Abatement costs of CO2 emissions in the Brazilian oil refining sector

Applied Energy 88 (2011) 3782–3790

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Applied Energy journal homepage: www.elsevier.com/locate/apenergy

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 Schaeffer Energy 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 2010 Received in revised form 25 April 2011 Accepted 27 April 2011 Available online 18 May 2011 Keywords: Brazilian oil refining CO2 emissions Abatement costs

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. For greenfield refineries that will be built until 2030, mitigation options include the modification of refining schemes and efficiency gains in processing units. For existing refineries and those already under construction, only mitigation options based on efficiency gains in processing units are evaluated. The abatement cost of each mitigation option was determined on the basis of incremental costs compared with a reference scenario. Two discount rates were applied: one adopted by the Brazil’s government official long term plan (8% p.a.), and another typically adopted by the private oil sector (15% p.a.). Findings indicate that refineries face high abatement costs. The cost of changing the processing scheme of greenfield plants reaches US$100/tCO2 at 15% p.a. discount rate. Even at 8% p.a. discount rate the abatement cost is higher than US$50/tCO2. The most promising alternative is thermal energy management, whose abatement cost equals 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 carbon mitigation measures in Brazilian oil refineries. Ó 2011 Elsevier Ltd. All rights reserved.

1. Introduction Refineries are intrinsically carbon dioxide (CO2) emitters. The refining activity involves stages of separation, which is not a thermodynamically spontaneous process [1]. It consumes a large amount of energy in reducing the carbon to hydrogen ratio (C/H2) and adding hydrogen (H2) [2]. Furthermore, the refining sector worldwide is facing challenges related 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 processing units that increase CO2 emissions in two ways: first, due to their own 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 petrochemical products (typical of developing countries) and to absorb the foreseen increase in national oil production (typical of oil producer countries). Brazil’s petroleum refining sector currently presents 12 refineries, mainly concentrated in the southeast region of the country [5].1 ⇑ Corresponding author. Tel.: +55 21 25628760; fax: +55 21 25628777. E-mail address: [email protected] (D.A. Castelo Branco). The Brazilian refineries are: 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) – Alberto Pasqualini refinery; RLAM (BA) – Landulpho Alves refinery; REMAN (AM) Manaus refinery; LUBNOR (CE) – Northeast Lubricants; REPAR (PR) – Presidente Getúlio Vargas refinery; IPIRANGA – Ipiranga refinery S.A. 1

0306-2619/$ - see front matter Ó 2011 Elsevier Ltd. All rights reserved. doi:10.1016/j.apenergy.2011.04.052

The number of refineries has not increased substantially over the past 30 years, and one small refinery, Manguinhos, located in city of Rio de Janeiro, has stopped operations in the last decade. Petrobras, the Brazilian oil company, has however invested in extending its facilities and in increasing refining capacity since the inauguration of the Henrique Lage Refinery in 1980, from 1.1 million barrels to 1.9 million barrels a calendar-day [5]. In 2005, the emissions from Brazilian 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 Official Long Term Energy Planindicates that the country will need at least seven more refineries by 2030 to cope with a growing domestic demand [7].3 The first of these, constructed by Petrobras, is almost complete and start-up is forecast for 2012. The remaining units are still at the planning stage, with two of them scheduled to begin operations between 2014 and 2020. The remaining four are expected to come on stream between 2020 and 2030 [7]. It is worth noting that

2 According to Diringer [59], in 2005, the Brazil’s energy GHG emissions were around 362 MtCO2e. It is worth noting that GHG emissions from fuel combustion represent 16% of Brazil’s total GHG emissions, since most of it (around 58%) comes from deforestation [6]. 3 The EPE study [7] predicts an increase in demand for petroleum derivatives in Brazil 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 study conducted by [8] indicates an even greater demand for petrochemical products by 2020. Consumption of petrochemical products is growing rapidly, particularly for propane (7.2% per annum) and ethylene (5.7% per annum).

