Operational Optimization of a Hydrotreating System Based on

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Operational Optimization of a Hydrotreating System Based on Removal of Sulfur Compounds in Hydrotreaters Coupled with a Fluid Catalytic Cracker Le Wu, Yongzhong Liu, and Qundan Zhang Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.7b00860 • Publication Date (Web): 27 Jul 2017 Downloaded from http://pubs.acs.org on July 28, 2017

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Energy & Fuels

Operational Optimization of a Hydrotreating System Based on Removal of Sulfur Compounds in Hydrotreaters Coupled with a Fluid Catalytic Cracker

Le Wua, Yongzhong Liua,b,*, Qundan Zhangc

a

Department of Chemical Engineering, Xi’an Jiaotong University, Xi’an, Shaanxi, 710049, P. R. China

b

Key Laboratory of Thermo-Fluid Science and Engineering, Ministry of Education, Xi’an, Shaanxi, 710049, P. R. China

c

SINOPEC Research Institute of Petroleum Processing, SINOPEC, Beijing 100083, P. R. China

*Corresponding Author Phone: +86-29-82664752 Fax:

+86-29-83237910

E-mail: [email protected]

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ABSTRACT Escalating stringent environmental regulations on fuel coupled with decreased quality of incoming crude oil make energy conservation techniques in fuel production a necessary venture. In this work, a non-linear programming (NLP) model was proposed to optimize the hydrotreating (HDT) system coupled with a fluid catalytic cracking (FCC) unit in refineries. Two optimization models, i.e. a total sulfur removal model (TSR) and a sulfur compounds removal model (SCR), were established based on the proposed NLP model that embeds the desulfurization kinetics for the total sulfur removal and the sulfur compounds removal. The effects of operational conditions on both utility costs and impurity removal degrees were investigated. An actual refinery was taken as a case study. Results show that when the sulfur content in the refined vacuum gas oil is 1510 µgg-1, the utility cost of the HDT system can be reduced by 3.75% by using the TSR model, whereas it can be reduced by 5.83% by using the SCR model. Further reduction of the utility cost in the HDT system can be achieved by taking the sulfur compounds removal into consideration. Moreover, the effects of allocation of sulfur in the FCC unit was also investigated by using the SCR model. Results show that the annual cost of the hydrogen consumption can be reduced by 17.31×106 CNY (China Yuan), and the utility cost can be lessened by 7.29%. For the precisive sulfur management and effective reduction of the energy and hydrogen consumptions of the HDT system in a refinery, the operating features of the HDT units coupled with the FCC unit and the characteristics of sulfur compounds removal in the hydrotreaters should be considered simultaneously. Keywords: Sulfur compounds; Hydrotreating process; Fluid catalytic cracking unit; Optimization; Non-linear programming model

2


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1. Introduction Refineries are forced to increase the sulfur removal degree due to the severer environmental regulations on fuel sulfur contents. Moreover, the hydrotreating (HDT) units consume large amount of energy and hydrogen, in which sulfur and hydrogen are reacted under high temperature and pressure. In addition, energy and hydrogen consumptions are further increased because more and more heavy and sour crude oil are being processed. Therefore, it is full of importance for a refinery to remove more sulfur while consumes less energy and hydrogen. The sulfur removal in a HDT unit is very complex1, Korsten and Hoffman2 proposed a trickle-bed reactor model of a vacuum gas oil (VGO) HDT unit which provided a good kinetic model for the optimization of a HDT unit. Moreover, the effects of react temperature, pressure and hydrogen oil ratio on sulfur removal were investigated. Based on Korsten and Hoffman’s research, Rodriguez and Ancheyta3 presented kinetic equations of hydrodesulfurization (HDS), hydrodenitrogenation (HDN) and hydrogenation of aromatics (HDA) in a VGO HDT unit. Bakhshi Ani et al.4 proposed the HDS, HDN and HDA kinetics with experimental data in a diesel HDT unit, then integrated these kinetics to a heterogeneous diesel HDT reactor and optimized the react conditions to decrease the sulfur and aromatics contents in diesel product. The abovementioned investigations all established the total sulfur removal kinetics, but different types of sulfur compounds have different removal kinetics. Froment et al.5 established the removal kinetics of benzothiophene and dibenzothiophene and shown that the removal difficulties are different between these sulfides. Vanrysselberghe et al.6 investigated the reaction kinetics of 4-methyl dibenzothiophene and 4,6-dimethyl dibenzothiophene. Ma et al.7 provided the distributions of sulfur compounds in a diesel HDT unit8 and a VGO HDT unit9, and 3


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the kinetics model and related parameters of the sulfur compounds were also presented. To simplify Ma’s model, Choudhary10 divided the sulfur compounds into nine groups and proposed a much simpler kinetics model. Therefore, the different sulfur compounds should be removed in their appropriate removal reaction conditions due to their different removal difficulties. Under these conditions, the energy consumption in the HDT units can be further reduced; also, the precisive management of sulfur can be achieved. To reduce the energy consumption of a HDT unit, Ahmad et al.11 proposed a synchronous integration design method to optimize a diesel HDT reactor, fractionation and heat recovery simultaneously, which obtained better optimization results than the step-by-step design method did. Al-Adwani et al.12 presented a residual oil HDT unit optimization model by integrating catalyst deactivation and investigated the relationship among the operating conditions, utility cost and desulfurization degree. Muñoz et al.13 studied the heat integration scheme of a heavy oil HDT unit. Zhang et al.14 proposed a non-linear programming (NLP) operation plan model to minimize the total cost by considering the material and energy consumptions and the seasonal price change of diesel and naphtha in a diesel HDT unit. However, all the above studies optimized a single HDT unit and only considered the total sulfur removal kinetics. In other words, the effects of different sulfide removal in different HDT reactors on the energy saving operation of HDT units were ignored. In general, in a fuel-type refinery, the feed oil of a fluid catalytic cracking (FCC) unit is the refined VGO from a VGO HDT unit. Then the products of the FCC unit, cracked diesel (CD) and cracked gasoline (CG), are the feedstocks of a CD HDT unit and a CG HDT unit respectively. In an actual production, one HDT unit has the limited ranges for adjusting operational conditions, which may not reach the 4


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appropriate reaction conditions for the removal of some sulfides, while may exceed the appropriate removal conditions for other sulfides. Under this circumstance, the energy consumption of the HDT unit increases meaninglessly to lower the sulfur content of product to satisfy the severe regulations. Among the HDT units in a refinery, the VGO HDT unit has the higher operating temperature and pressure than a diesel HDT unit does, while the conditions in the diesel HDT unit are higher than those in a gasoline HDT unit. Subsequently, the energy consumption of a refinery can be reduced and the operating conditions can be relaxed if more sulfur compounds with low reactivity are removed in a VGO HDT unit and more high reactivity sulfur compounds are removed in diesel and gasoline HDT units. Then, the precisive management of the sulfur in the refinery can be realized. In this work, a NLP model coupling an FCC unit, is proposed to minimize the utility consumption of a HDT system comprised of a VGO HDT unit, a CD HDT unit and a CG HDT unit. Two optimization models, namely, total sulfur removal model (TSR) and sulfur compounds removal model (SCR), are then established based on the NLP model integrated two desulfurization kinetics, named total sulfur kinetics and sulfur compounds kinetics, respectively. The TSR and SCR models are then solved to study their effects on the optimization of operating conditions, impurity removal degrees and the utility cost. Moreover, the effects of the FCC unit on the HDT system optimization are also analyzed and discussed.

