New design and optimization for replacing dimethyl disulfide with

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New design and optimization for replacing dimethyl disulfide with wasted disulfide oil in olefin furnaces Erfan Ziarifar, Rahbar Rahimi, and Morteza Zivdar Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b02773 • Publication Date (Web): 25 Oct 2018 Downloaded from http://pubs.acs.org on October 26, 2018

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New design and optimization for replacing dimethyl disulfide with wasted disulfide oil in olefin furnaces Erfan Ziarifar, Rahbar Rahimi*, Morteza Zivdar Chemical Engineering Department, University of Sistan and Baluchestan, Zahedan, Iran *Corresponding author, Email:[email protected]

Abstract This paper is aimed to examine and understand the feasibility of replacing dimethyl disulfide (DMDS) with disulfide oil (DSO) in olefin units of Amir Kabir Petrochemical Refinery (Khuzestan, Iran). This substitution not only provides a very low-priced supply for replacing DMDS in olefin plants, but also it restrains emitting the poisonous sulfur gaseous to the environment. Considering the fact that the conversion of DSO to hydrogen sulfide required a longer residence time related to DMDS, the DSO pilot was built to examine this alternation. Comparing the results with those of DMDS revealed that this pilot allowed for complete replacement. Poly-nuclear Aromatics mechanism was the predominate mechanism and optimization results showed that three selected parameters (temperature, retention time and DSO injection rate) affected the CO production. The rate of CO formation was very similar for using both cases. The total sulfur content, which is an environmental pollutant and a component of gasoline, was also controlled. With DMDS the total sulfur content varied from 20 to 130 ppm, while with DSO it varied from 20 to 100 ppm, which was acceptable. As a result of this process, approximately 221,000EUR would be saved per year in an olefin unit with an ethylene production capacity of 520,000 tons.

Keywords: Olefin Production, Steam Creaking, Disulfide Oil, Economic Evaluation, Optimization, Kinetics.

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Introduction Ethylene and propylene are considered to be the key components of the chemical industry with an annual production of nearest about 1.5 × 108 and 8 × 107 tons, respectively. The production rates of these components are expected to increase due to an increasing global population combined with rising living standards1.Cracking of hydrocarbon feedstocks ranging from ethane to gasoil into furnace crackers is one of the most important procedures for olefin production in the large scales. One of the main problems in steam furnace crackers is the formation of carbonaceous material inside the radiant coil and the tubes of transfer lines exchange (TLEs)2, 3, which dramatically decreases the efficiency, and increases the total utility cost and period of the process. Furthermore, carbon monoxide formed during the steam cracking acts as a poison for the catalysts used in the downstream hydrogenation reactors4. Sulfur injection is one of the most important procedures to increase the efficiency of olefin production, and prevent the undesirable products. In the cracking process of heavy hydrocarbons, the production of undesirable products such as CO, CO2, and deposited coke inside the reactor wall affects the operation of cracker furnaces with raising pressure drop, and reducing heat transfer. If it continues longer, accumulation of coke forces the operator to shut down the unit for a certain period. Therefore, the furnace has to be taken offline for decoking5, 6. Significant effort has been exerted over the past century to develop coke inhibitors, especially in industrial olefin plants, additives are commonly employed to control CO production or inhibit coke formation. Thus, different types of inhibitor additives are used commercially and/or under study. These inhibitors are categorized as sulfur based compounds, i.e. dimethyl sulfide (DMS), dimethyl disulfide (DMDS), hydrogen sulfide (H2S), benzothiophenes, bibenzyl sulfide, organophosphorus chemicals like Nalco’s trademarked COKE-LESS7,sulfur-siliconbased additive liquids like CLX family8, 9, and tin-based additives such as Chevron Phillips CCA50010,

11.

Amongst the additives, the traditional approach to coke elimination in the thermal cracking process is the purposeful addition of sulfur-based compounds, i.e., DMS or DMDS to the feedstocks8, 11. Influence of sulfur compounds to prevent coke formation is highly dependent on the metal composition12, application method13, concentration12, 13,as well as the chemical nature of the sulfur compounds12. Under the conditions related to cracking coils, DMDS thermal decomposition will occur, which produces dimethyl sulfide, methanethiol, carbon disulfide, and hydrogen sulfide as its main


