What Is Behind the High Values of Hot Filtration Test of the Ebullated

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What is behind the high values of hot filtration test of the ebullated bed residue H-Oil hydrocracker residual oils? Dicho Stoyanov Stratiev, Rosen Dinkov, Ivelina Kostova Shishkova, Ilshat Mirgazianovich Sharafutdinov, Natalia Toshkova Ivanova, Magdalena Sabeva Mitkova, Dobromir Ivanov Yordanov, Nikolay Rudnev, Kiril Stanulov, Alexander Artemiev, Irina Barova, and Borislav Chushkov Energy Fuels, Just Accepted Manuscript • Publication Date (Web): 04 Aug 2016 Downloaded from http://pubs.acs.org on August 4, 2016

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What is behind the high values of hot filtration test of the ebullated bed residue H-Oil hydrocracker residual oils? Dicho Stratiev1, Rosen Dinkov1, Ivelina Shishkova1, Ilshat Sharafutdinov1, Natalia Ivanova2, Magdalena Mitkova2, Dobromir Yordanov2, Nikolay Rudnev3, Kiril Stanulov4, Alexander Artemiev5, Irina Barova5, Borislav Chushkov6 1

LUKOIL Neftohim Burgas, Bulgaria

2

University “Prof. Dr. Assen Zlatarov”, Burgas, Bulgaria

3

Ufa State Petroleum Technical University, Ufa, Russia

4

University of Chemical Technology and Metallurgy, 1756 Sofia, Bulgaria

5

Kazan National Research Technological University, Petroleum and Petrochemistry Department, 420015 Kazan, Russia

6

University of Calgary, Department of Chemical Engineering 2015 University drive N.W. Calgary, Canada

Abstract This paper summarizes the results of multiple experiments performed in the LUKOIL Neftohim Burgas Research laboratory related to the issue of high values of hot filtration test (HFT) of the residue H-Oil hydrocracking residual oil products. After the start-up of the new residue H-Oil hydrocracker in the LUKOIL Neftohim Burgas refinery during the second half of 2015 the values of the HFT of the vacuum tower bottom product varied between 0.01 and 8.7%. It was found that the vacuum residual oil feed source has a profound effect on the processes of sedimentation in the H-Oil hydrocracker. The processing of vacuum residual oils from Arab Medium, Arab Heavy, and Basrah Light crudes reduces the sedimentation and allowed achievement of a higher conversion. The asphaltenes from all studied feeds decreased their H/C ratio after hydrocracking. However the decrease of the H/C ratio was the least pronounced with the Basra Light asphaltenes, while the asphaltenes from the vacuum residual oils originating from the crudes Urals, and El Bouri became with a much lower H/C ratio. The maltene fraction H/C ratio could become lower, the same, or higher after hydrocracking depending on the feed source, catalyst metal (vanadium) loading, or the hydrocracking unit (commercial, pilot plant, or laboratory unit). It was found that after addition of high aromatic fluid catalytic cracking gas oils the H-Oil residue HFT dropped and the dependence of the residue HFT on the concentration of FCC gas oils in the blend could be approximated by a third order polynomial. Correlations were developed to predict the H-Oil based residual fuel oil HFT from information of the base H-Oil residue HFT and the amount of added FCC gas oil. The treatment of the H-Oil residual oils with commercial HFT reducers may decrease the residual oil HFT. However, the efficiency in HFT reduction turned out to depend on the nature of the H-Oil residue and on the concentration range of the HFT reducing additive. From all studied additives solely the dodecylbenzene sulfonic acid was capable of reducing the H-Oil residual oil below 0.1%. However the treatment rate of the DBSA was an order higher than that of the commercial additives A, B, and C. DBSA was an order of magnitude

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more effective in reduction total sediment existent, and total sediment potential than the FCC HCO.

Key words: H-Oil residue hydrocracking, residual oil sediment content, colloidal stability, HFT reducers, dodecylbenzene sulfonic acid. 1. Introduction The continuous decrease in the heavy fuel oil demand worldwide makes refiners search for ways to reduce or even exclude the production of heavy fuel oil [1]. The transition of the low conversion visbreaking process to the higher conversion coking (delayed and fluid coking) or hydrocracking seems to be the right technological solution to diminish or even exclude the production of heavy fuel oil. After a comprehensive evaluation of seven processing schemes for higher conversion of vacuum residual oils which included the processes: Flexicoking, Delayed coking, Vacuum residue solvent deasphaltization, Gasification, VRDS, Hydrocracking in fixed bed - Hycoon, and ebullated bed residue (EBR) hydrocracking a decision was made to select the EBR H-Oil process as the most appropriate high residue conversion process for the LUKOIL Neftohim Burgas (LNB) refinery [2]. The LNB H-Oil ebullated bed residue hydrocracker was put in operation in the second half of 2015. The startup process of the H-Oil complex was accompanied by a lot of technical problems. Failures in main pieces of equipment like recycle treat gas compressors, feed pumps, washing water pumps, fuel gas compressors and many others were prevalent during the start-up process which lasted almost three months. During this period the H-Oil unit was stopped several times to solve the technical issues. Frequent appearing of leakages was also nightmare for the operating personnel of the H-Oil complex. After solving all these technical issues another problem based on the heavy oil chemistry appeared – oil incompatibility between the remaining visbreaker residue based fuel oil and the new H-Oil unconverted vacuum residue based fuel oil. It was found that the heavy fuel oil based on the visbreaking process and the one based on the EBR H-Oil hydrocracking were incompatible [3]. After a period of a month of stable operation of the new H-Oil hydrocracker when in the LNB refinery crude oil blend consisting of the crude oils Urals (Russia origin) – El Bouri (Libya origin) – Kazakh crude (Kazakhstan) – Vald’Agry (Italy) was processed the sediment content (hot filtration test) of the H-Oil unconverted vacuum residue increased from 0.001 to 5.6% (Figure 1). As a result of the higher sediment content in the H-Oil vacuum tower bottom (VTB) product the bottom pumps of the vacuum tower became incapable of pumping the product due to formation of deposition on the line between the vacuum tower bottom and the pumps. The vacuum tower was shut down for cleaning for a period of two weeks after only of a month and a half of operation. Then a decision was made in the refinery to process only one crude - Urals (Russia origin) till the issue with the higher sediment content in the H-Oil unconverted vacuum residue was resolved. In early November 2015 the LNB H-Oil unit processed vacuum residual feedstock originating from Urals crude oil and imported atmospheric residue. The severity in the unit was increased to reach the design conversion of 70% and the sediments in the unconverted vacuum tower bottom (VTB) product overshoot the value of 8% at a conversion of about 65% (Figure 1). After this extremely high sediment level in the VTB product the vacuum column was stopped again for cleaning.


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It is well documented that in residue hydroconversion processes sediment formation limits conversion level and shorten on-stream factor [4-19]. Sedimentation is still difficult to define, and regardless of the achieved progress in understanding the foundation of the sediment formation during residue hydroconversion it is still difficult to quantitatively predict it in a commercial scale. It is known that the hydroconversion process modifies the solvent power of the residual oil maltene fraction while the unconverted asphaltene cores after cracking become more aromatic and condensed [7]. The solvent power of the maltenes decreases, while unconverted asphaltene cores after cracking become more aromatic and condensed. All these changes induce the precipitation of the most aromatic and condensed molecules out of solution [7]. Addition of high aromatic fluid catalytic cracking (FCC) gas oils to the EBR feedstock increases the solvent power of the maltene fraction and in this way retards the process of sedimentation and allow achievement of a higher conversion and/or longer cycle length between two consecutive cleanings [5,6, 17]. Quality of the feedstock was also reported to affect sedimentation during residue hydroconversion [7]. In late November 2015 the feed mix to the LNB H-Oil unit included Heavy and Medium Arab crudes. Later Basrah Light vacuum residue was also added to the feed blend that was processed in the LNB H-Oil hydrocracker. A lower sedimentation in the H-Oil unit was registered during processing of theses crudes. A lot of samples from vacuum residual oil feed, atmospheric tower bottom (ATB), vacuum tower bottom (VTB), and finished fuel oil were examined in the LNB Research Laboratory with the aim to reveal what is behind the high hot filtration test (HFT) values of the H-Oil residual oils. In this work the relationships of the LNB H-Oil VTB sediment level (HFT) to the H-Oil atmospheric residue HFT, FCC gas oils dilution rate, HFT commercial reducers rate, and HFT after artificial thermal and chemical aging were investigated. The aim of this paper is to discuss the results of the study.

