Applied Energy 88 (2011) 3782–3790

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Applied Energy

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Abatement costs of CO2 emissions in the Brazilian oil refining sector

David A. Castelo Branco ⇑, Alexandre Szklo, Gabriel Gomes, Bruno S.M.C. Borba, Roberto SchaefferEnergy Planning Program, Graduate School of Engineering, Federal University of Rio de Janeiro, Centro de Tecnologia, Bloco C, Sala 211, Cidade Universitária,Ilha do Fundão, Rio de Janeiro, RJ, 21941-972, Brazil

a r t i c l e i n f o

Article history:Received 16 November 2010Received in revised form 25 April 2011Accepted 27 April 2011Available online 18 May 2011

Keywords:Brazilian oil refiningCO2 emissionsAbatement costs

0306-2619/$ - see front matter � 2011 Elsevier Ltd. Adoi:10.1016/j.apenergy.2011.04.052

⇑ Corresponding author. Tel.: +55 21 25628760; faxE-mail address: davidbranco@ppe.ufrj.br (D.A. Cas

1 The Brazilian refineries are: REPLAN (SP) – Paulíniade Caxias refinery; REGAP (MG) – Gabriel Passos refiBernardes refinery; RECAP (SP) – Capuava refinery;refinery; REFAP (RS) – Alberto Pasqualini refinery; Rrefinery; REMAN (AM) Manaus refinery; LUBNOR (CE) –(PR) – Presidente Getúlio Vargas refinery; IPIRANGA –

a b s t r a c t

This study aims at estimating the abatement costs of CO2 emissions of the Brazilian oil refining sector. Forgreenfield refineries that will be built until 2030, mitigation options include the modification of refiningschemes and efficiency gains in processing units. For existing refineries and those already under con-struction, only mitigation options based on efficiency gains in processing units are evaluated. The abate-ment cost of each mitigation option was determined on the basis of incremental costs compared with areference scenario. Two discount rates were applied: one adopted by the Brazil’s government official longterm plan (8% p.a.), and another typically adopted by the private oil sector (15% p.a.). Findings indicatethat refineries face high abatement costs. The cost of changing the processing scheme of greenfield plantsreaches US$100/tCO2 at 15% p.a. discount rate. Even at 8% p.a. discount rate the abatement cost is higherthan US$50/tCO2. The most promising alternative is thermal energy management, whose abatement costequals US$20/tCO2 at 8% p.a. discount rate. However, private investors perceive this option at US$80/tCO2, which is still high. This difference in cost indicates the need for public policies for promoting carbonmitigation measures in Brazilian oil refineries.

� 2011 Elsevier Ltd. All rights reserved.

1. Introduction The number of refineries has not increased substantially over the past

2 According to Diringer [59], in 2005, the Brazil’s energy GHG emissions were

Refineries are intrinsically carbon dioxide (CO2) emitters. Therefining activity involves stages of separation, which is not athermodynamically spontaneous process [1]. It consumes a largeamount of energy in reducing the carbon to hydrogen ratio(C/H2) and adding hydrogen (H2) [2].

Furthermore, the refining sector worldwide is facing challengesrelated to the increasing demand for ultra-specified oil products,despite the limited access to new sources of conventional oil[3,4]. Therefore, refiners need to install and operate oil processingunits that increase CO2 emissions in two ways: first, due to theirown energy consumption, and second, as a result of their H2

requirements [2].The Brazilian oil refining sector includes new projects, designed

to serve a growing market for medium distillate fuels and petro-chemical products (typical of developing countries) and to absorbthe foreseen increase in national oil production (typical of oil pro-ducer countries).

Brazil’s petroleum refining sector currently presents 12 refiner-ies, mainly concentrated in the southeast region of the country [5].1

ll rights reserved.

: +55 21 25628777.telo Branco).refinery; REDUC (RJ) – Duquenery; RPBC (SP) – PresidenteREVAP (SP) – Henrique LageLAM (BA) – Landulpho Alves

Northeast Lubricants; REPARIpiranga refinery S.A.

30 years, and one small refinery, Manguinhos, located in city of Rio deJaneiro, has stopped operations in the last decade. Petrobras, theBrazilian oil company, has however invested in extending its facilitiesand in increasing refining capacity since the inauguration of theHenrique Lage Refinery in 1980, from 1.1 million barrels to 1.9million barrels a calendar-day [5]. In 2005, the emissions from Brazil-ian refineries were estimated in 14 million tonnes of CO2e (Mt),which represents 5% of Brazil’s energy Greenhouse Gas (GHG)emissions.2

This scenario would change in the next years. Brazil’s OfficialLong Term Energy Planindicates that the country will need at leastseven more refineries by 2030 to cope with a growing domesticdemand [7].3 The first of these, constructed by Petrobras, is almostcomplete and start-up is forecast for 2012. The remaining units arestill at the planning stage, with two of them scheduled to begin oper-ations between 2014 and 2020. The remaining four are expected tocome on stream between 2020 and 2030 [7]. It is worth noting that

around 362 MtCO2e. It is worth noting that GHG emissions from fuel combustionrepresent 16% of Brazil’s total GHG emissions, since most of it (around 58%) comesfrom deforestation [6].