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components14. The most abundant sulfur-containing compounds is H2S; consequently, the formed H2S plays the major coke inhibiting function13, 14. Thus, it can be concluded that the effect of H2S addition on the rate of coke formation in the thermal cracking of hydrocarbons is obscure. On the one hand, investigations indicate that H2S would delay coke formation via forming a metal sulfide film on the inner wall of sample that hinders the secondary reactions15; on the other hand, H2S compounds/radicals play the initiating/accelerating role in raising the rate of coke deposition2,13. Trimm and Turner depicted that the effect of sequential addition of H2S on the coke formation during steam cracking of propane depends on the material, on which the coke is deposited16. In many developing countries with gas refineries, some sulfur-containing materials burn in flare systems, which results in enormous environmental hazards. One of these materials is DSO, which can be replaced by DMDS to prevent coke formation. In the refineries, Meraux reaction is used to separate the mercaptans existing in the liquid gaseous, butane, propane, light naphtha and kerosene. DSOs are the final product on the oxidation process of mercaptans. In the Meraux unit, NaOH is used as an extraction solution and it could be reused after recycling. Then, mercaptans converted to DSO in the presence of oxygen and alkaline solution (extracted solution). The final DSO formed in the units were deposited as waste or burned in the flares. DSO is not a desired byproduct in the gas refineries and it is injected to the depth of earth or burned in the flares which would cause environmental pollution. Generally, the main part of DSO is formed from a short chain of di alkyl disulfides. If DSO does not completely convert to H2S, it increases the total sulfur in the gasoline which in turn leads to serious environmental hazards. The inside surface of the tubular metal at furnaces is occupied by sulfur atoms, which causes reduced carbon monoxide production. Sulfur-metal bonds are more stable at the surface than bulk bond cases. After saturation, deeper layers of metal gradually begin to form bulk sulfides. Due to the positive charge induction, the metal regions exhibit less activity. To prevent coke formation by sulfide materials, numerous mechanisms have been presented and the most important of them are radical and molecular models. These models state that an important factor in preventing coke formation and reducing undesirable byproducts is hydrogen sulfide concentration. This substance is obtained from various sources, but in case of thermal cracking in the olefin units, it is obtained from direct injection of DMDS into cracking furnaces. In most gas Refinery Companies, DSO burns in the flares as a waste substance. Substituting this material in addition to reducing environmental hazards can also save money. DSO contains substances such as DMDS, DEDS and


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EMDS which can be converted to hydrogen sulfide at different temperatures. Therefore, in order to prevent entering sulfur in other forms to cracker units, DSO should completely be converted to hydrogen sulfide before being injected. The olefin units of Amir Kabir Petrochemical (Khuzestan, Iran) use DMDS (with the license of Linde Company) as an inhibitor of coke formation in the steam cracking process. This substance is expensive and causes to increase overall production costs. H2S functions act as an inhibitor and there are various resources for it, therefore, replacing DMDS with other cheap or wasted sources such as DSO can be examined. This compound contains large amounts of sulfur, and its disposal is currently an environmental issue. In fact, DSO contains sulfurous compounds of the DMDS family. Disulfide oil cannot be sold, and its substitution for DMDS after it flows out of the reactor (for obtaining the required parameters) minimizes environmental problems and brings in profit. In this work, the effect of replacing DMDS with DSO and indirect injection of DSO in olefin production furnaces, as well as the amount of the CO produced, which indicates the degree of combustion and coke formation, were investigated at pilot scale. The amount of total unconverted sulfur from the injection of two substances on products was also been measured. It was observed that the appropriate substitution of DMDS with the DSO provided a very cheap resource for replacing DMDS in olefin plants and reduced emitting the poisonous sulfur gaseous to the environment. The effects and interactions between the effective parameters on the coke formation were studied using central composite design (CCD) tab from RSM. In addition, the development of highly efficient cracker unit-operating required critical data. So, the mechanisms and kinetic of coke formation in this process were reviewed. Also, the overall economic calculation of the replacement process and the overall cost savings were considered. To the best of our knowledge, there were no similar reports on the literature, and this is being reported for the first time. Materials and Methods Feedstockes

In this study, DMDS was purchased from Linde Company (Germany). DSO was collected as a by-product from the sweetening process at Kangan Gas Refinery (Bushehr-Iran). The composition of DSO is shown in Table 1 and the composition and properties of the crude oil used in this study are listed in Table 2.


