fact that fouling is the effect of severalprocess variables and heat exchanger design. Fouling mayfollow the combination of different mechanisms [59].

In sum, fouling of heat exchangers is a bottleneck in theapplication of heat recovery schemes. Fouling predictionand mitigation can therefore improve energy efficiency.The fuel savings of 2% of total fuel use obtained by Petrickand Pellegrino [15] to US refineries agree with the results ofstudies performed in Brazilian refineries [44]. However, thehigher figure obtained by Panchal and Huangfu [60]indicates the need for new studies. These authors analyzedfouling effects of a 100,000 bbl/day crude distillation unitand found an additional heating load of 13.0MJ/barrel

33An interesting analysis of the effects of fouling on the performance of

heat exchangers in Brazilian refineries was carried out by Negrao et al.

[44].

processes (or around 3.4% of the average specific energyconsumption of Brazilian refineries).

5.3. Advanced process control

Advanced process control based on computer modelsand extensive use of sensors might result in improvedproduction reliability and thus increased product yield.Indeed, modern control systems are often not solelydesigned for energy efficiency, but rather to improveproductivity, product quality and efficiency of a produc-tion line. Control systems result in reduced down time,reduced maintenance costs, reduced processing time, andincreased resource and energy efficiency, as well asimproved emissions control [49]. Large potentials remainto implement control systems [61]. For instance, Timmonset al. [62] combined online optimizer with existing controlsystems to improve the operation of the FCC unit at theCITGO refinery in Corpus Christi, Texas. They reportedsavings of $0.05/barrel.According to Alsema [1], energy savings can be

estimated at 2–4% of fuel consumption. However, Worrelland Galitsky [49] indicate a savings potential varying from2% to 18% for US refineries, using moisture, oxygen, airflow and temperature controls based on fuzzy logic or rule-based systems.34

There is no estimate or study performed for Brazilianrefineries, precisely, on this subject. Therefore, we suggestas a conservative figure the lower value obtained by Alsema[1] to Dutch refineries (2% of fuel savings). In addition, nocost estimates are available for Brazilian refineries as well,but fixed costs are probable relatively high because of therequirement to install several sensors and to customize thecontrol software to each specific unit or plant. Actually,process control systems depend on information of manystages of the processes. A separate but related andimportant area is the development of sensors that areinexpensive to install, reliable, and analyze in real-time.Development aims at the use systems, which should beresistant to aggressive environments (e.g. oxidizing envir-onments in furnace or chemicals in chemical processes) andwithstand high temperatures. Nevertheless, it is expectedthat advanced control systems will be progressivelyimplemented in Brazilian refineries thanks to their variousbenefits, not only related to energy efficiency. According toKatzer et al. [64], the refinery of the future will look morelike an automated chemical plant.

5.4. Replacement of the conventional atmospheric and

vacuum distillation units

As mentioned in the introduction, the atmospheric andvacuum distillation columns are large consumers of heat.According to Worrell and Galitsky [3], atmospheric and

34An example of the use of fuzzy control in process units can be found in

Aprea [63].

ARTICLE IN PRESSA. Szklo, R. Schaeffer / Energy 32 (2007) 1075–1092 1085

vacuum distillation units accounted for 31% of the totalenergy use in US refineries in 2001. For the Brazilianrefineries in 2002, this share can be estimated at 46%,considering the average specific energy consumption ofdistillation units in the country, and the crude oil processedby each refinery. The higher share found in Brazilianrefineries in 2002 can be explained by the relatively lowerconversion and treatment capabilities of these refinerieswhen compared to US plants.35

Therefore, the large dependence of all refineries onphysical and chemical separation processes, presenting lowthermodynamic yields, underscores the need for R&D ofalternative separation technologies. Actually, leap-frogtechnology is needed to reduce the large amount of energyused in distillation through the refinery complex [24].

As described before, in distillation, the main short-termdevelopments are in improved integration using heatrecovery technology and integration of different distillationunits (i.e. CDU and VDU). In the long term, the majordevelopments are the integration of different distillationcolumns into one reactor (e.g. dividing-wall column) or thedevelopment of alternative processing routes allowing forcombination of conversion and distillation (e.g. reactivedistillation) [49]. Replacing distillations units by crackingones is also seen as a promising option [24].

