Exergy Costs and CO2 Emissions in Brazil

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or

5 April 2015Accepted 8 May 2015Available online 6 June 2015

portation sector, including fossil fuels (natural gas, oil-derived products and hydrogen), biofuels (ethanol

At a time of economic uncertainty and environmental concerns,

regulatory policies must be incorporated only after a detailed per-formance and sustainability assessment has been achieved,including not merely the end use stages, but also the upstream fuelproduction processes [2]. Because their non-renewable nature,

decline to 89% by 2030 [3], as vehicles running on renewableon such fuels un-extent to whichdepends on howay uneconomic inre still required asd, most regions dole electric vehicleste signicantly to

2 ce of strong effortsto decarbonize electricity generation, vehicle electrication alsoseems unlikely to be an environmentally friendly and cost-effectiveroute [1]. Fortunately, both Brazilian electricity and transportationsector mixes have been characterized by an approach that ispeculiar within the international context of dependence on fossilfuels. Brazilian electricity mix is mainly dominated by renewableenergy sources (89%) and although diesel oil (48.6%), gasoline(28.2%) and natural gas (2.2%) still dominate the transportationsector mix, sugar-cane ethanol shares more than 14.5% [5,6], and it

* Corresponding author.E-mail addresses: [email protected] (D. Florez-Orrego), [email protected]

Contents lists availab

Ener

els

Energy 88 (2015) 18e36(J.A.M. da Silva), [email protected] (H. Velasquez), [email protected] (S. de Oliveira).one of the major consumers of the world's primary energy, namelythe transportation sector, is recognized as a hugely important issueacross the global economy [1]. In fact, the rational use of the mostsuitable fuels favorably affects the way scarce resources are used,improving the economy performance and reducing the environ-mental impact. However, the quest for higher energy efcienciesthrough the advent of new technologies may also alter the vehicledemand proles, as well as modify the levels of emissions and fuelconsumption. Thus, gradual improvements on technology and

sources gain more attention and engines baseddergone constant developments. However, thefossil fuel substitution can be achieved largelyrenewables are produced, which is likely to stmost markets where continued cost reductions arenewable fuels scale up [3,4]. On the other hannot generate enough low CO2 electricity to enab(EV) and plug-in hybrid EV (PHEV) to contribularge CO reductions. Consequently, in the absendependence of global transportation sector (94%) is forecast toKeywords:RenewableNon-renewableExergy costTransportation sectorCO2 emissions

1. Introductionhttp://dx.doi.org/10.1016/j.energy.2015.05.0310360-5442/ 2015 Elsevier Ltd. All rights reserved.different units of the processing plants is characterized. An exergoeconomy methodology is developedand applied to properly allocate the renewable and non-renewable exergy costs and CO2 emission costamong the different products of multiproduct plants. Since Brazilian electricity is consumed in the up-stream processing stages of the fuels used in the generation thereof, an iterative calculation is used. Theelectricity mix comprises thermal (coal, natural gas and oil-red), nuclear, wind and hydroelectric powerplants, as well as bagasse-red mills, which, besides exporting surplus electricity, also produce sugar andbioethanol. Oil and natural gas-derived fuels production and biodiesel fatty acid methyl-esters (FAME)derived from palm oil are also analyzed. It was found that in spite of the highest total unit exergy costscorrespond to the production of biofuels and electricity, the ratio between the renewable to non-renewable invested exergy (cR/cNR) for those fuels is 2.69 for biodiesel, 4.39 for electricity, and 15.96for ethanol, whereas for fossil fuels is almost negligible.

2015 Elsevier Ltd. All rights reserved.

increasing price and the effects of global warming, the fossil fuelsReceived 3 November 2014Received in revised form and biodiesel) and electricity is performed, and the percentage distribution of exergy destruction in theArticle history: An exergy and environmental comparison between the fuel production routes for Brazilian trans-Renewable and non-renewable exergy cproduction of fuels for Brazilian transpo

Daniel Florez-Orrego a, *, Julio A.M. da Silva b, Hecta Polytechnic School, University of Sao Paulo, Sao Paulo, Brazilb Polytechnic School, Federal University of Bahia, Salvador, Brazilc Faculty of Minas, National University of Colombia, Medellin, Colombia

a r t i c l e i n f o a b s t r a c t

journal homepage: www.ts and CO2 emissions in theation sector

Velasquez c, Silvio de Oliveira Jr. a

le at ScienceDirect

gy

evier .com/locate/energy

Costs. Analogously, the CO2 emissions cost (cCO2) is dened as theamount of total CO2 emitted (directly and indirectly) to obtain oneunit of exergy of analyzed substance/ow or electricity [gCO2/kJ]. It

does not need to be explicitly known. It is pointed out that this

/ Energy 88 (2015) 18e36 19is expected to achieve 30% in 2030 [7]. Transportation sector inBrazil consumed almost 30% of national energy demand and pro-duced 48% of the total CO2 emissions through four types of vehiclestechnologies: gasoline C-dedicated, ex-fuel, hydrated ethanol-dedicated (commercialized until 2007), compressed natural gas(CNG) and diesel B05 (5% in vol. biodiesel), the latter used only bycommercial and passenger light vehicles with a minimum capacityload of 1000 kg [8e10]. Moreover, other technologies such as testeets of electric taxi cabs earned recent interest and started to becommercialized. In this way, a rational comparison of the fuel op-tions for the Brazilian scenario is required, encompassing petro-leum and natural gas derivatives, biofuels, as well as electricity. Thisprovides an opportunity to quantify the renewable and non-renewable exergy consumption and thereby pursues and priori-tizes the use of the most environmentally friendly sources of en-ergy, also serving as a theoretical base for issuing guidelines in thetransportation sector. Some studies based on Extended Life CycleAnalysis (ELCA) have addressed specic assessments on biofuels orpetroleum derivatives production routes. Beer et al. [11] inAustralia, and Hossain et al. [12] in Bangladesh, performed a lifecycle analysis of the production routes of vehicle fuels includingfossil and alternative sources. In Brazil, D'Agosto and Ribeiro [13]performed a Life Cycle Inventory (LCI) to determine the total andrenewable energy and greenhouse gas emissions of gasoline, CNGand ethanol-powered vehicles in the case of Rio de Janeiro. Theauthors concluded gasoline C presents the lowest energy con-sumption along its life cycle. Hawkins et al. [14] performed anenvironmental life cycle assessment of conventional and electricvehicles, concluding that electric vehicles powered by the presentEuropean electricity mix offer a 10%e24% decrease in globalwarming potential relative to conventional diesel or gasoline ve-hicles. Ma et al. [15] carried out a comparison between the lifecyclegreenhouse gas (GHG) emissions of battery electric vehicles inEurope, identifying the need to correctly assign the relevant GHGemissions to the electricity consumed in battery-powered vehicles,i.e. the emissions associated to thewell to tank analysis. Seckin et al.[16] developed the analysis of transportation sector in Turkey, byusing the Extended Exergy Accounting (EEA), obtaining globalexergy efciency as low as 36%, mainly due to the high proportionof non-renewable energy sources used in the transportation mix.However, these works are all based on the principle of the First Lawof Thermodynamics (except for [16]), which does not take intoaccount the quality of the energy consumed and the exergydestruction (entropy generation) through the irreversible processesoccurring in the fuel production routes. Thus, in this work an exergyand environmental analysis based on the Second Law of Thermo-dynamics is presented, encompassing the integrated productionroutes of the conventional and alternative fuels of the Braziliantransportation mix and accounting for their CO2 emission costs.

2. Methodology

The approach used in this analysis is based on thermoeconomymethodologies [17e23] and aims to properly allocate the renew-able and non-renewable exergy costs and CO2 emission costs alongthe different production routes. Each fuel production route iscomposed of three different types of stages, namely supply stage,transformation stage and end use stage, used to represent eachprocess that the different fuels are subjected to along the entireproduction and end use route, as shown in Fig. 1. The Non-Renewable Unit Exergy Cost (cNR) is dened as the quantity ofnon-renewable exergy necessary to produce one unit of exergy ofanalyzed substance/ow (e.g., water, wind, biomass, nuclear orfossil fuel) or electricity [kJ/kJ]. Thus, the Total Unit Exergy Cost (c )

D. Florez-Orrego et al.Tincludes the Renewable (cR) and Non-Renewable (cNR) Unit Exergyhypothesis does not necessarily imply that exergy consumed (C) oneach stage is totally destroyed, but that the exergy cost of the fuelthat lastly attains the transformation and end use stages is burdenedwith the global effect of the irreversibilities present along all thepreceding supply stages. Hence, the mathematical representation ofthe total and non-renewable exergy cost accumulation for a givensupply stage (see Fig 1a) can be expressed as in (1) and (2),

1 Stages whose objective is the extraction, transportation and preparation offeedstock or supplied fuels, F, used in the transformation and end use stages. Thesemust be pointed out that, even though the term fuel is generallyused to designate substances that store chemical exergy, in contrastto those used to produce mechanical exergy from their kinetic orpotential exergy (such as wind or water in a reservoir), the termfuel in this paper also represents any substance used to produceelectricity or mechanical power (such as wind in wind farms andnuclear fuel in pressurized water reactors).