2. Experimental 2.1. Materials Eight vacuum residual oils, obtained from the crudes Urals, El Bouri, Kazakh, Vald’Agri, Arab Medium, Arab Heavy, Basrah Light, and from imported atmospheric residue, were processed in the LNB H-Oil hydrocracker during this study. Physical and chemical properties of these vacuum residual oils are summarized in Table 1. SARA composition and element composition of the SARA fractions of the studied vacuum residual oils are presented in Table 2. Fluid catalytic cracking gas oils with properties given in Table 3 were used as diluents to reduce the H-Oil VTB sediment level. Three commercial HFT (hot filtration test) reducers, and dodecyl benzenesulfonic acid (DBSA), known also as asphaltene stabilizer [20-23] were also tested in this study. They were labeled A, B, C, and DBSA. Table 4 presents some information about the chemical nature of the additives used in this study. Additives A, B, and C are asphaltene dispersants. More details about additive B and the way how it acts can be found in [24]. The DBSA used in this study was 4- dodecyl benzenesulfonic acid (C18H30O3S) a mixture of isomers ≥ 95%. It was supplied by Sigma-Aldrich. 2.2. Procedures The investigation was performed at the LNB EBR H-Oil hydrocracker. A simplified process diagram of the LNB EBR H-Oil hydrocracker is presented in Figure 2. Details about the


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LUKOIL Neftohim Burgas H-Oil residue hydrocracker are given in [25]. The typical operating conditions of the LNB H-Oil residue hydrocracker are summarized in Table 5. The 540°C+ conversion was estimated by the equation:

Conversion (% ) =

EBRHCFeed540°C + − EBRHC Pr oduct540°C + × 100 EBRHCFeed540°C +

eq. (1)

where, EBRHCFeed540°C+ = weight of the EBRHC feed fraction boiling above 540°C, determined by high temperature simulated distillation, method ASTM D 7169; EBRHCProduct540°C+ = weight of the EBRHC product fraction boiling above 540°C, determined by high temperature simulated distillation, method ASTM D 7169. 2.3.

Analyses

Samples of H-Oil ATB and VTB were analyzed for their total existent sediment content (TSE), total sediment potential (after thermal aging - TSP), total sediment accelerated (after chemical aging – TSA) in accordance with the procedures IP 375, and IP 390 Procedure A, and IP 390 Procedure B respectively. The precision of the measurement of TSE, TSP, and TSA expressed by the repeatability and reproducibility is summarized below:

r = 0.089 HFTRe sult

e

R = 0.294 HFTRe sult

q.(2) eq.(3)

where, r = repeatability; R = reproducibility; HFTResult = result from measurement of hot filtration test. TSE is equivalent to hot filtration test of the residue sample. The hot filtration test means that the residual oil sample is filtered through an apparatus (described in IP 375) with openings of the filter of 1.6 micrometers at 100°C, and after solvent washing and drying the total sediment on the filter is weighed, and is expressed as weight per cent of the residual oil sample. TSP is equivalent to hot filtration test of the residue sample that has previously stayed at 100°C for 24 hours. The TSA is equivalent to hot filtration test of the residue sample that has been previously diluted with hexadecane in the ratio 1 ml per 10 g of the sample under carefully controlled conditions, followed by storage for one hour at 100°C. The samples were analyzed for their SARA (saturates, aromatics, resins, asphaltenes) composition in accordance with the procedure, described in [26].


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The procedure for measuring the residual oil colloidal stability is summarized as follows: small aliquots of samples of the vacuum residual oils under study were made up into two toluene dilutions (75 % vol. and 25 % vol.) before being titrated with i-octane. The optically detected flocculation point (decrease in transmittance) was then used to calculate stability values for the sample. In essence, the method is a modification to ASTM D 7157-05 [27], as only two dilutions are required for determination of stability values, which are calculated as: S – Intrinsic stability (S-value) of the oil. This parameter is an indication of the stability or available solvency power of oil with respect to the precipitation of asphaltenes; Sa – The peptisability or ability of the asphaltenes to remain in colloidal dispersion. Sa is related to the solubility of the asphaltenes, the length and number of the aromatic chains; So – The peptising power of oil is the “aromatic” equivalent of the oil; it is a measure of the solvency power of the oil with respect to asphaltene solubility. The sediments level in the unconverted pyrolysis product was measured in accordance with the ASTM D4870 (Hot filtration test). The element composition of the investigated residual oils was measured in accordance with ASTM D-5291 for carbon, hydrogen, and nitrogen content, and ASTM D-1552 for sulfur content. The VRO Conradson carbon content was measured according to ASTM D-189. The content of toluene insolubles in the VTB samples was measured in accordance to ASTM D 4312 method. The ash content in the VTB samples was determined following the ASTM D 482 method.

3. Results and discussion 3.1. Characterization and colloidal stability of the vacuum residual oil feedstock properties Asphaltene content and stability were shown to be the residual feedstock parameters that best correlate with the tendency of a specific residual feedstock to form sediments during hydroconversion [7]. From the data in Table 2 one can see that the processed vacuum residual oils (VROs) in the LNB H-Oil hydrocracker differ significantly in their asphaltene content; from 2.8% in the Kazakh VRO to 19.8% in the Arab Heavy VRO. About the stability of the asphaltene fractions of the studied VRO feedstocks can be judged by the colloidal stability parameters measured in accordance with the ASTM D 7157 method. The data in Table 1 show that all studied VRO feedstocks are characterized by a very high colloidal stability (Svalue ˃ 2.7) and absence of any sediments measured by the three procedures IP 375, IP-390 (Procedure A – thermal aging), and IP-390 (Procedure B –chemical aging). The most stable VRO that is characterized by the highest S-value was Kazakh VRO with S-value of 4.264, while the least stable was El Bouri with S-value of 2.797. The highest colloidal stability of the Kazakh VRO was because of its high asphaltene solubility Sa = 0.84, while the least colloidal stability of El Bouri VRO was because of its low asphaltene solubility Sa = 0.69. The data about H/C atomic ratio of the asphaltene fractions shown in Table 2 indicate that the asphaltenes from Urals VRO have the highest H/C ratio (1.10), while the asphaltenes from the Vald’Agri VRO have the lowest H/C ratio (1.02). The maltene fraction H/C ratio is the lowest for the Arab Heavy VRO, while the highest is the H/C ratio of the maltenes of Kazakh VRO. The lower the H/C ratio, the higher its solubility parameter, and the lower its solubility is [28]. The higher the difference between the solubility parameters of asphaltenes and maltenes the


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lower the residual oil colloidal stability is [29]. The highest is the difference between the solubility parameters, estimated by the correlation of Rogel [28], of the asphaltenes and the maltenes of Kazakh VRO (Δ = 6.4MPa1/2), while the lowest is that of Basrah Light VRO (Δ = 4.4MPa1/2). Based on this perception one could expect the Kazakh VRO should be the least stable. On the other hand the Kazakh VRO exhibited the highest S-value. This is an illustration of the very complex nature of the residual oil colloidal stability. By application of different criteria for evaluation of residual oil colloidal stability one could obtain different rating. According to Gray a general principle for solubility relationships is that the solubility parameters of the solvent and the solute must be within 3 MPa1/2 of each other to achieve reasonable dissolution. Consequently, sediment can be expected when the solubility parameter of the residual asphaltenes rises to more than 3 MPa1/2 above that of the liquid phase in the reactor [29]. The measurement of TSE, TSA, and TSP of the straight run VROs showed absence (zero) of precipitate which does not support the statement mentioned above in our case. An interesting observation was registered during measurement of S-value of the Vald’Agri vacuum residue. The used apparatus could not register any value for the colloidal parameter S-value. Some oils as reported by Wiehe [30] do not contain insoluble asphaltenes. Therefore the asphaltenes in such oils would not flocculate regardless the addition of increased amount So , and in case of absence of insoluble of alkanes. Considering that S − value = 1 − Sa asphaltenes Sa =1 (complete dissolution of asphaltenes) then the denominator (1-Sa) equals to zero and the quotient (S-value) tends to infinity, and eventually no S-value can be registered. Based on this speculation one could assume that the Vald’Agri vacuum residue does not contain insoluble asphaltenes. On the other hand the data in Table 2 show that the asphaltenes from the Vald’Agri VRO have H/C ratio of 1.02 and this figure is the highest among all studied in this work straight run VROs. The H/C ratio of the maltene fraction of the Vald’Agri VRO is relatively low (1.51) compared to those of the maltene fractions of the other VROs (between 1.5 and 1.72). One could suggest that the low H/C ratio of the maltene fraction of the Vald’Agri VRO along with the low content of asphaltenes could contribute to stabilization of the asphaltenes to such an extent that the addition of alkane cannot disturb the asphaltene stability. 3.2.

