Exergy assessment and energy integration of advanced gas turbine cycles on an offshore petroleum production platform

Energy Conversion and Management 197 (2019) 111846

Contents lists available at ScienceDirect

Energy Conversion and Management journal homepage: www.elsevier.com/locate/enconman

Exergy assessment and energy integration of advanced gas turbine cycles on an offshore petroleum production platform

T

Fernanda Cristina Nascimento Silva , Daniel Flórez-Orrego, Silvio de Oliveira Junior ⁎

Department of Mechanical Engineering, Polytechnic School, University of Sao Paulo, Av. Prof. Mello Moraes, 2231, Cidade Universitária, São Paulo, SP, Brazil

ARTICLE INFO

ABSTRACT

Keywords: Offshore Exergy Oxyfuel Air separation Carbon capture

On offshore platform applications, power and heat are normally supplied by simple open cycle gas turbine (OCGT) and heat recovery steam generators (HRSG) at lower efficiencies if compared to onshore combined cycle systems. Certainly, due to the reduced available space and the weight constraints, combined cycles are not commonly considered as cogeneration systems on conventional offshore petroleum platforms. However, more stringent environmental policies for the natural gas and oil production activities have motivated the integration assessment of advanced technological solutions that aim to mitigate the environmental impact that conventional offshore platforms are responsible for. Accordingly, in this paper, the effect of the integration of a low emission, oxyfuel gas turbine cycle is analyzed and compared against an amines-based post-combustion system and a conventional offshore petroleum platform operation in terms of its exergy efficiency and reduced atmospheric CO2 emissions. Indeed, although the conventional configuration is the most efficient, the oxyfuel powered platform configuration presents close power cycle efficiency of 27.10% and the lowest specific CO2 emissions of 0.014 kgCO2/toil, whereas the amines-based layout provides the best cogeneration efficiency (55.34%) of the advanced configurations. Moreover, an energy integration analysis is performed to identify the heat recovery potential, while the exergy method is used to evaluate and quantify the most critical components that lead to the largest irreversibilities along the primary separation, cogeneration and gas compression systems. As a result, the study points to ways of decarbonizing offshore applications in the oil and gas sector.

1. Introduction Currently, plenty of evidence seems to point towards the impairing effects on the climate conditions of the greenhouse gas emissions derived from the anthropic activities [1,2]. This fact has urged environmentally committed governments, private companies and academic institutions to search for the best combination of energy technologies that may help to mitigate the contribution of the natural gas and oil sectors to the overall budget of carbon dioxide emissions [3]. These concerns are justified if it is considered that the energy intensive heat and power generation fundamentally relies on the combustion of fossil fuels, whereas the corresponding integration of postcombustion carbon capture systems is rather an exception [2]. On the other hand, although fossil-free energy future could be envisaged at a long term, a more likely scenario in the transitional short and middle time frames will correspond to a diversified grid of energy resources. This is expected in part due to the extensive existing infrastructure of the fossil fuels production and distribution, as well as to the intermittency and early stages of development of renewable energy sources.

⁎

In fact, the most likely scenario seems to point at a diversified energy matrix in which the solutions are closely integrated and at the same time decentralized [4,5]. According to some estimates [6], more restrictive scenarios that include carbon capture and storage (CCS) as a mitigation tool show this technique might account for just under 10% of the total reduction of emissions in 2040, out of which one third would be allocated to the power and industrial sectors. Moreover, among the different reported CCS techniques, oxyfuel systems seem promising as they render the treatment of the main combustion products relatively easier compared to conventional air-blown post-combustion processes [7]. In this process, the fuel reacts with nearly pure oxygen (above 95% mole) resulting in a flue gas composed mainly of CO2 and water, which can be separated via condensation. Nonetheless, the energy savings in the flue gas purification stage is partially offset by the need for an air separation unit (ASU), which eventually impairs the overall efficiency of the system. Furthermore, in order to control the turbine inlet temperature and to avoid harmful material overheating, a partial recycling of the flue gases produced is still required. Hot section temperatures could

Corresponding author at: Department of Mechanical Engineering, Polytechnic School, University of Sao Paulo, Sao Paulo, Brazil. E-mail addresses: [email protected] (F.C. Nascimento Silva), [email protected] (D. Flórez-Orrego), [email protected] (S. de Oliveira Junior).

https://doi.org/10.1016/j.enconman.2019.111846

Available online 15 August 2019 0196-8904/ © 2019 Elsevier Ltd. All rights reserved.

Energy Conversion and Management 197 (2019) 111846

F.C. Nascimento Silva, et al.

Fig. 1. Conventional open cycle gas turbine-powered FPSO configuration.

also be controlled by either injecting steam (alongside the gaseous fuel, the oxidizer and the recycled flue gas) into the combustor chamber or directly into the turbine. Such strategy is actually employed in various works [8,9], as long as high temperature resistant gas turbines are not widely commercially available. Employment of such technique avoids the emissions dilution in nitrogen, which, beyond making the purification step easier and reducing the amount of excess air needed, allows a lower NOx power plants to be envisaged [10]. Although oxyfuel cycles and offshore platforms have been studied separately, the integration of both has rarely been investigated, let alone under the lens of an exergy analysis. Nonetheless, several works aiming at the efficiency enhancement of offshore platforms and/ or CO2 emissions reduction have been conducted. In [11], Nguyen et al. presents several strategies to improve the platform’s performance ranging from integration of steam cycles to organic Rankine cycles (ORC), among others. Furthermore, Carranza et al. in [12,13] investigated the impact of modes of operation and, more to the point, the integration of a post-combustion carbon capture system on a FPSO operating in the Pre-Salt region. Despite reductions in CO2 emissions and fuel consumption, the mitigation levels accomplished by employing those techniques are still significantly lower when compared to the levels the authors of oxyfuel cycles claim to achieve. In [14], different concepts are assessed in order to satisfy the power and heat supply requirements of an offshore platform. According to the authors, although a remarkable reduction of around 30% in CO2 emissions can be achieved by connecting the platform to the power grid in comparison to the Gas Turbine plus Waste Heat Recovery Unit configuration, the oxyfuel driven setups such as the S-Graz cycle and other technologies again outperform the environmental mitigation capabilities of the former reported configuration. Moreover, few studies that looked into the applicability of oxyfuel cycles in the context of offshore applications, such as that performed by Jordal et al. [15], which analyzed the semi-closed oxyfuel combustion combined cycle (SCOC-CC), some of its variants and integration opportunities, did not perform an exergy analysis, which would shed light on the understanding of the viability and challenges of employing advanced cycles. Accordingly, the fact that current efforts have not been enough to satisfactorily address emissions attenuation [16] and in light of the recent commitments declared by Petrobras, Brazil's largest oil and gas company, in its 2019–2025 strategic roadmap to abate CO2 emissions in

exploitation, production and refinery activities [17], the present work aims to compare the performance of three configurations for an FPSO unit intended to operate at the Brazilian Pre-salt oilfield conditions under different cogeneration and carbon capture scenarios. The conventional configuration, which represents the business as usual scenario, will be the reference against which a platform equipped with a post-combustion, amine-based carbon capture system, and an S-Graz cycle based platform will be compared. The exergy method is used to propose suitable exergy efficiency definitions to allow for a fair level playing field when comparing the three designed setups. The subunits exergy destruction breakdown as well as the unit exergy costs and the specific CO2 emissions calculated are also suggested as suitable indicators to quantify and allocate the irreversibility, the exergy intensity and environmental impact among the main units and streams composing the petroleum platforms. Meanwhile, the energy integration analysis is used to calculate the maximum potential of heat recovery. Finally, the penalties associated to the introduction of an air separation (in the S-Graz cycle based configuration) and an amines-based chemical absorption carbon capture system are discussed in the light of the performance of the conventional configuration, which spares any CCS technology. 2. Conventional, amine and oxycombustion-based platforms layouts Firstly, it is important to notice that the conventional platforms operating in Brazil are not yet equipped with carbon capture systems for the sake of mitigation of the atmospheric emissions produced through the combined heat and power generation. Thus, this study is mainly motivated by recent commitments for the introduction of carbon capture systems in the existent and new Brazilian FPSOs [18], due to the increasing environmental regulations in the natural gas and oil industry. For instance, the largest oil and gas company in Brazil, Petrobras, in its 2040 strategic plan and 2019–2023 business and management plan, aim to keep emissions in the same levels of 2015, even with increase in production. Emissions related to exploitation and production is expected to have a 32% reduction, whereas refining should decrease by 16% [17]. Accordingly, the advantages of two proposed platform configurations with carbon capture systems, namely a chemical absorption-based setup using a typical aqueous 2

Energy Conversion and Management 197 (2019) 111846

F.C. Nascimento Silva, et al.