2.1. Supply stage

At the rst stage (k 0) of the so-called supply stages1 (s), theexergy of the fuel B0F;s as present in the environment (petroleumand gas fromwell, coal and uranium ore, biomass, wind and water)enters the control volume used to analyze each route. As the streampasses through the downstream supply stages (k > 0), the total andnon-renewable exergy costs as well as CO2 emission cost related tothe supplied streamBkF;s, are accumulated along the route. Since theexergy consumed in the supply stages, BiC;s, has also been previouslyprocessed, either in the same stage (self-consumption of suppliedfuel) or in another stage (e.g. a petroleum renery product), it alsocarries total and non-renewable exergy costs and CO2 emissioncost, besides producing direct CO2 emissions when consumed inthe respective supply stage. In this way, the scheme that better tsthe supply stage is presented in Fig. 1a, where k and k1 stand forthe supplied fuel streams (F) that enter and leave the analyzed stage(s) and i represent the different exergy consumptions (C) of thesame stage. Processes that can be considered supply stages areextraction, mining, agriculture, transportation of pre-processedfuel or feedstock, and fuels distribution processes. Furthermore,since exergy consumption in construction, operation and decom-missioning stages can be amortized along the lifetime of theequipment or plant, then, those stages can also be considered assupply stages. Accordingly, the inputs of the supply stage correspondto the exergy of the supplied fuel (F) and the exergy consumed (C) inthat stage. Meanwhile, outputs correspond to the exergy of thesupplied fuel leaving the supply stage and the CO2 emissions relatedto such stage. Because these stages supply the raw material,feedstock and fuels (pre-processed or nished) necessary totransformation and end use stages to operate, a hypothesis thatsimplies the analysis of this kind of stages can be considered. Byregarding the exergy of the fuel supplied to the transformation, BlF;t ,or end use stage, BiF;n, as the basis to calculate the unit exergy andCO2 emission costs of the streams that go through the upstreamsupply stages along the different fuel production and electricitygeneration routes, consequently: B0F;s BkF;s Bk1F;s BF;ft or ng. In this way, an analysis based on exergy cost balancesinstead of exergy rate/ow rate balances is carried out and theirreversibility, i.e., the exergy destruction of each supply stageBigen,stages require additional exergy inputs called exergy consumption, C, besides ofthat supplied by the fuel F itself.

supplied fuel [gCO2/kJ]. Those terms can be calculated using Eqs.

Sup

D. Florez-Orrego et al. / En20respectively, where B stands for the exergy rate/ow rate of theanalyzed stream [kW]:

ck1T ;F;sBk1T ;F;s ckT ;F;sBkT ;F;s

Xi

ciT ;C;sBiT ;C;s (1)

ck1NR;F;sBk1T ;F;s ckNR;F;sBkT;F;s

Xi

ciNR;C;sBiNR;C;s (2)

Analogously, the CO2 emission cost balance can be written as in(3), where direct CO2 emissions,2 related to the consumption ofexergy input i in each stage, are accounted for in the MiCO2 term[gCO2/s], analogous to Z termused to account for capital investmentin thermoeconomy:

X

Fig. 1. Exergy and CO2 emissions costs accumulation stages: (a)ck1CO2;F;sBk1T ;F;s ckCO2;F;sBkT;F;s

i

ciCO2;C;sBiT ;C;s MiCO2;s (3)

Then, by considering that B0F;s BkF;s Bk1F;s BF;ft or ng , when dividing both sides of (1e3) by the exergy of thefuel that goes through the analyzed supply stage (s) Bk1F;s , thoseequations can be simplied to (4e6):

ck1T ;F;s ckT ;F;s Xi

ciT;C;s$r

iT ;s

(4)

ck1NR;F;s ckNR;F;s Xi

ciNR;C;s$r

iNR;s

(5)

ck1CO2;F;s ckCO2;F;s

Xi

ciCO2;C;s$r

iT ;s miCO2;s

(6)

where riT ;s andriNR;s represent the i-th total and non-renewable

exergy consumption per unit of exergy of supplied fuel [kJ/kJ],respectively, andmiCO2 ;s is the amount of CO2 directly emitted owedto the burning of the i-th consumed fuel per unit of exergy of

2 Net or fossil CO2 emissions which increase the amount of CO2 present in theatmosphere.(7e9):

riT ;s BiT ;C;sBk1T ;F;s

(7)

riNR;s BiNR;C;sBk1T ;F;s

(8)

miCO2;s MiCO2;sBk1T ;F;s

(9)ply stage (s); (b)Transformation stage (t); (c) End Use stage (n).

ergy 88 (2015) 18e362.2. Transformation stage

The objective of transformation stages (Fig. 1b) is the processingand transformation of raw materials, feedstock and pre-processedfuels, supplied by supply stages, in order to produce value-addedproducts (e.g. vehicle fuels) and other co-products used in otherstages. Whenmore than one product is produced in the same stage,a detailed exergoeconomy analysis of the specic stage must beemployed to properly split the exergy and CO2 emission costsamong all the different products in a rational manner. Thisapproach avoids classifying the products between main productsand by-products, splitting the costs between all the products of thesame plant based on the exergy destroyed for their production . Anexergy cost balance for a given transformation stage, based on theblack box analysis shown in Fig. 1b, yields to coarse results and abetter accuracy can be obtained if a more detailed analysis is ach-ieved. Fig. 2 evidences that a transformation stage can be analyzedas being composed of a series of sub-stages, which, in turn, may beconsidered as supply stages (sub-stage t4, e.g. as sugar canewashingand transportation units in themill, water cooling unit and so forth)or transformation stages (sub-stage t1 and t2, e.g. as fermentationprocesses, uidized catalytic cracking unit, et cetera.), as well as enduse stages, which will be analyzed later (sub-stage 5, e.g. as gen-eration of electricity exported to the grid).

Thus, based on the control volume adopted for the different sub-stages, the total and non-renewable exergy costs and CO2 emission

/ Encost balances for each sub-stage (t1, t2, t3 ) composing thetransformation stage, can be written as in Eqs. (10e11)Xr

crT ;P;tBrT;P;t

Xl

clT ;F;tBlT;F;t

Xj

cjT ;C;tBjT ;C;t (10)

Xr

crNR;P;tBrT ;P;t

Xl

clNR;F;tBlT ;F;t

Xj

cjNR;C;tBjNR;C;t (11)

where B stands for the exergy rate/ow rate of the supplied fuels (l)and the exergy consumptions (j) entering the transformation stage,

Fig. 2. Detailed analysis of a transformation stage.

D. Florez-Orrego et al.as well as for the exergy rate/ow rate of the different products (r)of the respective stage. On the other hand, the CO2 emission costbalances can be written as in (12), where the direct CO2 emissionseither produced by burning the different fuel consumptions (j), oras a result of the chemical reactions arisen from the transformationprocesses of the supplied fuels (e.g. fermentation, steam reformingprocess, etc.), are accounted for in theMjCO2;t and theMCO2 ;reac terms[gCO2/s], respectively:Xr

crCO2;P;tBrT ;P;t

Xl

clCO2;F;tBlT ;F;t

Xj

cjCO2;C;tB

jT ;C;t M

jCO2;t

MCO2;reac

(12)

2.3. End use stage

In the end use stages (Fig.1c) it is considered that the only exergyinput is the supplied fuel,BiF;n, used to generate electricity (i.e. powerplant) or mechanical power (e.g. a vehicle, in the case of trans-portation sector) (BE/W,n). Thus, in this kind of stage no additionalexergy inputs, aside from the fuel delivered from supply stages ortransformation stages, are considered. Hence, the supplied fuel isresponsible for the direct CO2 emissions, provided that it containsfossil carbon (Fig. 1c). In this way, in the case of the end use stage theterms BiT ;C;n and B

iNR;C;n are null by denition, so the balance for

exergy costs and CO2 emission cost can be written as shown in Eqs.(13e15):cT ;E=W;nBE=W;n cT ;F;nBT ;F;n (13)

cNR;E=W;nBE=W;n cNR;F;nBT;F;n (14)

cCO2;E=W;nBE=W;n cCO2;F;nBT;F;n MCO2;n (15)By dividing both sides of (13e15) by the electricity generated or

the mechanical power produced in the respective stage (BE/W,n),then Eqs. (16e18) are obtained:

cT ;E=W;n cT ;F;nrT ;n (16)

cNR;E=W;n cNR;F;nrNR;n (17)

cCO2;E=W;n cCO2;F;nrT;n mCO2;n (18)

where rT,n represents the total exergy consumption per unit ofelectricity generated or mechanical power produced [kJ/kJ], andmCO2 ;n the amount of CO2 directly emitted in the end use stage perunit of electricity generated or mechanical power produced [gCO2/kJ]. Those terms can be calculated by using Eqs. (19e20):

rT ;n BT ;F;nBE=W ;n

(19)

rCO2;n MCO2;nBE=W ;n

(20)

By inspection, the values of rT,n and mCO2;n correspond to theinverse of the exergy efciency,hex, and the specic direct CO2emissions (if present) at the end use stage, respectively. It is worthto notice that, whereas the exergy efciency of the electricitygeneration plants can be considered as reported in literature fordifferent technologies [23], in the case of the end use of a vehiclefuel used in transportation sector (or other fuels used in residentialor industrial sectors), the denition of exergy efciencywill dependon the useful product of the end use stage (transport service,heating, cooling, lighting) as discussed in Ref. [24]. In Fig. 3, asimplied representation of the relationships between the differenttypes of stages is shown. The supply stages s 1, 2 and s 3, 4could be interpreted as extraction and transportation stages forcrude oil and non-associated natural gas, respectively, to renery(transformation sub-stages called t1 and t2). Meanwhile, stagess 5, 6 and 7 could be understood as extraction, transportation andstock of mineral coal. The end use stages n 1 and n 2 may beinterpreted as an oil-red thermoelectric power plant and a vehiclerunning on, say, diesel oil. Other products of the transformationstage t 1 are not used either in transportation sector applicationsnor electricity generation; nevertheless, this analysis still can beused to allocate their corresponding unit exergy and CO2 costs (e.g.coke, sulfur in petroleum reneries, or glycerol, surplus bagasse,and so forth, in bioreneries).