2. The HDT system and its optimizing strategy In the HDT system, as shown in Figure 1, the VGO is upgraded in a VGO HDT unit then enters a FCC unit to produce CD and CG that are then purified in the CD and CG HDT units due to their high sulfur contents. Figure 1 also presents the flow 5


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diagram of a typical HDT unit, which is used to remove sulfur, nitrogen and aromatics in a refinery. The feedstock is pressured in a pump and mixed with the hydrogen mixture, and then enters a heat exchanger to cool the reactor efflux to a certain temperature. The feedstock and hydrogen mixture from the heat exchanger are then heated in a furnace to the reaction temperature, and then enter the reactor to conduct HDS, HDN and HDA reactions. The cooled reactor efflux from the heat exchanger is then separated into an oil phase and a gas phase in a separator. The oil phase is then rectified as the final refined product, while the gas phase is cyclic utilized as the cycle hydrogen after removing H2S in an absorber. The cycle hydrogen is pressured and then mixed with the make-up hydrogen as the hydrogen mixture. It is known that there are different sulfur compounds in distillates, which have different reaction activities. According to the work of Choudhary et al.10, the sulfur compounds in distillates can be further divided to six groups, 1) Thiophenes and benzothiophenes dibenzothiophenes

(T/BT);

2)

(C2+DBT);

C0/C1

dibenzothiophenes

4)

(C1-DBT);

Phenathrothiophenes

3)

(PhT);

C2+ 5)

Benzonapthothiophenes and five & six ring thiophenes (BNT); and 6) Nonaromatic sulfides (NArS). Figure 2 presents the relative reactivity of the sulfides of six groups, which are then divided into two parts, i.e., hard removal sulfur compounds and easy removal ones. PhT and C2+DBT belong to the hard removal sulfur compounds that have low reaction activity, while the NArS, B/T, BNT and C1-DBT belong to the easy removal sulfur compounds with high reaction activity. According to the actual HDT operating conditions, the VGO HDT unit has the highest temperature and pressure of all the HDT units in Figure 1 due to the high gravity and high impurity contents in the VGO distillate. Its operating temperature is 360~400 oC and the pressure is 8~12 MPa. The operating temperature and pressure in 6


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the diesel HDT unit are 290~340 oC and 6~8 MPa, and the gasoline HDT unit has the lowest operating temperature and pressure of 240~300 oC and 2~3 MPa, respectively. The operating temperature and pressure of each HDT unit and the energy consumption of the HDT system can be further reduced if more hard removal sulfur compounds are removed in the VGO HDT unit or more easy removal sulfur compounds enter the diesel and gasoline HDT units. The two optimization models, TSR and SCR, can be solved to discuss the effects of the two kinetics (total sulfur removal kinetics and sulfur compound removal kinetics) on the optimization of the HDT system if the impurity contents of feed and product, and the operating condition adjustment ranges and product regulations in each HDT unit are known. Furthermore, the effects of the FCC unit on the optimization of HDT system can be also investigated. The optimizing strategy of the HDT system can be specified as follows. At first, For each HDT unit, the utility cost is minimized by using the TSR and SCR models to obtain the optimal operating conditions and impurity removal degrees. Then the better kinetics are obtained by comparing the results of the TSR model and the SCR model. At last, the effects of the FCC unit on the optimization of the HDT system are investigated by utilizing the optimization model with better results.

3. Operation Optimization of the HDT System Based on TSR Model and SCR Model 3.1 Mathematic model: Minimizing Utility Cost of the HDT System In a HDT unit, the key factors that can affect the impurity removal degrees are the operating temperature and pressure. According to Figure 1, the heating duty of the furnace affects the operating temperature. And the lowest exhaust pressure among the 7


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feed oil pump, the cycle hydrogen compressor and the make-up hydrogen compressor determine the operating pressure. Therefore, the cost of the HDT system considered in this work is the utility cost of the above-mentioned devices, such as electricity, steam, fuel gas and hydrogen. The high pressure steam is used to drive stream turbines, which would exhaust low pressure steam after working. Therefore, the utility cost should take out the cost of the low pressure steam. min C

(1)

C = ( C elec + C HS − C LS + C FG + C H 2 ) AOT

(2)

where C is the utility cost, in CNYy-1, CNY means China Yuan; The superscripts, elec, HS, LS, FG and H2 denote electricity, high pressure steam, low pressure steam, fuel gas and hydrogen, respectively; AOT presents the annual operating time, in hy-1. The calculation of each utility cost in eq(2) is as follows. (1) Electricity cost There are two ways to drive a pump or a compressor in a refinery, electric motor and steam turbine, which consume electricity and high pressure steam respectively. The electricity cost can be calculated by eq(3) if the pumps and compressors are driven by electric motors. C elec = ∑∑Wi ,pump p elec + ∑∑Wi ,comp p elec j k i

j

i

(3)

k

where Wi ,pump is the jth electric driven pump in ith HDT unit, in kW; Wi comp is the kth j ,k electric driven compressor in ith HDT unit, in kW; pelec denotes the electricity price, in CNYkW-1. The pump power can be calculated as15: Wi pump = vifeed ( Pi pump,out − Pi pump,in ) ( 3.6ηipump )

(4)

where vifeed is the volumetric flowrate of feed in ith HDT unit, in m3h-1; P pump,in and 8


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P pump,out denote the inlet pressure and outlet pressure of the pump, in MPa; η is the

total efficiency, in %. The compressor power is shown as16: ( P comp,d P comp,s ) = C p Ti ,comp,s Wi ,comp ηicomp k k ,k i ,k  i ,k

γ −1 γ

− 1 Fi ,comp  k

(5)

where C p denotes the specific heat, in Jmol-1K-1; Ti comp,s is suction temperature of ,k the kth electric driven compressor in ith HDT unit, in oC; P comp,s and P comp,d are the suction pressure and discharge pressure of the compressor, in MPa; γ denotes heat capacity ratio, i.e. Cp/Cv; F is the flowrate of the compressed gas, in mols-1. (2) High pressure steam cost The high pressure steam is consumed when the pumps and compressors are driven by steam turbines. The cost is calculated as HS C HS = ∑∑ Fi ,HS l p i

(6)

l

The flowrate of the high pressure steam is related to the power of the driven turbine15. That is turb ( H HS − H LS )ηiturb  Fi ,HS l = Wi , l ,l  