3 The EPE study [7] predicts an increase in demand for petroleum derivatives inBrazil of 3.4% per annum between 2005 and 2030, particularly for diesel and jet fuel,both of which are forecast to grow above average. On the other hand, the studyconducted by [8] indicates an even greater demand for petrochemical products by2020. Consumption of petrochemical products is growing rapidly, particularly forpropane (7.2% per annum) and ethylene (5.7% per annum).

Table 1Energy consumption profile.

Groups Sources %

Process heat (PH) Fuel oila(FO) 27Refinery gas (RG) 17FCC cokeb(FC) 14Natural gasc (NG) 42

Total 100Hydrogen (HY) Hydrogen (HY) from natural gas 100

Total 100Electricity (EE) Grid electricity (EG) 24

Self-generated Electricityd(EO) 76

Total 100

a Includes consumption of fuel oil, vacuum residue and asphalt residue.b Product generated in the reaction of cracking and that is deposited on the

catalyst.c Includes import/export of steam and consumption of LPG.d Includes electricity generated in shale plants.

D.A. Castelo Branco et al. / Applied Energy 88 (2011) 3782–3790 3783

for these four refineries the preliminary feasibility studies do notinclude yet any calculations of GHG emissions.

In view of the potential impacts on climate change, Brazil has aresponsibility to contribute actively to international efforts to stabi-lize GHG concentrations [9]. This underscores the importance ofstudying the special features and peculiarities of the Brazilianenergy system and to plan its development on the basis of scenesetting exercises focused on the emissions arising from the produc-tion and consumption of energy. In this way it will be possible toidentify the potential for reducing emissions in the sector and therelated costs of abatement.

This study aims at estimating the average abatement costs(AAC) of CO2 emissions in the Brazilian oil refining sector in the2030 horizon. The AAC of a project is by definition the differencebetween the cost in a reference scenario and the cost in a scenariowith GHG mitigation (or a low carbon scenario), expressed inmonetary terms per tonne (metric ton) of CO2 equivalent (US$/tCO2e). The AAC could be seen as the carbon prices that would en-able, from an economic standpoint, the implementation of the con-sidered emission reduction measures. This method has beenwidely used in several studies to estimate the costs and potentialabatements of different economic sectors in many countries, suchas [10–13].

The Brazilian refining sector was divided in this study into twoparts: existing refineries, which includes the refineries in opera-tion and two refineries already under construction; and the newrefining, which includes all new refineries in the 2030 NationalEnergy Plan [7]. The existing refineries group comprises refineriesmore rigid for innovations, because these refineries are alreadyinstalled and there are even space limitations. Refineries underconstruction have its refining scheme already defined. Therefore,they were included in the group of existing refineries. On theother hand, for new refineries (not under construction), in theirconceptual phase, there is still a certain degree of flexibility inchoosing processing units and alternative production routes. Inthis case, the most relevant result of the simulation is the choiceof the refining scheme (or production routes) in light of a need toreduce GHG emissions.

Therefore, analyzing the impact of CO2 emission costs on newprojects in their design phase is very different from evaluatingemission reduction alternatives to adapt or retrofit existing facili-ties. For this purpose, we ran simulations of two complex refineryconfigurations through a linear programming (LP) optimizationmodel. The aim of this simulation was to determine the magnitudeof the CO2 price necessary to significantly change the emissions ofthe proposed configurations. Note that here the introduction of acarbon-emission price on conceptual refineries is similar to evalu-ating the costs of carbon abatement for different emissions limits.As the economic analysis indicates, at the boundary, Pigouviantaxes (such as a carbon tax) and the abatement costs converge[14].

The paper is organized as follows: the next section elaboratesthe country’s oil refineries carbon emissions inventory. Section 3describes the mitigation measures considered, and Section 4presents the two scenarios for estimating mitigation costs(baseline scenario and low carbon scenario). Section 5 presentsthe estimates of average abatement costs for each option listedin Section 3. Finally, Section 6 presents the concluding remarksof the study by analyzing the barriers to the implementation ofthe envisaged measures.

4 AD – atmospheric distillation unit; VD – vacuum distillation unit; FCC – fluidcatalytic cracking unit; RFCC – residue fluid catalytic cracking unit, RC – catalyticreforming, HCC – hydrocracking unit, CR – delayed coking, HDTL – hydrotreating unit,LUB – lubricants, HDS – hydrodesulfurization unit, ALQ – alquilation unit.

2. Co2 emissions in Brazilian oil refineries

The Brazilian refining sector can be described as a typicalcracking refinery scheme [15]. This study estimates the energy

consumption and elaborates the CO2 emissions inventory of allBrazilian refineries. The methodology applied is based on IPCC[16]. CO2 emissions were calculated using the energy consumedper barrel and the respective capacities of each process unit, foreach refinery, including the RENEST and COMPERJ refineries thatare still under construction. COMPERJ was designed to consumeinitially 150,000 barrels per day of Marlin crude oil. Petrobrasdecided to expand the refining capacity to 165 thousand barrelsper day (1st refining unit) plus a 2nd unit of refining with thesame capacity (165 thousand barrels per day of oil). RENESThas a nominal capacity around 200,000 barrels/day and will usetechnology based on delayed coking. This refining scheme allowsprocessing heavy oils, extracted primarily from the BrazilianMarlim oil field (in the Campos Basin) and the Venezuelan Mereytype oil [7].