Relationship between H-Oil ATB and VTB sediment content

Our previous experience with EBR hydrocracking ATB and VTB products sampled from a pilot ebullated bed residue H-Oil hydrocracker showed that the VTB product had a lower sediment level than the ATB product [31]. Contrary to our expectation the LNB H-Oil commercial unit exhibited that the VTB product had a higher sediment level than the ATB product as shown in Figure 3.The data from Figure 3 were taken from analyses of samples from the LNB H-Oil ATB, and VTB products. The analyses were performed in SGS Bulgaria laboratory, LNB Research Laboratory (RL), and two other West European laboratories. All data were consistent regardless of the place they were obtained and showed that the LNB H-Oil VTB TSE is about 1.6 times as high as that of the ATB. In order to eliminate the influence of more factors that could impact the VTB in the commercial unit a sample of H-Oil ATB was distilled in the LNB RL under vacuum according to ASTM D-1160 and the analyses of the TSE were following: ATB TSE = 0.49%; VTB TSE = 0.69%. These results are consistent with the trend of higher sediment level in the H-Oil VTB observed in the


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commercial LNB H-Oil unit. A higher H-Oil VTB TSE than the ATB TSE could mean that the sediments consist of hard organics and/or inorganics (catalyst dust). The analyses of toluene insoluble (TI) – an indicator for the hard organics, and the ash content – an indicator for the hard inorganics showed that TI ≈ 0.02%, and ash content ≈ 0.04%. This would mean that the contribution of toluene insolubles (hard organics) and the ash (hard inorganics) content to the H-Oil residual oil total sediment content is about 0.06%, and the remaining sediment content should be formed as a result of asphaltene aggregation and precipitation, since asphaltenes are known to be the major precursors of sediments in hydroprocessed residual oils [29, 32]. Taking into account the higher values of the HFT in the H-Oil residual oils one could conclude that the sediments were mainly formed from aggregation of the asphaltenes containing in the H-Oil residual oils, since the asphaltenes are concentrated in the VTB after evaporating the VGO from the ATB in the vacuum distillation column. Table 6 presents data of SARA composition and sediment content of ATB and of VTB sampled from the LNB H-Oil unit on 21.08.2015, and of another sample of H-Oil VTB taken on 28.07.2015. It is evident from these data that the higher the asphaltene content the higher the HFT of the H-Oil residual oils. It is also apparent that the VTB HFT sampled on the same date as the ATB (21.08.2016) had higher sediment content regardless that the colloidal instability index (CII) after removal of the higher saturate vacuum gas oil from the ATB dropped from 1.57 to 1.16 in the VTB. These data indicate that the saturate content does not have a discernible influence on the H-Oil residual oil sediment level. In order to examine the effect of high saturate content on the VTB sediment content both H-Oil VTB samples from 21.08.2015 and from 28.07.2015 were blended in a different ratio. Figure 4 presents in a graphical form the results of the HFT of the blends VTB (21.08.2015) – VTB (28.07.2015). These data indicate that the addition of the high saturate content VTB (28.07.2015) in amount between 20 and 30% to the high asphaltene, low saturate contents VTB (21.08.2015) leads to an increase of the sediment content from 1.6 to 1.98%. However, with the increase of the relative part of the high saturate content VTB (28.07.2015) in the H-Oil VTB blend the sediment level gradually decreases. The regression line in Figure 4 which connects the ultimate HFT values of the two H-Oil VTB samples (0.01 and 1.6%) is in fact the line of dilution of the high sediment, high asphaltene content VTB (21.08.1015) with the low sediment, low asphaltene content VTB (28.07.2015). It is evident from these data that at concentrations of 10%, and higher than 60% of the high saturate content VTB (28.07.2015) in the H-Oil VTB blend the measured VTB blend HFT values lie on, or are very close to the estimated regression line of the dilution. A conclusion could be made that at concentrations of the non-solvent high saturate content VTB (28.07.2015) in the H-Oil VTB blend in the range of 20 – 50% asphaltene aggregation and precipitation of the high asphaltenic VTB (21.08.2015) may occur. Figure 5 shows the relationship of the H-Oil VTB blend HFT to the VTB blend asphaltene content. These data clearly indicate that the asphaltene content of the H-Oil VTB is the main factor that controls the VTB sediments for the studied blend. Some slightly observable effect of association of asphaltenes a result from addition of the higher saturate content VTB could be distinguished. However, if the reproducibility limit of the method IP 375 is taken into account one can see that the difference between 1.61 and 1.98% is within this limit. These experimental data can explain why the removal of the higher saturate content VGO from the ATB does not decrease the HFT of the VTB. Instead it increases the HFT of the VTB due to the concentration effect of the asphaltenes, which turned out to have a much stronger effect on the sediment level in the LNB H-Oil residual oils than the removal of the saturate compounds.


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A correlation matrix of the data for SARA composition of 17 H-Oil VTB samples and one HOil ATB sample and the HFT (HFT for this data set of H-Oil residual oils varied between 0.01 and 4.0%) of these samples shows that the H-Oil residual oil HFT statistically meaningful correlates only with the asphaltene content (r=0.84) and the ratio asphaltene/(asphaltene+resins) (r=0.86) (Table 7). These data suggest that the increase of the H-Oil VTB and ATB asphaltene content and the ratio asphaltene/(asphaltene+resins) could lead to an increase of the sediment level in the H-Oil residual oils.

3.3.

Effect of the addition of high aromatic fluid catalytic cracking gas oils on H-Oil residual oil sediment content

Considering that the asphaltenes are the main factor controlling the HFT in the LNB H-Oil residual oils and that they are the most aromatic compounds and following the rule “like dissolves like” several samples of LNB H-Oil VTB having different sediment content were blended with FCC LCO, HCO, and slurry. Figure 6 shows that the addition of the high aromatic FCC HCO to the H-Oil VTB samples leads to a reduction of the HFT (TSE), that could be approximated by a third order polynomial. The data in Figure 6 also indicate that the higher the H-Oil VTB HFT the higher is the reduction effect of the FCC HCO on the HFT of the blend H-Oil VTB-FCC HCO. In the concentration range between 0 and 25% FCC HCO (75-100% H-Oil VTB) the dependence of the blend HFT on the FCC HCO could be approximated by a straight line. Figure 7 shows that the slope of the reduction of HFT a result of increasing the FCC HCO content in the range between 0 and 25% in the blend H-Oil VTBFCC HCO linearly increases with the increase of the H-Oil VTB HFT. The slope of reduction of the HFT beyond 25% FCC HCO content in the blend H-Oil VTB-FCC HCO is much lower and also can be approximated by a straight line to the point of 0.1% HFT. Figure 8 presents the dependence of the amount of FCC HCO that should be added above 25% in the blend HOil VTB-FCC HCO to the achievement of 0.1% HFT on the difference between HFT of the blend 75% H-Oil VTB / 25% FCC HCO and 0.1% sediment content. These data suggest that the required amount of FCC HCO which should be added to the H-Oil VTB to reach the specification of 0.1% HFT can be estimated from information about the H-Oil VTB HFT and the regression line equations depicted in Figures 7 and 8. Table 8 presents data about the H-Oil VTB samples used to prepare the graphs in Figures 6, 7, and 8. These data include information about the crude blend processed in the LNB refinery during production of these VTB samples, and the conversion level in the H-Oil unit, during sampling. They also include data for SARA composition, toluene insoluble content, ash and sulfur contents of the VTB samples. It is evident from these data that the highest sediment content (3.16%) is registered for the VTB sampled at the highest conversion (67.1). The lowest sediment content (0.23%), however, is registered for the VTB sampled not at the lowest conversion level (60.7%). This VTB sample (with HFT=0.23%) was not used to prepare the graphs in Figures 6, 7, and 8 because of the very low value of the HFT. The data in Table 8 indicate that crude slate has a profound effect on sediment content in the H-Oil VTB. The VTB sample obtained during processing of 25% Basra Light, has HFT = 0.47% and was sampled at conversion level of 65.0%, while at a bit lower conversion of 62.9% the VTB sample has a HFT = 2.16%. The latter was sampled during processing of a crude blend consisting of 54% Urals, 26.1% El Bouri, 1.9% Kazakh, 4.4% Vald’Agri, and 13.1%