�

3

in

tot

hyd

refi3

Thermal Cracking Process: Distillation is used to separatecrude oil into its various fractions based on differences inboiling points. An alternative to primary separationcould be the use of controlled thermal cracking, whichseparate crude oil into fractions by cracking largehydrocarbon molecules into smaller ones, thus loweringtheir boiling points. In addition, a controlled operation(low-residence time unit) could achieve primary separa-tion while also removing major fractions of contami-nants, particularly sulfur. Therefore, this latter effectindirectly reduces the energy consumption of hydrotreat-ing finished and non-finished oil products. Petrick andPellegrino [15] estimated a potential net energy savings of65MJ per barrel of oil processed. Brazilian oil refineriesconsumed 228,141 TJ in 2002 or presented an specificenergy consumption of 383MJ per barrel of oilprocessed. Therefore, it is possible to calculate a netenergy savings potential of 17% for the Brazilian refiningsector, if all crude and vacuum distillation towers werereplaced by thermal cracking.36 However, that fullreplacement of distillation towers in existing plants isnot likely, and it is a high-cost option. Refiners worldwide(and in Brazil) tend to be very cautious in investing in thiskind of drastic technological change, as the final remarksof this paper will emphasize.

5The total installed capacity in conversion units at Brazilian refineries

2003 was around 40% of the total primary capacity (this proportion

aled 89.3% in US refineries, according to Nakamura [4]). For

rotreating units this proportion was only 12.5% [22], while in US

neries it was 67.7%, and 88.8% in Californian refineries [4].6Interestingly, the estimate of Alsema [1] for Dutch refineries was 18%.

�

3

imp

rec

Progressive distillation unit: A progressive distillationunit integrates the atmospheric and vacuum distillationcolumns, saving up to 30% on total energy use for theseunits [65]. This technology includes atmospheric dis-tillation (topping), vacuum distillation, gasoline fractio-nation, naphtha stabilizer if required and gas plant [25].It is the extreme of heat integration between atmo-spheric and vacuum distillation, avoiding also super-heating of light cuts to temperatures higher than strictlynecessary for their separation. This option is merelyapplicable to distillation units to be constructed. There-fore, it is not a suitable option for existing refineries inBrazil.

� Dividing-wall distillation: The first commercial applica-

tion of the dividing-wall distillation column dates backto the early 1990s (Hallale [47]). A dividing-wall columnintegrates two conventional distillation columns intoone, increasing heat transfer. Dividing-wall columns(DWC) can save up to 30% in energy costs, whileproviding lower capital costs compared to conventionalcolumns [66]. Various companies (Kellog Brown &Root, and UOP) have developed DWC-concepts for theseparation of products. However, further developmentof DWC for the major distillation processes in thepetroleum refining industry is still needed [3,49].

� Reactive distillation: By combining the chemical reaction

and separation in one reactor, capital costs are reducedand energy efficiency is improved through betterintegration of these process steps [47]. Various researchinstitutes and technology developers aim at developingnew applications of reactive distillation. A new devel-opment includes the use of monolithic structures thatcontain the catalysts [67], reducing catalyst loss and thepressure drop. The most promising commercial applica-tion is not applicable for replacing distillation units,however. It is the catalytic distillation for replacingsevere hydrotreating. This technology will be analyzedin the next section.

5.5. Membrane separation technology

Membranes are an attractive technology for hydrogenrecovery at refineries [68].37 Membranes have beendemonstrated for recovery of hydrogen from hydrocrackeroffgases. Various suppliers offer membrane technologiesfor hydrogen recovery in the refining industry, includingAir Liquide, Air Products and UOP. The hydrogen contenthas to be at least 25% for economic recovery of thehydrogen, with a recovery yield of 85–95% and a purity of95% [3,49]. However, membrane technology represents thelowest cost option merely for low product rates, but not forhigh flow rates. Thus, development of low-cost andefficient membranes is still needed, in order to improve

7Hydrogen recovery is an important technology development area to

rove the efficiency of hydrogen recovery, reduce the costs of hydrogen

overy and increase the purity of the resulting hydrogen flow.