The first step of the inventory is based on the refining sectorprofile as of 2009. Additionally, an estimative of CO2 emissions in2015 is performed considering that RENEST and COMPERJ will starttheir operation before that year. The refining profiles for RENESTand COMPERJ are based on [5,17,18].

Refineries use different inputs as sources of energy for their pro-cesses and the profile of these inputs can vary significantly amongrefineries. In this study, refineries’ carbon emissions were esti-mated using the average energy consumption profile of a Brazilianrefinery, REDUC, between 2000 and 2005. The electricity can beimported from the grid or can be produced in the refinery. Allhydrogen is considered to be obtained from the steam reformingof natural gas. Table 1 summarizes this information.

The final energy consumption figures for each refinery unitwere based on [19–21]. The average energy consumption profilewas applied to the total fuel and electricity consumption in eachrefining unit.

The energy consumption (ECRU) of each refining unit, which isrepresented by Eq. (1), was divided into: energy consumption inthe process (EC1), energy consumption as hydrogen (EC2) and en-ergy consumption as electricity (EC3).

ECRUiðkJ=barrelÞ ¼X

j

ECj ð1Þ

i = AD, VD, FCC, RFCC, RC, HCC, CR, MTBE, DSF, HDTL, HDTQ, HDTN,HDTI, LUB, HDSG, HDSD, ALQ.4 j = PR, HY, EE

Table 2Estimation of carbon emissions for the years 2009 and 2015.

Emissions 2009 2015

Nominal capacity (millions of barrel/year)a 764.4 768.9Energy consumption (TJ/year)b 214.702 396.473kg CO2/barrel 22.3 28.5

a The average utilization factor of nominal processing capacity of Brazilianrefining was 88% in 2008 [22].

b Based on [15,19–21,23].

3784 D.A. Castelo Branco et al. / Applied Energy 88 (2011) 3782–3790

The energy consumption (ECj) was separated according to thecomposition of energy feedstock, which was provided by Table 1(see Eq. (2)):

ECjðkJ=barrelÞ ¼X

k

ECk ð2Þ

k ¼ FO;RG; FC;NG;HY;EG;EO

where ECFO (kJ/barrel) = energy consumption from fuel oil, ECRG (kJ/barrel) = energy consumption from refinery gas, ECFC (kJ/bar-rel) = energy consumption from FCC coke, ECNG (kJ/barrel) = energyconsumption from natural gas, ECHY (kJ/barrel) = energy consump-tion to produce hydrogen, ECEG (kJ/barrel) = energy consumptionfrom grid electricity, ECEO (kJ/barrel) = energy consumption fromself-generated electricity.

CO2 emissions (EMi) from each refining unit are representedby Eq. (3). Emission factors (EF) used to calculate EMi for eachunit derives from IPCC [16]. Besides, all hydrogen was assumedto be produced by natural gas reforming process. For this reasonthe emission factor of natural gas was used to hydrogenproduction.

EMiðtCO2=m3Þ ¼X

k

ðECk � EFkÞ ð3Þ

i = AD, VD, FCC, RFCC, RC, HCC, CR, MTBE, DSF, HDTL, HDTQ, HDTN,HDTI, LUB, HDSG, HDSD, ALQ.

k ¼ FO;RG; FC;NG;EG;EO:

CO2 Emissions of each Brazilian refinery (EMref) is representedby Eq. (4).

EMrefðtCO2=m3Þ ¼X

i

ðEMiÞ ð4Þ

i = AD, VD, FCC, RFCC, RC, HCC, CR, MTBE, DSF, HDTL, HDTQ, HDTN,HDTI, LUB, HDSG, HDSD, ALQ.

Finally, CO2 Total Emissions of Brazilian refining sector (EMtotal)is estimated by the sum of the each refinery emission, representedby Eq. (5).

EMtotalðtCO2=m3Þ ¼X

k

ðEMkÞ ð5Þ

k = REDUC, RPBC, RECAP, REVAP, REFAP, REGAP, REPLAN, RLAM, RE-MAN, LUBNOR, REPAR, IPIRANGA, RENEST, COMPERJ.5

The estimation of carbon emissions is presented in Table 2.Based on these results, measures to reduce GHG emissions in

the Brazilian refining sector are suggested.

5 COMPERJ (RJ) – petrochemical refinery; RENEST (PE) – Abreu e Lima refinery;REPLAN (SP) – Paulínia refinery; REDUC (RJ) – Duque de Caxias refinery; REGAP (MG)– Gabriel Passos refinery; RPBC (SP) – Presidente Bernardes refinery; RECAP (SP) –Capuava refinery; REVAP (SP) – Henrique Lage refinery; REFAP (RS) – AlbertoPasqualini refinery; RLAM (BA) – LandulphoAlves refinery; REMAN (AM) Manausrefinery; LUBNOR (CE) – Northeast Lubricants; REPAR (PR) – PresidenteGetúlio Vargasrefinery; IPIRANGA – Ipiranga refinery S.A.