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imported atmospheric residue. It is difficult to distinguish the contribution of each of the studied VROs to the sediment formation in the LNB H-Oil hydrocracker, since the H-Oil feed consisted of up to five different VROs. What is evident is that during processing of vacuum residual feed that contains vacuum resids from the crudes Basrah Light, Arab Medium, and Arab Heavy the sediment content in the LNB H-Oil hydrocracker VTB was lower. If we compare the VTB samples taken at conversions of 58.5% and 55.8.1% we can see that the VTB sediment content differentiate by a factor of four. The increase of the El Bouri content in the crude from 13.9 to 27.1% and the decrease of the Kazakh crude from 8.6 down to 2.0 has led to an increase of the sediment content from 0.41 to 1.60%, regardless of the lower conversion observed during processing the VRO feedstock that contained more El Bouri VRO. It should be considered here that the increased HFT of 1.60% was obtained during processing of a feed that also contained 4.6% Vald’Agri. If we also compare the VTB samples taken from the LNB H-Oil hydrocracker at the almost same conversions 62.7 and 62.9% we can see that the HFT differentiate by a factor of two (HFT from 1.1% to 2.16%). The difference in the feed blends is that at conversion of 62.7% the feed consists of 82% Urals, 7% imported AR, and 11% El Bouri, while at conversion of 62.9 the feed consists of 54.5% Urals, 13.1% imported AR, 26.1% El Bouri, 1.9% Kazakh, and 4.4% Vald’Agri. One could notice that the feedstocks that contain a higher relative part of VRO from El Bouri crude registered a higher sediment content in the VTB obtained from these feedstocks. However the presence, although at smaller concentrations of other VROs (from Vald’Agri, and Kazakh crudes) cannot allow to make a firm conclusion that processing of El Bouri crude in a higher amount is the only reason for the observed increased amount of sediments in the LNB H-Oil hydrocracker VTB. The data in Table 8 also indicate that the contents of toluene insoluble and of ash are pretty low and therefore the sediments in the VTB could be considered as formed by the presence of insoluble asphaltenes in the H-Oil VTB products. To better understand the effect of the different feeds on the sediment level of the unconverted H-Oil VTB we analyzed the operation of the LNB H-Oil hydrocracker during processing of three VRO feedstock blends: Feed blend 1 =56.6% Urals/27.1% El Bouri/2% Kazakh/4.6% Vald'Agri/9.7% Imported AR; Feed blend 2 = 56% Urals/ 24% Basrah Light/Imported AR; and Feed 3 = 100% Urals. It is evident from these data that during processing of Feed blend 1 the TSE increased from 0 to 1.7% at conversion level of the Feed blend 1 = 55.8%. It is also evident that the asphaltene H/C ratio decreased from 1.05 down to 0.86, while maltene H/C ratio increased from 1.6 up to 1.73. This means that while the asphaltenes become more aromatic the maltenes become more saturated, that could be seen from the SARA analyses of both Feed blend 1 and the VTB obtained from it. The difference between the solubility parameters, estimated by Rogel’s correlation [28], of the asphaltenes and the maltenes increased from 5.8 in the feed to 9.1 MPa1/2 in the VTB product. In that particular case the conversion of the asphaltenes was 70.4%. The amount of FCC HCO that should be added to the VTB from Feed blend 1 to reach the residual fuel oil specification of 0.1% sediments was 38%. During the processing of Feed blend 2 the TSE of the VTB product was 0.55% regardless that conversion was the highest among all studied LNB H-Oil feeds. It is interesting to note here that the asphaltene H/C ratio in the VTB product decreased less than that of the asphaltenes of the other VTB products obtained from the other feedstocks during hydroprocessing. The maltene fraction H/C ratio remained almost unchanged (between 1.53 and 1.54). In that case the difference between the solubility parameters of the asphaltenes and maltenes increased from 4.7 in the feed to 6.1 MPa1/2 in the VTB product and it was the


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smallest difference among all other studied hydroprocessing residual oils. This finding supports the common perception that the lowest the difference between H/C ratio (aromaticity), and consequently the solubility parameters of the asphaltenes and maltenes the lower the rate of sedimentation during hydroprocessing of residual oils. The processing of Basrah Light VRO allowed the LNB H-Oil hydrocracker to operate at a higher conversion without experiencing problems with excessive sedimentation. The conversion of the asphaltenes during processing the Feed blend 2 was 47.3%. The amount of FCC HCO that should be added to the VTB from Feed blend 2 to reach the residual fuel oil specification of 0.1% sediments was the lowest = 29% for the three studied feeds. During the processing of Feed 3 (100% Urals) at a conversion level of 65% an extremely high sediment content in the VTB product of 4.28% was registered. After this very high sediment content the vacuum tower from the LNB H-Oil hydrocracker had to be stopped for cleaning. The asphaltenes H/C ratio of the VTB from this feed dropped from 1.11 to 0.87, while the maltene H/C ratio remained almost unchanged, or slightly reduced (from 1.62 in the feed to 1.60 in the VTB product). The difference between the solubility parameters of the asphaltenes and maltenes increased from 5.4 in the feed to 7.6 MPa1/2 in the VTB product and was not the highest but the sediment level in the VTB product was the highest. Probably the high asphaltene content with the low H/C ratio of the asphaltenes and not sufficiently low H/C ratio of the maltenes could be considered responsible for the very high sediment content in that VTB product. The amount of FCC HCO that should be added to the VTB from 100% Urals VRO to reach the residual fuel oil specification of 0.1% sediments was the highest = 58% (This means that 58% of the blend H-Oil VTB consists of FCC HCO, and 42% of the blend is H-Oil VTB. In other words the amount of the diluent that is required to add is bigger than the amount of the produced VTB). Based on these data one could conclude that the sediment level in the hydroprocessed residual oils depends on the asphaltene content, asphaltene solubility (H/C ratio), and the maltene H/C ratio (solubility power). The VTB product from the VRO feed blend that contained Basrah Light VRO had the highest asphaltene H/C ratio, the lowest maltene H/C ratio and the highest asphaltene content. The VTB from the Feed blend 1 had the lowest asphaltene content, the lowest asphaltene H/C ratio, and the highest H/C ratio of the maltenes. This VTB did not have the highest sediment content probably because of the lowest asphaltene content. It is interesting to note here that during processing the Feed blend 1 the highest hydrogenation of the maltene fraction was registered. In this case it is difficult to understand whether this an effect of the feed properties, and the operation conditions (the lowest reaction temperature), or it is an effect from the highest catalyst hydrogenation activity due to the lowest metal (vanadium) content on the catalyst. From the available data it is difficult to explain why the Basra Light unconverted asphaltenes become less aromatic than the Urals unconverted asphaltenes during hydrocracking. Additional study is needed to find explanation of that observed phenomenon. From the feedstock characterization data available in this study it is difficult to predict the behavior of any VRO feedstock in the LNB H-Oil hydrocracker. The results from the characterization of the VROs in this work could not distinguish that the Basrah light VRO would allow achievement of higher conversion while retarding the process of sedimentation. Probably more sophisticated techniques like for example that reported by Rogel et al. [7] could allow a better differentiating of the behavior of the different VRO feedstock during hydroprocessing. In order to evaluate the efficiency of the reduction effect on the H-Oil residual oil HFT of the three FCC gas oils (LCO, HCO, and slurry) six H-Oil VTB samples having HFT (TSE)


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between 0.41 and 3.16% were blended with LCO, HCO, and slurry in concentrations of the FCC gas oils in their blends with the H-Oil VTB samples of 10, 30, and 50%. Table 9 summarizes the results of the analyses of the HFT of the studied H-Oil VTB-FCC gas oil blends. It can be seen from these data that in most of the studied cases the FCC HCO is the best diluent. However, if one takes into account the reproducibility limit for the IP 375 method he will see that most differences in the HFT of the blends with the three different FCC gas oils lie within this limit. Therefore it could not be concluded that there is a discernible difference in the efficiency between FCC LCO, HCO, and slurry concerning their reduction impact on the HFT of the H-Oil residual oils. Hong and Watkinson reported that solubility of asphaltenes increased monotonically with temperature over the range of 60 to 300°C [33]. Considering that the asphaltenes are the main contributor to sediment formation in the H-Oil residual oils we measured the HFT at two temperatures 100°C as per the requirements of IP 375 and 200°C. The results of this experiment are depicted in Figure 9. These data are in agreement with the statement of Hong and Watkinson that asphaltene solubility increases with the increase of the temperature. The data generated in this work suggest that sediments in the LNB H-Oil residual oils are mainly a result from asphaltene aggregation, since as evident from the data in Tables 8 and 9 the contributions of the toluene insolubles and of the ash content to the total sediment content are negligible. Quantitative relations between H-Oil VTB HFT and the required amount of high aromatic FCC gas oils to produce fuel oil with HFT not higher than 0.1% were developed. However, the fuel specification besides the property TSE includes also the properties TSP, and TSA. For that reason 23 samples of fuel oils produced from the H-Oil VTB and H-Oil VTB themselves were subject of IP 375 and IP 390 procedures to measure the existent total sediments (TSE) and the total sediments potential (TSP = thermal aging). The results of TSE and TSP measurements are depicted in Figure 10. It is evident from these data that TSP is about 2.5 times as high as the TSE. Therefore to produce H-Oil based fuel oil having TSP not higher than 0.1% would require the TSE to be not higher than 0.04%. Figure 11 presents a graph of the relationship between the TSE and TSA of H-Oil based residual fuel oils. These data indicate that TSA is about 1.3 times as high as the TSE. Comparing the data from Figures 10 and 11 one can see that the TSP is about twice as high as the TSA. The reason of lower chemical aging HFT (TSA) could be the high saturates content in the H-Oil based residual fuel oils. As saturates take already an important part in the fuel oil, when cetane (hexadecane) is added for accelerating aging according to chemical IP390 method, the effect of cetane is not significant as total saturates (cetane included) content is not changed significantly. The higher TSP than the TSE might come from possible oxidation reactions which may take place during the H-Oil residual oil stay at 100°C for 24 hours during the thermal aging procedure. The oxidation of bitumen at low temperature was reported to increase bitumen viscosity a result from a change in the effective volume of solvation of the aggregated species [34, 35]. The increased viscosity was correlated to the formation of carbonyl (C=O) and sulfoxide (S=O) functional groups in the bitumen [36]. In order to verify this option four HOil residual oils were examined for their viscosity variation after thermal aging. Properties of the four examined H-Oil residual oils are presented in Table 11. These data indicate that for two samples the TSP is about three times as high as the TSE (partially blended fuel oil from 100% Urals VRO, and 65% conversion; and fuel oil from 95% Urals/5% Kazakh at 58% conversion), and for the other two samples the TSP equals to TSE (the one prepared from 70% VTB obtained during hydrocracking of 100% Urals at 70% conversion in an EBR