The calculation procedure of the exergy consumption in thedifferent stages along the electricity generation routes in Brazilianelectricity mix follows closely that carried out by Ref. [23]. It isimportant to notice that, often in Life Cycle Analysis (LCA) litera-ture, the energy consumption (thermal or electrical) in each stageof a given electricity generation route is reported in the way ofconsumed energy per unit of electricity generated (or I/O,inputeoutput ratio, in kJ/kWh or GW/GWe). Based on those values,it is possible to calculate the exergy consumption per unit of exergy

ergy 88 (2015) 18e36 21of a supplied fuel (the fuel that goes through the supply stage),quantity that was previously dened as ris [kJ/kJ]. This is achieved by

ffere

D. Florez-Orrego et al. / En22using the energy efciency of the electricity generation stage, hen,and the value of 4, i.e., the ratio between the specic chemicalexergy (bCH) and the lower heating value of the fuel (LHV) [25], forboth consumed 4iC and supplied fuel 4nF , according to (21):

ris

EiC;sEE=W;n

!|{z}

I=O

$4iC;s$

EE=W;nEF;n

|{z}

hen

$14F;n

(21)

Here EiC;s stands for energy rate/ow rate of the consumed fuel,which, in turn, can be total or non-renewable, and E is the energy

Fig. 3. Relationship between the diF,nof the supplied fuel. Besides, EE/W,n is the electricity generated oneach route. It must be pointed out that in the case of the exergyassociated to substances like water and wind, as well as to elec-tricity, the value of 4 is considered equal to unity, since the po-tential and kinetic energies as well as the electric energy are equalto the potential, kinetic or electric exergies of the substances orelectricity, respectively. In the case of the power plant, the value ofrn 1/hex can be calculated by using (22):

rn

EF;nEE=W;n

!|{z}

1=hen

$4F;n (22)

Meanwhile, direct CO2 emissions, derived from the combustionof a fuel containing carbon, will depend on the amount ofconsumed fuel and its fossil carbon content.3 Those emissions canbe calculated according to (23):

MCO2 MC$IC$Rm (23)

where Rm ~ 3.7 [kgCO2/kgCarbon] is the ratio between the molecularweight of carbon dioxide and atomic carbon, MC [kgFuel/s] is the fuel

3 Biomass-derived net CO2 emissions are considered null, since the CO2 emittedby those sources undergoes a closed cycle of absorption and release by the plants[26].consumption rate, and IC [kgCarbon/kgFuel] is the fossil fuel carboncontent of the consumed fuel, based on the elemental analysis. Inthis way, the net direct CO2 emissions per unit of exergy of fuelpassing through the supply stage (s) [gCO2/kJ] can be calculatedaccording to (24):

miCO2;s EiC;sEE=W

!|{z}

I=O

$

EE=WEF;n

|{z}

hen

$

MiC;sEiC;s

!|{z}1=LHViC

$IiC;C;s$Rm$14F;n

$1000

nt types of stages and sub-stages.

ergy 88 (2015) 18e36(24)

where IiC;C;s represents the fossil carbon content of the i-th fuelconsumed in the supply stage (s), which clearly is zero in the case ofthe electricity consumption. Analogously, in order to determine thedirect CO2 emissions per unit of electricity generated in the elec-tricity generation stage (n), those values can be calculated by using(25) [gCO2/kJ]:

mCO2;n

EF;nEE=W;n

!|{z}

1=hen

$

MC;sEF;n

|{z}1=LHVC

$IC;F;n$Rm$1000 (25)

where IC,F,n represents the carbon content of the fuel fed to the enduse stage (namely, the power plant). By denition, IC,F,n is zero forthe fuels of wind farms, nuclear power plants and hydropowerplants. Finally, it is emphasized that, differently from unit exergycost balances, for which the initial value of unit exergy costsentering the control volume of each route can be regarded as theunity (or a given value if known from other exergoeconomy anal-ysis), the initial value for CO2 emission cost balances is considerednull. Moreover, since some processed streams are consumed inother stages, and some stages consume electricity from the grid, aniterative calculation is employed to solve the set of non-linearequations for the mass, exergy, unit exergy costs and CO2 emis-sion cost of the fuels involved in the Brazilian transportation sector.

3. Petroleum and natural gas production route

Fig. 4 shows the stages of the routes of production of natural gasand petroleum-derived fuels. This scheme is used to calculate theaccumulated unit exergy cost and CO2 emission cost according tothe methodology proposed in Section 2. The streams are labeled byusing a letter based on the previous stage, i.e. crude oil or naturalgas followed by ES represents the stream leaving the extractionand primary separation process. Analogously, T and P stand forthe streams leaving the shuttle tanker and the pipeline trans-portation stage, respectively. Since almost 90% of Brazilian petro-leum production is offshore, the petroleum is considered as

Rening stage is based on a typical petroleum renery asstudied by Silva and Oliveira Jr. [32]. and Silva et al. [27], with acracking-coking scheme (See Appendix A.1). A specic exer-goeconomy analysis encompassing the different production unitsof the petroleum renery is used to calculate the exergy and CO2emission costs for the different products, including diesel and fueloil used in other stages and for power generation. In Fig. 5 thepercentage distribution of destroyed exergy at different units in therenery is presented.

As it can be seen in Fig. 5, utilities plant is responsible for 34% ofthe destroyed exergy, due to the highly irreversible processes thatoccur in that unit such as steam throttling for pressure reduction,

D. Florez-Orrego et al. / Energy 88 (2015) 18e36 23extracted from the well of an offshore platform [27]. According toNakashima et al. [28], the non-renewable unit exergy costs forcrude oil and natural gas after extraction and primary separationare 1.006 kJ/kJ and 1.025 kJ/kJ, respectively. Since part of the pro-duced natural gas is consumed in this stage, the exergy consump-tion and CO2 emissions per unit of exergy of crude oil and naturalgas produced can be obtained. In this way, CO2 emission costs canalso be easily calculated and those values are shown in Table 1.

The exergy consumption in oil transportation from sea to land iscalculated assuming the use of a shuttle tanker Suezmax-type. Byconsidering a travelling route of 800 km at a speed of 13 knots and aload capacity of 155,000 tons, as well as the ofoading operations ofplatform and tanker, it is possible to calculate the exergy con-sumption of bunker fuel and the direct CO2 emissions as 42.32 kJ/(km.tOil) and 3.06 gCO2/(km.tOil) [27]. As bunker fuel is a processedfuel, the determination of its unit exergy costs and CO2 emissioncost requires an iterative calculation. The oil transportation fromland base to the renery is performed through pipelines byconsuming electricity from the national electric grid. Thus, by usingthe ColebrookeWhite correlation [29] for pressure drop calcula-tion, in addition to data of petroleum pipeline and a pumping ef-ciency of 60%, the calculated exergy consumption is 100.3kJ/(km.tOil). Since electricity consumed in land oil transportationcomes from the national grid, the unit exergy costs and CO2 emis-sions of transported oil will depend on the whole electricity mix. Inthe case of natural gas transportation through pipelines, it isconsidered that part of transported gas is burnt in gas turbines todrive the gas compressors. By considering a transportation lengthof 1350 km through the BrazileBolivia gas pipeline (GASBOL) [30],together with an isentropic compression efciency of 80% and a gasturbine efciency of 37% (LHV basis), it is possible to determine theexergy consumption and CO2 emissions related to natural gastransportation as 1.063 kJ/(km.tNG) and 58.2 gCO2/(km.tNG),respectively. Natural gas composition reported by Ref. [31] is usedto calculate the 4 value for natural gas. Table 1 presents the unitexergy cost and CO2 emission of the different streams along theproduction route of the petroleum-derived fuels and natural gas.These values are used as input data in exergoeconomy analysis forthe renery stage.Fig. 4. Production route of pfossil fuel combustion and heat exchanges with nite temperaturedifferences. Combined distillation process is responsible for one-third of the exergy destruction in the renery owed to the pres-ence of highly irreversible combustion reactions present at theburning of the fuel consumption source used to distillate themixture. Meanwhile, sulfur recovery, storage and transfer, and acidwater treatment units together are responsible for only 1.4% of theexergy destruction. The renewable and non-renewable unit exergycosts for the different products of the renery are summarized inTable 2:

According to Table 2, specic CO2 emissions associated withgasoline and diesel oil production amount to 0.0103 and0.0016gCO2/kJfuel, respectively. Considering the chemical exergyand density of those produced fuels, these values are equivalent to328.25kgCO2/m3 for gasoline and 63.13kgCO2/m3 for diesel oil. Thisis a consequence of a further processing of gasoline compared tocommon straight run diesel. On the other hand, because of the highenergy intensity of the endothermic steam methane reforming(SMR) process and large CO2 emissions in reforming and shift re-actions of hydrogen generation, this fuel presents the largest CO2emission cost and its unit exergy costs are greater than any otherpetroleum-derived fuel, even than that of hydro-treated diesel oil.Although hydrogen could achieve a high efciency conversionthrough water electrolysis (70%), this process remains a cost-intensive process due the massive use of electricity, and the eco-nomic attractiveness depends signicantly on the relative costs forhydrogen and natural gas. At present, the capital investments ofhydrogen production are about ve times smaller via natural gasrather than wind or solar energy in Brazil [33]. As a consequence,the share of hydrogen production by means of SMR process issubstantially higher than for other technologies [34], so that, in thiswork such scenario is adopted. Moreover, it must be noticed that cR/cNR ~0.0010 for the different products of the renery. The reason isthat, along the production route of petroleum-derived fuels, theonly renewable exergy contribution comes from the electricityused in the transportation of crude oil via pipelines. All theremaining exergy sources consumed are basically non-renewable.Finally, for natural gas dehydration and treatment process data,the energy consumption reported for Cabinas Treatment Plantetroleum-derived fuels.

(TECAB), with a processing capacity of 575,000 m3 of natural gas, isconsidered. According to [35], in order to treat 467,509 kJ of naturalgas, 8397 kJ of natural gas and 1901 kJ of electricity are required.Thus, by using this data and 4 value for natural gas, an exergyconsumption of 0.0180 kJ of natural gas and 0.0039 kJ of electricityper kJ of processed natural gas is calculated. Hence, the renewableand non-renewable exergy costs and CO2 emission cost of treatednatural gas are obtained as 0.0189 kJ/kJ, 1.0978 kJ/kJ and0.0049gCO2/kJ, respectively.

4. Biodiesel production route

of the energy consumption in the lifetime of the plant. Assuming

Table 1Unit exergy cost and CO2 emission cost of the different streams along the productionroute of petroleum-derived fuels and natural gas.