3. GHG emissions mitigation measures

All measures considered in this paper are directly related to oilrefining – i.e. are located inside battery limits of oil refinery plants(for example, the production of liquid biofuels to supplement or re-place petroleum products are not considered). GHG emissions mit-igation measures are divided into two groups. The first set ofmitigation options includes measures that can be adopted by exist-ing refining facilities. The second set of mitigation options involvesthe optimization of a possible new refinery in Brazil with the aimof minimizing its production costs (including an additional costfor carbon emissions) to satisfy a specific demand in the Brazilianmarket. The average abatement cost of each mitigation option wasdetermined on the basis of incremental costs compared with abaseline scenario at two discount rates: the one adopted by theBrazilian Official Long Term Plan (8% p.a.) [7]; and the one typicallyadopted by the private oil sector (15% p.a.), which provides the pri-vate agent’s opportunity cost.

3.1. Mitigation options for existing refineries

According to Petrick and Pellegrino [24], it is possible over themedium to long term to establish a target for reducing energyuse in existing refineries by between 15% and 20% (and, conse-quently, CO2 emissions). The recovery and reuse of thermal lossesis the main option in the short run, while mitigating incrustationand fouling are of crucial importance over the medium to longterm. Therefore, based on [25], two basic options for carbon emis-sions mitigation in existing Brazilian facilities are considered: ther-mal energy management and fouling mitigation.6

Thermal energy management is the main option for saving fuelsin Brazilian existing refineries in the short term. Although chemicalplants in Brazil and other parts of the world have already success-fully adopted thermal energy management techniques, there areno large efforts in research and development associated to this op-tion [26].

The Brazilian refineries have an impressive fuel savings poten-tial as can be noted by their average Solomon Index (EII) values,which totaled 101, 105 and 106 in 2004, 2005, and 2006, respec-tively [27]. The Solomon Index EII is used to evaluate the energyefficiency of refineries around the world, by comparing a givenrefinery with a reference plant with the same level of technologicalcomplexity (the reference refinery is normalized as 100). An indexhigher than 100 indicates that the given refinery has a higher pri-mary energy consumption than the reference refinery. For exam-ple, between 2004 and 2006 the average EII values hoveredaround 94 and 95 for exxon [28], 95 and 96 for BP [29], and 84and 85 for shell [30].

Several measures associated with thermal energy managementwere considered to be implemented in the Brazilian oil refineries:

� Use of low quality exhaust heat in refrigeration cycles byabsorption [31].� Use of thermal residues for preheating feedstock (for example

recovery systems can recover the heat produced in cokingprocesses).� Design of energy and/or mass (water and hydrogen) integration

basically employing the Pinch Techniques [32,33]; the use ofPinch Techniques provides energy savings in refineries of 20%[24]. According to [32,33], typical values would be between10% and 25% (as a percentage of total fuel consumption only).� Improving burners through better burning control [34].

6 Other innovative options for mitigating carbon emissions, which are based ontechnologies under development, are discussed in the last section of this paper, butare not valued in terms of abatement costs.

Table 3Fuel savings for existing facilities.

Options Fuel savings (%)

Thermal energy management 15Fouling mitigation 2

7 For further details, see [43].

D.A. Castelo Branco et al. / Applied Energy 88 (2011) 3782–3790 3785

� Direct feeding of intermediate products to the processes, with-out cooling and storage, aiming at recovering part of the resid-ual heat in these products. For example, the thermal energy ofthe products of the distillation column can be directly recoveredin the downstream units, thereby avoiding storage and cooling[23].� Using heat pumps [35].� Increasing turbulence in the heat exchange surfaces.� Adoption of a steam management system [35]. For example, the

quality of steam used in stripping and vacuum generation isnormally lost in the cooling water or wasted to the atmosphere.Normally steam used for stripping ensures the flashpoint tem-perature and improves the fractioning of products, increasingthe yield of the refining units.

Two studies developed in the Brazilian REPLAN refinery [31,36]and a study undertaken in the Brazilian REDUC refinery [37] ana-lyze the technical potential for using Pinch Techniques in Brazilin refineries for energy (energy integration) and water (mass inte-gration). These studies confirm that energy and mass integrationnetworks are feasible options over the short term for the two Bra-zilian refineries. However, not all the hot waste streams are avail-able for heat exchange. Volatile products that need to be rapidlycooled by water quench, intermittent streams [31] and streamscontaining suspended solids (e.g. catalysts) can be cited as exam-ples. Finally, some streams in inaccessible parts of the refinery[31] are difficult to recover (e.g. FCC exhaust gases). According toMoreira et al. [38], which assessed a thermal energy managementnetwork for a Brazilian refinery, around 60% of the fuel consump-tion in the distillation tower can be saved. Considering the esti-mated share of atmospheric distillation units in the final energyconsumption of Brazilian, this would correspond to a fuel savingsof approximately 17%.