(7)

where Fi ,HS is flowrate of high pressure steam consumed by the lth steamy driven l device in ith HDT unit, in th-1; pHS is the price of the high pressure steam, in CNYt-1; W turb

denotes the power of the steam turbine, in kW; H HS and H LS are the

enthalpies of high pressure steam and low pressure steam, in MJt-1. (3) Low pressure steam cost The flowrate of the low pressure steam exhausted from steam turbine is the flowrate of the high pressure steam if the leakage is ignored. LS C LS = ∑∑ Fi ,LS l p i

(8)

l

HS Fi ,LS l = Fi , l

(9) 9


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where Fi ,LSl denotes flowrate of low pressure steam consumed by the lth steamy driven device in ith HDT unit, in th-1; pLS is the price of the low pressure steam, in CNYt-1. (4) Fuel gas cost Fuel gas is used to heat the feed oil to the reaction temperature. Its cost can be calculated by C FG = ∑Wi fur p FG

(10)

i

where Wi fur is heat duty of the furnace in ith HDT unit, in kW; pFG denotes the price of the fuel gas, in CNYMJ-1. The heat duty of a furnace has a linear relationship with its outlet temperature according to Wu and Liu’s work17. Wi fur = aifur Ti out + bifur

(11)

where T out is the outlet temperature of the furnace, in oC; a and b are the coefficients. (5) Hydrogen cost Hydrogen cost can be calculated as C H2 = ∑ Fi H 2 p H 2

(12)

i

where Fi H is the hydrogen flowrate of the ith HDT unit, in Nm3h-1; p H is the 2

2

hydrogen price, in CNYNm-3. In a HDT unit, hydrogen is mainly consumed to remove the sulfur, nitrogen and aromatics. The distillate can also dissolve a certain amount of hydrogen. In addition, hydrogen can react with other impurities like oxygen, metal and olefins. The hydrogen consumption of a HDT unit can be calculated by eq(13)18: Fi H 2 = Fi S + Fi N + Fi A + Fi D + Fi O

(13)

where the superscripts, S, N, A, D and O, denote desulfurization, denitrogenation, aromatics saturation, dissolution and other hydrogen consumption, respectively. 10


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Desulfurization hydrogen consumption can be expressed as18 Fi S = 23vifeed ( Sifeed − Siprod ) 10000

(14)

where vifeed is the volumetric flowrate of the feed oil, in m3h-1; S feed and S prod are the sulfur content in feed and product, in µgg-1. Denitrogenation hydrogen consumption can be expressed as18 Fi N = 62vifeed ( N ifeed − N iprod ) 10000

(15)

where N denotes the nitrogen content, in µgg-1. Hydrogen consumption in aromatics saturation can be expressed as18 Fi A = 480vifeed ( Aifeed − Aiprod )

(16)

where A is the aromatics content, in %. Dissolved hydrogen can be expressed as18 Fi D = d i vifeed

(17)

where d is the coefficient of dissolved hydrogen. In a HDT unit, apart from the hydrogen consumption mentioned above, the remaining hydrogen consumption mainly attributes to the processes of olefin saturation and demetalation. Because the process of olefin saturation is a fast reaction and the metal concentrations in streams are much less than other impurities, we assumed that the term Fi O in eq(13) is constant19 although the reactions occur under different operational conditions. Therefore, in practice, if the total hydrogen consumption of a certain HDT unit in the original hydrogen network is known, the term Fi O can be calculated by subtracting the hydrogen consumption of the processes of desulfuration, denitrification, aromatic hydrogenation and dissolution from the total hydrogen consumption.

11


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3.2 Constraints of Operating Temperature, Operating Pressure and Products Quality 3.2.1 Operating Temperature According to Figure 1, the feed oil and hydrogen mixture are heated in the furnace then entered the reactor. Therefore, the outlet temperature of the furnace is the operating temperature. Ti out = Ti R

(18)

where T R is the operating temperature, in oC. This work addresses to optimize the impurity removal degrees so that the operating temperature and pressure will be adjusted if necessary. However, the adjustment ranges of the operating conditions should be within the refinery regulations. Ti R,L ≤ Ti R ≤ Ti R,U

(19)

where superscripts L and U denote the lower bound and upper bound. 3.2.2 Operating Pressure The operating pressure is related to the discharge pressure of the feed oil pump, the make-up hydrogen compressor and the cycle hydrogen compressor, so that the lowest discharging pressure of the three devices is the operating pressure. According to Figure 1, the feed oil is pressurized in a pump then heated in a heat exchanger and a furnace with hydrogen mixture to the operating temperature. The reaction efflux is then separated to an oil phase and a gas phase. The gas phase is the cycle hydrogen after purification and then compressed to mix with the pressured make-up hydrogen. To optimize the operating pressure, the pressure drops of the three streams, feed oil, make-up hydrogen and cycle hydrogen, should be considered in the model. Pi pump,out = Pi R + Pi drop,pump-R

(20) 12


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Pi MHC,d = Pi R + Pi drop，MHC-R

(21)

Pi CHC,s = Pi R − Pi drop，R-CHC

(22)

Pi MHC,d = Pi CHC,d

(23)

Pi H2 = Pi R yiCH

(24)

where the superscript, drop, denotes the pressure drop of the streams; the superscripts MHC, CHC and R, stand for the make-up hydrogen compressor, the cycle hydrogen compressor and the reactor respectively; P drop,pump-R is the pressure drop between the pump and the reactor, in MPa; P drop,MHC-R is the pressure drop between the make-up hydrogen compressor and the reactor, in MPa; P drop,R-CHC is the pressure drop between the reactor and the cycle hydrogen compressor, in MPa; y CH denotes the purity of the cycle hydrogen, in %(vt)。 The adjustment range of the operating pressure is shown as Pi R,L ≤ Pi R ≤ Pi R,U

(25)

3.2.3 Impurity Contents of Products The impurity contents of products should obey the refinery regulations. Siprod ≤ Siprod,U

(26)

N iprod ≤ N iprod,U

(27)

Aiprod ≤ Aiprod,U

(28)

In addition, the feed sulfur content is constrained due to the poisoning of sulfur to catalyst. Sifeed ≤ Sifeed,U

(29)

3.3 HDS, HDN and HDA Kinetics The impurity removal degrees in distillates are related to the feed properties, operating conditions and the self-properties of impurities. The kinetic models of HDS 13


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in TSR and SCR, HDN and HDA are listed in Table 1. In Table 1, S gfeed is the gth group of sulfur compounds in feed, in µgg-1; The superscripts, SC, TS, N and A, denote sulfur compounds, total sulfur, nitrogen and aromatics, respectively; k denotes the kinetic constant, in h-1; KS and KN are the inhibition coefficients of sulfur and nitrogen contents in feed on HDS reaction; P H

2

is the partial pressure of hydrogen, in MPa; α denotes the pressure dependence term; LHSV is the liquid hourly space velocity, in h-1; X is the conversion of aromatics, in %; The superscripts, f and r, are the forward and reverse reactions of HDA; M denotes the ratio of non-aromatics and aromatics in feed oil. k = A exp ( − E RT R )