Fig. 2. Chemical absorption-based (methanolamine), open cycle gas turbine-powered FPSO configuration.

methanolamine solution and other based on the so-called zero-emission S-Graz cycle, are thoroughly compared with the performance of a conventional configuration of an offshore petroleum platform. Figs. 1–3 depict the three types of plants studied, which are assumed to operate at the conditions of highest oil production rates in a mature oilfield located at the Brazilian Pre-salt reservoir [12]. Therefore, the results are not indicative of how the platform will perform throughout its entire lifetime cycle and efficiency is expected to drop once the peak of oil production passes. It is also noteworthy that water production is not considered at this point of the lifetime of the well, based on data by [19]. The representative production rates of oil, CO2, and natural gas are based on the reported literature [20–22] and are briefly described in this section. For all the three configurations, petroleum is extracted from the well at a mass flow rate of 196 kg/s, 40 °C and 15 bar, and goes through an energy intensive primary separation unit modeled as a black box. The multiphase separation process of petroleum into natural gas, CO2 and oil considers the specific energy consumption required to separate the mixture [11,23,24]. After the primary separation, oil is

pumped to the shore at a flow rate of 161 kg/s. Meanwhile, the separated gas phase is compressed to 52 bar [25] and sent through a membrane purification system which separates it into a permeate methane-rich stream and a CO2-rich stream that still contains a large amount of methane. The stream composition after the membrane separation is such that the methane-rich stream (28 kg/s) is composed of approximately 97% of methane and 3% CO2 (molar). Next, a fraction of the purified natural gas stream (approx. 1.5 kg/s, depending on the power plant configuration used) is decompressed to about 40 bar and fed as fuel into the cogeneration system. The remaining purified gas is then further compressed to above 245 bar and exported to the shore. Meanwhile, the carbon dioxide rich stream (approx. 8 kg/s), which has a molar composition of 70% CO2 and 30% methane, is compressed up to 450 bar suitable for injecting it into the well for the sake of enhanced oil recovery (EOR). The conventional configuration shown in Fig. 1 is the most common configuration in the commercial scenario of the Brazilian FPSOs. In this design, high temperature gases (1,400 °C) are expanded in the open

Fig. 3. S-Graz cycle-powered FPSO configuration. 3

Energy Conversion and Management 197 (2019) 111846

F.C. Nascimento Silva, et al.

cycle gas turbine (OCGT) to produce power, whereas the energy available at the turbine exhaust is used to raise hot water that will heat up the petroleum mixture at the primary separation system. The expanded cold flue gases at low pressure are finally discharged to the atmosphere without any other procedure undertaken for flue gas purification purposes. As concerns the amine-based configuration (Fig. 2), the exergy embodied in the gas turbine exhaust gas is not only used to supply the heat requirement in the primary separation unit, but also to raise steam for providing the reboiler duty in the chemical desorption process of the MEA loop, wherein methanolamine is used to separate the CO2 out from the combustion gases before being compressed for re-injection purposes. On the other hand, the purified flue gas is discharged to the environment close to atmospheric pressure. During the CO2 compression, the moisture is continuously condensed and separated, and the dried CO2 gas is compressed to elevated pressures of about 450 bar, so it can be injected back to the well for enhancing the petroleum recovery and mitigating the environmental impact. The oxyfuel cycle studied in this work resembles the S-Graz configuration proposed by Wolfgang Sanz in 2005 [10] and inspired by the original idea of the Graz cycle by Herbert Jericha, 1985 [26]. In the simplified flowsheet of the S-Graz cycle-powered platform (Fig. 3), the primary separation of petroleum, the compression process of the exported methane-rich gas and of the CO2 rich-streams are the same as in the previous configurations. However, since pure oxygen is used for combustion instead of normal air, an additional air separation unit (ASU) is required. Differently from the previous offshore platform configurations, a fraction of the methane-rich gas is fired with an oxygen-rich stream at 40 bar. Recycled combustion gases (78% H2O and 22% CO2 molar) together with expanded steam are injected into the turbine combustor in order to control the gas turbine inlet temperature (1,400 °C). Furthermore, superheated steam (565 °C, 180 bar) is generated in a heat recovery steam generator by using the exhaust gases of the gas turbine, and expanded to produce further power before the steam injection [8]. It is important to point out that steam is not only injected to the combustor chamber, but also at the admission of the gas turbine. Out of the total amount of combustion gases produced, 71.5% of the molar flow is recirculated and compressed back to 40 bar before entering the combustor chamber. The remaining 28.5% of the flue gases are further expanded (0.04 bar) and then cooled to 18 °C by a vapour-compression refrigeration system, partially separating the water in a vapour-liquid separator. The captured CO2 is then recompressed to suitable pressures for geological injection and storage, whereas the excess water produced in the combustion process is discarded to the sea.

ASU is calculated as 286.3 kWh/tO2. 3. Process modeling and performance indicators In the following sections, a combined energy integration analysis and exergy assessment are used to determine the overall performance of the studied configurations, as well as of the utility systems thereof in terms of energy consumption, process irreversibility, as well as the thermodynamic potential for heat recovery. The methodology used for the allocation of the unit exergy costs and specific CO2 emission among the representative streams of the studied platforms is also described, along with the proposed exergy efficiency definitions used to rank the performance of the advanced and conventional configurations. Mass, energy and exergy balances of each sub-process of interest are carried out by the use of Aspen Hysys® V8.8 software. As for the thermo-physical properties of each flow present in the system, PengRobinson and Acid Gas Fluid Packages have been used. The latter developed with the Peng-Robinson equation of state for vapour phase and electrolyte non-random two liquid (eNTRL) activity coefficient model for electrolyte thermodynamics, according to the documentation of the software and which are further detailed in [29–32]. Physical and chemical exergy calculations, as well as exergy efficiencies are assessed by using VBA® scripts as user defined functions [33]. Various performance indicators are proposed for each configuration so that objective comparisons between the different designed setups can be achieved. Table 1 displays three exergy efficiency definitions that allow different interpretations of the configurations studied. All equations are applied to control volumes that extend from air entering the air compression train to release of flue gas (Power generation unit), as in the conventional case, or CO2 captured leaving for re-injection, as in the case of the SGraz (Air separation, power generation and CO2 compression units) and amines absorption cycles (Power generation, MEA loop and CO2 compression units). Eq. (1) aims to specifically evaluate the ability of the utility system to efficiently convert the chemical exergy of the fuel consumed into net power, required by the ASU and the injection compression system together with other ancillary equipment in the platform. On the other hand, Eq. (2) evaluated the capacity of the utility system to operate in a combined heat and power (CHP) generation mode. Finally, Eq. (3) measures the increase in output total exergy relative to the inlet as a result of consumption of the fuel stream exergy, effectively contextualizing the FPSO unit’s main function, which is separating petroleum into its products. It is important to stress that ΔBtotal is calculated with respect to the streams that are not consumed within CH Q the utility system as fuel. Moreover, the terms Wcycle , BHRSG and Bfuel refer to the net power produced considering the control volume aforementioned; the exergy associated to waste heat recovery from the flue gas at the turbine outlet and from the compression waste heat available also within the given control volume; and chemical exergy of the fuel stream, respectively. Previous works by Oliveira Junior and van Hombeeck [34], Silva and Oliveira Junior [35] and Carranza and Oliveira Junior [12] have already calculated the exergy performance of the offshore petroleum platforms in Brazil, whereas Nguyen et al. wrote extensively about different exergy efficiencies applied to the offshore context [36]. Further studies [37–39] analyzed the processes present in