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for these four refineries the preliminary feasibility studies do not include yet any calculations of GHG emissions. In view of the potential impacts on climate change, Brazil has a responsibility to contribute actively to international efforts to stabilize GHG concentrations [9]. This underscores the importance of studying the special features and peculiarities of the Brazilian energy system and to plan its development on the basis of scene setting exercises focused on the emissions arising from the production and consumption of energy. In this way it will be possible to identify the potential for reducing emissions in the sector and the related costs of abatement. This study aims at estimating the average abatement costs (AAC) of CO2 emissions in the Brazilian oil refining sector in the 2030 horizon. The AAC of a project is by definition the difference between the cost in a reference scenario and the cost in a scenario with GHG mitigation (or a low carbon scenario), expressed in monetary terms per tonne (metric ton) of CO2 equivalent (US$/ tCO2e). The AAC could be seen as the carbon prices that would enable, from an economic standpoint, the implementation of the considered emission reduction measures. This method has been widely used in several studies to estimate the costs and potential abatements of different economic sectors in many countries, such as [10–13]. The Brazilian refining sector was divided in this study into two parts: existing refineries, which includes the refineries in operation and two refineries already under construction; and the new refining, which includes all new refineries in the 2030 National Energy Plan [7]. The existing refineries group comprises refineries more rigid for innovations, because these refineries are already installed and there are even space limitations. Refineries under construction have its refining scheme already defined. Therefore, they were included in the group of existing refineries. On the other hand, for new refineries (not under construction), in their conceptual phase, there is still a certain degree of flexibility in choosing processing units and alternative production routes. In this case, the most relevant result of the simulation is the choice of the refining scheme (or production routes) in light of a need to reduce GHG emissions. Therefore, analyzing the impact of CO2 emission costs on new projects in their design phase is very different from evaluating emission reduction alternatives to adapt or retrofit existing facilities. For this purpose, we ran simulations of two complex refinery configurations through a linear programming (LP) optimization model. The aim of this simulation was to determine the magnitude of the CO2 price necessary to significantly change the emissions of the proposed configurations. Note that here the introduction of a carbon-emission price on conceptual refineries is similar to evaluating the costs of carbon abatement for different emissions limits. As the economic analysis indicates, at the boundary, Pigouvian taxes (such as a carbon tax) and the abatement costs converge [14]. The paper is organized as follows: the next section elaborates the country’s oil refineries carbon emissions inventory. Section 3 describes the mitigation measures considered, and Section 4 presents the two scenarios for estimating mitigation costs (baseline scenario and low carbon scenario). Section 5 presents the estimates of average abatement costs for each option listed in Section 3. Finally, Section 6 presents the concluding remarks of the study by analyzing the barriers to the implementation of the envisaged measures.

Table 1 Energy consumption profile. Groups

Sources a

Process heat (PH)

Hydrogen (HY) Electricity (EE)

%

Fuel oil (FO) Refinery gas (RG) FCC cokeb(FC) Natural gasc (NG)

27 17 14 42

Total Hydrogen (HY) from natural gas

100 100

Total Grid electricity (EG) Self-generated Electricityd(EO)

100 24 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.

consumption and elaborates the CO2 emissions inventory of all Brazilian refineries. The methodology applied is based on IPCC [16]. CO2 emissions were calculated using the energy consumed per barrel and the respective capacities of each process unit, for each refinery, including the RENEST and COMPERJ refineries that are still under construction. COMPERJ was designed to consume initially 150,000 barrels per day of Marlin crude oil. Petrobras decided to expand the refining capacity to 165 thousand barrels per day (1st refining unit) plus a 2nd unit of refining with the same capacity (165 thousand barrels per day of oil). RENEST has a nominal capacity around 200,000 barrels/day and will use technology based on delayed coking. This refining scheme allows processing heavy oils, extracted primarily from the Brazilian Marlim oil field (in the Campos Basin) and the Venezuelan Merey type oil [7]. The first step of the inventory is based on the refining sector profile as of 2009. Additionally, an estimative of CO2 emissions in 2015 is performed considering that RENEST and COMPERJ will start their operation before that year. The refining profiles for RENEST and COMPERJ are based on [5,17,18]. Refineries use different inputs as sources of energy for their processes and the profile of these inputs can vary significantly among refineries. In this study, refineries’ carbon emissions were estimated using the average energy consumption profile of a Brazilian refinery, REDUC, between 2000 and 2005. The electricity can be imported from the grid or can be produced in the refinery. All hydrogen is considered to be obtained from the steam reforming of natural gas. Table 1 summarizes this information. The final energy consumption figures for each refinery unit were based on [19–21]. The average energy consumption profile was applied to the total fuel and electricity consumption in each refining unit. The energy consumption (ECRU) of each refining unit, which is represented by Eq. (1), was divided into: energy consumption in the process (EC1), energy consumption as hydrogen (EC2) and energy consumption as electricity (EC3).