ARTICLE IN PRESS

Table 11

Energy saving potential in Brazilian refineries

Energy saving option Estimated fuel saving potential (percentage

of total fuel consumption)

Applicability

Heat integration and waste heat recovery(1) 10% Fully applicable

Fouling mitigation 2% Fully applicable

Advanced process control 2% Fully applicable

Replacement of topping units by Only for new refineries

Thermal cracking 17%

Progressive distillation 15%

Dividing-wall distillation 15%

Pumps and advanced motors with variable

speed

1%(2)

Vacuum pumps and surface condensers — Application restricted by steam recovery and

heat integration

Membrane separation — Non commercial for high flow rates

Note: (1) These options include: use of waste heat in absorption refrigeration systems; use of waste heat to pre-heat feeds; heat and/or mass (water and

hydrogen) integration using Pinch techniques; improvement of furnaces efficiencies combined with computer controlled combustion; direct feed of

‘‘intermediary products’’ to processes without cooling and storage; use of heat pumps; decreased film temperature and increased turbulence on heat

transfer surfaces; insulation of buildings and process units; and adoption of steam management. (2) Percentage of the electricity consumption.

38The near to-medium term is in accordance with the time horizon of the

estimates performed in Section 4 (expansion of HDT units in Brazil and

impacts on energy use and CO2 emissions).

A. Szklo, R. Schaeffer / Energy 32 (2007) 1075–10921086

the cost-effectiveness of hydrogen recovery, and enable therecovery of hydrogen from gas streams with lowerconcentrations.

As of today, a broader application of membranetechnology to separate products in refineries does notseem very promising, and actual savings are unclear.Petrick and Pellegrino [15] do not even mention thisoption. According to Worrell and Galitsky [3], furtherresearch is needed to develop appropriate membranematerials that can withstand the environment found inpetroleum refining processes. In addition, membranetechnology should be evaluated as an integrated part ofthe specific process for which it is being implemented towarrant the full energy savings potential. For this reason,this study did not considered here this option forestimating the energy savings potential in Brazilianrefineries.

5.6. Use of vacuum pumps and surface condensers

Vacuum pumps and surface condensers can largelyreplace barometric condensers in many refineries. Repla-cing the steam ejector by vacuum pump reduces the sourwater flow and increase energy efficiency [25]. Precisely, thereplacement of the steam ejectors by vacuum pumpsincreases the electricity consumption, while reduces theheat consumption, the cooling water consumption, and theconsumption of agents used for conditioning coolingwater. The net energy saving is positive. All Brazilianrefineries are able to adopt this option, but since there aremany processes in it where surplus steam is recovered andused for the production of vacuum, a suitable energymanagement might undermine the usefulness of thisoption. Improving energy integration and steam recoveryand management in Brazilian refineries tend to restrict theapplication of this option.

5.7. Use of pumps with variable speed

Pumps at refineries are usually operated at variableconditions [28]. Normally, the flow control is based onvalves, resulting in energy losses. Therefore, an optionstudied by Olim et al [46] for the Brazilian refinery Replanwas the use of frequency inverters for electric motors drive.For instance, the atmospheric distillation column ofReplan has five pumps operating at fixed speeds, withcapacities ranging from 125 hp to 200 hp. The analysisindicated an electricity savings potential of 2.6GWh peryear, with an attractive internal rate of return (between 20and 55% per year, depending on the size of the pump).Therefore, summing up the energy savings alternatives

that can be implemented together in Brazilian refineries inthe near to medium terms, a net energy savings potentialhovering between 10% and 20% can be estimated(Table 11).38 Clearly, these energy savings options can beapplied to oil refineries, whether or not alternativetreatment processes are implemented. This study consid-ered the possibility of adopting, simultaneously, energysavings options and alternative treatment units. Therefore,the net benefit of these two measures depends on theanalysis undertaken in the next section.

6. Alternative treatment processes

As discussed before, hydrotreating processes have beengaining ground in refining parks supplying markets withmore stringent fuel specifications [12,13]. As noted, sulfur isa key contaminant for oil products specifications. Thesulfur compounds to be removed during hydrotreatment,

ARTICLE IN PRESSA. Szklo, R. Schaeffer / Energy 32 (2007) 1075–1092 1087

more specifically during hydrodesulfurization, includemercaptans, sulfides, thiophenes and benzothiophenes(BTs). Stricter specifications on the sulfur content of fuelsare forcing refineries to invest in severe hydrodesulfuriza-tion units or seek alternative desulfurization processes. But,as stressed before, deep hydrodesulfurization presents twomajor problems when used in gasoline streams:

1.