The second group of measures assessed for existing Brazilianrefineries includes the control of fouling at heat exchangers. Be-sides reducing the area of heat exchangers fouling causes mainte-nance problems and risk of accidents. Heat exchange networkswith incrustations have approach temperatures higher than 40 �C[33] when typical values in refineries hover between 10 �C and20 �C. Estimates done in the early 1980s for a typical refinery ofits period with a primary processing capacity of 100 thousand bar-rels per day suggest that fuel consumption could be 30% less in theatmospheric distillation column by controlling fouling in the heatexchangers [39]. A more recent study, however, pointed to a lowerpotential. Although still significant, the reduction was only 10%[40]. Yet, incrustation in heat exchange networks is a bottleneckimpeding the application of heat recovery systems. The gainsachieved from reducing fuel consumption by controlling incrusta-tion were estimated at 2% for refineries in the United States [24].This percentage was similar to that obtained by [41] for Brazil.Meanwhile, Panchal and Huangfu [42] analyzed the effects ofincrustation in a 100 kbpd atmospheric distillation column andfound an additional energy consumption of 13.0 MJ per barrel pro-cessed (or around 3.4% of specific energy consumption in Brazilianrefineries).

In sum, adopting the estimates of [25], the potential fuel savingsof each option considered to be installed in Brazilian existing refin-eries are resumed in Table 3.

3.2. Mitigation options for greenfield refineries

Our analysis was based on the results obtained by the simula-tion of [43] through a linear programming model representingtwo types of new refineries in Brazil: a refinery with focus on dieseland other with focus on petrochemicals. These are precisely thetwo refineries that are listed in Brazil’s Official Energy Plan [7].

The model is a static, single-refinery LP, based on the Generateurde Matrices pour ModelesEnergie (GEMME), from the InstituteFrances du Pétrole (IFP). GEMME was modified to consider therefining configurations proposed by [43], their respective yieldsfrom processing Brazilian crude oils, and the output of refinedproducts suitable for consumption in the Brazilian market.

The optimization model considered monetary values for thecost of CO2 emissions in order to seek viable solutions for avoidingsuch emissions. Fig. 1 presents in simplified form the main unitspre-defined in the model.

The following procedure was adopted7:

1. Adjustment of the linear programming model for two basicrefining configurations.

2. Optimization of these two configurations without consideringcarbon prices.

3. Optimization of the two configurations with the insertion of acarbon price (US$25/tCO2, US$50/tCO2, US$100/tCO2 and US$150/CO2). The outputs of the refineries were kept unalteredin terms of products (quantity and quality).

4. Identification of the carbon price that altered the refineryscheme in the optimized model.

The most relevant result of the simulation was the choice of therefining schemes (or the routes to obtain oil products) for newrefineries, at different carbon prices. The findings of the optimiza-tion model indicated that the refinery schemes changed in thesame direction for both discount rates adopted in our study. How-ever, the abatement cost at 8% p.a. was 58 US$/tCO2, while it was100 US$/tCO2 at 15% p.a. Therefore, we found that the technicalpossibilities to change the refinery schemes without altering therefinery yield are limited, mainly focusing on replacing FCC unitsby hydrocracking ones and switching fuels with high carbon con-tent. In sum, abatement costs changed according to the discountrates adopted, but not because of the choice of a different schemeat a lower (or a higher) discount rate.

The 100 US$/tCO2 is the carbon price that leads to the modifica-tion of the original refining scheme (at 15% p.a. discount rate anduseful life of 30 years). Actually, the two proposed refineries (fo-cused on diesel or basic petrochemicals) significantly reduce theiremissions starting at a price of US$ 100/tCO2 – see Table 4. Atprices under 100 US$/tCO2, the proposed refineries reduced theiroperational margins, but did not alter their schemes.

After reaching US$ 100/tCO2 at 15% p.a. (or US$ 58/tCO2 at 8%p.a.), the basic alterations of the original refinery schemes were[43]:

1. Switching of carbon-intensive fuels with natural gas.2. Hydrogen is used both as a fuel and as input for hydroconver-

sion processes. Hydrocracking gains importance, while FCCloses. The former is less energy-intensive than the latter.

This result shows that there is not much room for curbing carbonemissions through changing new refineries’ configuration at lowabatement costs. Actually, when considering CO2 prices, refinerieshave little margin to alter their process configuration at values be-

Fig. 1. Initial scheme of the proposed refining units.

Table 4Emissions per barrel for new refineries with and without carbon prices (kgCO2/barrel). Source: [43].

Low carbon scenario Petrochemical Diesel

Without carbon prices (original scheme) 54.8 30.7With carbon prices (US$ 100/tCO2 at 15% p.a or US$

58/tCO2 at 8% p.a.)37.7 17.3

Table 5Carbon emissions of existing refineries – reference scenario (MtCO2/year).

Emissions 2007 2015

MtCO2/yr 13.8 25.5

3786 D.A. Castelo Branco et al. / Applied Energy 88 (2011) 3782–3790

low US$100/tCO2. This is a very high figure when compared to thecurrent carbon price in the European market (around US$25/tCO2)or even to the forecasted price of US$50/tCO2 [44].

8 Results in [47] show a 10% fuel saving for a crude oil refinery with a capacity of 1MMTa. This value was obtained considering a 6.5% self-consumption (based on itssimilarity to the Brazilian REGAP refinery). Since the measures associated with energythermal management save 6450 SRFT (Standard Refinery Fuel Tonne), they savedexactly 10% of fuel at the refinery, confirming the value used in this article. The datafrom [47] also confirm the economic forecasting from [45].