ECRUi ðkJ=barrelÞ ¼

X

ECj

ð1Þ

j

i = AD, VD, FCC, RFCC, RC, HCC, CR, MTBE, DSF, HDTL, HDTQ, HDTN, HDTI, LUB, HDSG, HDSD, ALQ.4 j = PR, HY, EE 2. Co2 emissions in Brazilian oil refineries The Brazilian refining sector can be described as a typical cracking refinery scheme [15]. This study estimates the energy

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

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

3. GHG emissions mitigation measures

Emissions

2009

2015

Nominal capacity (millions of barrel/year)a Energy consumption (TJ/year)b kg CO2/barrel

764.4 214.702 22.3

768.9 396.473 28.5

a The average utilization factor of nominal processing capacity of Brazilian refining was 88% in 2008 [22]. b Based on [15,19–21,23].

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

ECj ðkJ=barrelÞ ¼

X

ECk

ð2Þ

k

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/barrel) = energy consumption from FCC coke, ECNG (kJ/barrel) = energy consumption from natural gas, ECHY (kJ/barrel) = energy consumption to produce hydrogen, ECEG (kJ/barrel) = energy consumption from grid electricity, ECEO (kJ/barrel) = energy consumption from self-generated electricity. CO2 emissions (EMi) from each refining unit are represented by Eq. (3). Emission factors (EF) used to calculate EMi for each unit derives from IPCC [16]. Besides, all hydrogen was assumed to be produced by natural gas reforming process. For this reason the emission factor of natural gas was used to hydrogen production.

EMiðtCO2 =m3 Þ ¼

X

ðECk  EFk Þ

ð3Þ

k

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 represented by Eq. (4).

EMref ðtCO2 =m3 Þ ¼

X

ðEMiÞ

ð4Þ

i

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, represented by Eq. (5).

EMtotal ðtCO2 =m3 Þ ¼

X

ðEMkÞ

ð5Þ

k

k = REDUC, RPBC, RECAP, REVAP, REFAP, REGAP, REPLAN, RLAM, REMAN, 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) – Alberto Pasqualini refinery; RLAM (BA) – LandulphoAlves refinery; REMAN (AM) Manaus refinery; LUBNOR (CE) – Northeast Lubricants; REPAR (PR) – PresidenteGetúlio Vargas refinery; IPIRANGA – Ipiranga refinery S.A.