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hydrocracking pilot plant, and 30% FCC HCO; and the second fuel oil obtained during hydrocracking of the VRO feed 58.8% Urals/ 25.2% Basrah Light/ 16% Imported AR). The kinematic viscosities of the two H-Oil residual oils, which have about three times as high TSP as the TSE, after thermal aging are lower than those before aging, which does not support the hypothesis of occurrence of low temperature oxidation reactions during performance of the thermal aging procedure. The other two H-Oil residual oils (the one prepared from 70% VTB obtained during hydrocracking of 100% Urals at 70% conversion in an EBR hydrocracking pilot plant, and 30% FCC HCO; and the second fuel oil obtained during hydrocracking of the VRO feed 58.8% Urals/ 25.2% Basrah Light/ 16% Imported AR) practically did not show any change in the viscosity before and after thermal aging. These facts suggest that, if any oxidation reactions take place during the performance of the thermal aging procedure, they are at a very small scale, and difficult to substantiate. These data also indicate that the feed and the environment where the hydrocracking takes place have a profound effect on sediment level in the finished fuel oil. The fuel oil prepared from the pilot plant VTB originating from 100% Urals VRO converted at 70% in the pilot plant has no sediments. Its asphaltene H/C ratio of 0.88 is very close to the commercial scale asphaltene H/C ratio obtained from Urals crude. However, the maltene H/C ratio of 1.48 is the lowest among all studied residual fuel oils in this work. The fuel oil obtained during hydrocracking of the VRO blend 58.8% Urals/ 25.2% Basrah Light/ 16% Imported AR has the asphaltenes with the highest H/C ratio (0.99) and low maltene H/C ratio (1.50). This again supports the statement that the higher the asphaltene H/C ratio and the lower the maltene H/C ratio, the lower the sediment content in the hydroprocessed residual oils is. The sediments in the residual oils could be considered a result from formation of aggregates of complex structuring units [37, 38]. The complex structuring units are postulated to consist of a nuclei of associated asphaltenes surrounded by an adsorption layer of resins and aromatic compounds [37, 38]. The radii of both associated asphaltenes and the adsorption layer could be different and they can vary depending on the conditions on which the residual oil is exposed [38]. A smaller radius of the asphaltene core and a bigger radius of the adsorption layer retard the process of a further agglomeration of the complex structuring units and an increase of the HFT [38]. In the opposite a bigger radius of the asphaltene nuclei and a smaller radius of the solvated layer contribute to the process of agglomeration of the complex structuring units and consequent increase of the HFT. The 24 hours stay of the H-Oil residual oil at an elevated temperature of 100°C during the thermal aging may allow some dissolution of the adsorption layer, leading to a reduction of its thickness that may contribute to the process of a further agglomeration of the complex structuring units and increase of the HFT. This might be the possible explanation of the increase of HFT after the thermal aging (TSP). In order to evaluate how the HFT of the H-Oil residual oils varies with the course of time and whether the TSP procedure simulates the actual residual oil aging five H-Oil residual oil samples were subject of TSE and TSP measuring for a period between one and five months. In order to compare the HFT variation with time of the H-Oil residual oils with a residual oil from vacuum residue visbreaking (VB) a sample of VB residual oil was also subject of measuring the TSE and TSP after 24 months. It should be mentioned here that all examined residual fuel oil samples were stored in a laboratory at ambient temperature of 25 ±3°C. The results of this study are presented in Figures 12a and 12b. These data show that the H-Oil residual oils do not change their TSE with the course of time. However, for one of the H-Oil residual oil sample an increase of the TSP with time was observed. This sample was finished fuel oil, produced from 65% H-Oil VTB and 35% FCC LCO, HCO, and slurry. The H-Oil VTB was obtained during processing of vacuum residue distilled from a crude oil blend


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consisting of 95% Urals crude and 5% Kazakh crude, and the conversion level in the LNB HOil hydrocracker was between 55 and 60%. 3.4.

Effect of addition of commercial HFT reducers to H-Oil based residual fuel oils

The sample of finished H-Oil based residual fuel oil obtained during processing the crude oil blend 95% Urals / 5% Kazakh was subject of measurement of TSE, and TSP within 140 days and this fuel oil sample was treated with a commercial HFT reducing additive. The results of this experiment are presented in Figure 12. These data indicate that no difference in the fuel oil TSP was observed for the first 30 days of the study (0.15 and 0.18% TSP). However, at the end of the 60th day study (the 52th and the 59th days) the TSP grew up to 0.46 and 0.52% respectively. On the 135th day of the study the TSP was 0.47%. The difference in the TSP at beginning and at the end of the period of 135 days amounts of 0.37%, which is three times as high as the reproducibility limit of 0.11%.Unlike the TSP, the TSE of this fuel oil sample varied within reproducibility limit for HFT. These data confirm the earlier conclusion that the TSE of the studied LNB H-Oil residual oil samples does not change with time. It is difficult to find a reasonable explanation for the increase of the thermal aged fuel oil HFT with the course of time. Interestingly the addition of the commercial HFT reducer A to the fuel oil at the 59th day decreased the TSP from 0.51 down to 0.2%. In other words it seems that the HFT reducer A may retard the process of evolution of the aggregation. However, 0.2% TSP is not lower than the TSP value of 0.15% on the day one of this study. That was the reason for us to make additional measurements of the HFT of other H-Oil residual oil samples with this reducer and two other HFT reducing additives. Figure 14 shows the effect of the use of three commercial HFT reducers on H-Oil VTB HFT (TSE). These data show controversial results about the decreasing effect of the additives on the H-Oil VTB TSE level. Additive B reduced the TSE of the H-Oil VTB sample having HFT=2.7% (this was the sample obtained at 62.9% conversion during processing 54.5% Urals, 26.1% El Bouri, 1.9% Kazakh, 4.4% Vald’Agri, and 13.1% imported AR (see Table 8)), from 2.7 down to 0.33% in the concentration range 0 – 3000 ppm. The increase of the additive concentration beyond 3000 ppm (4000, 5000, 6000, and 7000 ppm) however recovered the higher level of TSE up to 2.5%. It should be noted here that the initial TSE of the untreated VTB sample was 2.16% (see Table 8). However after a month of stay at ambient laboratory conditions (temperature = 25±3°C) the measured TSE was recorded at 2.7% before the treatment of this VTB sample with the additive B. Based on these results a conclusion could be made that the additives have an optimum concentration range of application. Below or above this concentration range an improvement in the fuel oil HFT may not be observed. Additive B is a substitute for the natural resins [24]. It works by surrounding the asphaltene molecules, similar to the natural resins. The critical resin concentration is shifted to a higher level, resulting in a more stabilised asphaltene solution. This keeps the hydrocarbons in a colloidal system and the asphaltenes in a disperse phase to prevent fouling and plugging [24]. The mechanism to control asphaltenes is to inhibit their growth by stabilizing the colloidal suspension of the sub-micrometer asphaltene particles to significantly slow the flocculation and settling processes. Some dispersants are capable of slowing or stopping the flocculation and the growth. More about the mechanism of inhibition of the process of asphaltene aggregation, and precipitation by addition of dispersants having different chemical nature can be found in [22]. Another H-Oil VTB sample having HFT=1.60%, that was the sample obtained during processing of Feed blend 1 from Table 9 (Feed blend 1 =56.6% Urals/27.1% El Bouri/2% Kazakh/4.6% Vald'Agri/9.7% Imported AR) was treated with the HFT reducers A and C in the concentration range of the additives 0-4000ppm. In this concentration range the HFT dropped from 1.60 down to 0.16%. No difference in the action of both HFT reducers (A and