2.1. Air separation unit A cryogenic air separation unit (ASU) has been modelled to fulfil the oxygen requirement of the S-Graz power cycle. A mass flow rate of 31.38 kg/s of normal air at ambient conditions of 25 °C and 1 bar enters the air separation unit and is compressed up to 7.45 bar and 40 °C. About 95% of the compressed air is cooled down in the main recovery heat exchanger (−170 °C) and then it is fed into a high pressure column (HPC) [27]. The remaining 5% of the compressed air (−139 °C) is expanded to 2.95 bar before entering the low pressure column (LPC). Next, both the liquid bottom and vapour overhead outlet of the HPC are cooled down by using the nitrogen rich stream coming from the LPC overhead, and then expanded and sent to the LPC where further air separation occurs. Both columns are thermally integrated as the HPC condenser provides the duty required by the LPC reboiler. A last expansion step up to atmospheric pressure of the nitrogen rich stream produced in the LPC allows for an increased cooling effect in the main heat exchanger [28]. The final ASU products correspond to an oxygenrich stream (99.5% molar) and a nitrogen-rich stream, the latter discharged to the environment. The specific power input required for this

Table 1 Overall exergy efficiencies proposed for the FPSO units. Definition Power

Formula power

=

Buseful, output Bchemical, fuel

=

Wcycle BCH fuel

cogen

=

Buseful, output Bchemical, fuel

=

Q Wcycle + BHRSG BCH fuel

Cogeneration Separation

4

Equation

sep

=

Btotal Bconsumed

=

Btotal, output Btotal, input Btotal, fuel

(1) (2) (3)

Energy Conversion and Management 197 (2019) 111846

F.C. Nascimento Silva, et al.

Table 2 Main process variables in the studied configurations. Process parameter

Amine-based

Graz cycle-powered

Conventional

Oil production flow rate (kg/s) Total CO2 from well (kg/s) Methane fuel consumed (kg/s) Methane exported (kg/s) Air consumption (kg/s) Oxygen consumption (kg/s) Oxygen purity (%) ASU oxygen recovery (%) ASU specific power consumption (kWh/tO2) ASU N2 rich waste gas (kg/s) Combustor pressure (kPa) Gas turbine exhaust pressure (kPa) Net power produced (kW) Cooling requirement (kW)1 Specific cooling requirement (kJ/tOil) Condensate from CO2 compression (m3/h) Combustor/Gas turbine steam splitting (%) Recycled flue gas CO2 mole fraction Percentage of recycled flue gas (%) Graz total water disposal (m3/h) Minimum temperature approach - flue gas/HRSG (°C) Water/CO2 mixture flash pressure (kPa) CO2 rich stream separated by membrane (kg/s) CO2 emissions in methane export (kg/s) CO2 captured (kg/s)2 Specific CO2 captured (kgCO2/tOil)2 Total CO2 emitted (kg/s) MEA make up water (m3/h) CO2 recovery using MEA (%) CO2 fed to MEA loop (kg/s) MEA loop reboiler duty (kW) Specific MEA desorber steam consumption (MJ/kgCO2)

161 9.28 1.55 24.38 45.82 – – – – – 4,000 300 21,629 51,397 319,240 0.49 – – – – – – 8.2 2.07 3.81 23.7 0.26 4.7 93.7 4.04 17,002 4.49

161 9.28 1.53 26.47 31.38 5.79 99.5 79.19 286.3 25.59 4,000 100 27,477 52,156 323,954 6.3 91.5/8.5 0.22 71.52 11.40 83 4 8.2 2.07 4.15 26.2 2.3E-3 – – – – –

161 9.28 1.43 26.57 42.29 – – – – – 4,000 300 19,801 35,088 217,940 – – – – – – – 8.2 2.08 – – 3.73 – – – – –

1. Cooling tower water inlet at 18 °C, 60% relative humidity; 2. This value only includes the CO2 produced when burning the methane fuel, excluding the original CO2 already extracted from the well.

the Brazilian petroleum refineries by using exergy as the efficiency indicator for separation processes. In some studies, the exergy content has been suitably considered as a rational criterion for the allocation of the unit costs among the crude oil and the natural gas produced in offshore platforms that operate under the conventional configuration. For instance, in the work of Nakashima et al. [23], the performance of two energy technologies used for an enhanced petroleum recovery, namely, the gas lifting and the two-phase screw pumping processes are compared in light of the exergoeconomy theory. Those results have been used, in turn, to calculate the cumulative exergy cost and the specific CO2 emissions of different fuels, chemicals and transportation services [40] in petrochemical refineries, biorefineries [41], fertilizers complexes [42] and even of the Brazilian electricity mix [43]. The methodology used in those studies relies on the concept of the total unit exergy cost (cT) [kJ/kJ], defined as the rate of exergy necessary to produce one unit of exergy rate (or flow rate) of a substance, fuel, electricity, work or heat comprised in the petroleum production platform. Analogously, the specific CO2 emission cost (cCO2) [gCO2/MJ] is defined as the rate of CO2 emitted to obtain one unit of exergy rate (or flow rate) of the stream analyzed (either material or energy flow). Thus, by considering the control volume embodying each representative process unit (Figs. 1–3) of the offshore platform, the exergoeconomy balance of total exergy costs can be written as in Eq.(4):

j

j

cTi , F BT , F i

j cCO B = 2 T ,P

i

i

i (cCO B + MCO2, F ) + MCO2, Rxn 2, F T , F i

(5)

It is worthy to notice that, in the case of the allocation of CO2 emissions, initial input values for unit CO2 emissions cost must be considered equal to zero (or known). This differs from the conventional approach of adopting the unity (or a known value from previous analyses) as the unit exergy cost of an external input entering the control volume. Figs. A.1–A.3 in Appendix A show the simplified control volumes, as well as allocation criteria, adopted for calculating the unit exergy costs and specific CO2 emissions related to the streams of the offshore petroleum platform. Finally, it is important to notice that practitioners often use the specific power consumption (kWh/tcrude oil) or the overall energy intensity (MJ/tcrude oil) in order to quantify the performance of the overall offshore petroleum production platforms and their components. However, the present approach is more advantageous, as it allows mapping the generation of the costs along the industrial processes and, consequently, to spotlight the systems responsible for the highest exergy consumption and energy degradation, as well as those entailing the largest non-renewable CO2 emissions. Furthermore, this methodology allows an improved insight into the influence of the energy demanding CO2 capture, recompression and sequestration processes on the overall platform performance. This is possible thanks to an iterative calculation of the unit exergy costs and the specific emissions of the recirculated CO2-rich streams to the well, as they aim to enhance the petroleum recovery while mitigating the environmental impact [20].

i

j

cTj, P BT , P = j

[gCO2/s], respectively:

(4)

where B stands for the exergy rate (or flow rate) of the exergy flow inputs (or fuels, F) and products (or byproducts P) of the respective control volume. Similarly, the CO2 emission cost balances can be written as shown in Eq. (5), where the direct CO2 emissions, either produced by burning the fuel i consumed or arisen/captured from other chemical reactions, are accounted for in the MiCO2,F and MCO2,Rxn terms