All measures considered in this paper are directly related to oil refining – i.e. are located inside battery limits of oil refinery plants (for example, the production of liquid biofuels to supplement or replace petroleum products are not considered). GHG emissions mitigation measures are divided into two groups. The first set of mitigation options includes measures that can be adopted by existing refining facilities. The second set of mitigation options involves the optimization of a possible new refinery in Brazil with the aim of minimizing its production costs (including an additional cost for carbon emissions) to satisfy a specific demand in the Brazilian market. The average abatement cost of each mitigation option was determined on the basis of incremental costs compared with a baseline scenario at two discount rates: the one adopted by the Brazilian Official Long Term Plan (8% p.a.) [7]; and the one typically adopted by the private oil sector (15% p.a.), which provides the private agent’s opportunity cost. 3.1. Mitigation options for existing refineries According to Petrick and Pellegrino [24], it is possible over the medium to long term to establish a target for reducing energy use in existing refineries by between 15% and 20% (and, consequently, CO2 emissions). The recovery and reuse of thermal losses is the main option in the short run, while mitigating incrustation and fouling are of crucial importance over the medium to long term. Therefore, based on [25], two basic options for carbon emissions mitigation in existing Brazilian facilities are considered: thermal energy management and fouling mitigation.6 Thermal energy management is the main option for saving fuels in Brazilian existing refineries in the short term. Although chemical plants in Brazil and other parts of the world have already successfully adopted thermal energy management techniques, there are no large efforts in research and development associated to this option [26]. The Brazilian refineries have an impressive fuel savings potential as can be noted by their average Solomon Index (EII) values, which totaled 101, 105 and 106 in 2004, 2005, and 2006, respectively [27]. The Solomon Index EII is used to evaluate the energy efficiency of refineries around the world, by comparing a given refinery with a reference plant with the same level of technological complexity (the reference refinery is normalized as 100). An index higher than 100 indicates that the given refinery has a higher primary energy consumption than the reference refinery. For example, between 2004 and 2006 the average EII values hovered around 94 and 95 for exxon [28], 95 and 96 for BP [29], and 84 and 85 for shell [30]. Several measures associated with thermal energy management were considered to be implemented in the Brazilian oil refineries:  Use of low quality exhaust heat in refrigeration cycles by absorption [31].  Use of thermal residues for preheating feedstock (for example recovery systems can recover the heat produced in coking processes).  Design of energy and/or mass (water and hydrogen) integration basically employing the Pinch Techniques [32,33]; the use of Pinch Techniques provides energy savings in refineries of 20% [24]. According to [32,33], typical values would be between 10% 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 on technologies under development, are discussed in the last section of this paper, but are not valued in terms of abatement costs.

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 Direct feeding of intermediate products to the processes, without cooling and storage, aiming at recovering part of the residual heat in these products. For example, the thermal energy of the products of the distillation column can be directly recovered in 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 is normally lost in the cooling water or wasted to the atmosphere. Normally steam used for stripping ensures the flashpoint temperature and improves the fractioning of products, increasing the 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] analyze the technical potential for using Pinch Techniques in Brazil in refineries for energy (energy integration) and water (mass integration). These studies confirm that energy and mass integration networks are feasible options over the short term for the two Brazilian refineries. However, not all the hot waste streams are available for heat exchange. Volatile products that need to be rapidly cooled by water quench, intermittent streams [31] and streams containing suspended solids (e.g. catalysts) can be cited as examples. Finally, some streams in inaccessible parts of the refinery [31] are difficult to recover (e.g. FCC exhaust gases). According to Moreira et al. [38], which assessed a thermal energy management network for a Brazilian refinery, around 60% of the fuel consumption in the distillation tower can be saved. Considering the estimated share of atmospheric distillation units in the final energy consumption of Brazilian, this would correspond to a fuel savings of approximately 17%. The second group of measures assessed for existing Brazilian refineries includes the control of fouling at heat exchangers. Besides reducing the area of heat exchangers fouling causes maintenance problems and risk of accidents. Heat exchange networks with incrustations have approach temperatures higher than 40 °C [33] when typical values in refineries hover between 10 °C and 20 °C. Estimates done in the early 1980s for a typical refinery of its period with a primary processing capacity of 100 thousand barrels per day suggest that fuel consumption could be 30% less in the atmospheric distillation column by controlling fouling in the heat exchangers [39]. A more recent study, however, pointed to a lower potential. Although still significant, the reduction was only 10% [40]. Yet, incrustation in heat exchange networks is a bottleneck impeding the application of heat recovery systems. The gains achieved from reducing fuel consumption by controlling incrustation 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 of incrustation in a 100 kbpd atmospheric distillation column and found an additional energy consumption of 13.0 MJ per barrel processed (or around 3.4% of specific energy consumption in Brazilian refineries). In sum, adopting the estimates of [25], the potential fuel savings of each option considered to be installed in Brazilian existing refineries are resumed in Table 3. 3.2. Mitigation options for greenfield refineries Our analysis was based on the results obtained by the simulation of [43] through a linear programming model representing two types of new refineries in Brazil: a refinery with focus on diesel and other with focus on petrochemicals. These are precisely the two refineries that are listed in Brazil’s Official Energy Plan [7].