Stream cT (kJ/kJ) cR (kJ/kJ) cNR (kJ/kJ) cCO2 (gCO2/kJ)

Petroleum 1.0000 0.0000 1.0000 0.0000Crude oil e ES 1.0060 0.0000 1.0060 0.0006Natural gas e ES 1.0250 0.0000 1.0250 0.0006Bunker fuel 1.0504 0.0008 1.0496 0.0029Crude oil e T 1.0073 0.0000 1.0073 0.0007Electricity 1.7956 1.4628 0.3328 0.0174Water 1.0000 1.0000 0.0000 0.0000Crude Oil e P 1.0082 0.0007 1.0075 0.0007Natural gas e P 1.0550 0.0000 1.0550 0.0023

D. Florez-Orrego et al. / En24Around the world, different cultures, including soy, sunower,rapeseed, palm fruit, coconut or evenwasted frying oil from animalfats are used to produce biodiesel. However, oil-seed crops otherthan tropical palm oil (with 18e26% oil and producing 5900 L/ha)yield fairly small amounts of fuel per hectare, which impactsnegatively the production of food supplies and increases the fossilenergy expended in agriculture and transport activities. This facthas suggested the culture of palm as the utmost potential crop forbiodiesel production in Brazil [36]. The biodiesel production routevia palm oil can be divided in agriculture and transportation stagesand in the biodiesel production plant. The plant comprises an oilextraction and purication unit, a biodiesel production unit, aFig. 5. Percentage distribution of destroyed exergy at different units in the petroleumrenery. DE, combined distillation unit; CQ, delayed coking unit; FCC, uidized cata-lytic cracking unit; HDT, hydrotreating unit; HG: hydrogen generation unit; SR: sulfurrecovery unit; ST: storage and transfer unit; SWT: sour water treatment unit; UT:utilities plant.water treatment unit and a utilities plant (See Appendix A.2). Fig. 6shows the representation of different stages through which thefresh fruit bunches (FFB) passes in the biodiesel production route,used to calculate the accumulated unit exergy and CO2 emissioncosts of the biodiesel and its by-products (glycerol). The differentFFB streams are labeled by using a letter based on the previousstage, i.e., FFB followed by A stands for the stream leaving theagriculture process, whereas a letter T represents a stream leav-ing transportation stage.

Natural resource inputs in the agriculture stage such as solarenergy, water and CO2 absorbed by the plant are considered to beequal to the mass, energy and exergy embodied in the biomass ofthe FFB. Thus, the only irreversibilities emerged from agricultureactivities are considered as those related to the use of non-renewable energy sources such as fertilizers, pesticides and dieseloil in agriculture activities [37]. By considering that FFB arecomposed of oil (26%), water (49%), and ber (25%), the chemicalcomposition of the FFB is used to calculate the chemical exergy(16268kJ/kgFFB) and 4 value (1.0736) thereof. The approximatechemical composition of biodiesel derived from palm oil (C18H35O2)allows determining the chemical exergy (39,128 kJ/kg) and the 4value (1.0484) of this fuel [38,39]. For the Brazilian case, herbicidesand irrigation systemsmake only a small contribution to the energyconsumption, as adult palms are not irrigated and herbicides areused only sporadically in isolated crop areas a few times per year[40]. Then, the major fossil exergy consumption (2.85 MJ/kgbiodiesel)comes from other inputs such as natural gas for fertilizers pro-duction (29.3%), diesel oil for farming (64.2%), and transportation ofraw material (4.4%). Table 3 presents the unit exergy and CO2emission costs of the different streams along the biodiesel pro-duction route. These values are used as input data in exer-goeconomy analysis for the biodiesel plant stage. On the otherhand, by considering a biodiesel production plant with a lifetime of20 years, the energy required to build the plant and equipment isreported as 0.732MJ/kgbiodiesel [41], which represents less than 5%

Table 2Renewable and non-renewable unit exergy costs and CO2 emission cost for thedifferent products of the petroleum renery.

Product cT (kJ/kJ) cR (kJ/kJ) cNR (kJ/kJ) cCO2 (gCO2/kJ) cR/cNR

GLP 1.0738 0.0010 1.0728 0.0081 0.0009Kerosene 1.0308 0.0010 1.0298 0.0016 0.0010Gasoline 1.0810 0.0011 1.0799 0.0103 0.0010Diesel 1.0308 0.0010 1.0298 0.0016 0.0010Naphtha 1.0400 0.0011 1.0389 0.0021 0.0011Gasoil 1.0422 0.0010 1.0412 0.0028 0.0010Sulphur 1.0928 0.0011 1.0917 0.0075 0.0010Coke 1.0726 0.0011 1.0715 0.0037 0.0010Diesel HDT 1.1129 0.0010 1.1119 0.0074 0.0009Hydrogen 1.5139 0.0002 1.5137 0.0739 0.0013

ergy 88 (2015) 18e36that this energy is provided by diesel oil and taking into accountthat 4diesel 1.0662, the exergy consumption is calculated as r 0.0115kJ/kJFBB, whereas related direct CO2 emissions resultsmCO2 0.0008 gCO2/kJCFF.

After FFB arrive at the biodiesel production plant, a sterilizationprocess by using saturated steam at 3 bar during 60 min is per-formed. Sterilization of FFB is necessary for deactivating enzymesresponsible for oil splitting in free fatty acids (FFA), facilitating thedigestion by weakening the pulp structure of the fruits and helpingin the threshing process [42]. Thereafter, the fruits (mesocarp, berand nut) are conveyed to a digester where they are softened andconverted into a homogenous mash, while the empty fruit bunches(stems) are returned to the plantation or used as boiler fuel. Themash is transferred to a twin screw press where oil is extracted, andthe press cake and liquor (composed of oil, water and impurities)

between the renewable and non-renewable unit exergy cost forbiodiesel production from palm oil is cR/cNR 2.69.

5. Ethanol production route

Ethanol production in Brazil relies entirely on sugar cane (14.5%sucrose, 13.5% ber or bagasse, 2% soluble solids and 70% water),whereas cane bagasse represents 83% of the total biomass-basedelectricity generation capacity [44]. More than 70% sugar canemills operate using an annexed plant scheme with simultaneousproduction of sugar and ethanol [45]. The most common congu-

oute (CONST, construction stage).

D. Florez-Orrego et al. / Energy 88 (2015) 18e36 25are separated. Electricity consumption in extraction process is thelargest in the biodiesel production plant and reaches 9 kW h/tFFB[38]. The oil present in the liquor is claried by removing the sludgein sedimentation tanks. The claried phase is sent to centrifugalclarication and then goes through a vacuum dryer to reduce themoisture content in order to slow down hydrolysis and oxidation.On the other hand, the nuts and bers are recovered, dried andsubsequently separated from each other by using a cyclone system.By cracking the nuts, the shells and kernels are separated. Fiber andshells can be used as fuel in utilities plant, whereas the kernel isused for palm kernel oil extraction [38]. Total steam consumptionin FFB pre-treatment, oil extraction and separation unit is 446 kg/tFBB, whereas work consumption is 90,000 kJ/tFBB (25kWh/tFBB).Biodiesel is produced by transesterication of the vegetable oil,where triglycerides (TG) of cleaned oils are mixed with methanol(CH3OH) and a catalyst (usually sodium hydroxide, NaOH), causingthe oil molecules to break apart and reform into methyl esters (ME)and glycerol (G), according to (R.1). Transesterication reactor re-quires continuous stirring at 60 C for 1 h, using heat provided bysaturated steam at 3 bar [38]. Conversion efciency of trans-esterication process reaches 95e99% depending on the quantity ofFFA present in the oil [42]. Glycerol is then separated and the ob-tained methyl esters compose the biodiesel produced [1]:

TG 3CH3OH! NaOH3ME G (R.1)According to Fig. 7, the utilities plant is responsible for 70% of

destroyed exergy, mainly due to highly irreversible process such aschemical reactions in biomass-red boilers and heat exchange withnite temperature differences in the cogeneration plant. Watertreatment unit is the second largest contributor to exergydestruction, since that unit consumes a large quantity of exergywith the only useful effect of removing water pollutants, withoutan appreciable modication of the exergy of the substances. Oilextraction and biodiesel production unit present a lower quantity

Fig. 6. Biodiesel production rof destroyed exergy because of the high efciency of oil extractionand transesterication processes [38,39]. As a conclusion, therenewable and non-renewable unit exergy costs of biodiesel pro-duction are 1.0996kJ/kJbiodiesel and 0.4084kJ/kJbiodiesel, respectively,whereas CO2 emission cost is calculated as 0.0249gCO2/kJbiodiesel (or866kgCO2/m3biodiesel). This result is close to that reported for bio-diesel production as 864kgCO2/m3biodiesel [40e43]. Thus, the ratio

Table 3Unit exergy costs and CO2 emission cost of the different FFB streams along thebiodiesel production route.

Stream cT (kJ/kJFFB) cR (kJ/kJFFB) cNR (kJ/kJFFB) cCO2(gCO2/kJFFB)

FFB 1.0000 1.0000 0.0000 0.0000FFB-A 1.0362 1.0000 0.0362 0.0024FFB-T 1.0384 1.0001 0.0383 0.0026ration of utilities plants are based on cogeneration Rankine cyclesusing bagasse-red boilers (22 bar/300 C), able to entirely supplythe energy demand of themill, and still produce a surplus of bagasse(5e10% of biomass) and electricity to the grid (0-10 kW h/tc) [4,45].A back-pressure steam turbine of two stages produces the electricityconsumed in the whole plant and the surplus electricity, whereasanother turbine produces solely the mechanical power used in themilling process [46]. Cogeneration power plant efciency achieves15e17% [47]. Fig. 8 shows the different stages used to calculate theaccumulated unit exergy and CO2 emission costs of the ethanol andother products of the sugar cane mill. The cane streams are labeledby using a letter based on the previous stage, i.e., the letter Ameans the stream is leaving the agriculture process, whereas TFig. 7. Percentage distribution of destroyed exergy at different units in the biodieselproduction plant. EX, oil extraction and pretreatment unit; BD, biodiesel productionunit; WT, water treatment unit; UT, utilities plant.

sug

D. Florez-Orrego et al. / En26indicates the stream is leaving the transportation stage. The pro-cessing units of the mill are classied as cane washing and milling(juice extraction), juice clarication and concentration, syrup crys-tallization and sugar renement, must fermentation, wine distilla-tion, collection and cooling of condensates, and the utilities plant,where the steam, electricity andmechanical power used in the unitsof the mill are produced (See Appendix A.3).

The non-renewable energy consumption for the ethanol pro-duction is reported as 147kJ/MJethanol, distributed between theconsumption of natural gas to produce fertilizers (27%) and dieselconsumption in sugar cane transportation and farming (73%) [45].The yield of anhydrous ethanol, reported as 68.3 kg per ton of cane(tc) (or 86.3 L/tc) [4], together with the lower heating value (LHV)and 4 for natural gas (1.0325), diesel oil (1.0662), sugar cane(1.1880) and ethanol (1.0319) are used to trace back the total andnon-renewable exergy costs as well as the CO2 emission cost of thesugar cane, along the agriculture and transportation stages. Thisdata is summarized in Table 4. These values are used as input datain exergoeconomy analysis for sugar cane mill stage.