4. Results and discussion In the following sections, the performance of three FPSO setups are 5

Energy Conversion and Management 197 (2019) 111846

F.C. Nascimento Silva, et al.

compared in terms of (i) the specific exergy consumption, (ii) the net amount of CO2 emissions, (iii) the exergy efficiency, (iv) the specific exergy destruction at the plantwide and subunit levels, as well as (v) the unit exergy cost and specific CO2 emission cost of the streams pertinent to each process unit.

compression process corresponds to the fourth largest consumer with 7.09%. Other ancillary processes represents up to 5.04%, 3.51% and 1.15% of the overall consumed power in the amine-based, S-Grazpowered and the conventional configurations, respectively. 4.2. Energy integration analysis

4.1. Energy consumption remarks

The energy integration method provides means for calculating the minimum energy requirement (MER) of a chemical and power production plant in order to prioritize the recovery of the exergy of the heat available throughout all the energy conversion systems over the utilization of costly high temperature energy resources [44]. According to this, an energy integration analysis was carried out in order to determine whether the recovery of the waste heat available along the unitary operations of the platform might reduce the amount of fuel consumed, by either preheating the boiling feed water or raising the steam required in the process, otherwise provided by an auxiliary boiler. To this end, a global approach of 20 °C is considered, whenever the minimum temperature differences are not specified. Particularly tight minimum temperature differences are selected (2–5 °C) in the case of the air liquefaction process and the vapor compression refrigeration system, as heuristically suggested. Fig. 5a–c shows the integrated curves of the three studied configurations, which already include the utility systems balance. Clearly, the waste heat available at suitable integration temperatures is enough to heat up the cold streams in the platform. The excess waste heat not recovered is thus dissipated using cooling water. The respective cooling requirement has been indicated in Table 2. Much larger driving forces in the conventional plant suggest the degradation of the waste heat exergy available as long as low-grade hot water is produced from a costly hot utility stream in this configuration. However, when the air-blown OCGT system is used along with an additional chemical absorption CCS unit, the hot and cold composite curves get closer, which entails an improved heat exchanging processes at lower temperature differences. This approach, in turn, brings about a lower amount of exergy destroyed in the heat exchange network (HEN). Finally, in the S-Graz configuration, an enhanced waste heat recovery occurs as the recirculated water is heated up to suitably superheating temperatures by using the exergy embodied in the exhaust gases of the gas turbine, which is translated into better cogeneration efficiency of this power cycle. The reduced temperature differences present in the air separation unit allow for very close hot and cold composite curves, entailing a lower irreversibility in the cryogenic section.

Table 2 summarizes the results of the main design parameters of the three FPSOs, some of which have also been reported in a specific basis. As it can be seen, the specific consumptions are quite similar for both the amine-based and the S-Graz configuration, with the latter design burning only 1.29% less fuel than the amine-based configuration. The lowest fuel consumption in the conventional configuration is clearly associated to the reduced amount of unit operations employed in such layout, which is also reflected in a slightly higher amount of gas exported to the shore. Moreover, the S-Graz configuration allows capturing about 8.19% more CO2 from the power cycle than in the chemical absorption-based counterpart. However, the purity reached after the CO2 captured in the MEA loop is compressed up to the injection pressure is higher (98.98% mol) than that of the CO2 captured and compressed by using the S-Graz-powered configuration (94.20% mol). Regarding the overall CO2 actually emitted (not captured and injected), the amine-based platform emits about 0.26 kg/s of CO2, whereas the SGraz based platform emits only 2.3E-3 kg/s, with these residual CO2 emissions basically related to the CO2 diluted in the knock out condensate streams. Meanwhile, in the conventional case, a fraction of the CO2 extracted from the well (and not separated in the membrane separation process) along with the CO2 produced in the combustion reactions of the cogeneration system is irremediably emitted to the atmosphere. It is worthy to notice that a slightly higher pressure at the gas turbine outlet is adopted in the amine-based platform so that the contact of the flue gases with the solvent in the MEA absorber can be accomplished at a higher pressure and, thus, lower recirculation rate. Otherwise, the duty related to steam consumption in the desorber column may increase. Furthermore, as will be shown later, all three configurations studied proved to be capable of fulfilling the whole system heat requirements via heat integration of their units, without the need of burning an extra amount of fuel in an auxiliary boiler. This is possible thanks to a thorough energy integration process of the platform streams, avoiding the need for auxiliary boilers, either for the primary separation of petroleum or for supplying the reboiler duty of MEA desorber. Correspondingly, more gas can be exported to the shore and further emissions are avoided. Fig. 4a–c shows the distribution of the power generated among the different consumers of the different designed setups. It is important to emphasize that no net export power is aimed to, thus, only the platform internal demands need to be guaranteed. The air compression system is responsible for 49.4% of the consumption of the power generated both in the amine-based platform plant and in the conventional configuration. This high figure might be explained by the large amount of excess air needed for temperature control in air-blown gas turbines. S-Grazpowered configuration, on the other hand, less air is needed since nearly pure oxygen is used in combustion. Therefore, air compression contributes with only 11.30% of the total power demand in the platform. The exported gas compression accounts for the second largest power consumption in all the three plants considered, corresponding to about 35.13% in the amine-based, 23.97% in S-Graz-powered and 38.20% in the conventional configuration, respectively. Notably, the SGraz internals (recycle compressors, pumps, etc.) consume about 54.14% of the power generated by the cycle. The third largest consumption in the amine-based and the conventional configurations is the compression process of CO2 coming from the well, responsible for approximately 10.40% and 11.21% of the power consumed, respectively. Meanwhile, in the S-Graz-powered configuration, the same

4.3. Exergy destruction and exergy efficiency definition The closer a process is to be completely reversible (internally and externally), the lesser the exergy destroyed as it evolves from one given state to another. However, real processes take place on finite-driving forces and, thus, they are inherently irreversible. Accordingly, the exergy analysis gives a means to measure and allocate such irreversibility, accounted for in the amount of exergy destruction, so that the processes with the worst exergy performance can be identified and means to minimize the exergy destruction can be envisaged. Thus, in order to hierarchize the performance of the considered platforms, considering dead state temperature and pressure at T0 = 25 °C and P0 = 101.3 kPa, Fig. 6 shows the exergy efficiency as defined in Table 2. It should be noticed that, as the oil virtually goes unchanged through the control volume after the primary separation is performed, it carries with it a large amount of transit exergy. Therefore, if its chemical exergy were to be included in the efficiency calculation, the results may lead to untruthfully large exergy efficiencies, misrepresenting the performance of the actual transformations occurring inside the platform. The same arguments would apply for the large mass exergy flow rate of the methane-rich exported gas, compared to the much lower amount of the mass exergy of the gas consumed to drive the compressors. Accordingly, 6

Energy Conversion and Management 197 (2019) 111846

F.C. Nascimento Silva, et al.

Fig.4. Breakdown of the power supply and demand of the (a) amine-based, (b) S-Graz-powered and (c) conventional platform configuration (in kW).