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C) on this H-Oil VTB sample can be seen. As evident from the data in Table 4 the additives A, C, are antifoulants whose action could be explained by keeping the residual fuel oil in a colloidal system and the asphaltenes in a disperse phase preventing from further agglomeration. Additive A was also used to treat a H-Oil VTB sample having HFT = 0.46% (that sampled was obtained during processing the VRO feed consisting of 56.8% Urals, Arab Medium 6.7%, Arab Heavy, and 24.2% imported AR, at conversion level of 60%). The treatment rate was from 0 to 1000 ppm. No effect of reduction of this H-Oil VTB sample was registered as evident from the data in Figure 14. These data suggest that the reduction effect on HFT (TSE) by the use of HFT reducing additive depends on the H-Oil residual oil sample itself, and on the concentration range of the additive. Hashmi and Firoozabadi in their study [39] confirmed that the different oil composition affects the process of asphaltene aggregation, and ultimately their sedimentation out of suspension. Therefore the H-Oil residual oils obtained by hydrocracking of VROs originating from different crudes could be expected to behave in a different way during treatment with asphaltene dispersants. In order to evaluate the efficiency of using HFT reducer additive B, and DBSA to decrease sediment content in a H-Oil residual oil the partially blended fuel oil (PBFO) (100% Urals at 65% conversion) with properties (TSE=1.19%) shown in Table 11 was treated with additive B, and DBSA. The effect of treatment with additive B, and DBSA on the PBFO TSE level is presented in Figure 15. These data show that similar to the treatment of the VTB with TSE = 2.7% with additive B the TSE initially decreases reaching the value of 0.15% at 2000 ppm and then starts increasing with further enhancement of the treatment rate. In this case the optimum treating rate is 2000 ppm, while in the case of the VTB with TSE = 2.7% the optimal treating rate was 3000 ppm. This indicates that the optimal concentration of the additive is specific with respect to the H-Oil residual oil sample composition, and properties. The action of the DBSA differs from that of the additive B. Initially with enhancing of the DBSA concentration to 2% in the blend PBFO-DBSA the TSE increases, and then with further increasing the DBSA concentration the PBFO decreases, reaching 0.04% at 4% concentration of the DBSA. This finding is in line with the results reported by Goual and Firoozabadi [20] who showed that the amount of precipitated asphaltene increased first with increasing DBSA concentration. Beyond a certain concentration, there was a decrease in precipitation [20]. As far as the TSP of the PBFO treated with additive B and DBSA is concerned Figure 16 presents graphs of the effect of treating on the PBFO TSP. These data indicate a completely different behavior of the additive B and the DBSA. While the TSP is decreasing with the increase of the DBSA and reaches 0.09% at 4% DBSA in the blend PBFO-DBSA, that is lower than 0.1%, the TSP is continually increasing with the enhancement of the additive B treating rate reaching the extremely high TSP of 6.35% at 2000 ppm concentration. This suggests that both additives B, and DBSA may act in a different way. In order to understand whether the additives B, DBSA, and the FCC HCO could interfere with the phase separation processes of the asphaltenes, or inhibit growth by stabilizing the colloidal suspension of the asphaltene particles to slow the flocculation and settling processes measurement of the colloidal stability parameters S-value, Sa, and So of the PBFO with properties shown in Table 11 was performed. These data indicate that with all three additive B, DBSA, and the FCC HCO no significant improvement in the S-value is observed. The intrinsic stability test (ASTM D 7157) conditions with addition of heptane is quite a severe destabilizing condition and because of the sensitivity of the optic probe, it can detect asphaltene agglomerations at a very early stage. The standard test uses a 960nm light source which should have a detection resolution of about 500nm particles. Asphaltene stabilisers can slow down the rate of agglomeration of asphaltenes and stabilize particles. But this is difficult


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Energy & Fuels

to do in the very early stages of destabilisation. So having initial growth to a level where the probe detects asphaltenes agglomeration but then having a slower growth or stabilized system at or just above this particle size level is quite possible. However this is not measured by the probe, hence no apparent increase in stability. The fact that after addition of the additive B, DBSA, and the FCC HCO to the PBFO sample the S-value remains almost unchanged, or slightly improved suggests that the additive B, DBSA, and the FCC HCO may act as inhibitors which slow down the rate of agglomeration of asphaltenes and reduce the size of agglomerates to less than 1.6 microns which allows them to go through the filter openings. As far as the efficiency towards reduction of the TSE and TSP is concerned the data in Table 12 show that a residual H-Oil fuel oil having TSE, and TSP less than 0.1% can be obtained by addition of 45% FCC HCO, and an order of magnitude lower 4% DBSA to the PBFO. The additive B cannot attain this target with this H-Oil residual oil.

3.5.

Colloidal stability and propensity to formation of sediments in the ebullated bed residie hydrocracking

Wiehe postulated that the region of near incompatibility is when the ratio between solubility bending number and the insolubility number is less than 1.4 (especially less than 1.3) [40]. The ASTM D 7157 measured S-value actually presents the ratio between solubility bending number and the insolubility number [27]. That is why the LNB visbreaker unit (before startup of the new H-Oil residue ebullated bed hydrocracker) severity was controlled by measuring S-value of the unconverted visbroken residue [41]. The S-value minimum for the unconverted visbroken residue was set at 1.43, to provide stable and reliable production of finished fuel oil with sediment content lower than the specified 0.1%. Our earlier study has shown that S-value of the unconverted thermally cracked residue continually decreases with the increase of conversion [42]. In order to understand how the colloidal stability of the vacuum residue varies with variation of conversion laboratory ebullated bed hydrocracking experiments were carried out. Details of the procedure for performance of the laboratory ebullated bed hydrocracking experiments are given in [43]. Data of S-value reduction with increasing of conversion in the laboratory ebullated bed hydrocracking that processed vacuum residue from Urals crude are shown in Figure 17. It is evident from these data that at a conversion higher than 40% the unconverted vacuum residue has S-value lower than 1.3 and therefore falls in the colloidal instable region. This suggests that the operation of the ebullated bed residue hydrocracker at a higher conversion is associated with the production of colloidal instable unconverted vacuum residue. In order to understand what is behind colloidal instability of the H-Oil unconverted VTB product the ASTM D 7157 colloidal parameters Sa (asphaltene solubility) and So (maltene solubility power) along with H/C ratio in asphaltenes at the different conversion levels in the laboratory ebullated bed hydrocracking unit that processed vacuum residue from Urals were compared. Figure 16 shows how the parameters Sa, So, and the asphaltene H/C ratio vary with the increase of conversion. These data indicate that the increase of conversion in the laboratory ebullated bed hydrocracking unit leads to a reduction in the asphaltene H/C ratio (asphaltenes become more aromatic with the increase of conversion), and consequently to a reduction of asphaltene solubility (lower Sa). The data in Figure 18 also indicate that the maltene solubility power gets decreased with increasing of conversion. This would mean that the maltene fraction becomes richer of saturates. Indeed the data for SARA analysis of the feedstock Urals VRO and the unconverted VTB product at two conversion levels 55.0 and 72.9% exhibited that the increase of conversion was associated


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with an increase of content of saturates (maltene solubility power decrease) and a reduction of content of aromatics and resins (Table 5). It should be noted here that the highest value of HFT (3.92%) was registered for the VTB that did not have the highest asphaltene content (11.0%) but had the lowest H/C ratio (0.86) as evident from Figure 17. Therefore for the high values of the HFT in the H-Oil residual oils contribute not only the higher concentration of the asphaltenes but also their higher aromaticity (lower H/C ratio). The sediments obtained during the hot filtration of the laboratory VTB sample produced at 72.9% conversion (3.92%) were analyzed for their element composition. The element composition of the asphaltenes from the VTB sample and of the sediments are summarized in Table 14. These data show that the element composition of both samples is the same with the exception of the hydrogen content. The sediment sample had lower hydrogen content (5.7%) than that of the asphaltene sample (6.4%). These findings are in line with those reported by Garcıa and Carbognani showing that the solid deposits are selectively the more aromatic ones and hydrogen-deficient [44]. Therefore the increase of conversion in the ebullated bed residue hydrocracking leads to obtaining of asphaltenes with lower hydrogen content, which are less soluble, and more prone to form sediments. A conclusion could be made that the asphaltene content, and the asphaltene hydrogen deficiency along with the hydrogen content of the maltene fraction in the LNB H-Oil residual fuel oils seem to be the main factors which controlled the high values of the hot filtration test during this study. Additional investigations are needed to distinguish the role of all these three factors on the sediment formation in the H-Oil residual fuel oils.