Table 3 Fuel savings for existing facilities. Options

Fuel savings (%)

Thermal energy management Fouling mitigation

15 2

The model is a static, single-refinery LP, based on the Generateur de Matrices pour ModelesEnergie (GEMME), from the Institute Frances du Pétrole (IFP). GEMME was modified to consider the refining configurations proposed by [43], their respective yields from processing Brazilian crude oils, and the output of refined products suitable for consumption in the Brazilian market. The optimization model considered monetary values for the cost of CO2 emissions in order to seek viable solutions for avoiding such emissions. Fig. 1 presents in simplified form the main units pre-defined in the model. The following procedure was adopted7: 1. Adjustment of the linear programming model for two basic refining configurations. 2. Optimization of these two configurations without considering carbon prices. 3. Optimization of the two configurations with the insertion of a carbon price (US$25/tCO2, US$50/tCO2, US$100/tCO2 and US $150/CO2). The outputs of the refineries were kept unaltered in terms of products (quantity and quality). 4. Identification of the carbon price that altered the refinery scheme in the optimized model. The most relevant result of the simulation was the choice of the refining schemes (or the routes to obtain oil products) for new refineries, at different carbon prices. The findings of the optimization model indicated that the refinery schemes changed in the same direction for both discount rates adopted in our study. However, the abatement cost at 8% p.a. was 58 US$/tCO2, while it was 100 US$/tCO2 at 15% p.a. Therefore, we found that the technical possibilities to change the refinery schemes without altering the refinery yield are limited, mainly focusing on replacing FCC units by hydrocracking ones and switching fuels with high carbon content. In sum, abatement costs changed according to the discount rates adopted, but not because of the choice of a different scheme at a lower (or a higher) discount rate. The 100 US$/tCO2 is the carbon price that leads to the modification of the original refining scheme (at 15% p.a. discount rate and useful life of 30 years). Actually, the two proposed refineries (focused on diesel or basic petrochemicals) significantly reduce their emissions starting at a price of US$ 100/tCO2 – see Table 4. At prices under 100 US$/tCO2, the proposed refineries reduced their operational margins, but did not alter their schemes. After reaching US$ 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 hydroconversion processes. Hydrocracking gains importance, while FCC loses. The former is less energy-intensive than the latter. This result shows that there is not much room for curbing carbon emissions through changing new refineries’ configuration at low abatement costs. Actually, when considering CO2 prices, refineries have little margin to alter their process configuration at values be7

For further details, see [43].

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

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

Petrochemical

Diesel

Without carbon prices (original scheme) With carbon prices (US$ 100/tCO2 at 15% p.a or US$ 58/tCO2 at 8% p.a.)

54.8 37.7

30.7 17.3

low US$100/tCO2. This is a very high figure when compared to the current carbon price in the European market (around US$25/tCO2) or even to the forecasted price of US$50/tCO2 [44]. 4. Co2 emissions abatement scenario The estimates of average abatement cost (AAC) require the comparison of CO2 emissions between scenarios. For this reason two scenarios were adopted: a reference scenario and a low carbon scenario. 4.1. Reference scenario The Reference Scenario considers the investments proposed by Petrobras up to 2015 for existing refineries. In this case, the calculated GHG specific emissions of existing refineries are depicted in Table 5. For greenfield refineries, the reference scenario was based entirely on the Brazilian Government Official Long Term Plan [7] (Fig. 2). GHG emissions from new refineries were calculated using the specific emissions of new refineries (without carbon prices) as depicted in Table 4. As such, total carbon emissions of new refineries are summarized in Table 6. 4.2. Low carbon scenario The low carbon scenario considers the implementation of the proposed mitigation options in new and existing Brazilian refineries. Two stages of mitigation measures implementation are considered for the existing refineries. The first stage occurs in 2015 at the following Brazilian refineries: REPLAN, REDUC and