Fig. 6 evidences across the board drops in efficiency when additional systems such as ASU, MEA loop and CO2 compression trains are added to a conventional configuration, as expected, although the values of the power efficiency do not drop as sharply. Although, the conventional configuration displays higher values of efficiency, its turbine inlet temperature considered is 1,400 °C, which is common in oxyfuel studies, but high for air-blown turbines. Therefore, bringing turbine inlet temperature values to 1,100–1,200 °C is likely to decrease conventional and amines-based layouts efficiencies which might give the S-Graz configuration the upper hand. Furthermore, between the two advanced configurations, the amine-based layout presents more opportunities of heat recovery and the S-Graz configuration has a separation and cycle more efficient. Although the impact of the ASU is in accordance with estimates given in open literature [45], some measures can be taken to improve upon its performance. The reversible work consumed by the ASU corresponds to the minimum exergy necessary to separate the air into its main components (namely, oxygen and nitrogen-rich streams). Since the system operates irreversibly, the actual work is indeed much higher. The actual exergy power consumed per ton of oxygen produced is calculated as 286.3 kWh/tO2, which is within the ranges (280–340 kWh/tO2) reported in the literature for typical ASUs [46]. Eq. (6) shows the definition considered to calculate the ASU exergy efficiency:

ASU

=

Wsep . consumed, reversible Wsep . consumed, actual

(6)

In this way, an exergy efficiency of 17.68% for the ASU modelled can be calculated according to Eq. (6). The ASU performance can be further improved by better integrating the dual pressure columns via pump around systems and intermediate heat exchanging sections in the LPC. In this way, the temperature differences are lowered while further decreasing the associated exergy destruction. Another way to achieve the same goal is to use HiDIC columns [47]. These columns are partially embedded one into the other in order to provide a more extended heat exchange area. Lower pressures and better temperature approaches in the contact columns, as well as better condenser/reboiler integration can also improve the ASU performance. Thus, further research must still be conducted for this particular case. Another way of comparing the performance of the different setups is through the specific exergy destruction per ton of exported oil. The three configurations are meant to operate in the same well and FPSO production conditions, so they are expected to produce the same yield of oil. According to Table 3, the conventional configuration destroys between 8.98% and 12.87% less exergy per ton of oil exported compared to the S-Graz-powered and amine-based platforms, respectively. It also presents lower specific fuel consumption, since it is the most efficient of all configurations. 7

Energy Conversion and Management 197 (2019) 111846

F.C. Nascimento Silva, et al.

Fig. 5. Composite curves for the (a) amine-based, (b) S-Graz-powered and (c) conventional configurations of the offshore petroleum production platform.

Fig.6. Exergy efficiency definitions for studied configurations as defined in Table 1.

8

Energy Conversion and Management 197 (2019) 111846

F.C. Nascimento Silva, et al.

Table 3 Specific exergy destruction, specific methane consumption and specific CO2 emissions.

Specific exergy destruction (MJ/toil) Specific methane consumption (kg methane/ toil) Specific CO2 emissions (kgCO2/toil)

Amine-based

S-Graz cycle

Conventional

373 9.62 1.6

362 9.48 0.014

325 8.88 23.2

Fig. 7. Exergy destruction breakdown for representative processes of the studied platforms.

As expected, a dramatic cut down of the atmospheric CO2 emissions can be achieved by employing the advanced configurations, as it can be observed in the Table 3. In that way, the massive environmental impact of the CO2 discarded in the conventional platforms may be attenuated by 10 to 1,000 times. Moreover, the amine-based platform discharges 100 times more CO2 than the S-Graz setup due to the release of the purified gas from the absorber overhead and the limited capacity of CO2 sequestration at post-combustion carbon capture operating conditions. Finally, it is also interesting to represent the exergy destruction breakdown among the various subunits composing the offshore petroleum platforms, as shown in Fig. 7 and according to the subunit control volumes depicted in Figs. 1–3. These subunits and its components will be spotted as the main candidates for potential improvements in their operation parameters. As expected, the power generation systems entail the largest contributions to the exergy destroyed in all the three platforms, corresponding to some 46–55% of exergy destruction. This might be explained by the fact that in this part of the plant the highly irreversible combustion reactions take place in which about 25–30% of exergy is destroyed [48]. Moreover, the compression of the combustion air in conventional and amine-based plants, as well as the large number of equipment inside the S-Graz power generation unit, are considerable contributors to the amount of exergy destruction observed in this subunit. The air and petroleum separation processes also appear as significant points of exergy destruction. Changes both to ASU operation parameters and technology, as aforementioned, could improve its performance and reduce its impact on the overall system, as well as the adoption of other methods of petroleum separation, as pointed out by

[34]. Meanwhile, in the amines-based configuration, the MEA loop represents an impact just as expressive as other CCS techniques in onshore applications. For the sake of comparison, by considering the two advanced plants with CCS technologies, the joined contribution of the ASU and the CO2 captured compression process to the share of the exergy destruction in the whole S-Graz-powered FPSO is comparable to the joined contribution of the MEA loop and its respective CO2 captured compression system in the chemical absorption-based platform, with the S-Graz cycle performing slightly better. Other ancillary equipment such as the remaining heat exchanging network is responsible for 23–27% of the irreversibility in the S-Graz-powered, amine-based and conventional platforms. Certainly, a thorough optimization of parameters and design values, as well as the processing units and cogeneration plant layouts may help to improve the overall performance of the entire offshore petroleum production system. Heat recovery is an interesting strategy for the improvement of the conventional configuration, since much of the exergy associated with the produced flue gas is not utilized. On the other hand, the installation of more equipment would be necessary, which could be prohibitive given the reduced space in conventional platforms. More efficient, closer to stoichiometry combustion could also help reduce the impact on the most stressed subunit of the conventional setup. As for the S-Graz cycle, in [10,49], the researchers give some insights into how its performance may be enhanced. Since a heat transfer hindering layer in the cooling tubes of the condenser may interfere with condensation process, the working fluid could be rather cooled close to 1 bar and separated from recycled water, so that the heat transfer can be improved.

9

Energy Conversion and Management 197 (2019) 111846

F.C. Nascimento Silva, et al.

Fig. 8. Unit exergy costs and specific CO2 emissions of the crude oil and natural gas produced in the various offshore platform configurations for each cogeneration and carbon capture technology used.

The water used in this cooling process would then be vaporized and expanded in a low pressure steam turbine to vacuum pressures even lower than the one currently in effect. Moreover, tighter temperature approach values in the main heat exchanger of the power generation unit would help reducing exergy destruction caused by large driving forces in heat transfer processes. Finally, the amines-based configuration could benefit from a higher desorption pressure, especially for high recovery rates which is the case, and increased absorber column internal height [50], together with the enhanced recovery of flue gas energy. A more recent study [51] shows that the integration of an alternative oxyfuel-based cycle, namely the Allam cycle, to an offshore platform outperforms the overall exergy efficiency and the extent of energy integration of the other two platform configurations with carbon capture systems, described in this paper. For instance, the Allam cyclebased platform reportedly consumes 32-38% less methane fuel than a conventional plant to support the same basic offshore petroleum processing facilities, even accounting for oxygen production and higher compression levels required in the CO2 recirculation systems. However, the Allam cycle does not count on enough heat at appropriate temperature to fulfil all heating requirements which renders it dependent on an additional auxiliary boiler, thus impacting its overall atmospheric emissions [51].

advanced platform configurations. Initially, it could be expected an increased exergy consumption (kJ/kJ) of the natural gas leaving the platforms based on more advanced cogeneration and carbon capture systems. However, the unit exergy costs calculated show a slight reduction of the cumulative exergy consumption of those systems, when compared to the conventional configuration instead. This result can be explained by an enhanced energy conversion processes in the amine-based and S-Grazpowered scenarios. Meanwhile, the difference in the exergy consumption in the production of crude oil is less pronounced, but still the highest specific CO2 emissions are attributable to the conventional configuration. More detailed information about the thermodynamic properties, as well as the unit exergy costs and specific CO2 emissions of selected streams for each configuration of FPSO are shown in Figs. A.1–A.3 and summarized in Tables A.1–A.4 in Appendix A. 5. Conclusions An S-Graz oxyfuel cycle powering an FPSO unit in Brazil’s Pre-Salt region is investigated by comparing it to a post-combustion-equipped and a conventional open gas turbine cycle-based platform. Exergy analysis is used to assess the platform performance and the rate of exergy destruction, whereas CO2 emissions are measured to account for the environmental impact. Moreover, an energy integration analysis identifies the heat recovery opportunities and allows mapping the unit exergy costs and specific CO2 emissions associated to the various streams of the plant. As a result, although the conventional configuration is the more efficient one, the advanced layouts are found to be competitive, even with the impairing effects of the introduction of an air separation unit, a chemical absorption unit and a compression battery for CO2 re-injection purposes. Regarding the more advanced configurations, the S-Graz cycle proves to be a more efficient and the least pollutant configuration, with lower specific exergy destruction rate, even for an specific fuel consumption relatively similar to that of the amine-based platform. As compared to the conventional configuration, the S-Graz presents a