3

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60–4

wit

ext

the

tem

It affects the gasoline quality (octane rating), bylowering its olefins content. This fact refers mainly togasoline from FCC, which accounts for 85–95% of thesulfur content of the product,39 and simultaneouslycontains a great quantity of olefins (20–40wt%), whichprovides it with a fairly good octane number [13].40 Inother words, to remove sulfur from gasoline means toremove it mainly from FCC gasoline, aiming at notcompromising the quality of the finished gasoline.

2.

As detailed in the previous sections, it increases theenergy use of the refinery, resulting in higher operatingcosts and also more severe environmental impactscaused by refining activities (for example, higheremissions of GHGs such as CO2, tightening up thetrade-off between local and global pollution referred tobefore in this paper). For instance, the Brazilian casestudy indicated that, overall, the units intended speci-fically to meet the diesel and gasoline specifications,particularly for sulfur removal, boost the energy use ofthe refining industry by around 30%, accounting for 2%of the total CO2 emissions derived from the Brazilianenergy system.

Alternative treatment processes are designed specificallyto mitigate these problems. Organic sulfur compounds arepresent in almost all oil cuts leaving the distillation tower(straight-run streams). Cuts with higher boiling points (orhigher cut-off temperatures) contain relatively higher sulfurlevels and their sulfur compounds have heavier molecularweights. There are also differences in the sulfur compoundreactivity, affecting the efficiency and efficacy of theirremoval during the hydrotreatment process.

Lighter fractions from Atmospheric Distillation nor-mally contain aliphatic compounds (such as mercaptans)that are highly reactive and can be withdrawn easilythrough conventional HDS and even other processes suchas Merox Treatment.41

For heavier fractions, such as heavy naphtha and dieselleaving the distillation column, FCC naphtha, delayedcoking naphtha and coking diesel, the predominant sulfur

9Usually, FCC gasoline constitutes 40–60% of the gasoline pool

,13].0In Brazil, light naphtha straight-run has the average octane rating of

65, while FCC gasoline presents the average ranging from 80 to 90 [22].1Mercaptans are slightly acidic organic sulfur compounds. They can be

hdrawn from light ends mixtures by caustic washing in a Merox

raction system. This system uses organometallic catalysts to accelerate

oxidation of mercaptans to organic disulfides at or near ambient

perature and pressure, in an alkaline environment [12].

compounds are less reactive: thiophenes, benzothiophenes,dibenzothiophenes, and other polyaromatics compoundswith sulfur, particularly alkylbenzothiophenes.42

Deep desulfurization of products at the refinery shouldremove these less-reactive compounds. One possibility is tostep up the severity of the HDS. However, this measureleads to undesirable reactions (e.g. olefin saturation ofFCC gasoline). Additionally, the higher temperaturesrequired for severe HDS also step up coke formation andthe de-activation of the hydrotreatment catalyst—i.e., theyshorten the useful life of the catalyst, which increases theoperating costs of the refinery. Finally, as discussedpreviously, severe HDS boosts energy use at the refinery.Thus, in response to the problems caused by severe

HDS, alternative treatment processes are being proposed.One focus of research is the development of more selectivecatalysts, which lower the probability of the occurrence ofundesired parallel reactions during HDS [11,12,70]. An-other focus is the development of advanced reactors thatalso include special supports for the catalysts [67]. Aninteresting alternative is the combination of the treatmentprocess with other processes in order to ensure desulfur-ization and the production of high-grade fuels.

6.1. ISAL process

ISAL43 process combines conventional deep HDS (usingmolybdenum and cobalt oxide catalysts on alumina44) withisomerization reactions of paraffins, to subsequent octanerecovery. One of the drawbacks of these processes can besome yield loss in gasoline due to cracking into lightproducts. Another disadvantage with respect to selectiveprocesses is the hydrogen consumption needed for thequasi-total olefin saturation [13]. Nevertheless, ISAL is notper se an option for saving energy and reducing CO2

emissions. It still depends on deep HDS and presents highH2 requirements. Thus, its main advantage is the fact thatoctane loss during HDS is lowered, and, as such, thequality of the gasoline pool is kept unchanged without theneed for adding additives to gasoline or changing the pool(e.g., adding alkylates and isomerates).