4. Co2 emissions abatement scenario

The estimates of average abatement cost (AAC) require thecomparison of CO2 emissions between scenarios. For this reasontwo scenarios were adopted: a reference scenario and a low carbonscenario.

4.1. Reference scenario

The Reference Scenario considers the investments proposed byPetrobras up to 2015 for existing refineries. In this case, the calcu-lated GHG specific emissions of existing refineries are depicted inTable 5.

For greenfield refineries, the reference scenario was based en-tirely on the Brazilian Government Official Long Term Plan [7](Fig. 2).

GHG emissions from new refineries were calculated using thespecific emissions of new refineries (without carbon prices) as de-picted in Table 4. As such, total carbon emissions of new refineriesare summarized in Table 6.

4.2. Low carbon scenario

The low carbon scenario considers the implementation of theproposed mitigation options in new and existing Brazilian refin-eries. Two stages of mitigation measures implementation areconsidered for the existing refineries. The first stage occurs in2015 at the following Brazilian refineries: REPLAN, REDUC and

REGAP. The second stage is implemented in the other refineriesup to 2020: RPBC, RECAP, REVAP, REFAP, RLAM, REMAN, LUB-NOR, REPAR and IPIRANGA.

Considering only the thermal energy management in Brazilianrefineries using the data obtained from two major refineries, thepotential fuel savings hover around 10% (of total fuel consump-tion). The implementation cost, based in [45], is approximately13 US$/GJ a year, considering a project of 15 years of life and a dis-count rate of 15% p.a. (this cost equals 9 US$/GJ a year at 8% p.a.).Around 90% of these costs derive from investments in the begin-ning of the project [25,46].

This figure can be considered slightly conservative when com-pared with those from [38], between 15% and 21%.8 In sum, thefouling of heat exchange network is a bottleneck for applicationof heat recovery systems. The gains from saving fuels only control-ling the fouling have been estimated at 2% to US refineries [24] – anamount that is consistent with those obtained in [41] for Brazil. Ahigher value, however, is provided in [42], indicating the need forfurther studies. These authors analyzed the effects in an atmo-spheric distillation column of 100 kbpd. They found an additionalconsumption of 13.0 MJ per barrel processed (or about 3.4% ofthe specific energy consumption in Brazilian refineries).

Alsema [45] estimates the annual costs of operation and main-tenance of approximately 21 US$/GJ and 15 years of useful life oftechnology, while the investment cost can be considered zero.These numbers are also consistent with the experience of a refineryin India with thermal energy management systems [47].

Fig. 2. Expansion of refining capacity in Brazil. Source: [6].

Table 6Carbon emissions of new planned refineries – reference scenario (MtCO2/year).

2015 2020 2025 2030

2.8 8.6 11.4 14.2

Table 7Capital cost and O&M cost for implementing mitigation measures in existing Brazilianrefineries.

Year Cost (US$) Mitigation measures

Thermal energymanagement

Foulingmitigationc

2015 Total capitalcosta

367,340,552 0

Total O&M costb 40,815,617 90,701,371

2020 Total capital cost 321,512,072 0Total O&M cost 35,723,564 79,385,697

a Total capital cost in the year of implementation of measures in all Brazilianrefineries.

b Total O&M cost per year.c Fouling mitigation was treated as a operational cost (such as maintenance

costs).

Table 8Annual carbon emissions avoided in existing refineries – low carbon scenario (tCO2/year).

Year Thermal energy management Fouling mitigation

2015 2,021,760 269,5682020 3,831,053 510,807

Table 9Carbon emissions from new refineries – low carbon scenario.

Total emissions 2015 2020 2025 2030

(tCO2/year) 1,580,685 5,225,979 6,806,664 8,387,349

D.A. Castelo Branco et al. / Applied Energy 88 (2011) 3782–3790 3787

The results are summarized in Table 7 and Table 8, respectively.For the new refineries, mitigation options are associated with

the modification of the refining scheme for the carbon price ofUS$100/tCO2, as calculated in Section 4 – see Table 9.

The carbon price of US$100/tCO2 was obtained at a 15% p.a. dis-count rate. As mentioned before, this is the rate typically adoptedby the private oil sector, and used by Pertusier [48]. Yet, the samescheme was also optimized at 8% p.a. discount rate. In this case theaverage abatement cost equaled US$58/tCO2 – i.e., at 8% p.a. dis-count rate and US$58/tCO2 new refineries would abate the sameamount of carbon that they would abate at 15% p.a. and US$100/tCO2.

5. Average abatement cost

The Low Carbon Scenario considers the 2010–2030 period.However, mitigation measures for existing refineries can have alifetime that goes beyond this period of analysis. For this reason,a levelized cost (LC) was adopted to estimate the average abate-ment cost (AACa) of each measure,9 according to Eq. (6):

AACa ¼P2030

i¼2010LCiP2030i¼2010Ei

ð6Þ

where AACa = average abatement cost per ton of CO2 avoided.LC = levelized cost for mitigation option. E = annual avoided emis-sions for each option considered. i = period of analysis (2010–2030).

The LC of an option represents the difference of the levelizedinvestment cost (LIC) and annual financial results (AFR) of the mit-igation option implementation (Eq. (7)). The AFR is given by totalrevenue (RE) less the expenditures in operation and maintenancecost (OM) for each mitigation option (Eq. (8)). The levelized invest-ment cost (LIC) and annual financial results (AFR) for each option isrelated to the reference scenario.