(30)

where A is the pre-exponential factor, in h-1; E denotes the activation energy, in kJmol-1. 3.4 Impurity Distributions of the FCC Unit The FCC unit is used to produce more gasoline and diesel to meet the increasing market demand.20 The impurities, like sulfur, nitrogen and aromatics are cracked and then reallocated to the cracked gasoline and diesel.21 In this context, the impurity distributions in a FCC unit should be considered in the optimization of the HDT system. 3.4.1 The Allocation of Sulfur in the TSR Model According to Pashikanti’s work22, the allocation of sulfur in a FCC unit can be described as the sulfur contents of products are linear to their feed sulfur content. feed S S S FCC = aFCC,CD S FCC,CD + bFCC,CD

(31)

feed S S S FCC = aFCC,CG S FCC,CG + bFCC,CG

(32)

feed where S FCC is the feed sulfur content of the FCC unit, in µgg-1; SFCC,CD and SFCC,CG

are the sulfur contents in CD and CG, in µgg-1; a and b denote the coefficients. 14


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The relationships of sulfur content between the FCC unit and its upstream and downstream HDT units are prod feed SVGO =S FCC

(33)

feed SFCC,CD =SCD

(34)

feed SFCC, CG =SCG

(35)

3.4.2 The Allocation of Sulfur Compounds in the SCR Model Valla23 demonstrated a cracking rule of sulfur compounds in a FCC unit. The broken bond of a cracked sulfur compound is the bond between the functional group and the side chain. Then the same type sulfur compound with small molecular weight and a hydrocarbon are produced. For example, when the sulfur compounds group, T/BT, is cracked, it is likely to create a small molecular of T/BT and a hydrocarbon. According to Valla’ study23 and the actual refinery operating data, the distributions of sulfur compounds in a FCC unit can be described as S gCD = ∑ a gCD S gFCC,feed

(36)

g

S gCG = ∑ a gCG S gFCC,feed

(37)

g

3.4.3 Nitrogen and Aromatics Distributions The nitrogen and aromatics are also cracked in a FCC unit. According to Zhang et al.’s research24 and Wu et al.’s work19 and the actual operating data as well, the linear relationships are also existed in the distributions of nitrogen and aromatics in a FCC unit. feed N N N FCC = a FCC,CD N FCC,CD + bFCC,CD

(38)

feed N N N FCC = aFCC,CG N FCC,CG + bFCC,CG

(39)

feed A A AFCC = aFCC,CD AFCC,CD + aFCC,CD

(40)

feed A A AFCC = aFCC,CG AFCC,CG + aFCC,CG

(41) 15


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The connections of nitrogen and aromatics between the FCC unit and the HDT system can be expressed as prod feed N VGO =N FCC

(42)

feed N FCC,CD =N CD

(43)

feed N FCC, CG =N CG

(44)

prod feed AVGO =AFCC

(45)

feed AFCC,CD =ACD

(46)

feed AFCC, CG =ACG

(47)

4 Case Study 4.1 Fundamental Data 4.1.1 Operating Data Take a refinery with annual processing capability of 8 million tonnes as an example to illustrate the proposed strategy based on its actual operating data. The processing procedure of the refinery is that the crude oil is separated to several distillates with certain boiling ranges. The VGO distillate is refined in a VGO HDT unit with 2.2 million tonnes annual processing capability then enters a FCC unit to produce CD and CG that are upgraded in CD and CG HDT units with 0.6 and 1.4 million tonnes annual processing capability respectively. A HDT system comprised of the three above-mentioned HDT units is used to demonstrate the proposed the models. The feed properties and operating conditions of the HDT system are listed in Table 2. The adjustment ranges and regulations of operating conditions are listed in Table 3. In addition, the pressure drops between the two devices are in Table 4. All the cycle hydrogen compressors are driven by steam turbines and all other rotating

16


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devices are driven by electric motors in the refinery. The enthalpies of the high pressure steam and the low pressure steam are 3189 MJt-1 and 2777 MJt-1 respectively. All the inlet pressures of feed oil pumps are 0.2 MPa. The suction temperatures of all the cycle hydrogen compressors are 50

o

C. The suction

temperatures and pressures of all the make-up hydrogen compressors are 40 oC and 3.5 MPa respectively. To simplify the calculations, we assume that: (1) The total efficiencies of all the cycle hydrogen compressors, make-up hydrogen compressors, feed oil pump and furnace in each HDT unit are 68%, 75%, 52% and 93% respectively. (2) The purities of all the cycle hydrogen are invariable, and the methane is the only impurity in the cycle hydrogen. (3) The flowrates of all the cycle hydrogen are invariable to satisfy the hydrogen oil ratio; (4) The pressure drops between the two devices are invariable within the adjustment ranges of operating conditions. The other hydrogen consumption Fi O and the pressure dependence term α can be calculated based on the data in Table 2. According to the previous studies19, 23, 25, 26 and the actual operating data, the impurity distributions of the FCC unit can be obtained by regression analysis. The utility prices are listed in Table 5. 4.1.2 Impurities in Distillates The total sulfur, nitrogen and aromatics contents in all related distillates are listed in Table 6. For the CG samples, the sulfur compounds contents can be obtained by the chromatographic detection. For the CD and VGO samples, the sulfur compounds contents can be obtained by the mass spectrometry. The typical chromatogram of the CG feed oil is shown in Figure 3. The sulfur compounds in all distillates can be obtained by analyzing the detection results, as listed in Table 6. 17


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4.2 Analysis and Comparison of the Results of TSR Model and SCR Model The sulfur content in the refined VGO can directly affect the feed oil sulfur content in the followed HDT units. To make full comparisons between the TSR model and SCR model, the sulfur content of the refined VGO is fixed as original data to reduce its affection on the optimization results. In other words, the sulfur content of the FCC feed oil is fixed. The TSR and SCR models are solved according to the data in Table 2~Table 6 in GAMS (V24.1) by using the solver KNITRO. The optimal operating conditions of the two models and the comparison with original data are listed in Table 7. The optimal impurity removal degrees of TSR model and SCR model are listed in Table 8. The sulfur compound data obtained from the SCR model are presented in Figure 4~Figure 6. Figure 7 and Table 9 show the comparison of utility cost among results of the two models and the original cost. 4.2.1 Operational Conditions Table 7 presents the comparison of operating conditions among the results of TSR model and SCR model, and original data. When comparing the optimal operating conditions with original ones, the two models share the same trend when either adjust the operating temperature or adjust pressure in each HDT unit. This is to say that the adjustments of the VGO HDT unit can be optimized by either lowering the pressure or/and increasing the temperature, whereas the CD HDT and the CG HDT units prefer to reduce temperature and raise pressure. When comparing the TSR model with SCR model, the SCR model has the better results except the results in the CG HDT unit. This will be further explained in Section 4.2.3. According to Table 7, the optimal operating temperature of the VGO HDT unit in the SCR model is 7 oC lower than that of TSR model. The optimal operating pressure of the CD HDT in SCR is 0.43 MPa lower. The reason for this 18