6.2. Olefin alkylation of thiophenic sulfur (OATS) process

The Olefin Alkylation of Thiophenic Sulfur (OATS)process steps up the boiling point of the sulfur compoundsin the gasoline through acid-catalyzed alkylation reactions[12]. This means that the less-reactive sulfur compoundsbecome heavier and are concentrated in the refinerybottom streams. For instance, the alkylation reaction

42The reactivity of the sulfur compounds in the heavy fractions at the

HDS units normally complies with the following order (from more to less

reactive): thiophene, alkylated thiophene, benzothiophene, dibenzothio-

phene and alkylated dibenzothiophene [67]).43The name of the technology comes from ‘isomerization’ and ‘Salazar’

- name of the technology inventor [67].44CoMo–P/Al2O3 associated to a Ga–Cr/HZSM-5 zeolite [13].

ARTICLE IN PRESSA. Szklo, R. Schaeffer / Energy 32 (2007) 1075–10921088

between thiophene and olefins (usually hexane) steps up thethiophene boiling point from around 86 1C to some 250 1C[67], which allows it to be separated from the gasolinethrough simple distillation. This reaction is very simple andcan take place under rather mild conditions [70]. It alsohardly influences the octane number of gasoline [13].Finally, the HDS process is no longer necessary, reducinghydrogen and energy use by the refinery. The heavy sulfurcompound removed through simple distillation may beadded to the diesel or heavy gasoil pool at the refinery.

However, this technique was invented by BP in 1999 [71],and still must be tested. BP had built a small-scale test setup [70], but there is no data about energy use in a futurecommercial unit. In addition, besides thiophene, in gaso-line there were many thiophene derivatives such asmethylthiophene, dimethylthiophene, ethylthiophene, andso on. Since these derivatives already have one or two sidechains, their alkylation reactions and the reaction extentcould be changed. These questions need to be answered byfurther studies.

Zekai et al. [70] also found that in OATS there are twoparallel alkylation reactions: the aromatics alkylation andthe alkene alkylation (oligomerization). Both compete withthe thiophene alkylation. Apparently, their mechanism isthe same as that of the thiophene alkylation, especially inthe case of aromatics alkylation. Moreover, although itsreaction thermodynamics is slightly less favorable than thatof aromatics alkylation, the highly concentrated alkenes inFCC gasoline facilitated the alkene oligomerization. Onceagain, these questions need to be answered by furtherstudies.

46Diesel HDS accounted for 39% of the total expanded energy use

estimated in Section 4.47The severity of the desulfurization conditions is controlled by the

boiling temperature range of the fraction itself.48A variation of this process, which improves its efficiency, is based on

the use of two columns instead of one. In this design, two distillation

6.3. The oxidative desulfurization process (ODP) process

The oxidative desulfurization (ODP) process is appliedunder mild conditions (room temperature and atmosphericpressure) [20]. As the OATS process, it is a non-consuminghydrogen technique, which is based on the oxidation oforganic sulfur compounds, followed by the extraction ofreaction products (through simple distillation, extractionby solvent, adsorption, etc.). This extraction is possiblebecause when the organic sulfur compounds are oxidized,they form sulfonic compounds (more polar), whosephysical and chemical properties differ considerably fromthose of the hydrocarbons.45 Oxidants such as hydrogenperoxide and formic acid are being tested [72]. This processis still under development, with good prospects for diesel[19], but not so promising for gasoline, due to competitiveolefin epoxidation reactions [73]. In addition, some studiesrecommend the use of the oxidation extraction techniqueas an additional process to the HDS to enable the refineriesto meet the future environmental sulfur regulations [73]:conventional HDS is used to lower the sulfur content to

45Thus, they may be withdrawn from the diesel by solvent extraction

using water-soluble polar solvents, such as NMP, DMF, DMSO and

MeOH [20].

few hundreds parts per million. Then, the oxidation/extraction approach is used to go for ultra deep dieseldesulfurization.There is no data for energy use in commercial units.