LCi ¼ LICi � AFRi ð7Þ

9 The average life considered in the case studied was 15 years for existing refineriesand 30 years for new refineries.

AFRi ¼ ðREoption � REreferenceÞi � ðOMoption � OMreferenceÞi ð8Þ

where LC = levelized cost for mitigation option. LIC = levelizedinvestment cost. AFR = annual financial results. RE = total revenue.OM = operation and maintenance cost. i = period of analysis(2010–2030).

Finally, the levelized investment cost (LIC) is the differentialcost of annual investment required for the option implementationmultiplied by the capital recovery factor (CRF) in each scenario (Eq.(9)).

LICi ¼ ½ðCIoptionÞi � CRFoption� � ½ðCIreferenceÞi � CRFreference� ð9Þ

Table 10Average abatement costs.

Mitigation options (US$/tCO2) Emission reduction(1000 tCO2)

8%discountrate

15%discountrate

Changing design ofnew refineries

58.3 99.9 51,796

Improving energy use of existing refinery unitsThermal energy

management20.2 77.3 52,250

Fouling mitigation 115.6 210.8 6967

Table 11Additional investments for mitigating carbon emissions (2010–2030).

Mitigation options Net present values (1000 US$)

8% discount rate 15% discount rate

Changing design of new refineries 1,587,206 831,3906Improving energy use of existing refinery unitsThermal energy management 2,159,889 1,332,723Fouling mitigation 479,975 296,161

3788 D.A. Castelo Branco et al. / Applied Energy 88 (2011) 3782–3790

where

CRFoption ¼ð1þ tÞnoption � tð1þ tÞnoption � 1

CRFreference ¼ð1þ tÞnreference � tð1þ tÞnreference � 1

LIC = levelized investment cost. CRF = capital recovery factor. CI =cost of annual investment. t = discount rate. n = lifetime of the pro-ject. i = period of analysis (2010–2030).

As mentioned before, the estimation of the average abatementcosts followed two approaches:

� The first aimed to compare the alternatives according to the dis-count rate used by the Brazilian government (8% p.a.). This is agood proxy of a ‘‘social’’ discount rate [49]. Although the discus-sion about an intergenerational equitable discount rate is con-troversial, the discount rate used here is in line with thosepointed out by [50,51]. Furthermore, the figure used is equiva-lent to the opportunity cost of capital for the Brazilian govern-ment. Actually, as of today, the long term opportunity cost forthe Brazilian government is around 1.5–2.5% spread over theUS treasury T-Bond 30, which pays 4–5% p.a. [52].10

� The second aimed to estimate the carbon price (break-even car-bon price) that guarantees the feasibility of the mitigationoption compared to the reference scenario, according to theinternal rate of return (IRR) required by the Brazilian oil sector.The IRR considered was 15% p.a. Table 10 summarizes theresults.

The additional cost of investment between 2010 and 2030 inpresent values is also calculated for the discount rates of 8% and15% p.a. (Table 11).

At 15% p.a., the reduction in GHG emissions still shows a highabatement cost. This result is consistent with the current experi-ence of several refining plants worldwide, which are exposed totargets for reducing GHG emissions; they face major technicalchallenges to realize these goals and frequently prefer to pay finesof around 100 euros/tCO2 (or around 140 US$/tCO2) [56,57].

However, Holmgren and Sternhufvud [58] found lower CO2

MAC for two Sweden oil refineries. These authors considered thefollowing major alternatives: LPG replacing fuel oil, and naturalgas replacing butane and fuel oil. They based their economic anal-ysis on a 6–12% p.a. discount rate, which is lower than the oneadopted in this paper for describing Brazil’s oil sector opportunitycost. Thus, findings presented in [58] are not easily comparablewith our results. Actually, the measures are not the same, andHolmgren and Sternhufvud [58] identified for their specific casestudies huge carbon abatement potential by replacing fuel oil withnatural gas or LPG. In this case, the relative fuel prices drive most ofCO2 MAC found by these authors. In [58], natural gas and LPG rel-ative prices tend to favor their use for hydrogen production andheat generation, respectively. This is not the case in Brazilian oilrefineries.

6. Final remarks

Brazil’s responsibility to actively contribute to international ef-forts to stabilize concentrations of greenhouse gases, in addition tothe new oil refinery projects, makes the study of abatement costsan important issue. The existing refineries in Brazil are being mod-ified to meet the objectives of reducing the sulfur content of the oil

10 Rambaud and Torrecillas [50] listed discount rates varying from 2 to 10% p.a.However, the justification for choosing one rate is controversial [53]. As stressed byDixon et al. [54], approaches that avoid subjectivity whendefining this rate include:the opportunity cost of capital, donor lending agency requirements, and cost ofmoney to the government. Finally, 8-9% seems to be consistent with the cost of capitalof oil companies [51,55].

derivatives produced and of increasing the conversion of heavycrudes into high-quality medium and light products. The maininvestments made so far have been to adapt existing units and toinstall deep conversion (delayed coking) and hydrotreatment units.The Brazilian case is thus emblematic, as it involves new complexrefining projects, conceived to satisfy a growing market for med-ium derivatives and petrochemical feedstocks, typical of develop-ing countries, and to absorb the forecast increase in domesticcrude output, typical of oil producing countries. On top of thesefactors, Brazil may assume carbon emission reduction targets after2012, along with the other BRICs [59].