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Mesuremeant Hydrogen sulfide in streams was analyzed using a gas chromatograph (Shimadzu, Japan) equipped with a 100 µL sample loop, two thermal conductivity detectors (TCD) and one flame ionization detector (FID) according to ASTM-D5453 test method. This test method can be used to determine sulfur in process feeds sulfur in final products, and can also be used for purposes of regulatory control.In all tests,it was assumed that the total sulfur content is equal to the amount of hydrogen sulfide.The CO amount was measured using online CO analyzer at the end of the cracking process. Optimizatin and Exprimental Desgin The optimization of thermal process and effect of DSO on the coke formation as an inhibitor were carried out by three chosen independent variables (retention time, temperature, and DSO injection) with six replicates at center points, according to central composite (CCD) design. The ranges and the levels of the variables (high and low) are given in Table 3. This design leads to purposes twenty runs, the amount of CO production was taken as the response of the design experiments. The conditions and results of each are presented in Table 4. CrackingTests With the direct injection of DSO into the furnace under the same conditions of DMDS, the residence time caused many problems such as an increase in the sulfur content of the by-products (i.e., pyrolysis gasoline). For solving this problem, a new and special plant was installed before the furnaces which injected 99.99% hydrogen sulfide into the steam crackers. Thus, the other sulfur-containing materials, mercaptans, etc., would not enter or remain in the furnaces. The diagram of the pilot plant for converting DSO is shown in Fig. 1 (outlet stream presented in section (a) in support information). The reactor was made up of Incoloy800 alloy (35cr, 45Ni), the pipe size (24.31-33.41 mm ID) was selected in order to maintain the pipe stability under the current operating conditions and heat losses through the pipe enabling direct estimation of temperature and pressure gradients of injection and production. The pilot equipment would be described as: reactor body (grade 80 steel pipe), double-pipe heat exchanger (Alstom), dosing pump( Marelli)(5 bar), 90 electric elements (=30 KW), final cooling double-pipe exchanger (Alstom), inline mixer(ABB), self-tuning regulator of input vapor pressure (Masoneilan), vapor vortex flow meter


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with flange (Yokogawa), vapor pneumatic control valve (Masoneilan), couplings(Masoneilan & Sapag), mini PLC system (Yokogawa), Instrumentation pneumatic regulator (Siemens), class 600 safety valve (Cossby), feedstock stop valve(Cossby), input manual valve (Yokogawa), output manual valve(Yokogawa). The DSO with a mass flow rate of 10 kg/hr. at ambient temperature flew from the DSO tank to the P-100 pump. In the pump, the pressure was raised to 5 bar and the fluid was transferred to the mixer MIX-100. In the parallel current and in the steam unit, the required steam was produced at the pressure of 10 barand193 °C. The steam pressure was reduced to 5 bar into the VLV-100 valve and it was mixed with the DSO stream in the MIX-100 mixer. In the mixer, DSO evaporated completely in the vicinity of hot steam. The mass ratio of vapor to flow rate of DSO was adjusted at 1.5.For thermal decomposition of disulfides, the mixed stream was introduced to the reactor R100 and heated up to 650 °C. The volume of exhausted gas from the reactor was 61/33 L/hr. The exhausted gas from the reactor was directed to the Laval Nozzles. To keep safety, all pipes and electrical elements were protected by the pressure-positive environment; the tubes were separated from the ambient. The chamber was cleaned through a continuous stream of nitrogen. Product streams were analyzed online using a gas chromatograph (CP-SIL5CB Varian 3800, USA). Decoking procedure The furnace outlet temperature declined to 820 °C while the mass flow rate did not exceed 50 kg/hr. This temperature should then be kept constant. The dilution steam/hydrocarbon feed ratio should be controlled and the hydrocarbon feed valves should be closed gradually. The hydrocarbon feed must reduce stepwise from 26 to 0 Ton/hr. The DMDS or DSO injection should be stopped, so the furnace is in the standby condition. While closing the hydrocarbon feed valve, the furnace outlet temperature is held constant at 820 °C by reducing the fired duty. The heat release of the floor and side wall burners would automatically reduce by the COT control. As soon as the feed flow falls to zero, the block valve upstream of the feed control valves should be closed and the feed lines should be purged with process steam. Then we would switch over to MP (Medium pressure steam) by first opening the valve in the MP-steam supply line, and then closing the valve at the process steam supply line to the furnace. We would switch over from the process line to the decoking gas line (to the stack). When the temperature stabilizes at 820 °C, switching to the decoking line could begin. When the cracked gas valve is completely closed, the LP (low pressure