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phenomenon is that the SCR model can optimize the removal degree of each sulfur compound, and then the operating conditions can be further relaxed. 4.2.2 Impurity Removal Degrees According to the original impurity removal degrees in Table 6, and the optimal results of the TSR model and the SCR model in Table 8, the little difference in sulfur contents of all distillates can be observed because of the restrictions on sulfur contents of VGO and the refined VGO. Therefore, the impacts of total sulfur kinetics and sulfur compounds kinetics on other impurity removal and utility cost can be clearly demonstrated. In the TSR model, the nitrogen content of the refined VGO with 1862 µgg-1 is lower than the original nitrogen content of 1945 µgg-1, which causes the reduction of nitrogen content in the CD feed oil. In contrast to the TSR model, the SCR model shows different trends. It indicates that the nitrogen content of the refined VGO with 2026 µgg-1 is higher than the original data, which causes the increase of the nitrogen content in the CD feed oil. Moreover, the comparison of the two models in the aromatics removal have the same trend. The aromatics contents in the refined VGO and CD are both increased compared to the original contents. The difference between the TSR and the SCR models is mainly caused by their different optimal operating conditions listed in Table 7. It affects the nitrogen and aromatics removal degrees. Therefore, when different desulfurization kinetics are adopted, different optimizing strategies for the impurity removal should be used. 4.2.3 Results of Sulfur Compounds in the SCR Model The optimal sulfur compound contents in all distillates of the SCR model are shown in Figure 4 ~ Figure 6. As shown in Figure 6, the sulfur compounds in the CG feed oil are all easy removal sulfur compounds. This is the reason for the little 19


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difference in the optimal operating conditions of CG HDT unit between the TSR model and the SCR model, which is mentioned in Section 4.2.1. Therefore, there is less advantage of the SCR model for the optimization of the CG HDT unit, but the advantage of adopting the the SCR model is obvious for the optimization of the VGO and CD HDT units. According to the sulfur compounds of the VGO HDT unit in Figure 4, when the sulfur removal degree of the VGO HDT unit is fixed, the easy removal sulfur compounds in the refined VGO, e.g. T/BT, are higher than the original data, whereas the hard removal sulfur compounds, e.g. C2+DBT, are lower. It means that more hard removal sulfur compounds are removed in the VGO HDT unit. But the optimal temperature of the SCR model is lower than that of the TSR model. It can be explained in terms of Choudhary et al.’s study10, which is that the increasing rate of the C2+DBT reactivity is more than that of the T/BT reactivity when the reaction temperature increases. In other words, the C2+DBT reactivity is more sensitive than the T/BT reactivity to temperature. Moreover, the sensitivities of the C2+DBT reactivity and the T/BT reactivity on pressure change have opposite trends. This is to say that when the pressure increases, the increasing speed of the C2+DBT reactivity is lower than that of the T/BT reactivity.10 Therefore, when the optimal operating conditions of the SCR model are the temperature rising and pressure dropping, more hard removal sulfur compounds and less easy removal sulfur compounds are removed in the VGO HDT unit, whereas the total sulfur removal degree meets the refinery specifications. Valla23 indicated that in a FCC unit a cracked sulfur compound is more likely to produce a sulfur compound with small molecular weight in the same type and a hydrocarbon. As the refined VGO with less hard removal sulfur compounds and more 20


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easy removal sulfur compounds enters the FCC unit, the product of the FCC unit, CD, will contain less hard removal sulfur compounds and more easy removal sulfur compounds. This conclusion can be verified according to the sulfur compound data in the CD HDT unit shown Figure 5. More easy removal sulfur compounds (T/BT) and less hard removal sulfur compounds (C2+DBT) are removed in the CD HDT unit compared to the original data. Based on the above analysis, we explain why the operating conditions can be further relaxed when the removal difficulties of sulfur compounds in HDT units and their distributions in a FCC unit are taken into consideration. 4.2.4 Utility Cost By solving the TSR model and the SCR model, both the utility costs are reduced compared to original cost. The annual utility cost of the TSR model reduces by 9.89×106 CNY with 3.75% reduction, whereas the SCR model can make the 5.83% reduction with 15.37×106 CNY lower than the original cost based on Figure 7 and Table 9. As the detail of utility cost shown in Table 9, it indicates that the SCR model has better optimization results in all utility consumption than the TSR model does. For the hydrogen cost, the SCR model has a more reduction of 5.03×106 CNYy-1 than the TSR model does. The main reason is that the TSR model removes much more nitrogen in the VGO HDT unit and then increases the hydrogen consumption of denitrogenation, as presented in Table 8. It should also be noticed that the hydrogen cost takes the most proportion among all the utility cost. Therefore, both the TSR model and the SCR model proposed in this work can reduce the energy and hydrogen consumptions, whereas the SCR model has the more promising results by taking the removal of sulfur compounds into consideration. In addition, the most effective way to lower the utility cost of a HDT system is to reduce 21


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the hydrogen consumption of the system.

5. Effects of the FCC Unit on Optimization of the HDT system 5.1 Discussion of the Function of a FCC Unit The proportion of the hydrogen cost in the utility cost is more than 87% according to Table 9. Hence, the reduction of hydrogen consumption is the key to reduce the total cost of the HDT system. In the HDT system, the FCC unit is the bridge between the VGO HDT unit and the CD and CG HDT units. The impurity distributions of the FCC unit can affect the hydrogen consumption of these HDT units. Moreover, the impurities, such as sulfur and nitrogen, are also cracked when the heavy distillates are cracked. Then H2S and NH3 produce and flow to LPG or dry gas eventually. It implies that the FCC unit also has some effects of desulfurization and denitrogenation without hydrogen consumption. Subsequently, it is necessary and favorable to make full use of this feature of the FCC unit when the hydrogen cost and total cost of the HDT system are to lessen. In this context, the SCR model is adopted to investigate the effects of the FCC unit due to its better optimization results and the cracking rule of sulfur compounds in a FCC unit. The SCR model with different sulfur contents of the FCC unit feed oil, i.e. SCR with relaxed FCC unit, was solved in GAMS (V24.1) with the solver KNITRO. Then the effects of the allocation of sulfur in the FCC unit on the optimization of the HDT system are analyzed and discussed. The optimal operating conditions are listed in Table 10. The impurity removal degrees are listed in Table 11. The sulfur compounds data are presented in Figure 8 ~ Figure 10, and the minimized utility cost are shown in Figure 11 and Table 12. 5.2 Optimal Results of SCR with Relaxed FCC Unit 22