After the cane reaches the mill, it is conveyed and washed, inorder to remove rocks, stalks and impurities that it may contain.Then, the cane is prepared using rotary blades in order to enhancethe juice extraction, for which imbibitionwater is also added. In theextraction process unit, ber and juice (sucrose, water and dissolvedsolids) are separated by using four tandemmills composed of threemilling rolls powered by mechanical driving (16 kWh/tc) suppliedby utilities plant [38,46]. After extraction, bagasse (48e52% hu-midity) can be used as fuel at the cogeneration plant. Thereafter, inthe juice claricationprocesses, lime is added to the juice in order toocculate solid impurities, remove dissolved gases, reduce viscosityand perform the juice sterilization. The decanted residue of clari-cation (mud) is taken to a rotary vacuum lter (0.24e0.78 bar)

Fig. 8. Combined production route of ethanol,where it is mixedwith ne bagasse (bagacillo) and imbibitionwaterto recover the sucrose, so conforming the lter cake which can beused as a crop fertilizer. Next, claried juice is sent to concentrationprocess unit, which consists of a vacuum evaporation systemcomposed of ve sequential Robert type evaporators. Steam pro-duced in the rst evaporator is used to heat the juice in the next one,reducing the steam consumption in the plant. The juice preheaterand the rst heat exchanger are fed with saturated steam (2.5 bar)supplied by cogeneration plant. The steamproduced in the rst heatexchanger, or vegetable steam (1.7 bar), is used in the second one aswell as in other processes (clarication, crystallization and sugarrenement). Finally, concentrated juice or syrup (65 Brix4) is sent tocrystallization units, where batch vacuum evaporators are used toobtain the massecuite (saturated sugar solution and sugar crystals),

4 1 Brix corresponds to 1 g of sucrose per 100 g of juice.and then it is conduced to centrifugal separation process, wheresucrose crystals are separated from saturated solution (molasses).This solution is evaporated and centrifuged until molasses exhaus-tion is achieved (95 Brix, 23 purity), when it can be used for ethanolproduction by mixing it with claried juice and syrup. Meanwhile,raw sugar is dissolved again until 65Brix, decanted, vacuumevaporated, and centrifuged. Then, rened sugar is dried, packedand stored. Some chemicals, such as ammonium sulfate (NH4)2SO4,mono potassium phosphate KH2PO4, as well as a blend of yeast milkand sulfuric acid are added to molasses, syrup and claried juicemixture, in order toobtain themust thatwill be sent to fermentationvats. By keeping the temperature at 33 C and anaerobic conditionsin a Melle-Boinot batch, yeast (Saccharomyces cerevisiae) convertsreduced sugars into ethanol and CO2, according to (R.2) [47]:

C12H22O11H2O/2C6H12O67kcal/4C2H5OH4CO254kcal(R.2)

Fermentation process efciency achieves 91%, although otherchemical compounds such as aldehydes, heavy oils and fusel oil canalso be formed. After the fermentation, the mixture is centrifuged,separating the yeast, while the wine is sent to the distillationprocess unit. Distilled and rectied hydrated ethanol is produced inseparate distillation columns. If necessary, anhydrous ethanol isobtained in a third column used to split the azeotrope and obtain a99.9%v/v alcohol. The energy consumption for the mill and ma-chinery construction is reported as 43MJ/tc [5]. Considering dieseloil (4 1.0662) as the exergy consumption source used for theconstruction stage and the exergy embodied in machinery, alongwith the chemical exergy of cane (5273 kJ/kg), then the exergyconsumption and direct CO2 emissions are calculated asr 0.0082kJ/kJcane and mCO2 0.0006 gCO2/kJcane. According to

ar and electricity (CONST, construction stage).

ergy 88 (2015) 18e36Fig. 9, utilities plant account for 62% of the exergy destruction,mainly due to biomass burning as fuel and the low energy con-version efciencies in the low pressure Rankine cycles. Fermenta-tion reaction of ethanol and CO2 production also contribute withabout 21.2% of destroyed exergy, so better control of fermentationvat temperatures can enhance the performance of this process [46].Exergy destruction inwashing and milling process unit is related tosucrose loss in the bagasse, as well as to high power consumption oflow efciency equipment, such as direct driving turbines,commonly employed in Brazilian sugar cane mills.

Renewable and non-renewable unit exergy costs of the differentproducts of sugar cane mill are shown in Table 5, which closelyagree with those reported in Ref. [47]. The high cost of electricity isa consequence of the low energy conversion efciency and largeexergy destruction of the cogeneration plant.

Obtained CO2 emission cost of ethanol production is0.0127gCO2/kJethanol (or 300.12kgCO2/m3ethanol), ranging between

269 and 345kgCO2/m3alcool reported by Refs. [4,45]. It is worth tonotice that, since the CO2 emitted in fermentation process (30.96kgCO2/tc or 754kgCO2/m3ethanol) is derived from sugar canebiomass and recycled in sugar cane growing, it is not considered asatmospheric net CO2 emissions. Finally, by considering all the sugarcane mill products, mean cR/cNR ratio is calculated as 16.

6. Electricity generation in Brazilian electricity mix

In Brazil, the total electricity demand in 2011was approximately567 TWh including the net imports (about 35.9 TWh), accountingfor 18.1% of total energy consumption and approximately 8.0% ofnational CO2 emissions. The integrated Brazilian electricity mix isdominated by hydroelectricity (81.9%) and biomass cogeneration

Table 4Unit exergy costs and CO2 emission cost of substances along the upstream processes of ethanol production route from sugar cane.

Stream LHV (kJ/kg) cT (kJ/kJcane) cR (kJ/kJcane) cNR (kJ/kJcane) cCO2(gCO2/kJcane)

Cane 4438 1.0000 1.0000 0.0000 0.0000Cana-A 4438 1.0514 1.0000 0.0514 0.0034Cana-T 4438 1.0590 1.0000 0.0590 0.0039Natural gas 47,330 1.0550 0.0000 1.0550 0.0023Diesel oil 42,350 1.0382 0.0008 1.0374 0.0033Water e 1.0000

D. Florez-Orrego et al. / Energy 88 (2015) 18e36 27plants (6.6%), followed by natural gas (4.4%), nuclear (2.7%) and oilproducts (2.5%), with coal products playing a much smaller role(1.4%). Wind power undergoing recent developments still repre-sents only 0.5% of electricity mix [6]. The renewable (1.4627kJ/kJe)and non-renewable (0.3328kJ/kJe) unit exergy costs and CO2emission cost (62.63 gCO2/kWh) of the electricity generation inBrazil, as reported by Refs. [23], were calculated by using aweighted average of the renewable and non-renewable unit exergycosts and CO2 emission cost of the electricity generated in eachroute, according to the national electricity mix prole [6]. Thosevalues are useful to compare the utilization of electricity and otherenergy sources at the end use stages, such as transportation, resi-dential and industrial sectors.Fig. 9. Percentage distribution of destroyed exergy at different units of sugar cane mill.CL, clarication unit for sugar (SU) or ethanol (ET) production; CO, concentration unit;CR; crystallization and sugar renement; DE, distillation unit; FE, fermentation unit;MO, washing and milling unit; RE, condensates cooling unit; UT, utilities plant.7. Discussion

In Fig. 10, a comparison between the renewable and non-renewable unit exergy costs and CO2 emission cost in the produc-tion of the fuels used in transportation sector is shown.

As it can be seen in Fig. 10, even though petroleum-derived fuelsand natural gas show the lowest total unit exergy cost, most of suchcost is non-renewable, cR/cNR~0. Among the petroleum derivatives,gasoline, LPG and hydrotreated diesel present the largest CO2emissions, because of the further processing, if compared with theproducts of combined distillation unit. Meanwhile, hydrogen unitexergycost is approximately 25% greater than that of natural gas andother petroleum-derived fuels, besides showing the largest CO2emission cost. Indeed, as hydrogen is produced fromnon-renewablesources, such as energy intensive SMRprocess, the benets of its useover natural gas (and gas-to-liquid derivatives) in transportationsector, in terms of logistic, distribution, technological limitationsand safety is still questioned [48,49]. On the other hand, despite thatthe largest unit exergy costs correspond to biofuels and electricity,the largest proportion of these costs is renewable. For instance, ahigh share of hydropower and biomass electricity generationmakesa large proportion of the unit exergy cost of the Brazilian electricityto be renewable (cR/cNR 4.39). Furthermore, the ratio betweenrenewable to non-renewable unit exergy cost for sugar cane ethanolis calculated as cR/cNR 15.96, whereas for biodiesel, that gure is2.69.However, as far as traditional cogenerationplants still persist inBrazil, it is possible to increase the conversion efciency of utilitiesplant by using advanced technologies such as bagasse integratedgasication combined cycles (BIGCC) or supercritical cycles [47],reducing the costs of the different products of the mill. It is alsoworth to notice that, among the biofuels, ethanol presents thelowest non-renewable unit exergy costs, partly because of the dis-tribution of unit exergy costs and CO2 emission cost of ethanolproduction between the sugar and electricity generated. Thus, inautonomous distilleries, CO2 emissions related to ethanol produc-tion could be higher depending on the amount of ethanol produced.Regarding palm oil biodiesel, CO2 emission costs are appreciablyincreased because of the use of energy-intensive fossil inputs, suchasmethanol and sodiumhydroxide. Sincemethanol is still producedfrom natural gas, methanol-based transesterication process pro-duces more CO2 emissions than if it was yielded using bioethanol[26,38e42]. It is very important to point out that, at this extent, the

1.0000 0.0000 0.0000CO2 emissions shown in Fig.10 do not take into account the analysisof fuel distribution and the end-use applications in transportationsector (i.e. direct burning of liquid or gaseous fuels in internal

Table 5Renewable and non-renewable unit exergy cost of the different products of sugarcane mill.

