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Energy & Fuels 2000, 14, 60-63
Application of the Oil Compatibility Model to Refinery Streams Irwin A. Wiehe*,† and Raymond J. Kennedy Exxon Research and Engineering Co., Corporate Research Laboratories, Route 22 East, Annandale, New Jersey 08801 Received June 22, 1999. Revised Manuscript Received September 20, 1999
The plugging of a fixed bed hydrotreater was determined to be caused by an incompatibility of the mixture of hydrotreater feeds. Insoluble asphaltenes coked a heat exchanger upstream of the hydrotreater, flaked off the heat exchanger, and plugged the catalyst bed. The Oil Compatibility Model and tests were expanded to include oils that contain no asphaltenes. As a result, the most insoluble asphaltenes were determined to be in the fluid catalytic cracker bottoms and the poorest solvent oils were the virgin gas oils. By maintaining the feed composition within the compatibility limits predicted by the Oil Compatibility Model, subsequent plugging of the hydrotreater was avoided.
Introduction Fouling during the processing of petroleum oils in refineries is costly in the lost production when units are shut down for cleaning, in higher energy requirements of transferring heat through surfaces insulated by foulant, and in the cleaning itself. There are a number of potential causes of such fouling by insoluble organics and inorganics. Therefore, the challenge in solving a fouling problem is to determine the cause and then to apply scientific understanding to develop a mitigation strategy. Recently, with the development of the Oil Compatibility Model1 a new tool is available to diagnose and solve fouling problems caused by the precipitation of asphaltenes on blending of petroleum oils. This paper describes a case study where the Oil Compatibility Model needed to be extended before being used to solve a hydrotreater plugging problem. Hydrotreaters with fixed catalyst beds occasionally plug. This may be tolerated if it is an infrequent occurrence. However, when this event happened every two weeks, the cause and mitigation plan needed to be determined quickly. The foulant, located only in the top few inches of the bed, was primarily carbonaceous with little inorganic ash. Since this hydrotreater processed an unusual mixture of feeds, incompatibility was one of the possible causes. Although the Oil Compatibility Model had been developed for crudes, it had never been applied to oils without asphaltenes. Therefore, new tests had to be devised to diagnose and cure the plugging problem. Oil Compatibility Model. The Oil Compatibility Model1 is a solubility-parameter-based model that has been applied to determine the correct order and propor* Corresponding author. Fax: (908) 470-0939. E-mail:
[email protected]. † Present address: Soluble Solutions, 3 Louise Lane, Gladstone, New Jersey 07934. (1) Wiehe, I. A.; Kennedy, R. J. Energy Fuels 2000, 1, 56.
tions of blending petroleum oils to prevent rapid fouling and coking from the precipitation of asphaltenes.2 It was derived from the hypothesis that asphaltenes precipitate at the same mixture solubility parameter when the oil is blended with any noncomplexing liquids, including other oils. Two compatibility numbers need to be evaluated for each oil in the blend. The insolubility number, IN, measures the degree of insolubility of the asphaltenes, and the solubility blending number, SBN, measures the solvency of the oil for asphaltenes. To measure the compatibility numbers, one blends the oil with various volume ratios of test liquids composed of many volume ratios of toluene and n-heptane and determines if each dissolves or precipitates asphaltenes. At each volume ratio of oil, Voil, to test liquid, VTL, the minimum volume percent toluene in the test liquid to keep the asphaltenes in solution is determined. At least two of these measurements are required to measure the compatibility numbers. One test is usually the heptane dilution test that determines the maximum volume of n-heptane that can be blended with 5 mL of oil without precipitating asphaltenes, VH. The other test is commonly the toluene equivalence test,3 TE, at a concentration of two grams of oil and 10 mL of test liquid. The compatibility numbers can then be calculated:1
IN )
TE VH 125d
[
[
SBN ) IN 1 +
]
(1)
]
VH 5
(2)
where d is the density of the oil in g/mL. Mixture of Oils. Since the solubility parameter of a mixture is given by the volumetric average of the components,1 the solubility blending number of a mixture of oils is likewise determined:
10.1021/ef9901342 CCC: $19.00 © 2000 American Chemical Society Published on Web 12/03/1999
Oil Compatibility Model and Refinery Streams
SBNmix )
V1SBN1 + V2SBN2 + V3SBN3 + ... V1 + V2 + V3 + ...