4.4. Unit exergy cost and specific CO2 emissions An interesting way of evaluating the component and plant wide performance is the calculation of the cumulative exergy consumption and the associated CO2 emissions of the intermediate and final products of a polygeneration system (heat, power, chemicals). This is possible thanks to the use of the concept of exergy to allocate unit exergy cost and the specific CO2 emissions in a rational way (i.e. regardless of the nature of the substance or energy flow). Fig. 8 shows the calculated values for the crude oil and natural gas produced. Clearly, the highest environmental impact corresponds to the conventional scenario, in contrast with the strikingly six to tenfold lower emissions produced by using the more

10

Energy Conversion and Management 197 (2019) 111846

F.C. Nascimento Silva, et al.

superior performance regarding only the power generation. However, due to the need for an additional air separation unit, the exergy efficiency of the S-Graz-powered platform can be eventually comparable and even a slightly lower than that of a conventional platform. Moreover, further improvements can still be expected to enhance ASU performance, such as the use of energy-integrated distillation columns and intermediate reboilers, although gains are limited. Furthermore, lower driving forces associated to smaller temperature differences in the heat recovery network may help reduce the amount of irreversibility in the petroleum production facilities, as well as alternative methods for petroleum separation. Additionally, the unit exergy costs of the produced oil and gas are quite similar among all the studied setups, but the specific CO2 emissions are remarkably lower for the platforms equipped with CCS technologies, particularly for the S-Graz configuration. Finally, although CCS techniques, in particular oxyfuel, can bring about substantial attenuation of emissions especially when coupled with an extensive heat exchange network for energy integration purposes, it should be regarded as a last resort in case decarbonisation is not possible and as something to be phased out as renewable sources take on the main role. Moreover, for the platforms that will still be needed in the meantime, it is fundamental to quickly deploy and develop alternative technologies such as the S-Graz cycle. Despite some concerns about the greater number of equipment required in the advanced cogeneration and CCS systems, which can be prohibitive

considering the limited space and weight budget in most of the current FPSOs, these configurations might be an attractive alternative for centralized power production plants that supply a cluster of FPSO units operating in the same production field [52]. Declaration of competing interest The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper. Acknowledgements The present work was supported by the cooperation of the Brazilian National Agency of Petroleum, Natural Gas and Biofuels (ANP) and Shell Brazil, through the Investment in Research, Development and Innovation Clause, contained in contracts for Exploration, Development and Production of Oil and Natural Gas. The second author would like to acknowledge the Brazilian National Agency of Petroleum, Gas and Biofuels – ANP and its Human Resources Program (PRH/ANP Grant 48610.008928.99), as well as the Colombian Administrative Department of Science, Technology and Innovation – COLCIENCIAS, Grant 1.128.416.066. First and third author would also like to thank the Brazilian National Research Council for Scientific and Technological Development, CNPq (grant 167509/2018-7 and 304935/2016-6).

Appendix. A Tables A.1–A.3 summarize the physical and thermodynamic properties, as well as the unit exergy costs and specific CO2 emissions of selected streams for each configuration of offshore platform shown in Figs. A.1–A.3. As it can be seen, both the heat exergy supplied (e.g. primary separation heat requirement, reboiler duty) and the overall power generated have the highest unit exergy costs and specific CO2 emissions associated, thus, directly impacting the processes that depend on those utility streams. Actually, this effect can be readily evidenced from the exergy intensity and the environmental impact calculated for the products of the air separation unit (namely, oxygen) and the CO2 compression trains, as well as for the utility streams supplied in the form of heat to the carbon capture and separation unit and the primary separation processes. Table A1 Conventional offshore platform configuration. Thermodynamic properties, unit exergy costs and specific CO2 emissions of selected streams in Fig. A.1. N°

Stream name

T (°C)

P (kPa)

m (kg/s)

BT (kW)

cT (kJ/kJ)

cCO2 (gCO2/MJ)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20

Combustion air Natural gas (fuel) Natural gas (well) CO2 (well) Oil (well) Primary separation (Heat requirement) Net power (to compression systems) NG to compression & membrane CO2 to compression & membrane Oil to pump Oil pump power Oil export to shore Gas compression power Methane-rich exported natural gas CO2 rich-permeate NG export compression power CO2 compression power to injection Natural gas export CO2 (from well) to injection Flue gas to atmosphere

25 38 40 40 40 150 – 40 40 60 – 60 – 38 38 – – 113 128 100

101.3 4,800 1,500 1,500 1,500 – – 1,500 1,500 1,500 – 2,300 – 4,800 300 – – 24,500 45,000 300

42.2 1.4 28.0 8.3 161.0 – – 28.0 8.3 161.0 – 161.0 – 26.6 8.3 – – 26.6 8.3 43.7

0 69,114 1,349,493 63,442 7,211,029 1,985 19,801 1,349,493 61,856 7,211,029 447 7,211,029 8,039 1,285,657 60,975 7,850 3,458 1,291,027 63,442 4,743

1.0000 1.0202 1.0081 1.0081 1.0081 13.6969 2.6066 1.0112 1.0112 1.0112 2.6066 1.0114 2.6066 1.0202 1.0202 2.6066 2.6066 1.0302 1.0965 0.0000

0.00 1.23 0.31 0.31 0.31 319.02 191.77 0.39 0.39 0.39 191.77 0.40 191.77 1.23 1.23 191.77 191.77 2.28 9.72 0.00

The bold values represent the most important streams or final products of the processing units and cogeneration plant of the platform.

11

Energy Conversion and Management 197 (2019) 111846

F.C. Nascimento Silva, et al.

Fig. A1. Conventional offshore platform configuration. Unit exergy cost and specific CO2 emissions calculation scheme. Table A2 Offshore platform configuration with a chemical absorption carbon capture unit. Thermodynamic properties, unit exergy costs and specific CO2 emissions of selected streams in the Fig. A.2. N°

Stream name

T (°C)

P (kPa)

m (kg/s)

BT (kW)

cT (kJ/kJ)

cCO2 (gCO2/MJ)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

Combustion air Natural gas (fuel) Natural gas (well) CO2 (well) Oil (well) Oil pump power Primary separation (Heat requirement) Net power (to compression systems) Waste water Gas compression power Natural gas to compression & membrane CO2 to compression & membrane Methane-rich exported natural gas CO2 rich-permeate Oil to pump Oil export to shore Amine loop power consumption Makeup water Reboiler duty (Heat requirement) Purified flue gas to atmosphere Captured CO2 to compression Waste water Waste water Captured CO2 to injection Captured CO2 injection compression power NG export compression power CO2 (well) to injection compression power Natural gas export CO2 (from well) to injection Non purified flue gas

25 38 40 40 40 – 150 – 40 – 40 40 38 38 60 60 – 25 104 30 42 42 40 90 – – – 113 130 40

101.3 4,800 1,500 1,500 1,500 – – – 300 – 1,500 1,500 4,800 300 1,500 2,300 – 130 – 300 100 100 multiple 45,000 – – – 24,500 45,000 300