Product cT (kJ/kJ) cNR (kJ/kJ) cCO2 (gCO2/kJ) cR/cNR

Rened sugar 1.9550 0.1129 0.0083 16.32Ethanol 3.0560 0.1802 0.0127 15.96Surplus Electricity (9.2kWh/tc) 6.6230 0.3658 0.0246 17.10

cos

/ Encombustion engines, electricity utilization in battery-powered ve-hicles or hydrogen consumption in fuel cells). If direct CO2 emissionsfor those activities were accounted for, the CO2 emission cost for thefossil fuels would increase further, probably surpassing the emis-sions related to biofuel and electricity production. Besides, it isreasonable to expect that other technological, economic, social andpolitical issues can inuence the choice of fuels production, butthose issues areoutof the scopeof thiswork. Finally, it is emphasizedthatwhatever the primary energy source, either renewable or fossil,all of them are kinds of solar energy storage. The only difference isthe time scale on which they are produced. While biofuels capturesolar energy in a relatively small time scale, petroleum reservoirs

Fig. 10. Comparison between the renewable and non-renewable unit exergy

D. Florez-Orrego et al.28represent a process that occurs in a geological time scale. This dif-ference in the dynamic of the solar energy storage is the key of ourdenition of renewable and non-renewable energy [26]. Accordingto this, considering an scenario forwhich the exploitation rate of theprimary energy sources could not be continued indenitely at thecurrent energy consumption rate or, as well, by using low efciencytechnologies, then the sustainability could not be guaranteed evenfor renewable energy sources or any of those studied in this work.

8. Conclusion

In this work, an exergy and environmental comparison betweenthe fuel production routes for transportation sector in Brazil,including fossil fuels, biofuels andelectricitygeneration is presented.Renewable and non-renewable unit exergy and CO2 emission costsare calculated and the R/NR invested exergy ratios (cR/cNR) for bio-diesel (2.69), electricity (4.39), and ethanol (15.96) are calculated. Asa result, it was found that fossil fuels require the lowest exergy in-vestment for the entire production chain, including oil and naturalgas extraction, transportation, oil rening andnatural gas treatment.In spite of this, the renewable fraction of the invested exergy isalmost negligible, whereas the CO2 emission costwill depend on thelevel of processing of the fuel. On the other hand, besides the sub-sidies and governmental policies required to renewable fuels scaleup, other improvements on biofuels production routes, such as ahigher efciency of cogeneration power plants and the defossiliza-tion of the exergy consumption at the upstream agriculture andtransportation stages, are required. In this way, lower unit exergycosts of ethanol andelectricitycouldbeachievedby (i) usingbiomassderivatives such as biofuels to carry out the farming activities, (ii)promoting the organic fertilization, using the residual biomass of thedifferent cultures, and (iii) replacing the traditional cogenerationtechnologies at the Brazilian sugar cane mills (introducing BIGCC orsupercritical cycles). Regarding hydrogen used as a transportationfuel, as far as it depends on fossil fuels for its production, the cost-benet, security, energy density and environmental impacts sug-gest that other fossil sources such as natural gas or petroleum de-rivatives may accomplish a better performance.

ts and CO2 emission cost of the different fuels used in transportation sector.

ergy 88 (2015) 18e36Acknowledgments

The rst author would like to acknowledge National Agency ofPetroleum, Gas and Biofuels e ANP and its Human Resources Pro-gram (PRH/ANP) grant No. 6000.0067392.11.4. Second authorwould like to thank CNPq grant No. 143302/2009-4. Fourth authorwould like to thank National Research Council, CNPq grants306033/2012-7.

Nomenclature

c unit exergy cost (kJ/kJ)B exergy rate or ow rate (kW)b specic exergy (kJ/kg)BIGCC bagasse integrated gasication combined cyclesCNG compressed natural gasE energy (kJ)EEA extended exergy accountingELCA extended life cycle analysisEV electric vehiclesE/W electricity (kWh) or mechanical power (kW)FAME fatty acid methyl-estersFFA free fatty acidsFFB fresh fruit bunchesG glycerolGHG greenhouse gasesI fuel carbon content (% weight)

I/O input to output energy ratioLCA life cycle analysisLHV lower heating valueLCI life cycle inventorym specic direct CO2 emissions (gCO2/kJ)M direct CO2 emissions (gCO2/s)ME methyl estersPHEV plug-in hybrid electric vehicler exergy consumption (kJ/kJ)Rm molecular mass ratio between carbon dioxide and

elemental carbon (kg/kg)SMR steam methane reformingT temperature, C, Ktc ton of caneTG triglyceridesv/v volume fraction

Greek symbolsh efciency4 ratio between the chemical exergy (bCH) and lower

heating value (LHV)

Subscripts and superscriptsC Fuel consumptionCH chemical exergyCO2 carbon dioxide

en energyex exergyF Processed fueli i-th supply stage consumptionj j-th transformation stage consumptionk k-th supply stage inputk1 k-th supply stage outputl k-th transformation stage inputn end use stageNR non-renewable0 initial stepP Produced fuelPH physical exergyr r-th transformation stage productR renewablereac non combustion-derived CO2 emissionss supply stageT totalt transformation stage

Appendix A

In this section, the schemes of the fuel production plants as wellas the properties and unit exergy costs of the streams produced ineach unit are depicted.

A.1. Petroleum renery

D. Florez-Orrego et al. / Energy 88 (2015) 18e36 29Fig. A.1. Scheme of the petroleum renery. Adapted from Ref. [32].

Table A.1Thermal properties, unit exergy costs and CO2 emission costs of the different streams in petroleum renery units.

N Name T (C) P (bar) m (kg/s) BT (kW) bCH (kJ/kg) bPH (kJ/kg) cT (kJ/kJ) cNR (kJ/kJ) cCO2 (gCO2/kJ)

1 Crude oil-TT 30 6.0 315.28 14,121,120 44,789 0.55 1.0082 1.0075 0.00072 Natural gas-TT 25 1.0 2.60 127,062 48,870 0.00 1.0550 1.0550 0.00233 Water 25 1.0 195.92 9796.13 50.00 0.00 1.0000 0.0000 0.00004 Heat e e e 3593.94 e e e e e5 Fuel gas 36 5.0 1.68 82,617.55 49,143 42.82 1.0308 1.0298 0.00166 Condensate 25 1.0 0.00 0.00 50.00 0.00 2.1089 2.1069 0.09217 Low pressure steam 164 4.0 2.47 1855.37 50.00 701.16 1.0308 1.0298 0.00168 Compressed air e e 0.3 56.63 e e 5.0454 5.0424 0.25449 Fuel gas 36 5.0 3.26 161,045 49,143 42.82 1.0737 1.0724 0.008210 Low pressure steam 165 4.0 7.56 5678.77 50.00 701.16 1.9491 1.9474 0.080411 Medium pressure steam 292 14 10.42 10,612.25 50.00 968.45 2.1944 2.1922 0.098412 Electricity e e e 6690.00 e e 3.1818 3.1801 0.162613 Industrial water 25 1.0 0.00 0.00 50.00 0.00 1.8810 1.8805 0.045314 Rectied water 25 1.0 28.99 1449.63 50.00 0.00 1.0727 1.0716 0.006615 Sour water 25 1.0 15.51 775.50 50.00 0.00 2.1089 2.1069 0.092116 Vacuum residue 170 5.0 71.75 3,103,806 43,261 56.46 1.0308 1.0298 0.001617 Heavy gasoil 108 5.0 44.59 1,971,732 44,215 19.82 1.0308 1.0298 0.001618 Light gasoil 125 5.0 3.28 146,059 44,481 28.70 1.0308 1.0298 0.001619 Heavy naphtha 25 1.0 12.43 582,209 46,854 0.00 1.0308 1.0298 0.001620 Liqueed gas 39 5.0 1.21 60,013 49,562 72.64 1.0308 1.0298 0.001621 Kerosene 25 1.0 22.44 1,037,912 46,253 0.00 1.0308 1.0298 0.001622 Heavy diesel 163 5.0 12.82 574,353 44,789 36.33 1.0308 1.0298 0.001623 Light diesel 125 5.0 66.18 3,012,217 45,514 30.41 1.0308 1.0298 0.001624 Light naphtha 25 1.0 20.82 988,093 47,465 0.00 1.0308 1.0298 0.001625 Vacuum residue 172 5.0 25.62 1,108,275 43,260 57.99 1.0308 1.0298 0.001626 Top residual gasoil 25 1.0 8.43 377,141 44,720 0.00 1.0308 1.0298 0.001627 Residual water 25 1.0 11.85 592.39 50.00 0.00 1.0727 1.0716 0.006628 Sour water 25 1.0 10.70 535.00 50.00 0.00 3.8990 3.8974 0.184129 Rectied water 25 1.0 7.56 378.23 50.00 0.00 1.0727 1.0716 0.006630 Rectied water 25 1.0 7.15 357.25 50.00 0.00 1.0727 1.0716 0.006631 Sour water 25 1.0 9.84 491.85 50.00 0.00 2.1014 2.0993 0.091332 Sour water 25 1.0 26.67 1333.50 50.00 0.00 2.1766 2.1753 0.073133 Rectied water 25 1.0 6.60 329.80 50.00 0.00 1.0727 1.0716 0.006634 Low pressure steam 165 4.0 0.21 160.18 50.00 701.16 2.1944 2.1922 0.098435 Condensate 95 4.0 12.10 969.63 50.00 30.15 2.1940 2.1918 0.098436 Low pressure steam 165 4.0 0.03 18.84 50.00 701.15 1.9491 1.9475 0.080437 Medium pressure steam 292 14 12.29 12,512.94 50.00 968.45 2.1944 2.1922 0.098438 Sour gas 98 1.48 0.57 10,374.35 18,178 32.97 1.0727 1.0716 0.006639 Low pressure steam 165 4.0 1.84 1379.41 50.00 701.16 1.4139 1.4125 0.009540 Medium pressure steam 292 14 2.03 2067.00 50.00 968.45 1.0327 1.0317 0.007341 Medium pressure water 143 29 3.87 508.27 50.00 81.48 2.5523 2.5503 0.103242 Fuel gas 25 6.0 0.03 1699.97 47,978 260.63 1.0737 1.0724 0.008243 Compressed air e e 0.30 56.63 e e 5.0454 5.0424 0.254444 Natural gas 24 30 2.52 124,352 48,870 464 1.0550 1.0550 0.002345 Medium pressure water 143 28 3.87 508.83 50.00 81.48 2.5523 2.5503 0.103246 High pressure water 143 117 15.29 2143.05 50.00 90.16 2.6721 2.6701 0.110047 Electricity e e e 730.00 e e 3.1818 3.1801 0.162648 Fuel gas 25 6.0 0.27 13,342.32 47,978 388.12 1.0737 1.0724 0.008249 Low pressure steam 165 4.0 8.03 6034.82 50.00 701.16 1.5139 1.5137 0.073950 Condensate 95 4.0 12.96 1038.76 50.00 30.15 2.9875 2.9856 0.128951 Medium pressure steam 292 14 4.97 5061.70 50.00 968.45 2.1944 2.1922 0.098452 Fuel gas 25 6.0 0.49 24,020.61 47,978 510.53 1.0737 1.0724 0.008253 Electricity e e e 4080.00 e e 3.1818 3.1801 0.162654 Compressed air e e 0.30 56.62 e e 5.0454 5.0424 0.254455 Condensate 95 4.0 15.95 1278.03 50.00 30.15 2.1766 2.1753 0.073156 Low pressure steam 165 4.0 1.19 893.88 50.00 701.16 1.0810 1.0799 0.010357 Fuel gas 25 6.0 5.33 267,255 47,978 11,532 1.0810 1.0799 0.010358 CO gas 728 2.6 58.01 67,963.71 e e 1.0810 1.0799 0.010359 Medium pressure steam 292 14 17.03 17,344.20 50.00 968.45 1.0810 1.0799 0.010360 Compressed air e e 0.30 56.63 e e 5.0454 5.0424 0.254461 Electricity e e e 1716.00 e e 3.1818 3.1801 0.162662 Medium pressure water 143 28 18.22 2395.57 50.00 81.48 2.5523 2.5503 0.103263 Industrial water 25 1.0 36.02 1812.17 50.00 0.00 1.8810 1.8805 0.0453