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steam), normally injected for purging purposes, would serve as sealing medium to the valve and the furnace (pilot) would be decoked. Results and Discuation Examination and Substitution of DSO and DMDS Compersion In order to assess the feasibility of replacing DMDS with DSO, effects of injection of each substance on the produced CO and total sulfur concentrations in the final product were investigated. According to the datasheet of DMDS producer (Linde Co.), the amount of carbon monoxide produced by injection of this substance to each cracker furnace should be less than 400 ppm. Thus, the amount of injectable DMDS in each furnace would be around 5 kg. As seen from Table 5, one kilogram of DMDS yields in 723 grams of H2S, whereas this value for DSO is 619 grams. Hence, produced H2S ratio for DMDS relative to DSO is equal to 1.2, therefore, the injected amount of DSO must be 1.2 times more than the amount of DMDS injected under similar conditions to achieve the initial throughout. In other words, to obtain an efficiency similar to DMDS, the injected DSO must be twice as DMDS. In all tests, two kilograms of DSO was consumed, which means that 0.8 extra kilograms of H2S was added to the mix (entered feed). It is assumed that CO is produced solely from the gasification of coke. Thus, the amount of CO produced into steam cracker units is used as an indicator for coke formation/deposition. Also, in the downstream hydrogenation reactor to produce an on-specification product, in the cases of high CO concentrations, high operating temperatures are required. Hence, the effect of DMDS and DSO on the CO production rate was investigated at the same conditions, the results are reported in Fig. 2. It isobserved that the effect of DMDS and DSO on the rate of CO formation are very similar. Bycomparing the results, it couldbe seen that by additional DSO can achievethe same efficiency when using DMDS. But due to the DSO converting to H2S before injection, the rate of CO formation in the presence of DSO decreases with a slope steeperthan that of DMDS;it indicates that this pilot can effectively be used for DSO or other containing sulfur materials injection to the furnaces. Carbon monoxide is produced in the steam cracker through the following reactions: H2S + CO ↔ COS + H2

(1)

CH4 + H2O ↔ CO + 3H2

(2)


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Increasesin temperaturediminishes the equilibrium state of both reactions and the reactions tend to produce more CO.Hence, can be expected that by increasing the H2S concentration in equation (1), the reaction moves toward the forward reaction due to Le Chatelier’s principle; Consequently, the amount of carbon monoxide would reduce.Reducing the amount of produced CO at a faster rate, when DSO is used for coke inhibitor, can be attributed to the conversion of this substance to hydrogen sulfide prior to injection. Gasoline sulfur content One of the products of cracking in olefin furnaces is pyrolysis gasoline, whose sulfur content is important for downstream industries and environmental conditions. The coil outlet temperature and the pressure inside these pipes affect the conversion products 17, but by replacing DMDS with DSO, the total sulfur content of the pyrolysis gasoline changes to 25.89 ppm for a unit with a production capacity of 18 tons/hour. The sulfur content of gasoline produced from DMDS varies from 20 to 130 ppm but following the injection, it ranges from 20 to 100 ppm, which confirms the accuracy of the calculations. The total sulfur content of gasoline is shown in Fig.4 for different amounts of DMDS and DSO injection. Process Optimization Design Expert software proposed a quadratic equation based on the value of factors to predict CO Production (ppm). Final equation in terms of coded factors is presented by equation (4). CO Production (ppm) = 351.59 -7.04×A - 8.75 × B -5.52 × C - 7.38 × A × B - 4.13 × A × C - 5.38 × B × C + 25.02 × A2 + 11.23 × B2 +14.06 × C2(4) The results of the design was interpreted using analysis of variance method which is presented in Table 6. As it could be seen in this table, the F-value and p-value for the predicted model were equal to 60.6 and less than 0.0001 respectively, indicating that the proposed model was absolutely stable (see Table 6). There was only a 0.01% chance that a "Model F-Value" of this large could occur due to noise. The overall performance of the model is expressed by R2. Correlation degree between the observed and the predicted values is expressed by Adj.R218. For this model, R2 and Adj.R2 were 0.982 and 0.966, respectively, which shows that the model can be used for predicting the behavior and role of the process parameters at design space. The "Lack of Fit F-value" of 2.10 implies the Lack of Fit is not significant relative to the pure error. There is a 21.68% chance that a


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"Lack of Fit F-value" this large could occur due to noise. Non-significant lack of fit is good. "Adeq. Precision" measures the signal to noise ratio. A ratio greater than 4 is desirable. The model ratio of 22.44 indicates an adequate signal. This model can be used to navigate the design space. According to the interactions between parameters of proposed model, effects of selected parameters on CO production/coke formation in the thermal cracking process were investigated using 3D- surface graphs (Figs.4-6). In these graphs, the effect of two factors was considered whereas the other was adjusted in a constant volume. Fig. 4 shows the interaction between retention time and DSO injection parameters on the CO production. It can be seen that the amount of CO decreased as the retention time increased. This can be due to more elimination or completely dehydrogenation of aromatic compounds as a main source for coke formation. Also, when the retention time remained a constant value, the CO production rapidly decreased with increasing in DSO injection to 6 kg/hr. This could be attributed to raising HS radical concentration. The H-S energy band dissociation is equal to 91 kcal/mol, which is less than its value for C-H band in the ethane (101.1kcal/mole), methane (104.99kcal/mole), and propane (98.6 kcal/mol) molecules. Thus, with increases of DSO (H2S) the concentration of HS radicals would increase too; it prevents carbon monoxide production or coke deposition19. The interactions between (cracking) temperature and DSO injection are depicted at Fig. 5. As it can be seen, when the temperature is adjusted at its minimum or maximum, the production of monoxide would be higher than other situations. This phenomenon can be justified by the sensitivity of thermal cracking process to the temperature. So that, temperature enhancing moves the CO production equilibrium reactions towards more coking formation (CO production)20. The lowest amount of carbon monoxide produced was at the temperature of about 800 °C and DSO injection rate of 6 kg/hr. Studying theinteractions between the retention time and temperature on the process behavior is represented in Fig. 6. It can be observed that CO production remained at its lowest amount when the temperature and retention time wereinto their highest and midst values. The lowest amount of carbon monoxide wasresulted at the temperature and retention time of about 800 °C and 8 s, respectively.