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

2007

2015

MtCO2/yr

13.8

25.5

REGAP. The second stage is implemented in the other refineries up to 2020: RPBC, RECAP, REVAP, REFAP, RLAM, REMAN, LUBNOR, REPAR and IPIRANGA. Considering only the thermal energy management in Brazilian refineries using the data obtained from two major refineries, the potential fuel savings hover around 10% (of total fuel consumption). The implementation cost, based in [45], is approximately 13 US$/GJ a year, considering a project of 15 years of life and a discount rate of 15% p.a. (this cost equals 9 US$/GJ a year at 8% p.a.). Around 90% of these costs derive from investments in the beginning of the project [25,46]. This figure can be considered slightly conservative when compared with those from [38], between 15% and 21%.8 In sum, the fouling of heat exchange network is a bottleneck for application of heat recovery systems. The gains from saving fuels only controlling the fouling have been estimated at 2% to US refineries [24] – an amount that is consistent with those obtained in [41] for Brazil. A higher value, however, is provided in [42], indicating the need for further studies. These authors analyzed the effects in an atmospheric distillation column of 100 kbpd. They found an additional consumption of 13.0 MJ per barrel processed (or about 3.4% of the specific energy consumption in Brazilian refineries). Alsema [45] estimates the annual costs of operation and maintenance of approximately 21 US$/GJ and 15 years of useful life of technology, while the investment cost can be considered zero. These numbers are also consistent with the experience of a refinery in India with thermal energy management systems [47]. 8 Results in [47] show a 10% fuel saving for a crude oil refinery with a capacity of 1 MMTa. This value was obtained considering a 6.5% self-consumption (based on its similarity to the Brazilian REGAP refinery). Since the measures associated with energy thermal management save 6450 SRFT (Standard Refinery Fuel Tonne), they saved exactly 10% of fuel at the refinery, confirming the value used in this article. The data from [47] also confirm the economic forecasting from [45].

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

Table 6 Carbon emissions of new planned refineries – reference scenario (MtCO2/year). 2015

2020

2025

2030

2.8

8.6

11.4

14.2

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 of US$100/tCO2, as calculated in Section 4 – see Table 9. The carbon price of US$100/tCO2 was obtained at a 15% p.a. discount rate. As mentioned before, this is the rate typically adopted by the private oil sector, and used by Pertusier [48]. Yet, the same scheme was also optimized at 8% p.a. discount rate. In this case the average abatement cost equaled US$58/tCO2 – i.e., at 8% p.a. discount rate and US$58/tCO2 new refineries would abate the same amount of carbon that they would abate at 15% p.a. and US$100/ tCO2.

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

ð6Þ

where AACa = average abatement cost per ton of CO2 avoided. LC = levelized cost for mitigation option. E = annual avoided emissions for each option considered. i = period of analysis (2010–2030). The LC of an option represents the difference of the levelized investment cost (LIC) and annual financial results (AFR) of the mitigation option implementation (Eq. (7)). The AFR is given by total revenue (RE) less the expenditures in operation and maintenance cost (OM) for each mitigation option (Eq. (8)). The levelized investment cost (LIC) and annual financial results (AFR) for each option is related to the reference scenario.

LCi ¼ LICi  AFRi

Year

Cost (US$)

Mitigation measures Thermal energy management

Fouling mitigationc

2015

Total capital costa Total O&M costb

367,340,552

0

40,815,617

90,701,371

2020

Total capital cost Total O&M cost

321,512,072 35,723,564

0 79,385,697

a Total capital cost in the year of implementation of measures in all Brazilian refineries. b Total O&M cost per year. c Fouling mitigation was treated as a operational cost (such as maintenance costs).

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

5. Average abatement cost

P2030 LCi AACa ¼ Pi¼2010 2030 i¼2010 Ei

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

ð7Þ

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

Year

Thermal energy management

Fouling mitigation

2015 2020

2,021,760 3,831,053

269,568 510,807

Table 9 Carbon 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

AFRi ¼ ðREoption  REreference Þi  ðOMoption  OMreference Þi

ð8Þ

where LC = levelized cost for mitigation option. LIC = levelized investment 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 differential cost of annual investment required for the option implementation multiplied by the capital recovery factor (CRF) in each scenario (Eq. (9)).

LICi ¼ ½ðCIoption Þi  CRFoption   ½ðCIreference Þi  CRFreference 

ð9Þ

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where

CRFoption ¼

Table 10 Average abatement costs.