D. Florez-Orrego et al. / Energy 88 (2015) 18e3630

Table A.1 (continued )


64 Natural gas 13 4.0 0.17 8408.42 48,870 100 1.0550 1.0550 0.002365 Mechanical power e e e 17,350.00 e e 4.3900 4.3855 0.214766 Low pressure steam 165 4.0 1.60 1201.86 50.00 701.16 1.0726 1.0715 0.003767 Fuel gas 35 1.4 2.62 125,787 47,978 31.79 1.0726 1.0715 0.003768 Condensate 95 4.0 11.67 935.65 50.00 30.15 2.1014 2.0993 0.091369 Compressed air e e 0.30 56.63 e e 5.0454 5.0424 0.254470 High pressure water 143 117 0.09 12.05 50.00 90.16 2.6721 2.6701 0.110071 Fuel gas 25 1.0 1.26 60,452.28 47,978 0.00 1.0737 1.0724 0.008272 Low pressure steam 165 4.0 5.47 4108.85 50.00 701.16 1.9491 1.9475 0.080473 Medium pressure steam 292 14 10.41 10,602.06 50.00 968.45 2.1944 2.1922 0.098474 Electricity e e e 6390.00 e e 3.1818 3.1801 0.162675 Condensate 95 4.0 0.0001 0.00815 50.00 31.50 1.9491 1.9475 0.080476 Gasoil 25 1.0 1.50 67,069.83 44,713 0.00 1.0456 1.0445 0.003677 Electricity e e e 5575.00 e e 3.1818 3.1801 0.162678 Natural gas 25 1.0 0.06 2932.38 48,870 0.00 1.0550 1.0550 0.002379 Low pressure steam 165 4.0 0.0001 0.08 50.00 701.16 1.9491 1.9475 0.080480 Compressed air e e 0.3 56.63 e e 5.0454 5.0424 0.254481 Liqueed gas 35 1.3 2.16 103,413 47,805 57.56 1.0726 1.0715 0.003782 Light naphtha 25 1.0 6.67 309,966 46,502 0.00 1.0726 1.0715 0.003783 Heavy naphtha 205 2.75 2.60 116,980 45,063 85.89 1.0726 1.0715 0.003784 Heavy gasoil 34 18 11.94 516,482 43,268 2.28 1.0726 1.0715 0.003785 Heat e e e 426.77 e e e e e86 Light gasoil 194 18 12.56 565,382 45,011 84.82 1.0726 1.0715 0.003787 Medium gasoil 187 18 17.06 748,699 43,880 69.39 1.0726 1.0715 0.003788 Heat e e e 3141.91 e e e e e89 Naphtha 25 1.0 17.31 813,084 47,081 0.00 1.0456 1.0445 0.003690 Gasoil 25 1.0 58.08 2,552,814 44,114 0.00 1.0456 1.0445 0.003691 Light cycled oil 25 1.0 0.00 0.00 43,739 0.00 1.0810 1.0799 0.010292 Decanted oil 25 1.0 7.76 329,421 42,467 0.00 1.0810 1.0799 0.010293 Liqueed gas 25 1.0 7.76 380,265 49,024 0.00 1.0810 1.0799 0.010294 Gasoline 25 1.0 42.38 1,992,087 47,004 0.00 1.0810 1.0799 0.010295 Light cycled oil 37 1.0 7.09 309,993 43,739 0.45 1.0810 1.0799 0.010296 Sour gas 35 1.4 0.10 1595.08 15,877 182.74 1.0726 1.0715 0.003797 Sulfur 25 1.0 1.30 24,899.99 19,154 0.00 1.0928 1.0917 0.007598 Sour gas 98 1.4 0.90 16,418.60 18,178 32.97 1.1129 1.1119 0.007499 Low pressure steam 165 4.0 18.06 13,567.28 50.00 701.16 1.5139 1.5137 0.0739100 Hydrogen 35 20 0.66 79,499.36 117,116 3796.6 1.5139 1.5137 0.0739101 Medium pressure steam 292 14 4.46 4546.14 50.00 968.45 1.5139 1.5137 0.0739102 Medium pressure steam 292 14 0.11 111.01 50.00 968.45 1.1129 1.1119 0.0074103 Sour water 25 1.0 24.25 1212.56 50.00 0.00 3.8990 3.8974 0.1841104 Heat e e e 6.34 e e e e e105 Hydrotreated diesel 25 6.2 58.59 2,649,372 45,222 e 1.1129 1.1119 0.0074106 Heat e e e 1050.01 e e e e e107 Wild naphtha 25 1.0 0.16 7141.10 44,632 0.00 1.1129 1.1119 0.0074108 Heavy diesel 163 5.0 22.28 997,760 44,789 54.44 1.0308 1.0298 0.0016109 Liqueed gas 25 1.0 11.13 543,691 47,805 0.00 1.0738 1.0728 0.0081110 Kerosene 25 1.0 22.44 1,037,912 46,253 0.00 1.0308 1.0298 0.0016111 Gasoline 25 1.0 42.38 1,992,087 47,004 0.00 1.0810 1.0799 0.0103112 Vacuum residue 25 1.0 25.62 1,108,275 43,260 0.00 1.0308 1.0298 0.0016113 Diesel oil 25 1.0 79.01 3,586,570 45,394 0.00 1.0308 1.0298 0.0016114 Naphtha 25 1.0 25.36 1,191,305 46,976 0.00 1.0400 1.0389 0.0021115 Gasoil 25 1.0 16.42 721,963 43,969 0.00 1.0422 1.0412 0.0028116 Coke 25 1.0 16.04 606,319 37,800 0.00 1.0726 1.0715 0.0037117 Brine 25 1.0 30.74 1449.63 50.00 0.00 1.0308 1.0298 0.0016118 Sour gas 25 1.0 0.39 6158.04 15,710 0.00 1.0809 1.0789 0.0103

D. Florez-Orrego et al. / Energy 88 (2015) 18e36 31

A.2. Biodiesel production plant

Fig. A.2. Scheme of the biodiesel production plant.

Table A.2Thermal properties, unit exergy costs and CO2 emission costs of the different streams in biodiesel production plant.

N Name T (C) P (bar) m (kg) BT (kJ) bCH (kJ/kg) bPH (kJ/kg) cT (kJ/kJ) cNR (kJ/kJ) cCO2 (gCO2/kJ)

1 FFB 25 1.0 1000 16,268,000 16,268 0.00 1.0000 0.0000 0.00002 Natural Gas 25 1.0 e e 48,873 0.00 1.0550 1.0550 0.00233 Diesel Oil 25 1.0 e e 45,152 0.00 1.0382 1.0374 0.00334 FFB-A 25 1.0 1000 15,839,000 16,268 0.00 1.0362 0.0362 0.00245 Diesel Oil 25 1.0 e e 45,152 0.00 1.0382 1.0374 0.00336 FFB-T 25 1.0 1000 15,839,000 16,268 0.00 1.0384 0.0383 0.00267 Shells 25 1.0 68.00 1,129,000 16,602.94 0.00 1.2480 0.0461 0.00318 Fibres 25 1.0 180.00 2,260,000 12,555.56 0.00 1.2480 0.0461 0.00319 Stems 25 1.0 210.00 1,536,000 7314.29 0.00 1.2480 0.0461 0.003110 Kernels 25 1.0 52.00 2,079,000 39,980.77 0.00 1.2480 0.0461 0.003111 Oil 25 1.0 210.00 8,155,560 38,836 0.00 1.2480 0.0461 0.003112 Mixed Condensate sat 3.0 220.43 25,935.79 50.00 67.66 1.2480 0.0461 0.003113 Clean Condensate sat, 3.0 195.59 23,013.70 50.00 67.66 8.8340 0.3284 0.022014 H2SO4 25 1.0 2.96 4929 1666 0.00 1.8005 1.3504 0.085715 NaOH 25 1.0 2.42 4523.30 1873 0.00 18.1126 13.813 0.861916 CH3OH 25 1.0 92.40 2,070,499 22,408 0.00 1.7946 1.7946 0.105417 CH3OH 25 1.0 70.11 1,571,025 22,408 0.00 1.5080 0.4084 0.024918 Na2SO4 25 1.0 5.37 700.30 130.31 0.00 0.00 0.0000 0.000019 Water loss sat 1.0 8.40 4472.16 50.00 482.4 0.00 0.0000 0.000020 FFA 25 1.0 7.35 274,831 37,391.97 0.00 0.00 0.0000 0.000021 Glycerol 25 1.0 22.29 410,208 18,403.23 0.00 1.5080 0.4084 0.024922 Biodiesel 25 1.0 200.50 7,845,164 39,128 0.00 1.5080 0.4084 0.024923 Clean Condensate sat 3.0 167.49 19,706.41 50.00 67.66 8.8340 0.3284 0.0220