Energy & Fuels, Vol. 14, No. 1, 2000 61 Table 1. Components of Hydrotreater Feed
(3)
For compatibility the solubility blending number of the mixture of oils must be higher than the insolubility number of any oil in the mixture. Therefore, for a mixture of oils, the compatibility criterion can be stated as follows:
compatibility criterion: SBNmix > INmax
(4)
Results and Discussion Hydrotreater Plugging. A refinery fixed bed hydrotreater was designed to desulfurize a wide mixture of feeds as shown in Table 1. This unit processed oil for several years without major problems. However, suddenly the hydrotreater began to build pressure drop that caused the unit to be shut down for cleaning. Only the top few inches of the bed was plugged with black solids. Analysis of the solids showed that they were composed of 86.83 wt % carbon, 3.82 wt % hydrogen, 3.42 wt % sulfur, and 0.26 wt % iron. Thus, they were primarily carbonaceous and not iron sulfide, a common hydrotreater foulant. With further operation, the run lengths became increasingly shorter until with only two-week run lengths the unit was shut down pending the resolution of the problem. Compatibility Testing. The possibility of feed incompatibility was investigated. First, the feed components were blended in the proportions last run in the hydrotreater. Examination of this mixture with an optical microscope clearly showed insoluble asphaltenes (particles that were dissolved on addition of toluene but not with n-heptane). Thus, feed incompatibility was determined to be the most likely cause. However, during the last few runs incompatibility had already been suspected, albeit not proven. Thus, when pressure drop had increased, the propane asphalt, that contained high concentrations of asphaltenes, was removed from the feed. Nevertheless, the hydrotreater continued to plug rapidly. In addition, the insoluble asphaltenes in the simulated feed blend were less than 10 µm in size, too small to plug a fixed bed hydrotreater with voids greater than 100 µm. Thus, it was difficult to explain these observations based on the basis of the incompatibility mechanism. Regardless, compatibility testing was initiated with the hope of explaining these paradoxes once the feed phase behavior was understood. Although the compatibility testing was at room temperature, the hydrotreater was at elevated temperature (above 350 °C). The effect of temperature on asphaltene solubility is somewhat controversial in the literature. Storm, Barresi, and Sheu4 report asphaltenes cluster more, but do not phase separate, at elevated temperatures, above 200 °C, based upon viscosity and smallangle X-ray scattering data. However, viscosity data is not definitive for structure and the small-angle X-ray data was done at room temperature after heating and cooling. Their bombs containing resid were heated to (2) Wiehe, I. A.; Kennedy, R. J. U.S. Patent 5,871,634, 1999. World Patent WO 98/26026. (3) Griffith, M. G.; Sigmund, C. W. In Marine Fuels; Jones, C. H., Ed.; ASTM: Philadelphia, 1985; pp 239-245. (4) Storm, D. A.; Barresi, R. J.; Sheu, E. Y. Fuel Sci. Technol. Int. 1996, 14, 243-260.
Virgin Atmospheric Gas Oil Virgin Vacuum Gas Oil Kerosene Oil from Fluid Catalytic Cracking Light Catalytic Cycle Oil Heavy Catalytic Cycle Oil Departiculated Fluid Catalytic Cracker Bottoms 150 Neutral Lube Extract 600 Neutral Lube Extract Propane Asphalt
350-400 °C, temperatures known to cause thermal cracking. In contrast, Winans and Hunt5 used smallangle neutron scattering data on 5 wt % asphaltenes in 1-methyl naphthalene-d10 measured directly at temperature and showed decreasing asphaltene aggregate size with increasing temperature to 340 °C. Previously, Espinat and Ravey6 showed that by small-angle X-ray scattering at temperature that the agglomerated size of asphaltenes in toluene decreased in heating from -27 to 77 °C. This agreed with Andersen and Stenby7 who observed increased asphaltene solubility on heating from 24 to 80 °C and with Wiehe8 who used hot stage microscopy to show insoluble asphaltenes redissolve in resid on heating from room temperature to 200 °C. To add to the confusion, it is known9 that petroleum crude that contains large amounts of dissolved gases (live oils) can precipitate asphaltenes on heating and in deasphalting with propane or butane, asphalt is precipitated on heating.10 However, this is due to the wellknown phenomenon11 of the rapid change of density and other thermodynamic properties as a mixture approaches the critical point of one of its major components. Therefore, it