ð1 þ tÞnoption  t ð1 þ tÞnoption  1

CRFreference ¼

ð1 þ tÞnreference  t ð1 þ tÞnreference  1

LIC = levelized investment cost. CRF = capital recovery factor. CI = cost of annual investment. t = discount rate. n = lifetime of the project. i = period of analysis (2010–2030). As mentioned before, the estimation of the average abatement costs followed two approaches:  The first aimed to compare the alternatives according to the discount rate used by the Brazilian government (8% p.a.). This is a good proxy of a ‘‘social’’ discount rate [49]. Although the discussion about an intergenerational equitable discount rate is controversial, the discount rate used here is in line with those pointed out by [50,51]. Furthermore, the figure used is equivalent to the opportunity cost of capital for the Brazilian government. Actually, as of today, the long term opportunity cost for the Brazilian government is around 1.5–2.5% spread over the US treasury T-Bond 30, which pays 4–5% p.a. [52].10  The second aimed to estimate the carbon price (break-even carbon price) that guarantees the feasibility of the mitigation option compared to the reference scenario, according to the internal rate of return (IRR) required by the Brazilian oil sector. The IRR considered was 15% p.a. Table 10 summarizes the results. The additional cost of investment between 2010 and 2030 in present values is also calculated for the discount rates of 8% and 15% p.a. (Table 11). At 15% p.a., the reduction in GHG emissions still shows a high abatement cost. This result is consistent with the current experience of several refining plants worldwide, which are exposed to targets for reducing GHG emissions; they face major technical challenges to realize these goals and frequently prefer to pay fines of 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 the following major alternatives: LPG replacing fuel oil, and natural gas replacing butane and fuel oil. They based their economic analysis on a 6–12% p.a. discount rate, which is lower than the one adopted in this paper for describing Brazil’s oil sector opportunity cost. Thus, findings presented in [58] are not easily comparable with our results. Actually, the measures are not the same, and Holmgren and Sternhufvud [58] identified for their specific case studies huge carbon abatement potential by replacing fuel oil with natural gas or LPG. In this case, the relative fuel prices drive most of CO2 MAC found by these authors. In [58], natural gas and LPG relative prices tend to favor their use for hydrogen production and heat generation, respectively. This is not the case in Brazilian oil refineries.

6. Final remarks Brazil’s responsibility to actively contribute to international efforts to stabilize concentrations of greenhouse gases, in addition to the new oil refinery projects, makes the study of abatement costs an important issue. The existing refineries in Brazil are being modified 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 by Dixon et al. [54], approaches that avoid subjectivity whendefining this rate include: the opportunity cost of capital, donor lending agency requirements, and cost of money to the government. Finally, 8-9% seems to be consistent with the cost of capital of oil companies [51,55].

Mitigation options

(US$/tCO2) 8% discount rate

Changing design of new refineries

58.3

15% discount rate 99.9

Improving energy use of existing refinery units Thermal energy 20.2 77.3 management Fouling mitigation 115.6 210.8

Emission reduction (1000 tCO2)

51,796

52,250 6967

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

Net present values (1000 US$) 8% discount rate

Changing design of new refineries 1,587,206 Improving energy use of existing refinery units Thermal energy management 2,159,889 Fouling mitigation 479,975