45.8 1.5 28.0 8.2 161 – – – 2.5 – 28.0 8.2 26.5 8.2 161 161 – 1.3 – 40.7 3.9 1.5 0.14 3.8 – – – 26.5 8.2 44.9

0 74,901 1,349,493 61,856 7,211,029 447 1,985 21,459 129 8,039 1,349,493 61,856 1,279,936 60,975 7,211,029 7,211,029 30 65 3,564 3,875 1,653 78. 30 2,709 1,659 7,815 3,458 1285213 63,442.3 4,964

1.0000 1.0198 1.0105 1.0105 1.0105 2.2139 8.9671 2.2139 0.0000 2.2139 1.0125 1.0125 1.0198 1.0198 1.0125 1.0127 2.2139 1.0000 8.9671 0.0000 11.6172 0.0000 0.0000 8.0895 2.2139 2.2139 2.2139 1.0277 1.0786 1.0197

0.00 0.31 0.25 0.25 0.25 13.05 14.47 13.05 0.00 13.05 0.25 0.25 0.31 0.31 0.25 0.26 13.05 0.00 14.47 0.00 16.74 0.00 0.00 16.11 13.05 13.05 13.05 0.38 0.88 0.31

The bold values represent the most important streams or final products of the processing units and cogeneration plant of the platform.

12

Energy Conversion and Management 197 (2019) 111846

F.C. Nascimento Silva, et al.

Fig. A2. Offshore platform configuration with a chemical absorption carbon capture unit. Unit exergy cost and specific CO2 emissions calculation scheme.

Table A3 Offshore platform configuration integrated to an S-Graz power cycle. Thermodynamic properties, unit exergy costs and specific CO2 emissions of selected streams in the Fig. A.3. N°

Stream name

T (°C)

P (kPa)

m (kg/s)

BT (kW)

cT (kJ/kJ)

cCO2 (gCO2/MJ)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27

Combustion air CO2 (well) Natural gas (well) Oil (well) NG to compression & membrane CO2 to compression & membrane Oil to pump Oxygen rich Nitrogen rich CO2 rich-permeate Oil export to shore Natural gas (fuel) Waste water Captured CO2 to compression Waste water Captured CO2 to injection Natural gas export CO2 (from well) to injection Primary separation (Heat requirement) Net power (to compression systems) NG export compression power CO2 (well) to injection compression power Air separation compression power Oil pump power Captured CO2 injection compression power Gas compression power NG to compression

25 40 40 40 40 40 60 25 1 40 60 38 18 23 23 100 113 130 150 – – – – – – – 38

101.3 1,500 1,500 1,500 1,500 1,500 1,500 101.3 101.3 300 2,300 4,800 400 100 multiple 45,000 24,500 45,000 – – – – – – – – 4,800

31.4 8.2 28.0 161.0 28.0 8.2 161.0 5.8 25.6 8.2 161.0 1.5 1.4 5.9 1.8 4.2 26.5 8.2 – – – – – – – – 26.5

0 61,856 1,349,493 7,211,029 1,349,591 61,870 7,211,029 711 344 60,975 7,211,029 73,798 70 2,901 5 2,901 1,285,275 63,442 1,985 27,477 7,822 3,458 5,970 447 1,732 8,039 1,280,183

1.0000 1.0084 1.0084 1.0084 1.0121 1.0121 1.0121 16.7763 1.0000 1.0201 1.0123 1.0201 0.0000 1.1704 0.0000 1.1839 1.0290 1.0849 16.2665 2.3708 2.3708 2.3708 2.3708 2.3708 2.3708 2.3708 1.0201

0.00 0.24 0.24 0.24 0.24 0.24 0.24 7.86 0.00 0.25 0.24 0.25 0.00 0.32 0.00 0.33 0.25 0.29 5.70 1.08 1.08 1.08 1.08 1.08 1.08 1.08 0.25

The bold values represent the most important streams or final products of the processing units and cogeneration plant of the platform.

13

Energy Conversion and Management 197 (2019) 111846

F.C. Nascimento Silva, et al.

Fig. A3. Offshore platform configuration integrated to an S-Graz power cycle. Unit exergy cost and specific CO2 emissions calculation scheme. Table A4 Auxiliary equations considered in order to calculate unit exergy costs and specific CO2 emissions. Conventional configuration Power cycle

Amines-based configuration

c20 = 0 cq =

c9 = 0

c1 B1 + c2 B2 B1 + B2

cq =

c1 B1 + c2 B2 B1 + B2

S-Graz cycle configuration

c13 = 0

= c30

c14 =

c8 B8 + c12 B12 B8 + B12

Primary separation

c10 = c9 = c8

c11 = c12 = c13

Compression & membrane separation

c15 = c14 cq = c13

c13 = c14 cq = c10

c 7 = c5 c6 = c5 c10 = c27 c26 = cq

cq = c16

cq = c26

cq = c21

cq = c17

cq = c27 c22 = 0 c21 = cq c19 = c7 cq = c25 c23 = 0 –

cq = c22

NG Export compression

CO2 injection compression

Amines loop carbon capture

–

Captured CO2 injection compression

–

Air separation unit

–

= cq

–

c15 = 0 cq = c25 c9 = c1 = 1 c23 = cq

Land, Sea and Air. 2005. Reno-Tahoe, Nevada, USA. [11] Nguyen TV, Voldsund M, Breuhaus P, Elmegaard B. Energy efficiency measures for offshore oil and gas platforms. Energy 2016;117:325–40. [12] Carranza-Sánchez Y, Oliveira Jr. S. Exergy analysis of offshore primary petroleum processing plant with CO2 capture. Energy 2015;88:46–56. [13] Carranza-Sánchez YA, Oliveira Junior S, da Silva JAM, Nguyen TV. Energy and exergy performance of three FPSO operational modes. Proceedings of the 23rd ABCM international congress of mechanical engineering. 2015. [14] Riboldi Luca, Nord Lars O. Concepts for lifetime efficient supply of power and heat to offshore installations in the North Sea. Energy Convers Manage 2017;148:860–75. [15] Jordal Kristin, Anantharaman Rahul, Langorgen Øyvind. Novel oxy-combustion gas turbine concepts for off-shore application. In: International CCS Research Centre; 2013. [16] IEA. Not on track. 2019 [cited 2019 February 6]; Available from: < https://www. iea.org/tcep/power/ccs/ > . [17] Petrobras. Business Plan and Management 2019-2023. [In Portuguese]; 2019. [18] Beck B, Cunha P, Ketzer M, Machado H, Rocha, Paulo S, et al. The current status of CCS development in Brazil. Energy Proc 2011;4:6148–51. [19] Barbosa YM, da Silva JAM, de Oliveira S, Torres EA. Performance assessment of primary petroleum production cogeneration plants. Energy 2018;160:233–44. [20] Silva JAM, Oliveira Junior S. Unit exergy cost and CO2 emissions of offshore petroleum production. Energy 2018;147:757–66. [21] Flórez-Orrego D, Silva JAM, Velásquez H, Oliveira Jr. S. Renewable and non-renewable exergy costs and CO2 emissions in the production of fuels for Brazilian transportation sector. Energy 2015;88:18–36. [22] Silva JAM, Flórez-Orrego D, Oliveira Jr. S. An exergy based approach to determine production cost and CO2 allocation for petroleum derived fuels. Energy