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Furthermore, Fig. 7shows the predicted values versus the experimental (actual) values for CO production in the cracking process, depicting that the supposed models successfully demonstrate the relation between the selected parameters and responses18. Kinetics Study The mechanisms of coke formation in thermal furnaces or transfer line exchangers are categorized as follows: I)

Catalytic Coking mechanism: the used coils in the cracking process always contain small amounts of Cr, Ni, and Fe metals which react with feed elements in the startup stage of cracker furnaces. The hydrocarbons existing in the feed are chemisorbed on the inner surface of TLEs in molecular level and convert to coke in the presence of these metals Accumulation of these particles and their diffusion cause a drop in the pressure of TLEs. Carbon deposition on the inner surfaces creates inactive crystalline dots/centers, which chemisorbs the hydrocarbon radicals and lead to the growth of passive and porous layers on the inner wall surfaces. In this mechanism, nature and properties of used metals are very important, so that, the metals encapsulation decreases the dehydrogenation rate of chemisorbed hydrocarbons, which leads to decrease catalytic activity and reduced coke formation and CO production.

II)

Radical Coking mechanism: poly-aromatic compounds are not completely dehydrogenated at the surface shared between coke and feed. The untreated hydrogens react with the radicals existing in feed such as methyl, ethyl and etc. In other words, the number of these active sites is a function of feed composition, which confirms this fact that the feed with potential of radical production causes more and more coke formation. The main property of this mechanism is formation of coke layers containing carbon atoms with sp2 hybridization. It justifies the high hardness and low regenerability of coke layers due to cross linked aromatic in the industrial process.

III) Poly-nuclear Aromatics mechanism: this mechanism is based on poly nuclear aromatic formation via radically reactions in the feed. Condensation and dehydrogenation of aromatics produce tar or soot particles, which deposit as a physical layer on the surface. The outer layer contains untreated hydrogen that can easily react with other radicals and produce next layers. This mechanism commonly occurs when the resource of feed is liquid.


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It is not important in the cases where the temperature is below 700 °C. With elimination of unsaturated and aromatic compounds, the number of reactions capable for coke formation can be reduced. The remained sources can be eliminated using various methods such as inhibitor addition, chemical surface modification of cracker and variation in the TLE composition. Table 7 shows the kinetics information in the presence of sulfur compounds21.Regarding the feed used in this process, which contains some aromatic compounds, it seems that the third mechanism is dominant and more important. Sulfur compounds can change the rate of the reactions that cause the growth of the coke layers. Radical regions, created by the hydrogen adsorption of active radicals such as hydrogen and methyl radicals in the gas phase, react with unsaturated compounds at the coke layer. If benzene and ethylene are used as a reference coke forming material in the coke layers, respectively, the reactions may occur in accordance with Table 7. Since DSO has been used as an inhibitor coke formation in this work, sulfur compounds entered the mechanisms in two ways. The kinetics data show that hydrogen and methyl radicals can react with hydrogen sulfide due to the decomposition of sulfur compounds. Therefore, produced SH radicals can react with active centers in coke layers. Hydrogen adsorption by SH radicals requires higher activation energy than adsorption by hydrogen and methyl radicals. If the increase in the rate of coke formation is due to the reaction with the SH radicals, then the concentration of these radicals should be approximately at the high concentration of hydrogen and methyl radicals, which is impossible. The best reason for justification of the increase in coke formation rate is the presence of SH radicals in the final reactions with the great coke radical. Therefore, the radical positions in the coke structure are changing, and the thiol (coke), created by the separation of hydrogen from hydrogen and methyl radicals, can easily be expanded. Dissociation of the C-S graft leads to the formation of two radical centers in the coke network, which increases the reactivity of the network with the gas phase components. Economic evaluation Various temperature and time periods are required for the complete conversion of materials to cracking products. For instance, coil outlet temperature (COT) directly affects production. The unit energy consumption of the ethylene cracking process is obtained via the following equation22.