Considering the set of mitigation options assessed in this paper,Brazilian oil refineries (existing and planned ones) should face rel-atively high carbon abatement costs. The most promising alterna-tive is thermal energy management. Private investors perceive thisoption at around US$80/tCO2, which is still high. The different per-ceptions of abatement costs according to the discount rate usedindicate the need of public polices for promoting carbon mitigationmeasures.

Indeed, oil companies usually prefer to focus on their core busi-ness. Therefore, the deployment of the mitigation options facesseveral barriers:

� The degree of maturity of some of the technologies consideredin the study negatively affects the risk perception of privateagents – i.e., could lead to higher transaction costs.� Even for the commercially available technologies, a huge differ-

ence exists between the discount rate used by the private seg-ment of the petroleum industry and the discount rate used bythe State for comparing infrastructure investments. This givesan idea of the high opportunity cost of oil companies.

To overcome these barriers, public policies could be deployedor reinforced. Actually, as of today, several fuel savings programsexist under the aegis of the National Program for Rationalizingthe Use of Petroleum Derivatives and Natural Gas (CONPET),which is a program run by the Brazilian Ministry of Mines andEnergy [60]. Nevertheless, the current annual budget of CONPETis relatively low – under US$2.5 million per year [61], and thusother sources of finance have to be tapped. For instance, CONPETactivities could be improved if assistance from the Brazilian

D.A. Castelo Branco et al. / Applied Energy 88 (2011) 3782–3790 3789

National Bank for Economic and Social Development (BNDES)programs were forthcoming. BNDES is linked to the Ministry ofDevelopment, Industry and Foreign Trade. It normally financeslarge industrial and infrastructure developments.

Finally, a further group of mitigation alternatives analyzed inthis paper involves the modification of the ‘optimum refiningscheme’ of greenfield refineries. Yet, new plants only modified itsrefining scheme at US$100/tCO2. However, as proposed by [43],this result is different when the possibility of capturing andsequestering carbon (CCS) is taken into consideration.

Several sources contributed to overall GHG emissions of an oilrefinery: steam boilers and process heaters, regenerators of FCCunits, and hydrogen production units. Catalysts regeneration inFCC units is a large emitter (coke deposited on a catalyst is burntwith air). However, the scientific literature indicates that capturingCO2 from this post-combustion stream is very expensive due tolow concentration11 and low pressure of flue gas streams [62–65].In order to deal with this issue, experts propose to use the oxy-firedFCC catalyst regeneration concept [62–64], or the chemical loopingcombustion concept – CLC [63,66,67]. In the oxy-fired FCC option,which is already under a development phase,12 pure oxygen, insteadof air, is used to burn the coke in the regenerator and flue gas ispartly recycled to avoid temperature runaway. De Mello et al. [64]showed a 45% decrease in CO2 capture cost for oxy-firing technologycompared to the amine absorption alternative. The CLC option is anovel (or still immature) technology, which is based on a solid car-rier able to chemically adsorb oxygen from air (oxidation in the airreactor) and release it in the presence of a gaseous fuel (reductionin the fuel reactor).

In sum, as of today, capturing CO2 from FCC post-combustionstreams is too expensive and would require the development anddeployment of novel concepts, such as oxy-firing or CLC. On theother hand, hydrogen production allows a single point source forCO2 capture [65]. This indicates that CCS could become a key mea-sure for reducing CO2 emissions from refineries in the future, alter-ing the unit refining operations and the refinery scheme.

However, new CCS concepts, especially focused on FCC emis-sions, should be addressed by R&D investment. In this case, theso-called Brazilian CT-Petro Sectoral Fund should well be a keyinstrument. This fund is financed with a fraction of the Braziliangovernment take (royalties) related to the petroleum production[68]. It could also be used for promoting research in other inno-vative techniques. For instance, two promising alternatives couldbe developed as well: the bio-desulfurization and oxidative desul-furization (ODP) of diesel. The former involves a set of promisingprocesses designed to reduce the sulfur content of petroleumproducts under moderate conditions (with less energy consump-tion). The latter is a non hydrogen consuming desulfurizationtechnique [25]. The ODP process, although still at the develop-ment stage, holds out good prospects for diesel [69]. ODP wouldalso save hydrogen that could be diverted to heat generation inthe refinery.

Acknowledgments

The authors thank the Brazilian National Council for Scientificand Technological Research (CNPq) for financial and institutionalsupport. This paper derives from a more comprehensive study car-ried on with support from the World Bank. Therefore, the authors

11 Fluid catalytic cracking units are operated in two modes: (1) full CO burn mode,where all CO is combusted to CO2 within the regenerator. The exhaust gas containsless than 1% CO; (2) partial burn mode, where the regenerator exhaust gas containsless than 6–8% CO [49,62].

12 Particularly noteworthy is the small pilot held by Petrobras at Landulpho Alvesrefinery [63,6].

would like to thank Christophe de Gouvello, the Senior Energy Spe-cialist of World Bank.

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