4. Conclusions The process of sedimentation during ebullated bed hydrocracking of vacuum residual oils is a complex phenomenon involving a deterioration of colloidal stability of the unconverted vacuum residual oil which eventually leads to precipitation of the most aromatic species of the residual oil. During the ebullated bed hydrocracking some of the asphaltene fraction is converted, and the remaining unconverted asphaltenes become more hydrogen deficient (lower H/C atomic ratio). The maltene fraction could be hydrogenated and increase its H/C ratio, could remain with the same H/C ratio, or could reduce its H/C ratio. Depending on the feed source the extent of dehydrogenation of the asphaltene fraction could be different. The VRO EBR hydrocracking feed that contains Basrah Light VRO during hydrocracking its asphaltene fraction is dehydrogenated at a lower degree in comparison to the asphaltene fraction from Urals VRO and VRO feedstock that contains El Bouri VRO. The hydrogenation of the maltene fraction may depend on the catalyst activity (at lower vanadium content higher hydrogenation was registered), feedstock source (the feedstock that contained El Bouri VRO showed higher hydrogenation activity of the maltene fraction), and the conditions at which the hydrocracking takes place. In a pilot ebullated bed residue hydrocracking plant the hydrogenation of the maltene fraction of the Urals VRO was the lowest, while in a laboratory EBR hydrocracking unit the maltene fraction was characterized with a higher saturate content. The difference between asphaltene and maltene H/C ratio (solubilty parameters) confirmed to have an effect on the sediment content of the vacuum tower bottom product from the LUKOIL Neftohim Burgas H-Oil hydrocracker. The lower the difference, the lower the VTB sediment content is. The VTB obtained from a VRO feedstock that contained Basrah Light VRO was characterized with a low sediment content, regardless of the high conversion achieved during processing that particular VRO feedstock. This VTB had the lowest


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Energy & Fuels

difference between H/C ratio of the asphaltene and maltene fractions. The content of the asphaltene was also found to have an effect on the sediment content in the residual oils from the LNB H-Oil hydrocracker. The increase of asphaltene content and the ratio asphaltenes/(aromatics+resins) was to found to statistically meaningful correlated with the VTB sediment content. The LNB H-Oil VTB HFT is 1.6 times as high as the HFT of the ATB. The higher VTB HFT content seems to be due to concentration of asphaltenes in the VTB. The addition of high aromatic FCC gas oils (LCO. HCO, and slurry) to the H-Oil VTB reduces the values of HFT of the residual oils. No statistically discernible difference between the three FCC gas oils related to the efficiency of reduction of the H-Oil VTB HFT exists. The HFT value of the residual fuel oil can be predicted from information of the H-Oil VBT HFT and of the correlations developed in this work. The H-Oil residual oil thermal aging HFT (TSP) is about 2.5 times as high as the TSE, while the chemical aging HFT (TSA) is about 1.3 times as high as the TSE for most studied H-Oil residual oil samples. The mechanism of increasing the H-Oil residual oil sediment content after thermal aging is still unclear. The treatment of the H-Oil residual oils with commercial HFT reducers may decrease the residual oil HFT. However, the efficiency in HFT reduction turned out to depend on the nature of the H-Oil residue and on the concentration range of the HFT reducing additive. The same HFT reducer may have different optimal treatment rate when different H-Oil residual oils are treated. Unfortunately none of the tested commercial HFT reducers could decrease the H-Oil residual oil HFT (TSE) down to 0.1%. Solely the dodecylbenzene sulfonic acid was capable of reducing the H-Oil residual oil below 0.1%. However the treatment rate of the DBSA was an order of magnitude higher than that of the commercial additives A, B, and C. DBSA was an order of magnitude more effective in reduction TSE, and TSP than the FCC HCO. The reduction HFT effect of the additives, DBSA, and the FCC HCO could be ascribed to inhibition of agglomeration of asphaltenes and reducing the size of agglomerates to less than 1.6 microns which allows them to go through the filter openings, during the HFT measurement.

Reference (1.) Sykes L., Changes in Bunker Fuel Quality Impact on Global Markets, International BBTC 2015, Istanbul, 2015. (2.) Stratiev D. Vacuum residue hydrocracking an opportunity to survive and prosper in the modern oil refining business. Anniversary Scientific Conference with International Participation 60 Years UCTM, Sofia, Bulgaria, 2013. (3.) Stratiev, D.; Shishkova, I.; Nedelchev, A.; Nikolaychuk E.; Sharafutdinov, I.; Nikolova, R.; Mitkova, M.; Yordanov, D.; Belchev , Z.; Rudnev, N. Fuel Processing Technology 2016, 143, 213–218. (4.) Robert, E. C.; Merdrignac, I.; Rebours, B.; Harle, V.; Kressmann, S.; Colyar, J. Pet. Sci. Technol. 2003, 21, 615. (5.) Marafi, M.; Al-Barood, A.; Stanislaus, A. A. Pet. Sci. Technol. 2005, 23, 899. (6.) Ortega G.F., Mar-Juárez, E.; Hernández, P.H. Energy Fuels 2012, 26, 2948−2952. (7.) Rogel, E.; Ovalles, C.; Pradhan, A.; Leung, P.; Chen, N. Energy & Fuels 2013, 27, 6587. (8.) Stanislaus, A.; Hauser, A.; Marafi, M. Today 2005, 109, 167.


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(9.) Pang, W.; Kuramae, M.; Kinoshita, Y.; Lee, J.; Zhang, Y.Z.; Yoon, S.; Mochida, I. Fuel 2009, 88, 663–669. (10.) Sayles, S.; Ohmes, R.; Manner, R., PTQ, 2015, Q2, www.digitalrefining.com/article/1001077. (11.) Bedyk, I.; Colyar, J.; Skret, I.; Wisdom, L. 17th World Petroleum Congress, Rio de Janeiro, Brazil, 2002, WPC-32205. (12.) Respini, M.; Ekres, S.S.; Wright, B.; Žajdlík, R. PTQ 2013 Q2, www.digitalrefining.com/article/1000794. (13.) Sundaram, K.M.; Mukherjee, U.; Baldassari, M. Energy & Fuels 2008, 22, 3226–3236. (14.) Matsui, K Tonen General H-Oil & BTM Upgrading, Japan, 2007; http://www.pecj.or.jp/japanese/overseas/china/JCKoilmeeting2007/JCKoilmeeting20 071203/b-6.pdf. (15.) Introduction to VR HCR, Japan, 2011; http://www.pecj.or.jp/japanese/overseas/conference/pdf/conference06-15.pdf. (16.) Kunnas, J.; O. Ovaskainen, O.; Respini, M. Hydrocarbon processing 2010, Oct, 59-64. (17.) Marques, J.; Maget, S.; Verstraete, J.J. Energy&Fuels 2011, 9, 3867-3874. (18.) Bannayan, M.A.; Lemke, H.K.; Stephenson, W.K. Studies in Surface Science and Catalysis, 1996, 100, 273–281. (19.) Marchal, C.; Uzio, D.; Merdrignac, I.; Barre, L.; Geantet, C. Applied Catalysis A: General 2012, 411– 412, 35– 43. (20.) Goual, L.; Firoozabadi A. AIChE Journal 2004, 50 (2), 470-479. (21.) Hashmi, S. M.; Firoozabadi A. Journal of Colloid and Interface Science 2013, 394, 115–123. (22.) Kraiwattanawong, K.; Fogler, H. S.; Gharfeh, S. G.; Singh, P.; Thomason, W. H.; Chavadej, S. Energy & Fuels 2009, 23, 1575–1582. (23.) Hu, Y.F.; Guo, T. M. Langmuir 2005, 21, 8168-8174. (24.) Otzisk, B.; Kempen, H. PTQ 2009, Q1 31-36. (25.) Sharafutdinov, I. H-Oil hydrocracking Complex Construction commissioning and start-up. Current challenges, and plans for the future. Russia & CIS BBTC 2016, 11th Bottom of the Barrel Technology Conference & Exhibition, Moscow, Russia, 2016. (26.) Stratiev, D.; Shishkova, I.; Nikolova, R.; Tsaneva, T.; Mitkova, M.; Yordanov, D. Petroleum & Coal 2016, 58 (1), 109-119. (27.) ASTM D 7157-05, Standard Test Method for Determination of Intrinsic Stability of Asphaltene-Containing Residues, Heavy Fuel Oils, and Crude Oils (nHeptane Phase Separation; Optical Detection), American Society for Testing and Materials. (28.)