Actually, this alternative technique is still under thedevelopment phase, aiming, for example, at improvingthe catalyst system [19]. However, the combined approachof less-severe HDS and ODP, to diesel desulfurization,would imply in energy savings of 40%, solely consideringthe replacement of the severe HDS units assessed for Brazilin Section 4. Clearly, this is a maximum savings potentialonly for diesel treating, as it does not consider the energyuse in the ODP process unit. Nevertheless, considering thatODP combined to less-severe HDS is close to commerci-ality in the mid term [72], 40% was used as a first proxy forestimating the energy savings potential (and CO2 emissionsreduction, similarly) for treating diesel in Brazil. As such,when replacing the conventional diesel HDS, the ODPprocess avoids 23.3% of the total expanded energy useforecasted in Brazil.46

6.4. Catalytic distillation (CD) process

The catalytic distillation (CD) process avoids a drop inthe FCC gasoline octane number by adapting the severityof the HDS process to each component in the gasoline. Ingeneral terms, the gasoline consists of a ‘‘basket’’ of lightand medium hydrocarbons. This ‘‘basket’’ may be frac-tioned by distillation before desulfurization, and eachfraction may be treated in compliance with its prevailingsulfur compound reactivity. Therefore, CD makes itpossible to treat separately various fractions of FCCgasoline under the most appropriate conditions for eachof them in a single operation. Lighter fractions with morereactive compounds are treated under less severe condi-tions.47 This reduces the saturation reactions of the olefins,which are light components of the gasoline. Simulta-neously, the heavier fractions of FCC gasoline containingmore refractory sulfur compounds undergo desulfurizationat higher temperatures at the bottom of the CD column[12].Catalyst distillation takes place in a single piece of

equipment where the FCC gasoline is fractioned and thesefractions are desulfurized. Thus, CD combines separationof FCC gasoline through distillation and catalytic HDS ina same process using in its simplest fitting up a singlereactor or vessel [13].48

columns (CDHydro for the light fractions and CDHDS for the heavy

fractions) are packed with desulfurization catalysts [12]. In this variation,

the first column (CDHydro process) treats light catalytic naphtha to

remove mercaptans and diolefins while increasing octane rating. It

ARTICLE IN PRESSA. Szklo, R. Schaeffer / Energy 32 (2007) 1075–1092 1089

This process was developed by CDTech and has beenapplied in some refineries worldwide, such as Irving St.John in Canada, Motiva Port Arthur in Texas (US) andPembroke Chevron-Texaco in Wales (UK).49 Therefore,differently from the other alternative desulfurizationtechniques, which were analyzed before in this paper, CDis already a commercial option.50 Moreover, data onefficiency of sulfur removal and on energy use areavailable.

For instance, EIPCCB [25] reported that a reduction of95% of sulfur content in FCC gasoline containing1800 ppm has been achieved in units installed in Europeanrefineries. A similar performance was reported by Peningeret al. [74] in Port Arthur refinery in Texas, while Song [12]suggests an average performance of 92%. At ChevronTexaco refinery in Pembroke Wales the distillationcatalytic unit has been successfully applied, since early2002, to reduce the sulfur content of FCC naphthas from2800 to 50 ppm [69]. The experience also showed that thecatalyst cycle at the CD unit is long (5 years of guaranteedcatalyst life), meaning that it reduces the shutdowns duringthe FCC cycle. CD eliminates catalyst fouling becausefractionation removes heavy coke precursors from thecatalyst zone before coke can form and foul the catalystbed [12]. Finally, the commercial experience with CDshows that octane loss was less than 1% [74,76], andgasoline yield loss was null [76].

In terms of energy use, CD also uses less energy, as it issevere only for the heavier fractions of the gasoline. For aunit with a processing capacity of 30,000 barrels per day,and costing around 20 million dollars,51 Hagiwara [76]indicates the hydrogen consumption of 18m3/m3, thepower consumption of 3 kWh/m3, the steam use of 70 kg/m3 and the fuel use of 5.3 kg/m3.

Compared to the severe gasoline HDS units to beinstalled in Brazil in the near-to-mid term (see Section 4),CD reduces the hydrogen consumption by 81% and saves52% of the energy use in HDS. As such, replacing HDS bycatalytic distillation in Brazil can save 62% of the energyuse for treating gasoline, including the energy use in theHDS process and the energy use in the hydrogenproduction. Clearly, the reduction in CO2 emissions is also62%. Moreover, since gasoline HDS accounts for 37% ofthe expanded energy use in Brazilian refineries due tohydrotreating and hydrocracking, CD can avoid 22.8% ofthis increase.