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𝐸=

1000 𝐺 + 80 𝑆 + 9.2 𝑊 + 92𝑠ℎ 𝑄

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(4)

Where, E is the unit energy consumption reduced into normal oil, G shows the unit consumption quantity of fuel gas, S represents the amount of diluted steam, W is the feed waterfor boiler, Sh indicates the unit production of high-pressure steam, and Q is the proudct (ethylene) yield. Therefore, the temperature must change to allow for the conversion of the injected sulfurcontaining materials. Moreover, although extensive temperature changes may accelerate the conversion of sulfur-containing materials to the H2S gas, it makes changes to the optimum production (i.e., the cracked materials). Following the theoretical calculations, simulations of the unit dedicated to the replacement of the two compounds and the pilot tests were carried out and it was found that complete replacement wasfeasible. Moreover, the required amount of DSO for this process was twice as DMDS. The cost of supplying one kilogram of DMDS is 2.4EUR and the cost of obtaining and using DSO plus the required utility is 0.58EUR. In other words, there is a difference of 1.8 EUR between the prices of one kiogram of the two substances. Considering the steam (30kW/hr) and electricity (15 kg/hr) consumptions, annual utility cost ofthis process was estimated about 14315 EUR, while the cost difference of DMDS and DSO wasequal to 235920 EUR. Final saving = cost difference of DMDS and DSO – utility Final saving = 221605 EUR Economic properties of the process arepresented in Table 8.According to the above calculations, 221600EUR wouldbe saved per year by replacing DMDS with DSO. Conclusion According to the literature and calculations, it was found that “disulfide oil” can be used instead of "dimethyl disulfide" in order to prevent coke formation at steam cracker of olefin units of refiners. For this purpose, DSO has to completely convert to hydrogen sulfide before the injection, hence, it required special equipment. After designing and constructing the required equipment in pilot scale, the values of DSO conversion to the hydrogen sulfide gas were carefully measured and revealed that conversion is equal to 99.30% at an injection rate of 6 kg/hr. Kinetic studies show that the ploy nuclear aromatic is one of the most important mechanisms for coke deposition in this


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process. Also, the amount of produced CO considered as a measure of catalyst poisoner and coke formation indicator. Results from DSO injection to furnaces cracker indicate that CO concentration would be minimum for 6 kg/hr. of DSO. Operational parameters were optimized via CCD tab from Design Expert software, CO production was selected as the coke indicator and analysis response. A quadratic model purposed to predict the behavior of the coke formation in the thermal cracking process. The interactions study showed that all selected parameters are effective on the CO efficiency. Regarding the overall results, it has been proved that this replacement can be completely performed using the constructed pilot, and according to the calculations and due to the lower efficiency of DSO compared to DMDS for H2S gas production only more injection of DSO is required. Based on cost calculations, it turned out that the economic benefits of this replacement would amount to about 221000 Euros per year. Furthermore, this substitution not only provides a very low-priced resource for DMDS in olefin plants, but also restrains the emission of sulfur gaseous, which is a hazardous material to the environment. Acknowledgement Authors would like to express their sincere appreciation to the Amir Kabir Petrochemical Co. for the financial support of the work. Supporting Information (a) Outlet stream for Fig. 1, (b) Calculations for H2S content determination, and (c) Calculations for gasoline total sulfur content.


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References: (1) Amghizar, I.; Vandewalle, L. A.; Van Geem, K. M.; Marin, G. B., New Trends in Olefin Production. Engineering 2017, 3, (2), 171-178. (2) Rahimi, N.; Karimzadeh, R.; Jazayeri, S. M.; Nia, K. D., An empirical investigation of the influence of sulfur additives on the catalytic rate of coke deposition and CO formation in the steam cracking of LPG over Incoloy 600 and stainless steel. Chemical Engineering Journal 2014, 238, 210-218. (3) Meyers, R. A.; Meyers, R. A., Handbook of petrochemicals production processes. McGrawHill Prof Med/Tech: 2005. (4) Dhuyvetter, I.; Reyniers, M.-F.; Froment, G. F.; Marin, G. B.; Viennet, D., The influence of dimethyl disulfide on naphtha steam cracking. Industrial & engineering chemistry research 2001, 40, (20), 4353-4362. (5) Crynes, B.; Albright, L. F.; Tan, L.-F., Thermal cracking. 2001. (6) Salari, D.; Niaei, A.; Shoja, M. R.; Nabavi, R., Coke formation reduction in the steam cracking of naphtha on industrial alloy steels using sulfur-based inhibitors. International journal of chemical reactor engineering 2010, 8, (1). (7) Tong, Y.; Poindexter, M. K., Method of inhibiting coke deposition in pyrolysis furnaces. In Google Patents: 1999. (8) Alatortsev, E.; Votin, A.; Vartapetyan, A.; Leont’eva, S.; Mityagin, V.; Podlesnova, E., Study of Chemical Processes in the use of Absorbers of Hydrogen Sulfide in Oil. Chemistry and Technology of Fuels and Oils 2017, 53, (5), 692-699. (9) Yamaguchi, A.; Jin, D.; Ikeda, T.; Sato, K.; Hiyoshi, N.; Hanaoka, T.; Mizukami, F.; Shirai, M., Effect of steam during catalytic cracking of n-hexane using P-ZSM-5 catalyst. Catalysis Communications 2015, 69, 20-24. (10) Mironenko, O.; Sosnin, G.; Eletskii, P.; Gulyaeva, Y. K.; Bulavchenko, O.; Stonkus, O.; Rodina, V.; Yakovlev, V., A study of the catalytic steam cracking of heavy crude oil in the presence of a dispersed molybdenum-containing catalyst. Petroleum Chemistry 2017, 57, (7), 618-629. (11) Eletskii, P.; Mironenko, O.; Sosnin, G.; Bulavchenko, O.; Stonkus, O.; Yakovlev, V., Investigating the process of heavy crude oil steam cracking in the presence of dispersed