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5.2.1 Operating Conditions of SCR with Relaxed FCC Unit In Table 10, the operating temperature of the VGO HDT unit is further reduced to 374 oC with the operating pressure of 10 MPa only. The operating pressure of the CD HDT unit is 7.9 MPa, which is 0.33 MPa higher than the optimal results of SCR model with fixed FCC in Table 7, and the pressure of the CG HDT unit is only 0.03 MPa higher. The reason for these results is that as fewer impurities are removed in the VGO HDT unit, then more impurities enter the FCC unit. It implies that the impurities are removed without consuming hydrogen; then more impurities are removed in the CD and CG HDT units, which leads to an increase of the operating pressure. 5.2.2 Impurity Removal Degrees of SCR with Relaxed FCC Unit By comparison of the original impurity removal degrees in Table 6 with the optimal data in Table 11, the impurity removal degrees of the VGO HDT unit are reduced. The sulfur in the refined VGO increases from 1510 µgg-1 to 2000 µgg-1, and the nitrogen increases from 1945 µgg-1 to 2207 µgg-1. Let more impurities enter the FCC unit, and the hydrogen consumption of the VGO HDT unit is decreased accordingly. However, the hydrogen consumptions in the CD and CG HDT units are increased as more impurities are fed into the FCC unit, and then its products contain more impurities. For example, the sulfur content in the CD unit increases from 2038 µgg-1 to 2688 µgg-1, and the nitrogen content increases from 319 µgg-1 to 349 µgg-1; the sulfur content in the CG unit rises from 171 µgg-1 to 236 µgg-1, and the nitrogen rises from 41 µgg-1 to 42 µgg-1. Even though the hydrogen consumption in the CD and CG HDT units increases by the abovementioned adjustments, the hydrogen reduction rate in the VGO HDT unit is much higher. Therefore, the total hydrogen consumption of the HDT system is lower than that of the original operation. 23


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5.2.3 Contents of Sulfur Compounds of SCR with Relaxed FCC Unit Figure 8~Figure 10 show the optimal contents of sulfur compounds in all distillates. On one hand, as shown in Figure 8, for the refined VGO, the easy removal sulfur compound (T/BT) increases by 38.0%, whereas the hard removal sulfur compounds (C2+DBT) increases by 25.0%. It means that more easy removal sulfur compounds enter the FCC unit and make the CD contain more easy removal sulfur compounds. On the other hand, for the CD feed oil, as shown in Figure 9, the easy removal sulfur compounds (T/BT, C1-DBT & NArS) increase by 35%, whereas the hard removal sulfur compounds (C2+DBT & PhT) increase by 25.7%. On the basis of the above analysis, it is clear that if more sulfur compounds can be allocated in the FCC unit, more hard removal sulfur compounds can be removed in the VGO HDT unit with higher operating temperature and pressure, and more easy removal sulfur compounds can be removed in the CD HDT unit. In this context, the operating conditions can be further relaxed, and then the utility consumption will decrease further. 5.2.4 Utility Cost of SCR with relaxed FCC Unit Figure 11 shows the comparison among the original utility cost, the results of the SCR model with fixed FCC feed sulfur (with fixed refined VGO sulfur content of 1510 µgg-1) and the results of the SCR model with relaxed FCC unit (without fixing refined VGO sulfur content). The annual steam cost of the SCR model with relaxed FCC unit is 1.14% more than that of SCR model with fixed FCC feed sulfur. This is due to the fact that the operating pressure of the CD HDT unit rises when more impurities are fed into the CD HDT unit. However, according to Table 12, the annual electricity, fuel gas, hydrogen and steam are all reduced when the impurity removal of 24


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the FCC unit are fully considered in the SCR model with relaxed FCC unit. The annual hydrogen cost reduces by 17.31×106 CNY. The total annual utility cost reduces by 19.23×106 CNY. Based on the above analysis, the SCR model with relaxed FCC unit can further improve the operating conditions of the HDT system, and the energy and hydrogen consumptions can be reduced by making full use of impurity removal and sulfur compounds allocation of the FCC unit. 5.3 Effect of Sulfur Allocation in FCC unit on Utility Cost In order to figure out the effect of the sulfur allocation in the FCC unit on the utility cost of the HDT system, we set the feed sulfur contents of the FCC unit as 1000, 1200, 1400, 1600, 1800 and 2000 µgg-1, respectively. That means that these sulfur contents of the refined VGO are set by the above values, which can be treated as new constraints to the sulfur contents of the refined VGO in the proposed model. And the SCR model is then solved in GAMS (V24.1) with the solver KNITRO based on the abovementioned constraints. The effect of the sulfur allocation in the FCC unit on the utility cost of the system is shown in Figure 12. It can be seen that the sulfur in the FCC feed directly affects the utility cost. The more sulfur contained in the FCC feed oil, the less the utility cost is spent. Moreover, when the sulfur in the FCC feed increases, the consumptions of electricity, fuel gas and hydrogen decrease, whereas the steam consumption rises because the operating pressure of the CD HDT unit is increased to remove more sulfur contained in the CD feed oil. Therefore, under the premise of meeting the refinery regulations on impurities contents, the utility cost can be further reduced when more sulfur compounds are allocated to the FCC unit. 25


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6. Conclusions In present, the major challenges that refineries faced are the large amount of hydrogen consumption and energy consumption due to the heavy and inferior of crude oil, the demand of clean fuels and the escalating severe environmental regulations. By coupling the FCC unit with the hydrotreaters in a refinery, a NLP model is proposed to optimize the HDT system comprised of a VGO HDT unit, a CD HDT unit and a CG HDT unit. Two optimization models, the TSR model and the SCR model, are then established based on the NLP model integrated two kinds of desulfurization kinetics, named the total sulfur kinetics and the sulfur compounds kinetics, to study their effects on the operating condition optimization, impurity removal degrees and the utility costs. Moreover, the effects of the FCC unit on the optimization of the HDT system are also analyzed and discussed. A case study of an actual refinery shows that when the sulfur content in the refined VGO is 1510 µgg-1, the utility cost of the HDT system can reduce by 3.75% with the TSR model, whereas the SCR model can achieve the reduction by 5.83%. The utility cost of the HDT system can be further reduced when the sulfur compounds removal are considered. When the sulfur content in the refined VGO is optimized to 2000 µgg-1, more promising optimization results can be obtained because the allocation of sulfur compounds in the FCC unit are considered. Compared with the original operational data, the annul hydrogen cost reduces by 17.31×106 CNY, and the annual utility cost reduces by 19.23×106 CNY. The sulfur in the FCC feed directly affects the utility cost. The more sulfur contained in the FCC feed oil, the less the utility cost is spent. Consequently, for effective reduction of the energy and hydrogen consumptions 26


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of a HDT system, the operating features of the HDT units and the characteristics of sulfur compounds removal should be considered simultaneously. Moreover, the utility cost can be further reduced by considering the allocation of sulfur compounds and the impurities removal in the FCC unit. Under this circumstance, the precisive sulfur management of desulfurization processes in the HDT system can be achieved.

Acknowledgments The authors gratefully acknowledge funding by the projects (No. 21676211 and No. 21376188) sponsored by the Natural Science Foundation of China (NSFC) and the Key Project of Industrial Science and Technology of Shaanxi Province (No.2015GY095). The authors are also indebted to Mr. Jacob Crowe of Michigan State University for his valuable comments and suggestions.