(footnote continued)

eliminates the need for separate caustic treating and selective hydrogena-

tion units. Coupled with the CDHDS process, it enables refiners to

produce ultra low sulfur gasoline at high reliability [69].49For further details, see Peninger et al. [74], Gardner et al. [75] and

Reedy [69].50As of today, there are seven CDHDS commercial units in operation:

Motiva (Port Arthur), Irving Oil (Saint John), Chevron Texaco Pembroke

(UK), Motiva (Convent), Sopus (Puget Sound) and Valero.51These figures agree with those proposed by Song [12], who also

provided operational costs of US$ 0.03 per gallon (including utilities,

catalysts, and hydrogen).

Finally, a promising alternative that is still in theresearch and development stages is biodesulfurization.The commerciality of the biodesulfurization process wouldbe a complete breakthrough in process development. Itwould offer mild processing conditions and reduce the needfor hydrogen makeup. Both would lead to high energy-savings (or CO2 emissions reductions) in the refinery. It hasbeen estimated that biodesulfurization can decrease CO2

emissions (or energy use) in refineries by 70–80%compared to conventional hydrodesulfurization [77].52

Moreover, the specificity of the biochemical reactions isgreater than that of a conventional HDS, particularly forless-reactive compounds such as dibenzothiophene[78,79,80]. For instance, aerobically grown strains, suchas Rhodococcus erythropolis and related species (IGTS8),remove the sulfur from compounds such as dibenzothio-phene (DBT) without degrading the carbon skeleton of thismolecule [81].In addition, DOE [82] anticipates that biodesulfurization

units will achieve, in the mid-to long term, 50% lowercapital costs and 15–25% lower operating costs thanconventional HDS. Biodesulfurization offers potential costsavings, not only because the process operates at ambienttemperature and pressure, but also because it produces anon-toxic by-product, eliminating the need for collateralprocessing of hydrogen sulfide [79].However, research is still needed to study the biological

mechanisms of the biocatalysts,53 including methods tocontrol their activity and selectiveness, and to reduce theircost [78]. Biocatalysts for desulfurization are usuallyobtained by culturing specific species of bacteria in mediawith dibenzothiophene as the sole sulfur source [80]. Asstressed by Cui-Qing et al. [83], at present, there is not yetany economically suitable method for large-scale prepara-tion of biocatalysts due to the high cost of dibenzothio-phene.In addition, the water needs of microbial cells require the

creation of a two-phase biodesulfurization system withhigh interfacial areas through energy-intensive mixing and/or addition of a surfactant, with a post-desulfurizationdeemulsification step [84]. Therefore, designing a cost-effective two-phase bioreactor system coupled to oil-waterseparation and product recovery is also a key challenge tothe viability of biodesulfurization processes. A possibility isto design a multi-staged air-lift reactor to achievecontinuous growth and regeneration of the biocatalyst inthe same system rather than in a separate reactor [85].

52Alsema [1] estimates a similar potential, presenting an average energy

savings of 300MJ/b due to biodesulfurization. For the Brazilian refining

sector, this savings represents 78% of its specific energy use (estimated at

383 MJ per barrel of feedstock—see Sections 4 and 5). Clearly, a similar

result is achieved for the CO2 emissions reduction potential.53The preferable pathway is the one in which dibenzothiphene is

oxidized to DBTO. DBTO is then transformed to DBT sulfone (DBTO2)

and to sulfinate (HPBS), followed by hydrolytic cleavage and subsequent

release of sulfite or sulfate [80]. As such, the sulfur is selectively withdrawn

from the oil product without lowering its heat value.

ARTICLE IN PRESSA. Szklo, R. Schaeffer / Energy 32 (2007) 1075–10921090

Then, the tight emulsions, formed by good oil-cell-watercontact and mixing, can be separated continuouslywith hydrocyclones, to obtain relatively clean oil andwater [84].54

In sum, biodesulfurization has promising prospects inthe mid-to-long term [89]. Biodesulfurization can poten-tially provide a solution to the need for expanded fuelupgrading, because bioprocesses do not require hydrogenand produce far less CO2 than thermochemical processes[88]. However, despite considerable progress, challenges forcommercial application remain [79]. As of today, thetechnology has not yet progressed beyond laboratory-scaletesting [88]. Critical aspects include cost and specificactivity of biocatalysts,55 reactor design and oil–waterseparation. Finally, the widely industrial application ofbiodesulfurization processes has to overcome the fact thatbiodesulfurization is unable to work on highly alkylatedcompounds [79]. Because the composition of organosulfurcompounds in oil products during the life of a refineryvaries significantly, biodesulfurization cannot yet providethe level of reliability required by industrial plants [88].