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Energy & Fuels

catalysts. II: Investigating the effect of Ni-containing catalyst concentration on the yield and properties of products. Catalysis in Industry 2016, 8, (4), 328-335. (12) Towfighi, J.; Zimmermann, H.; Karimzadeh, R.; Akbarnejad, M. M., Steam cracking of naphtha in packed bed reactors. Industrial & engineering chemistry research 2002, 41, (6), 1419-1424. (13) López García, C.; Becchi, M.; Grenier-Loustalot, M.; Paisse, O.; Szymanski, R., Analysis of aromatic sulfur compounds in gas oils using GC with sulfur chemiluminescence detection and high-resolution MS. Analytical chemistry 2002, 74, (15), 3849-3857. (14) Goswami, A.; Kumar, S., Failure of pyrolysis coils coated with anit-coking film in an ethylene cracking plant. Engineering Failure Analysis 2014, 39, 181-187. (15) van Haandel, L.; Bremmer, G.; Hensen, E.; Weber, T., Influence of sulfiding agent and pressure on structure and performance of CoMo/Al2O3 hydrodesulfurization catalysts. Journal of Catalysis 2016, 342, 27-39. (16) Trimm, D. L.; Turner, C. J., The pyrolysis of propane. II. Effect of hydrogen sulphide. Journal of Chemical Technology and Biotechnology 1981, 31, (1), 285-289. (17) Yuan, B.; Li, J.; Du, W.; Qian, F., Study on co-cracking performance of different hydrocarbon mixture in a steam pyrolysis furnace. Chinese Journal of Chemical Engineering 2016, 24, (9), 1252-1262. (18) Pakdehi, S. G.; Babaee, S.; Azizi, H. R., Kinetic Study and Optimization of Dehydration of Dimethyl Amino Ethyl Azide (DMAZ) Using Response Surface Methodology. Bulletin of the Chemical Society of Japan 2017, 90, (12), 1325-1332. (19) Kolts, J. H., Heterogeneous and homogeneous effects of hydrogen sulfide on lighthydrocarbon pyrolysis. Industrial & engineering chemistry fundamentals 1986, 25, (2), 265269. (20) Schädel, B. T.; Duisberg, M.; Deutschmann, O., Steam reforming of methane, ethane, propane, butane, and natural gas over a rhodium-based catalyst. Catalysis today 2009, 142, (1-2), 42-51. (21) Albright, L. F.; Marek, J. C., Mechanistic model for formation of coke in pyrolysis units producing ethylene. . Ind. Eng. Chem. Res. 1988, 27, (5), 755−759. (22) Su, L.; Tang, L.; Grossmann, I. E., Scheduling of cracking production process with feedstocks and energy constraints. Computers & Chemical Engineering 2016, 94, 92-103.


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

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Tables:

Table 1: Composition of disulfide oil (DSO) Compositions

Value (wt. %)

Dimethyl disulfide (DMDS)

10.38

Ethyl methyl disulfide (EMDS)

39.32

Diethyl disulfide (DEDS)

49.26

H2S

0.002

CH4

0.0001

C3H8

0.0001

Carbon Disulfide

0.001

Carbonyl Sulfide

0.001

Methyl-Mercaptan

0.003

Ethyl-Mercaptan

0.003


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Table 2: The composition and properties of the applied crude oil. Component kg/hr. Aromatics Naphthene Olefin Paraffin Iso-paraffin Average total sulfur Average density

Mixture Wt. %

1689.4 8412 2164.2 35922.53 56908.87 200 ppm 642 (kg/m3)