Nomenclature Parameters a, b

coefficients of FCC impurity distributions

AOT

annual operating time, hy-1

d

coefficient of hydrogen dissolution, Nm3m-3

KN

inhibition coefficient of nitrogen content in feed oil on HDS reaction

KS

inhibition coefficient of sulfur content in feed oil on HDS reaction

LHSV liquid hourly space velocity, h-1 R

gas mole constant, Jmol-1K-1

Variables A

aromatics content, % or pre-exponential factor, h-1

C

cost, CNYy-1 27


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CP

specific heat capacity, JmolK-1

E

activity energy, kJkmol-1

F

utility consumptions, th-1, Nm3h-1

k

reaction constant, h-1

M

ratio of non-aromatics and aromatics in feed oil

N

nitrogen content, µgg-1

p

prices of utilities, CNYmol-1, CNYkWh-1, CNYMJ-1

P

operating pressure, MPa

S

sulfur content, µgg-1

T

operating temperature, oC

v

volumetric feed flowrate, m3h-1

W

power of pump, compressor and turbine, kW

X

conversion of aromatics, %

yCH

hydrogen purity of cycle hydrogen, vt%

Superscripts A

aromatics

CH

cycle hydrogen

CHC

cycle hydrogen compressor

comp

compressor

d

discharge pressure of compressor

D

dissolve

drop

pressure drop

elec

electricity

f

forward reaction of HDA

FG

fuel gas 28


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Energy & Fuels

feed

feed

fur

furnace

HS

high pressure steam

H2

hydrogen

in

inlet stream

L

lower bound

LS

low pressure steam

MHC

make-up hydrogen compressor

N

nitrogen

O

other

out

outlet stream

prod

product

pump

pump

r

reverse reaction of HDA

R

reactor

s

suction pressure of compressor

S

sulfur

SC

sulfur compounds

TS

total sulfur

turb

turbine

U

upper bound

Subscripts CD

cracked diesel

CG

cracked gasoline

CH4

methane 29


Energy & Fuels

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comp

compressors

elec

electricity

FCC

fluid catalytic cracking unit

FG

fuel gas

H2

hydrogen

g

groups of sulfur compounds

i

hydrotreating units

j

electricity driven pumps

k

electricity driven compressors

l

turbines

VGO

vacuum gas oil

Greek letter

α

pressure dependence term

∆H

enthalpy value, MJt-1

η

efficiency, %

30


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References (1) Wincek, R. T.; Abrahamson, J. P.; Eser, S., Energy Fuels 2016, 30 (8), 6281-6289. (2) Korsten, H.; Hoffmann, U., AIChE J 1996, 42 (5), 1350-1360. (3) Rodríguez, M. A.; Ancheyta, J., Energy Fuels 2004, 18 (3), 789-794. (4) Bakhshi Ani, A.; Ale Ebrahim, H.; Azarhoosh, M. J., Energy Fuels 2015, 29 (5), 3041-3051. (5) Froment, G. F.; Depauw, G. A.; Vanrysselberghe, V., Ind. Eng. Chem. Res. 1994, 33 (12), 2975-2988. (6) Vanrysselberghe, V.; Le Gall, R.; Froment, G. F., Ind. Eng. Chem. Res. 1998, 37 (4), 1235-1242. (7) Ma, X.; Sakanishi, K.; Isoda, T.; Mochida, I., Energy Fuels 1995, 9 (1), 33-37. (8) Ma, X.; Sakanishi, K.; Mochida, I., Ind. Eng. Chem. Res. 1994, 33 (2), 218-222. (9) Ma, X.; Sakanishi, K.; Mochida, I., Ind. Eng. Chem. Res. 1996, 35 (8), 2487-2494. (10) Choudhary, T. V.; Malandra, J.; Green, J.; Parrott, S.; Johnson, B., Angew. Chem., Int. Ed. 2006, 45 (20), 3299-3303. (11) Ahmad, M. I.; Zhang, N.; Jobson, M., Chem. Eng. Res. Des. 2011, 89 (7), 1025-1036. (12) Al‐Adwani, H. A.; Lababidi, H.; Alatiqi, I. M.; Al‐Dafferi, F. S., Can. J. Chem. Eng. 2005, 83 (2), 281-290. (13) Muñoz, J. A.; Alvarez, A.; Ancheyta, J.; Rodríguez, M. A.; Marroquín, G., Catal. Today 2005, 109 (1), 214-218. (14) Zhang, B.; Chen, Q.; Hu, S.; Gu, W.; Hui, C., Chem. Eng. Res. Des. 2010, 88 (5), 513-519. 31


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(15) Smith, R., Chemical Process Design and Integration. 2nd ed.; John Wiley & Sons Ltd: Chichester, 2005; pp 271. (16) Liang, X.; Kang, L.; Liu, Y., Ind. Eng. Chem. Res. 2016, 55 (9), 2574-2583. (17) Wu, L.; Liu, Y., Fuel 2016, 164, 352-360. (18) Li, D. Hydrotreating Technology and Engineering. China Petrochemical Press: Beijing, 2004; pp 676-748. (In Chinese) (19) Wu, L.; Liang, X.; Kang, L.; Liu, Y., Chin. J. Chem. Eng., in press. (20) Zhang, J.; Che, Y.; Wang, Z.; Qiao, Y.; Tian, Y., Energy Fuels 2016, 30 (8), 6698-6708. (21) Wang, B.; Han, C.; Zhang, Q.; Li, C.; Yang, C.; Shan, H., Energy Fuels 2015, 29 (9), 5701-5713. (22) Pashikanti, K.; Liu, Y. A., Energy Fuels 2011, 25 (11), 5298-5319. (23) Valla, J. A.; Mouriki, E.; Lappas, A. A.; Vasalos, I. A., Catal. Today 2007, 127 (1–4), 92-98. (24) Zhang, J.; Shan, H.; Chen, X.; Liu, W.; Yang, C., Energy Fuels 2014, 28 (2), 1362-1371. (25) Valla, J. A.; Lappas, A. A.; Vasalos, I. A., Appl. Catal. A 2006, 297 (1), 90-101. (26) Valla, J. A.; Lappas, A. A.; Vasalos, I. A.; Kuehler, C. W.; Gudde, N. J., Appl. Catal. A 2004, 276 (1–2), 75-87. (27) Choudhary, T. V.; Parrott, S.; Johnson, B., Environ. Sci. Technol. 2008, 42 (6), 1944-1947. (28) Cotta, R. M.; Wolf-Maciel, M. R.; Filho, R. M., Comput. & Chem. Eng. 2000, 24 (2), 1731-1735. (29) Yui, S. M.; Sanford, E. C., Can. J. Chem. Eng. 1991, 69 (5), 1087-1095. 32