is concluded that the solubility of asphaltenes always increases by raising the temperature unless one of the components is near or above its critical temperature, which none were in this case. Thus, if compatibility of the hydrotreater feed can be designed at room temperature, it will be definitely assured at elevated temperatures. Compatibility Numbers for Components with Asphaltenes. Most of the feed components listed in Table 1 contained no asphaltenes. One volume of each feed component was mixed with 10 volumes of nheptane and determined by optical microscopy whether asphaltenes precipitated (submicroscopic particles that cluster into chain or shrimp-shaped agglomerates12). Only propane asphalt and fluid catalytic cracker bottoms (FCC bottoms) were found to contain asphaltenes. The other feed components without asphaltenes by definition had insolubility numbers of zero. However, no tests were available to measure the solubility blending numbers of oils without asphaltenes. With the (5) Winans, R. E.; Hunt, J. E. Prepr. Pap.sAm. Chem. Soc., Div. Fuel Chem. 1999, 44, 725-732. (6) Espinat, D.; Ravey, J. C. Soc. Pet. Eng. 25187 1993, 365-373. (7) Andersen, S. I.; Stenby, E. H. Fuel Sci. Technol. Int. 1996, 14, 261-288. (8) Wiehe, I. A. ACS Presentation, Div. Petr. Chem. 1997, San Francisco. (9) Leontaritis, K. J. Fuel Sci. Technol. Int. 1996, 14, 13-39. (10) Low, J. Y.; Hood, R. L.; Lynch, K. Z. Prepr. Pap.sAm. Chem. Soc., Div. Pet. Chem. 1995, 40, 780-784. (11) Rowlinson, J. S. Liquids and Liquid Mixtures; Butterworth Scientific Publications: London, 1959; pp 231-235. (12) Preckshot, G. W.; DeListle, N. G.; Cottrell, C. E.; Katz, D. L. Trans. AIME 1943, 151, 189-205. (13) Wiehe, I. A. Ind.Eng Chem. Res. 1993, 32, 2447-2454.
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Wiehe and Kennedy
Table 2. Compatibility Numbers for Feed Components Containing Asphaltenes feed component
toluene equivalence at 2 g oil/10 mL test liquid
heptane dilution (mL n-heptane/5 mL oil)
oil density (g/cc)
insolubility number
solubility blending number
propane asphalt FCC bottoms
11 74
16.3 2.2
1.00 1.11
23 80
105 116
Table 3. Compatibility Numbers for Nonsolvent Oils with FCC Bottoms as the Reference Oil nonsolvent oil
volume of NS oil (mL)
volume of n-heptane (mL)
insolubility number
solubility blending no.
Atm. Gas Oil Vacuum Gas Oil FCC Kerosene
5.5 5.5 16.25
2.2 2.2 2.2
0 0 0
48 48 69
Table 4. Compatibility Numbers for Solvent Oils with FCC Bottoms as the Reference Oil solvent oil
solvent oil equivalence at 2 g oil/10 mL T liq
toluene equivalence at 2 g oil/10 mL T liq
insolubility number
solubility blending no.
Light Cat. Cycle Oil Heavy Cat. Cycle Oil 150 Neutral Lube Extract 600 Neutral lube Extract
78 53 91 50
74 74 74 74
0 0 0 0
95 140 81 147
hydrotreater down, these tests had to be developed quickly. Nevertheless, the first step was to run the toluene equivalence and heptane dilution tests on samples of the feed components that contained asphaltenes. The result is shown in Table 2 along with the insolubility and solubility blending numbers, calculated with eqs 2 and 3. It immediately became clear that FCC bottoms (IN ) 80) contained the asphaltenes that become insoluble on mixing and not the propane asphalt (IN ) 23). The FCC bottoms became a reference oil to determine the solubility blending numbers of the feed components without asphaltenes. Ten volumes of each feed component were blended separately with one volume of FCC bottoms and determined if asphaltenes precipitated. Three feed componentssatmospheric gas oil, vacuum gas oil, and kerosene oil from fluid catalytic crackings were so determined to be nonsolvents for FCC bottoms while the other feed components were solvents. Nonsolvent Oil Dilution Test. The heptane dilution test was rerun on the FCC bottoms except the n-heptane was replaced with each of the three nonsolvent oils. Thus, each of the nonsolvent oils was added to 5 mL of FCC bottoms and the maximum volume in milliliters of nonsovent oil (VNSO) that could be added without precipitating asphaltenes was determined. The mixture at that flocculation point must have the same solubility blending number as when n-heptane (VH) was added to FCC bottoms in the heptane dilution test. From eq 4:
SBNmix )
VH(0) + VFCCBSFCCB ) VH + VFCCB VNSOSNSO + VFCCBSFCCB (5) VNSO + VFCCB
Rearranging and solving for the solubility blending number of the nonsolvent oil:
SNSO )
SFCCB[VNSO - VH] VH VNSO 1 + 5
[
]
(6)
The solubility blending numbers calculated with eq 6 for the nonsolvent oils are in Table 3.