1.60 8.00 2.06 34.18 54.15

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Table 3: Experimental range and levels of independent variables. Levels Factors

-α

-1

+1

+α

DSO injection (kg/hr)

A

2

3.62

8.38

10

Retention Time (s)

B

4

5.22

8.78

10

Temperature (C)

C

725 755.40

844.6

875


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Table 4: CCD perposed expriments condition and its responses. A B C Run Response (CO) DSO injection Retention time Temperature No. (ppm) (kg/hr) (s) (ᵒC) 1 6.00 7.00 800.00 357 2 3.62 8.78 844.60 405 3 10.00 7.00 800.00 407 4 6.00 7.00 875.00 375 5 6.00 7.00 800.00 350 6 3.62 8.78 755.40 413 7 6.00 7.00 800.00 352 8 8.38 5.22 755.40 413 9 3.62 5.22 844.60 415 10 6.00 7.00 800.00 351 11 8.38 8.78 755.40 395 12 3.62 5.22 755.40 403 13 6.00 10.00 800.00 364 14 6.00 4.00 800.00 400 15 8.38 5.22 844.60 410 16 8.38 8.78 844.60 369 17 6.00 7.00 725.00 405 18 2.00 7.00 800.00 435 19 6.00 7.00 800.00 345 20 6.00 7.00 800.00 355


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Table 5: H2S production per kilogram of component Component

H2S production (g)

DMDS

723

DEDS

577

EMDS

723

DSO

619


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Table 6: Kinetics data for reaction rates of coke formation (reference 21) E (kJ/mol)

K800˚C (m3/kmol s)

C6H6+H.→C6H5.+H2

67

1.37×103

C6H6+CH3.→C6H5.+CH4

63

1.71×106

C6H5. +CH2=CH2→C6H5-CH2CH2.

30.13

3.24×106

H2S+H.→HS.+H2

7.16

3.50×109

H2S+CH3.→HS.+CH4

16.6

62.2×106

C6H6+HS.→C6H5.+ H2S C6H5.+CH2=CH2→C6H5-CH2CH2. C6H5.+HS.→C6H5SH C6H5SH+H.→C6H5S.+H2

30.13

3.24×106

13.3

2.93×109

0.2

3.89×109

Reaction

C5H5S.+CH2=CH2→C6H5-SCH2CH2


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Model A B C AB AC BC A2 B2 C2 Residual Lack of Fit. Pure Error Cor. Total

Table 7: Analysis of variance results for the proposed model. Sum of p-value df Mean F-value Squares (Prob> F) significant 14787.85 9 1643.094 60.60753 < 0.0001 676.0947 1 676.0947 24.93858 0.0005 1046.427 1 1046.427 38.59873 < 0.0001 416.8803 1 416.8803 15.37714 0.0029 435.125 1 435.125 16.05012 0.0025 136.125 1 136.125 5.021137 0.0489 231.125 1 231.125 8.525328 0.0153 9023.842 1 9023.842 332.8554 < 0.0001 1818.972 1 1818.972 67.095 < 0.0001 2850.144 1 2850.144 105.131 < 0.0001 271.1039 10 27.11039 not significant 183.7706 5 36.75412 2.104244 0.2168 87.33333 5 17.46667 15058.95 19


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Energy & Fuels

Table 8: Result of replacing DMDS with DSO in one year Consumption (kg per year)

Cost price of one kg (EUR)

Total cost per year (EUR)

DMDS

80000

3.21

256800

DSO

160000

0.22

35200

Injected substance


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

Figure Caption:

Fig.1: The layout for overall steam cracker unit. Fig.2: Effect of DMDS and DSO injection on the CO production in a furnace cracker. Fig. 3: DMDS and DSO injection versus Total sulfur in gasoline attemperature of 700 °C and residence time of 10 s. Fig. 4: 3D-Response surface graph for interactions between retention time and DSO injection. Fig. 5: 3D-Response surface graph for interactions between temperature and DSO injection. Fig.6: 3D-Response surface graph for interactions between retention time and temperature. Fig.7: Relationship between predicted and experimental data.


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Energy & Fuels

Fig 1.


Energy & Fuels

1000 DSO

CO Production (ppm)

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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DMDS

800 600 400 200 0 0

1

2

3

4

5

6

Injection (kg/hr)

Fig 2.


7

8

9

10

Page 27 of 31

140 DSO 120

Total sulfur (ppm)

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

DMDS

100 80 60 40 20 0 0

1

2

3

4

5

6

7

Injection (kg/hr)

Fig. 3.


8

9

10

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

Fig.4:


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Fig.5:


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Fig.6:


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Fig. 7


New design and optimization for replacing dimethyl disulfide with

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