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Figures Figure 1. Hydrodesulfurization equipment in a refinery Figure 2. Relative reactivity of different sulfur compounds10 Figure 3. Chromatogram of sulfur compounds in CG feed oil Figure 4. Sulfur compounds in VGO HDT unit of SCR compared to original data Figure 5. Sulfur compounds in CD HDT unit of SCR compared to original data Figure 6. Sulfur compounds in CG HDT unit of SCR compared to original data Figure 7. Comparisons of utility cost among TSR, SCR and original data Figure 8. Sulfur compounds in VGO HDT unit of SCR with relaxed FCC unit Figure 9. Sulfur compounds in CD HDT unit of SCR with relaxed FCC unit Figure 10. Sulfur compounds in CG HDT unit of SCR with relaxed FCC unit Figure 11. Comparisons of utility cost of SCR with relaxed FCC unit Figure 12. Effect of sulfur in the feed of the FCC unit on the utility cost

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HDT units HDT unit

FCC unit

Acid gas

Acid gas

Gasoline Refined gasoline

VGO

Acid gas Diesel Refined VGO Refined diesel

Cycle H2

Make-up H2 Compressor

Compressor Absorber

Acid gas Furnace Reactor

Fractionator

Product Seperator Furnace

Feed

Heat exchanger

Pump

Figure 1. Hydrodesulfurization equipment in a refinery

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2.0

1.6

Relative reactivity

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1.2

0.8

0.4

0.0 NArS

BT/T

BNT

C1-DBT C2+DBT

PhT

Figure 2. Relative reactivity of different sulfur compounds10

35


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Figure 3. Chromatogram of sulfur compounds in CG feed oil

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8000

Original feed data Original product data Optimal feed data of SCR Optimal product data of SCR

7674 7674

7500 7000

Sulfur content / µg⋅g-1

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 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

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3081 3081

3000 2500 1946 1946

2000 1500 1000

1029 1029

834 861

676 649

500 0

172 172 0 0

T/BT

0

C1-DBT C2+DBT

PhT

0

0

0

BNT

Figure 4. Sulfur compounds in VGO HDT unit of SCR compared to original data

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1093

1100 1064

1000


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 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 38 of 58

578

555

500 400 300 249 239

200 141 140

100 0

0

T/BT

0

0

0

29

33

C1-DBT C2+DBT

9

17

PhT

6 0 6 0

NArS

Figure 5. Sulfur compounds in CD HDT unit of SCR compared to original data

38


Page 39 of 58

140


133

129

120


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 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

100 80 60 43

42

40 20 10 4

0

0

T/BT

0

NArS

Figure 6. Sulfur compounds in CG HDT unit of SCR compared to original data

39


Energy & Fuels

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 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Total

Page 40 of 58

Original data TSR results SCR results

105 100 95 90

Steam

Electricity

85 80

H2

Fuel gas

Figure 7. Comparisons of utility cost among TSR, SCR and original data

40


Page 41 of 58

8000

Original feed data Original product data Optimal feed data of SCR with relaxed FCC Optimal product data of SCR with relaxed FCC

7674 7674

7500 7000


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 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

3081 3081

3000 2500

1946 1946

2000 1500 1155

1000

1029 1029

834

676

845

500 0

172 172 0 0

T/BT

0

C1-DBT C2+DBT

PhT

0

0

0

BNT

Figure 8. Sulfur compounds in VGO HDT unit of SCR with relaxed FCC unit

41


Energy & Fuels

1462

1500


1250 1064

1000


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 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

578

Page 42 of 58

723

500 400 311

300 249

200

184 141

100 0

0

T/BT

0

0

0

29

32

C1-DBT C2+DBT

9

18

PhT

6 0 8 0

NArS

Figure 9. Sulfur compounds in CD HDT unit of SCR with relaxed FCC unit

42


Page 43 of 58

178

180


150


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 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

129

120 90

58

60 42

30 4

0

10 0

T/BT

0

NArS

Figure 10. Sulfur compounds in CG HDT unit of SCR with relaxed FCC unit

43


Energy & Fuels

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 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 44 of 58

Total 105 100 95

Steam

Electricity

90 85

H2

Fuel gas

Original data SCR results with fixed FCC feed sulfur SCR results with relaxed FCC unit

Figure 11. Comparisons of utility cost of SCR with relaxed FCC unit

44


Page 45 of 58

260

Utility cost / ×106 CNY⋅Y-1

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 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

Steam Electricity

Fuel gas H2

250 240 230 220 210 200 1000

1200

1400

1600

1800

2000

Sulfur in FCC feed/ µg⋅g-1

Figure 12. Effect of sulfur in the feed of the FCC unit on the utility cost

45


Energy & Fuels

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 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Tables Table 1. Kinetics of HDS, HDN and HDA Table 2. Feed Properties and Operating Conditions Table 3. Adjustment Ranges of Operating Conditions and Regulations Table 4. Pressure Drops Table 5. Utility Prices Table 6. Sulfur Compounds, Nitrogen and Aromatics contents Table 7. Comparisons of the Operating Conditions of Original Data, TSR and SCR Table 8. Optimal Impurity Contents of TSR and SCR Table 9. Comparison of the Utility Cost of Original Data, TSR and SCR Table 10. Operating Conditions of Original Data and SCR with Relaxed FCC Unit Table 11. Optimal Impurity Contents of SCR with Relaxed FCC Unit Table 12. Comparison of Utility Cost of SCR with Relaxed FCC Unit

46


Page 46 of 58

Page 47 of 58

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 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48

Energy & Fuels

Table 1. Kinetics of HDS, HDN and HDA Sulfur compounds

Total sulfur

Equation HDS

Reference

 −kiSC ( Pi H2 ) ,g  Siprod = ∑ Sifeed exp ,g  K S Sifeed + K N N ifeed LHSVi g 

αiSC ,g

N

HDN

HDA

   

(

)

(

)

Reference

 ( Pi H2 ) Siprod = Sifeed exp  −kiTS  LHSVi 

αiTS

27

Choudhary

prod i

 k f P H 2 αi − k r M i i i i X iA =  A H 2 αi f r  ki Pi + ki  A

Equation

=N

feed i

αi  Pi H2  N exp  −ki LHSVi  

(

)

N

    

   f H2 αiA   −  ki Pi + kir    feed    M = 1 − Ai   1 − exp   i feed  LHSVi Ai         

(

)

47


   

Li18

Li18 & Cotta28

Yui29

Energy & Fuels

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 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Page 48 of 58

Table 2. Feed Properties and Operating Conditions HDT units -1

Feed flowrate/th Density/kgm-3 FH2/mols-1 FCH/mols-1 yCH/% TR/oC PR/MPa LHSV/h-1 PCHC,s/MPa

VGO

CD

CG

231.82 912.82 246.6 2234.5 86.76 370 10.8 1 10.48

53.38 847.71 94.4 193.2 81.1 313 7.05 2.5 6.42

111.39 730.23 38.8 339.6 90 258 2.1 2.6 2.69

48


Page 49 of 58

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 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60

Energy & Fuels

Table 3. Adjustment Ranges of Operating Conditions and Regulations HDT units

TR/oC

PR/MPa

Sfeed/µgg-1

Sprod/µgg-1

Nprod/µgg-1

Aprod/%

VGO CD CG

360-400 290-340 240-300

8-12 6-8 2-2.3

Operational Optimization of a Hydrotreating System Based on

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