Therefore, for the near-to-mid term, ODP process fordiesel treating and CD process for gasoline treating appearas the most promising desulfurization alternatives. Accord-ing to the estimates of this study, while conventional HDSfor treating finished oil products potentially expand energyuse by 30% in Brazilian refineries, CD and ODP canpartially avoid the hydrotreating and reduce by 46% thisincrease in energy use.

7. Final remarks

This paper discusses some challenges faced by the worldrefining industry, which are prompted by stricter environ-mental specifications for oil products. These challenges aredriving innovation in oil refineries.

For instance, in Brazil, the reduction in the sulfurcontent of diesel and gasoline between 2002 and 2009might expand the energy use in refineries by some 30%,with similar implications for CO2 emissions. Precisely, thisstudy forecasted the expanded energy use in Brazilianrefineries as 70.4 PJ (expanded CO2 emissions of 1.52MtC).On the opposite, energy savings options can reduce energyuse by 35 PJ (and CO2 emissions by 0.75MtC);56 andalternative desulfurization techniques, which are applicablein the near-to-mid term, can reduce this energy use by 32 PJ(and CO2 emissions by 0.57MtC).

54A promising alternative could be the use of enzymes active in non-

aqueous media [86,87].55For instance, the current available biocatalysts require an increase in

desulfurization rate of about 500-fold [88].56This figure considers an energy savings potential of 15%, deriving

from measures applied simultaneously with alternative treatment pro-

cesses. Thus, energy savings measures can potentially reduce energy use in

Brazilian refineries that simultaneously lower their fuel consumption by

adopting alternative treatment processes.

Therefore, the expanded energy use (or CO2 emissions)in Brazilian refineries resulting from severe hydrotreatmentto comply with more stringent specifications of oil productsmay be almost completely offset by energy savings optionsand alternative desulfurization techniques, if barriers toinvest in technological innovation are overcome.Actually, the petroleum industry is competitive and the

domestic downstream business has, on average, financialresults below other segments of the oil business. The lowreturns in the refining and marketing segment result fromthe competitive nature of the business as well as thesignificant amount of regulatory driven investments thattend to capture little to no return in the market [17]. InBrazil, uncertainties about the domestic oil market regula-tion (price and quality) are also worthwhile. Therefore,decisions by refiners to invest in expanding capacity arecomplex and depend on expectations of return oninvestment. Refinery assets are long-lived and capital needsin refining compete with capital needs in other petroleumsegments. As such, usually, refiners tend to present riskaversion for investing in drastic technological innovations,whose return depends on the uncertain premium price ofhighly specified oil products. Moreover, spending onmandatory environmental projects can detract frominvestments in the core business, which provide capacitygrowth, yield flexibility and reliability improvements.Finally, it is worthwhile to stress that the decreased

sulfur content of diesel and gasoline affects not only theenergy use and the CO2 emissions by refineries worldwide,but also presents impacts on the fuel efficiency of engines(cars and trucks). As this paper discussed before, loweringthe sulfur content of the gasoline pool, through hydro-treating units, reduces its octane number or the thermo-dynamic performance of the Otto engine fuelled with it. Onthe other hand, lowering sulfur in gasoline improves theperformance of the three-way catalytic converter, reducingNOx and CO emissions by the engine. In the case of diesel,lowering its sulfur content affects negatively its lubricity,but positively its cetane number, or the thermodynamicperformance of the diesel engine. In addition, near-zerosulfur diesel allows advanced post-engine exhaust cleanup[26]. Overall, the complete life-cycle energy efficiencyimpact would probably more than offset the expandedenergy use in the refinery, which was estimated by thispaper. However, as mentioned before, this paper empha-sizes alternatives directly related to oil refining (or under-taken inside refineries). Refiners must deal with theexpansion of in-house CO2 emissions and energy use, asthe first is an increasing issue for industrial activities, andthe latter represents an important share of refiners’operational costs.

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