References [1] Figueroa JD, Fout T, Plasynski S, McIlvried H, Srivastava RD. Advances in CO2 capture technology—The U.S. Department of Energy’s Carbon Sequestration Program. Int J Greenhouse Gas Control 2008;2:9–20. [2] IPCC. Climate Change 2014: Mitigation of Climate Change, in Working Group III Contribution to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change; 2014, UN. p. 1454. [3] IEA. Energy and Climate Change, World Energy Outlook Special Report. International Energy Agency; 2015. p. 1–200. [4] Boait P, Advani V, Gammon R. Estimation of demand diversity and daily demand profile for off-grid electrification in developing countries. Energy Sustain Develop 2015;29:135–41. [5] Zhang Q, Li H, Mclellan B. An integrated scenario analysis for future zero-carbon energy system. Energy Proc 2014;61:2801–4. [6] IEA. Outlook for Natural Gas, in World Energy Outlook 2017. International Energy Agency; 2017. p. 449–60. [7] Leung DYC, Caramanna G, Mercedes Maroto-Valer M. An overview of current status of carbon dioxide capture and storage technologies. Renew Sustain Energy Rev 2014;39:426–43. [8] Heitmeir F, Sanz W, Jericha H. 1.3.1.1. Graz cycle – a zero emission power plant of highest efficiency, in The Gas Turbine Handbook, U.D.E. Office, Editor. National Energy Technology Laboratory; 2006. [9] Mancuso L, Ferrari N, Paolo C, Martelli E, Romano M. Oxy-combustion turbine power plants. Report: 2015/05. International Energy Agency; 2015. [10] Sanz, W., Jericha, H., Luckel, F., Göttlich, E., Heitmeir, F. A further step towards a graz cycle power plant for CO2 capture. In: ASME Turbo Expo 2005: Power for

14

Energy Conversion and Management 197 (2019) 111846

F.C. Nascimento Silva, et al. 2014;67:490–5. [23] Nakashima C, Oliveira Jr. S, Caetano EF. Subsea multiphase pumping system x gas lift: an exergo-economic comparison. Therm Eng 2004;3:1676–790. [24] Nguyen TV, Fülöp TG, Breuhaus P, Elmegaard B. Life performance of oil and gas platforms: site integration and thermodynamic evaluation. Energy 2014;73:282–301. [25] Baker R, Lokhandwala K. Natural gas processing with membranes: an overview. Ind Eng Chem Res 2008;47(7):2109–21. [26] Jericha H. Efficient steam cycles with internal combustion of hydrogen and stoichiometric oxygen for turbines and piston engines. Int J Hydrogen Energy 1987;12(5):345–54. [27] Agrawal R, Herron D. Air Liquefaction: distillation. In: Wilson I, Poole C, Cooke M., editors. Encyclopedia of separation science. Academic Press; 2000. p. 4502. [28] Fu C, Gundersen T. Using exergy analysis to reduce power consumption in air separation units for oxy-combustion processes. Energy 2012;44(1):60–8. [29] Zhang Y, Chen H, Chen C-C, Plaza JM, Dugas R, Rochelle GT. Rate-based process modeling study of CO2 capture with aqueous monoethanolamine solution. Ind Eng Chem Res 2009;48:9233–46. [30] Zhang Y, Chen CC. Thermodynamic modeling for CO2 absorption in aqueous MDEA solution with electrolyte NRTL model. Ind Eng Chem Res 2011;50:163–75. [31] Zhang Y, Que H, Chen C-C. Thermodynamic modeling for CO2 absorption in aqueous MEA solution with electrolyte NRTL model. Fluid Phase Equilib 2011;311:68–76. [32] Song Y, Chen C-C. Symmetric electrolyte nonrandom two-liquid activity coefficient model. Ind Eng Chem Res 2009;48:7788–97. [33] Abdollahi-Demneh F, Moosavian M, Omidkhah M, Bahmanyar H. Calculating exergy in flowsheeting simulators: a HYSYS implementation. Energy 2011;36(8):5320–7. [34] Oliveira Júnior S, Van Hombeeck M. Exergy analysis of petroleum separation processes in offshore platforms. Energy Convers Manage 1997;38(15–17):1577–84. [35] Silva JAM, Oliveira Jr S. An exergy-based approach to determine production cost and CO2 allocation in refineries. Energy 2014;67:607–16. [36] Nguyen TV, Voldsund M, Elmegaard B, Ertesvåg IS, Kjelstrup S. On the definition of exergy efficiencies for petroleum systems: application to offshore oil and gas processing. Energy 2014;73:264–81. [37] Silva JAM. Exergoenvironmental Performance of Petroleum Processing [In Portuguese]. Novas Edicoes Academicas; 2017. [38] Silva JAM, Oliveira Jr. S, Pulgarin J, Velasquez H, Molina A. On the exergy determination for petroleum fractions and separation processes efficiency. Heat Transf Eng 2015;36(11):974–83. [39] Oliveira S Jr. Exergy: production, cost and renewability. Sao Paulo: Springer; 2013. [40] Flórez-Orrego D, Silva JAM, Oliveira Jr S. Exergy and environmental comparison of

[41]

[42] [43] [44]

[45] [46] [47] [48] [49] [50] [51]

[52]

15

the end use of vehicle fuels: the Brazilian case. Energy Convers Manage 2015;100:220–31. Flórez-Orrego D. Thermodynamics and environmental comparison (CO2 emissions) of production and end use routes of vehicle fuels, derived from petroleum, natural gas, biofuels, hydrogen and electricity (electric vehicles) [In Portuguese], MSc, in Department of Mechanical Engineering. University of São Paulo: São Paulo; 2014. p. 229, doi: 10.11606/D.3.2014.tde-23122014-154428. Flórez-Orrego D, Oliveira Junior S. On the efficiency, exergy costs and CO2 emission cost allocation for an integrated syngas and ammonia production plant. Energy 2016;117(Part 2):341–60. Flórez-Orrego D, Silva JAM, Oliveira Jr S. Renewable and non-renewable exergy cost and specific CO2 emission of electricity generation: The Brazilian case. Energ Convers Manage 2014;85:619–29. Florez-Orrego D, Sharma S, Oliveira S Jr, Marechal F. Combined exergy analysis and energy integration for design optimization of nitrogen fertilizer plants. In: 30th International conference on efficiency, cost, optimization, simulation and environmental impact of energy systems, ECOS 2017, July 2–6 2017. San Diego, United States of America: San Diego State University. Beysel G. Enhanced cryogenic air separation: a proven process applied to oxyfuel. The Linde Group. In: 1st Oxyfuel combustion conference. Cottbus, September 8th; 2009. Flórez-Orrego D, Nascimento Silva F, Oliveira Junior S. Syngas production with thermo-chemically recuperated gas expansion systems: An exergy analysis and energy integration study. Energy 2019;178:293–308. Suphanit B. Design of internally heat-integrated distillation column (HIDiC): uniform heat transfer area versus uniform heat distribution. Energy 2010;35(3):1505–14. Dunbar WR, Lior N. Sources of combustion irreversibility. Combust Sci Technol 1994;103(1–6):41–61. Jericha H, Sanz W, Göttlich E. Design concept for large output graz cycle gas turbines. In: ASME Turbo Expo 2006: power for land, sea and air. Barcelona, Spain; 2006. Nagy T, Koczka K, Haáz E, Tóth AJ, Rácz L, Mizsey P. Efficiency Improvement of CO2 Capture. Period Polytech, Chem Eng 2016:51–8. Nascimento Silva F, Freire R, Florez-Orrego D, Oliveira Junior S. Comparative assessment of advanced power generation and carbon sequestration cycles for offshore petroleum platforms. In: 32th International Conference on Efficiency, Cost, Optimization, Simulation and Environmental Impact of Energy Systems, ECOS 2019, Wroclaw, Poland, June 23 – 28; 2019. Freire RLA, De Oliveira Junior S. Lifetime exergy analysis of electricity and hot water production systems in offshore projects with multiple platforms. in ENCIT. Águas de Lindóia, SP, Brazil; 2018.