5.41 50.00 12.77 1.5080 0.4084 0.02490 50.00 0.00 18.1200 0.7025 0.0469

D. Florez-Orrego et al. / Energy 88 (2015) 18e363224 Washing water 69,7 1.0 75.60 47425 Washing water 25 1.0 84.00 420

26 Condensate 60 3.0 590.90 34,431.15 50.00 8.27 18.1200 0.7025 0.0469

A.3. Ethanol production plant


N Name T (C) P (bar) m (kg) BT (kJ) bCH (kJ/kg) bPH (kJ/kg) cT (kJ/kJ) cNR (kJ/kJ) cCO2 (gCO2/kJ)

27 Residual Water 30 1.0 294.20 14,710 50.00 0 18.1200 0.7025 0.046928 Air 25 1.0 506.60 0.00 0.00 0.00 0.0000 0.0000 0.000029 Flue Gas e 1.0 612.40 118,561 98.90 94.70 0.0000 0.0000 0.000030 Air 25 1.0 680.20 0.00 0.00 0.00 0.0000 0.0000 0.000031 Flue Gas e 1.0 822.20 159,178 98.90 94.70 0.0000 0.0000 0.000032 Biomass 25 1.0 258.20 3,242,476 12,558 0.00 1.2480 0.0461 0.003133 Electricity e e e 1048.38 e e 8.8340 0.3284 0.022034 Steam sat 3.0 446.00 309,970 50.00 645 8.8340 0.3284 0.022035 Electricity e e e 90,000 e e 8.8340 0.3284 0.022036 Electricity e e e 11,340 e e 8.8340 0.3284 0.022037 Steam sat 3.0 167.50 116,413 50.00 645 8.8340 0.3284 0.022038 Residual Biomass 25 1.0 199.80 2,509,088 12,558 0.00 1.2480 0.0461 0.003139 Sludge 25 1.0 310.00 433,038 1396.90 0.00 1.2480 0.0461 0.0031

FFA: Free Fatty Acids.

D. Florez-Orrego et al. / Energy 88 (2015) 18e36 33Fig. A.3. Scheme of ethanol, sugar and electricity combined production mill. Adapted from Ref. [46].

Table A.3Thermal properties, unit exergy costs and CO2 emission costs of the different streams in sugar cane mill.


1 Cane 25 1 138.90 732,420 5273 0.00 1.0000 0.0000 0.00002 Natural gas 25 1 e e 48,873 0.00 1.0550 1.0550 0.00233 Diesel 25 1 e e 45,152 0.00 1.0382 1.0374 0.00334 Cane-A 25 1 138.90 732,420 5273 0.00 1.0514 0.0514 0.00345 Diesel 25 1 e e 45,152 0.00 1.0382 1.0374 0.00336 Cane-T 25 1 138.90 732,420 5273 0.00 1.0590 0.0590 0.00407 Washing water 25 1 37.00 1850 50.00 0.00 1.0000 0.0000 0.00008 Washing water 25 1 37.00 1850 50.00 0.00 0.0000 0.0000 0.00009 Imbibition water 50 6 41.70 2278.91 50.00 4.65 1.8240 0.1054 0.007710 Mech. power e e e 8000 e e 6.6230 0.3685 0.024611 Bagasse 25 1 38.90 388,416.5 9985 0.00 1.1610 0.0647 0.004312 Juice (sugar) 35 6 98.80 272,336.3 2755 1.44 1.1610 0.0647 0.004313 Juice (ethanol) 35 6 42.90 118,251.3 2755 1.44 1.1610 0.0647 0.004314 Electricity e e e 1200 e e 6.6230 0.3685 0.024615 Flash steam 97 0.9 1.5 783 50.00 472 0.0000 0.0000 0.000016 Filter cake 25 1 3.40 7350.8 2162 0.00 1.2160 0.0717 0.005517 SO2 25 1 0.10 489.20 4892 0.00 2.0379 1.5542 0.463418 CaO 25 1 0.10 196.51 1965.05 0.00 2.6049 1.9866 0.237919 Water 107.4 6 2.20 200.20 50.00 41.00 1.8240 0.1054 0.007720 Water 107.4 6 6.80 618.80 50.00 41.00 1.8240 0.1054 0.007721 Condensate sat 1.7 14.10 1381.80 50.00 48.00 1.8240 0.1054 0.007722 Claried juice 97 6 103.20 273,996 2625 30.00 1.2160 0.0717 0.005523 Water bar. condenser 30 1 8.67 442.17 50.00 1.00 1.8240 0.1054 0.007724 Water bar. condenser 50 1 8.92 490.60 50.00 5.00 1.2160 0.0717 0.005525 Bagasse 25 1 0.50 4992.50 9985 0.00 1.1610 0.0647 0.004326 Vegetable steam sat 1.7 14.10 8637.66 50.00 562.60 1.8240 0.1054 0.007727 Electricity e e e 627 e e 6.6230 0.3685 0.024628 Vegetable steam sat 1.7 34.20 20,950.92 50.00 562.60 1.8240 0.1054 0.007729 Steam sat 2.5 47.70 31,863.60 50.00 618.00 6.6230 0.3685 0.024630 Condensate sat 2.5 47.70 5294.70 50.00 61.00 6.6230 0.3685 0.024631 Syrup 58.7 0.16 20.90 238,740.7 11,416.74 6.26 1.8240 0.1054 0.007732 Dilution water 107.4 6 4.16 378.56 50.00 41.00 1.8240 0.1054 0.007733 Condensate sat 1.7 11.80 1156.40 50.00 48.00 1.9550 0.1129 0.008334 Condensate sat 1.7 2.20 215.60 50.00 48.00 1.9550 0.1129 0.008335 Electricity. e e e 900 e e 6.6230 0.3685 0.024636 Flash steam 97 0.93 0.70 365.40 50.00 472.00 0.0000 0.0000 0.000037 Vegetable steam sat 1.7 6.10 3736.86 50.00 562.60 1.8240 0.1054 0.007738 Water 107.4 6 1.00 91.00 50.00 41.00 1.8240 0.1054 0.007739 Water 107.4 6 2.90 263.90 50.00 41.00 1.8240 0.1054 0.007740 Condensate sat 1.7 6.10 597.80 50.00 48.00 1.8240 0.1054 0.007741 Filter cake 25 1 1.50 3243 2162 0.00 1.2110 0.0705 0.004942 Claried juice 97 6 44.90 119,209.5 2625 30.00 1.2110 0.0705 0.004943 CaO 25 1 0.10 196.51 1965.05 0.00 2.6049 1.9866 0.237944 Water bar. condenser 50 1 3.90 214.50 50.00 5.00 1.2110 0.0705 0.004945 Water bar. condenser 30 1 3.80 193.80 50.00 1.00 1.8240 0.1054 0.007746 Bagasse 25 1 0.20 1997 9985 0.00 1.1610 0.0647 0.004347 Electricity e e e 273.00 e e 6.6230 0.3685 0.024648 Water bar. condenser 30 1 360.30 18,375.30 50.00 1.00 2.7640 0.1609 0.011649 Water bar. condenser 50 1 370.20 20,361 50.00 5.00 1.8240 0.1054 0.007750 Condensate 50 1 10.60 583.00 50.00 5.00 1.8240 0.1054 0.007751 Syrup 58.7 0.16 2.60 29,699.80 11,416.74 6.26 1.8240 0.1054 0.007752 Vegetable steam sat 1.7 14.00 8576.40 50.00 562.60 1.8240 0.1054 0.007753 Water bar. condenser 30 1 337.60 17,217.60 50.00 1.00 1.8240 0.1054 0.007754 Water bar. condenser 50 1 347.40 19,107.00 50.00 5.00 1.9550 0.1129 0.008355 Molasses 25 1 5.90 75,661.60 12,824 0.00 1.9550 0.1129 0.008356 Condensate sat 2.5 0.20 22.20 50.00 61.00 6.6230 0.3685 0.024657 Steam sat 2.5 0.20 133.60 50.00 618.00 6.6230 0.3685 0.024658 Drying air 90 1 4.30 26.83 0.00 6.24 0.0000 0.0000 0.000059 Dry sugar 25 1 9.00 157,967 17,551.86 0.00 1.9550 0.1129 0.008360 Drying air 25 1 4.30 0.00 0.00 0.00 0.0000 0.0000 0.000061 Electricity e e e 1950 e e 6.6230 0.3685 0.024662 Dilution water 25 6 17.00 867 50.00 1.00 1.0000 0.0000 0.000063 KH2PO4 25 1 0.05 57.48 1061 0.00 9.6486 7.3583 0.459163 H2SO4 25 1 0.02 39.34 1666 0.00 1.8005 1.3504 0.085663 (NH4)2SO4 25 1 0.02 118.08 5000.76 0.00 2.0647 2.0647 0.121364 Cooling water 25 1 7.9 395 50.00 0.00 0.0000 0.0000 0.000065 Cooling water 25 1 7.9 395 50.00 0.00 1.0000 0.0000 0.000066 CO2 25 1 4.30 1941.84 451.59 0.00 0.0000 0.0000 0.000067 Wine 25 1 66.30 137,307 2071 0.00 2.5680 0.1531 0.010968 Electricity e e e 600 e e 6.6230 0.3685 0.024669 Hydrated ethanol 25 1 4.50 124,290 27,620 0.00 3.0560 0.1802 0.012770 Secondary ethanol 25 1 0.20 5376.40 26,882 0.00 3.0560 0.1802 0.012771 Vinasse 25 1 61.50 3075 50.00 0.00 3.0560 0.1802 0.0127


.30

.40

.60

.88

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N Name T (C) P (bar) m (kg/s) BT (kW)

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Renewable and non-renewable exergy costs and CO2 emissions in the production of fuels for Brazilian transportation sector1. Introduction2. Methodology2.1. Supply stage2.2. Transformation stage2.3. End use stage

3. Petroleum and natural gas production route4. Biodiesel production route5. Ethanol production route6. Electricity generation in Brazilian electricity mix7. Discussion8. ConclusionAcknowledgmentsNomenclatureAppendix AA.1. Petroleum refineryA.2. Biodiesel production plantA.3. Ethanol production plantReferences

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Exergy Costs and CO2 Emissions in Brazil