Rogel, E. Energy & Fuels 1997, 11, 920-925

(29.) Wiehe, I. A. Process Chemistry of Petroleum Macromolecules; CRC Press: Boca Raton, FL, 2008. (30.) Ancheyta, J.; Trejo, F.; Rana, M.S. Asphaltenes: Chemical Transformation During Hydroprocessing of Heavy Oil, CRC Press Taylor & Francis Group, 2009.


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(31.) Gray, M.R. Upgrading oilsands bitumen and heavy oil, The University of Alberta Press Ring House 2 Edmonton, Alberta, Canada T6G 2E1, 2015 (32.) Stratiev, D.S.; Russell, C.A.; Sharpe, R.; Shishkova, I.K.; Dinkov, R. K.; Marinov, I.M.; Petkova, N. B.; Mitkova, M.; Botev, T.; Obryvalina, A. N.; Telyashev, R.G.; Stanulov, K. Fuel Processing Technology. 2014, 128, 509–518. (33.) Hong, E.; Watkinson, P. Fuel. 2004, 83, 1881–1887. (34.) Siddiquee, M. N.; de Klerk A. Energy Fuels 2014, 28, 6848−6859 (35.) Petersen, J. C. Fuel Sci. Technol. Int. 1993, 11, 57−87. (36.) Herrington, P. R. Petrol. Sci. Technol. 1998, 16, 1061−1084. (37.) Laux, H.; Rahimian, I.; Neumann, H.-J. Erdől Erdgas Kohle. 1993, 109, (9), 368-372. (38.) Sunyaev, Z.I. Chemistry and technology of fuels and oils 1986, 8, 5-7. (39.) Hashmi, S. M.; Firoozabadi, A. J. Phys. Chem. B 2010, 114, 15780 -15788. (40.) Wiehe I. A. Journal of Dispersion Science and Technology 2004, 25:3, 333339. (41.) Stratiev, D.; Nedelchev, A.; Shishkova, I.; Ivanov, A.; Sharafutdinov, I.; Nikolova, R.; Mitkova, M.; Yordanov, D.; Rudnev, N.; Belchev, Z.; Atanassova, V.; Atanassov, K. Fuel Processing Technology. 2015, 138, 595–604. (42.) Stratiev, D.; Shishkova, I.; Dinkov, R.; Nikolova, R.; Mitkova, M.; Stanulov, K.; Sharpe, R.; Russell, C. A.; Obryvalina, A.; Telyashev, R. Fuel. 2014, 123, 133– 142. (43.) Stratiev, D.; Sherwood Jr. D.; Sharafutdinov, I.; Argirov G.; Mitkova, M.; Nikolova, R.; IJlstra, W. Optimization of the feedstock blend for the new H-OilRC™ ebullated bed resid upgrading unit at LUKOIL Neftohim Burgas, to maximize the conversion and yields of the on-site FCC unit. 13th International Bottom of the Barrel Technology Confernce, Istanbul, 2015. (44.) Garcıa, M. del Carmen; Carbognani, L. Energy & Fuels 2001, 15, 1021-1027.


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Table 1 Physical and physical properties of the vacuum residual oils processed in the LNB H-Oil hydrocracker Vacuum residual oils VRO Properties Urals Specific density d420 Conradson carbon, % Specific viscosity at 120°С, °Е 2

Kinematic viscosity at 120°C, mm /s S-value Sa So Sulfur, % V, mg/kg Ni, mg/kg Total sediments existent, wt.% Total sediments potential, wt.% Total sediments accelerated, wt.% 1 npm = not possible to measure.

Imported Arab Arab El Bouri Kazakh AR Medium Heavy

Basrah Vald'Agri Light

1.001 18.3

1.007 18.0

1.036 25.5

0.967 10.9

1.010 17.1

1.026 26.6

1.030 25.6

1.001 20.4

47.5

38.8

139.2

17.0

94.8

254.8

65.2

79.5

352 3.749 0.75 0.94 2.6 227.0 76.0 0 0 0

287 3.243 0.754 0.797 2.2 125 35 0 0 0

1029 2.797 0.69 0.86 3.3 80.0 74.0 0 0 0

126 4.264 0.84 0.68 0.9 65.0 21.0 0 0 0

702 2.989 0.72 0.83 5.1 142.9 40.3 0 0 0

1886 2.884 0.715 0.821 5.8 114.6 47.8 0 0 0

482 2.919 0.707 0.856 6.2 42 12 0 0 0

588 npm1 1.00 0.93 6.6 19.0 25.0 0 0 0


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Energy & Fuels

Table 2 SARA composition and element composition of the SARA fractions of the VROs processed in the LNB H-Oil hydrocracker

VROs

Val'd Agri

REBCO

Kazakh VR

Basra Light VR

El Bouri VR

Arab Heavy VR Arab Medium VR

SARA, wt.%

C, %m/m

H, %m/m

N, %m/m

S, %m/m

Sat. Aro.

26.5 59.7

85.1 82.7

13.2 9.5

< 0.01 0.02

7.96

Res.

8.7

82.8

9.5

0.7

-

Asp. Sat. Aro.

5 42.4 46.5

82.9 86.2 85.3

7.1 13.1 10.3

0.5 0.1 0.5

9.31 1.2 4.1

Res.

4.8

83.0

10.1

1.4

-

Asp. Sat. Aro. Res. Asp. Sat. Aro. Res. Asp. Sat. Aro. Res. Asp. Sat. Aro. Res. Asp. Sat. Aro. Res. Asp.

6.3 48.5 39.3 9.5 2.8 27.5 52.5 6.2 13.8 26.7 43.2 12.6 17.5 26.4 47.8 6.1 19.8 32.6 55.5 7.5 4.5

85.1 86.34 86.69 83.57

7.9 13.93 10.83 10.53

1.4 < 0.01 0.59 1.26

5.1 0.1 1.38 1.64

85.11 84.94 83.07 80.98

7.82 12.17 9.76 9.75

1.13 0.1 0.3 1.11

2.9 3.65 8.31 6.94

81.52 86.69 82.26 83.39

7.4 12.65 9.75 9.69

0.87 < 0.1 0.55 1.19

10.41 1.66 4.38 3.54

85.38 85.21 83.41 81.72

7.55 12.09 9.76 9.62

1.24 < 0.01 0.24 0.98

5.11 3.2 7.3 6.19

82.55

7.38

0.8

9.39

Maltenes Asphaltenes H/C atomic ratio H/C atomic ratio (δasp.) (δmalt.) 1.51

1.02

(20.0 MPa1/2)

(25.2 MPa1/2)

1.62

1.11

(18.9 MPa1/2)

(24.2 MPa1/2)

1.72

1.10

(17.9 MPa1/2)

(24.3 MPa1/2)

1.51

1.09

(20.0 MPa1/2)

(24.5 MPa1/2)

1.53

1.06

(19.9 MPa1/2)

(24.8 MPa1/2)

1.5

1.07

(20.1 MPa1/2)

(24.6 MPa1/2)

nd = not determined δmalt.= solubility parameter of maltenes, δasp.= solubility parameter of maltenes, solubility parameter is estimated by the correlation developed by Rogel [13, 28] and has the form: δ = 35.87-10.477(H/C)


Energy & Fuels

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Table 3 Physical and chemical properties of the FCC gas oils used as diluents in this study LCO

FCC gas oils HCO Slurry

3

Density at 15°C, g/cm High Temp. Sim. Dist., ASTM D-7169, wt.% 0.5 5 10 30 50 70 90 95 99.5 SARA composition, wt.% Saturates Aromatics Resins Asphaltenes Kw-factor HFT, %

0.9399 158 189 200 224 245 264 292 308 380

1.0147 1.1008 200 247 257 311 273 325 306 359 322 393 339 433 372 525 393 594 460 701

19.9 77.1 0 0 10.40 0

18.2 75.1 5.4 0 10.09 0


15.1 50.7 27.6 3.5 9.65 0.07

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Energy & Fuels

Table 4 Some properties of the three commercial HFT reducing additives used in this study A

Property/Additive

Type Content of hydrocarbons, C10, aromatics, >1% naphthalene, % (w/w) Naphthalene content, % (w/w) Calcium alkyl phenate sulfide, phosphorous sulfide polyolefin content, % (w/w) Polyisobuthylene Succinimide content, % (w/w) Pour point, °C Boiling point, °C Flash point, °C Relative density Viscosity, cSt

B

C

antifoulant, amines in aromatic solvent

antifoulant

antifoulant, polymer in aromatic solvent

10.0 - 20.0

50 - < 55 %

≥25

0.1 –

What Is Behind the High Values of Hot Filtration Test of the Ebullated

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