15% discount rate 831,3906 1,332,723 296,161

derivatives produced and of increasing the conversion of heavy crudes into high-quality medium and light products. The main investments made so far have been to adapt existing units and to install deep conversion (delayed coking) and hydrotreatment units. The Brazilian case is thus emblematic, as it involves new complex refining projects, conceived to satisfy a growing market for medium derivatives and petrochemical feedstocks, typical of developing countries, and to absorb the forecast increase in domestic crude output, typical of oil producing countries. On top of these factors, Brazil may assume carbon emission reduction targets after 2012, 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 relatively high carbon abatement costs. The most promising alternative is thermal energy management. Private investors perceive this option at around US$80/tCO2, which is still high. The different perceptions of abatement costs according to the discount rate used indicate the need of public polices for promoting carbon mitigation measures. Indeed, oil companies usually prefer to focus on their core business. Therefore, the deployment of the mitigation options faces several barriers:  The degree of maturity of some of the technologies considered in the study negatively affects the risk perception of private agents – i.e., could lead to higher transaction costs.  Even for the commercially available technologies, a huge difference exists between the discount rate used by the private segment of the petroleum industry and the discount rate used by the State for comparing infrastructure investments. This gives an idea of the high opportunity cost of oil companies. To overcome these barriers, public policies could be deployed or reinforced. Actually, as of today, several fuel savings programs exist under the aegis of the National Program for Rationalizing the Use of Petroleum Derivatives and Natural Gas (CONPET), which is a program run by the Brazilian Ministry of Mines and Energy [60]. Nevertheless, the current annual budget of CONPET is relatively low – under US$2.5 million per year [61], and thus other sources of finance have to be tapped. For instance, CONPET activities could be improved if assistance from the Brazilian

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National Bank for Economic and Social Development (BNDES) programs were forthcoming. BNDES is linked to the Ministry of Development, Industry and Foreign Trade. It normally finances large industrial and infrastructure developments. Finally, a further group of mitigation alternatives analyzed in this paper involves the modification of the ‘optimum refining scheme’ of greenfield refineries. Yet, new plants only modified its refining scheme at US$100/tCO2. However, as proposed by [43], this result is different when the possibility of capturing and sequestering carbon (CCS) is taken into consideration. Several sources contributed to overall GHG emissions of an oil refinery: steam boilers and process heaters, regenerators of FCC units, and hydrogen production units. Catalysts regeneration in FCC units is a large emitter (coke deposited on a catalyst is burnt with air). However, the scientific literature indicates that capturing CO2 from this post-combustion stream is very expensive due to low concentration11 and low pressure of flue gas streams [62–65]. In order to deal with this issue, experts propose to use the oxy-fired FCC catalyst regeneration concept [62–64], or the chemical looping combustion concept – CLC [63,66,67]. In the oxy-fired FCC option, which is already under a development phase,12 pure oxygen, instead of air, is used to burn the coke in the regenerator and flue gas is partly recycled to avoid temperature runaway. De Mello et al. [64] showed a 45% decrease in CO2 capture cost for oxy-firing technology compared to the amine absorption alternative. The CLC option is a novel (or still immature) technology, which is based on a solid carrier able to chemically adsorb oxygen from air (oxidation in the air reactor) and release it in the presence of a gaseous fuel (reduction in the fuel reactor). In sum, as of today, capturing CO2 from FCC post-combustion streams is too expensive and would require the development and deployment of novel concepts, such as oxy-firing or CLC. On the other hand, hydrogen production allows a single point source for CO2 capture [65]. This indicates that CCS could become a key measure for reducing CO2 emissions from refineries in the future, altering the unit refining operations and the refinery scheme. However, new CCS concepts, especially focused on FCC emissions, should be addressed by R&D investment. In this case, the so-called Brazilian CT-Petro Sectoral Fund should well be a key instrument. This fund is financed with a fraction of the Brazilian government take (royalties) related to the petroleum production [68]. It could also be used for promoting research in other innovative techniques. For instance, two promising alternatives could be developed as well: the bio-desulfurization and oxidative desulfurization (ODP) of diesel. The former involves a set of promising processes designed to reduce the sulfur content of petroleum products under moderate conditions (with less energy consumption). The latter is a non hydrogen consuming desulfurization technique [25]. The ODP process, although still at the development stage, holds out good prospects for diesel [69]. ODP would also save hydrogen that could be diverted to heat generation in the refinery.

Acknowledgments The authors thank the Brazilian National Council for Scientific and Technological Research (CNPq) for financial and institutional support. This paper derives from a more comprehensive study carried 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 contains less than 1% CO; (2) partial burn mode, where the regenerator exhaust gas contains less than 6–8% CO [49,62]. 12 Particularly noteworthy is the small pilot held by Petrobras at Landulpho Alves refinery [63,6].

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would like to thank Christophe de Gouvello, the Senior Energy Specialist of World Bank.

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