Solvent Oil Equivalence Test. Four of the feed components contained no asphaltenes and are solvents for FCC bottoms: light and heavy catalytic cycle oil and 150 and 600 neutral lube extracts. For these, the toluene equivalence test (TE) was rerun on the FCC bottoms but toluene was replaced by each of the solvent oils (SOE). Thus, the concentration of two grams of FCC bottoms per 10 mL of test liquid was maintained. The minimum volume percent solvent oil in the test liquid (rest is n-heptane) to keep asphaltenes in solution was determined. The mixture at that flocculation point must have the same solubility blending number as the mixture of the toluene equivalence test on FCC bottoms:
SBNmix )
VTH(0) + VT(100) + VFCCBSFCCB VTH + VT + VFCCB
)
VSO H (0) + VSOSSO + VFCCBSFCCB VSO H + VSO + VFCCB VT 10 TE ) 100 SSO ) 100 VSO SOE 10
[ ]
(7)
(8)
The solubility blending numbers calculated with eq 8 for solvent oils are in Table 4. Overall Range of Compatibility Numbers. Since refinery oils can vary significantly with crude and process changes, samples were collected for a number of days of operation for each of the feed components. The compatibility numbers were measured as described above. One exception was for some samples of FCC bottoms that were either insoluble in toluene or close to it. Then chlorobenzene equivalence was used by replacing toluene in the toluene equivalence with chlorobenzene. Using the principle of equivalent flocculation solubility parameter, the toluene equivalence, TE, can be related to any other equivalence, SE, by
δf )
VHδH + VTδT + Voilδoil VSHδH + VSδS + Voilδoil ) VH + VT + Voil VS δ + V + V H H
S
oil
(9)
Oil Compatibility Model and Refinery Streams
Energy & Fuels, Vol. 14, No. 1, 2000 63
VH + VT + Voil ) VSH + VS + Voil ) 10 + Voil (10) VHδH + VTδT ) VSHδH + VSδS
(11)
VH ) 10 - VT; VSH ) 10 - VS
(12)
10δH + VT[δT - δH] ) 10δH + VS[δS - δH] (13) TE ) 100
VS VT ; SE ) 100 10 10
(14)
δS - δ H δT - δ H
(15)
TE ) SE
[
]
where δS ) solubility parameter for the solvent ) 9.67 (cal/cc)1/2 for chlorobenzene, δH ) solubility parameter for n-heptane ) 7.50 (cal/cc)1/2, and δT ) solubility parameter for toluene ) 8.93 (cal/cc)1/2 This predicts, when measured on the same oil, the toluene equivalence will be 1.52 times the chlorobenzene equivalence. This was checked on a FCC bottoms sample where the toluene equivalence was measured to be 95 and the chlorobenzene equivalence was measured to be 65, giving a ratio of 1.46, within experimental error of the predicted ratio. Using eq 15, toluene equivalences now could be measured and insolubility numbers could be evaluated that were over 100 (toluene-insoluble). The full range of insolubility numbers and solubility numbers is shown in Figure 1. The range of propane asphalt insolubility numbers is lower than the range of solubility blending numbers for all feed components except for some atmospheric gas oils. As a result, propane asphalt never was insoluble in the feed mix. This is the reason removing it from the feed did not reduce the rate of fouling. Actually, removing propane asphalt made the total feed a poorer solvent (lower solubility blending number). On the other hand, FCC bottoms are insoluble in the three nonsolvent oils in Table 4 and sometimes in 150 neutral lube extract as well. However, the plugging was due primarily to an incompatibility between the FCC bottoms and the virgin gas oils. With this knowledge, refinery records were reviewed and it was discovered that the plugging started after the concentration of virgin gas oils in the hydrotreater feed was greatly increased. Root Cause Analysis. After obtaining the data in Figure 1, a root cause analysis was done with all the evidence. As discussed above, it was clear that feed incompatibility was the root cause. However, the high
Figure 1. Range of insolubility numbers and solubility blending numbers for each feed component over days of operation.
concentration of coke in the scale trap, the screen above the bed of catalyst, and in the first few inches of the bed indicated that the coke was formed upstream of the bed. The very small size (
