Performance evaluation of HDS catalysts by distribution of sulfur compounds in naphtha

E

ILEE

RWOR M A

N’: 0016-2361(95)00076-3

Fuel Vol. 74 No. 9, pp. 1254-1260, 1995 Copyright 0 1995 Elsevier Science Ltd Printed in Great Britain. All rights reserved 0016-2361/95/$10.00+0.00

Performance evaluation of HDS catalysts by distribution of sulfur compounds in naphtha

Jamal A. Anabtawi, Khurshid Alam, Mohammed A. Ali, Syed A. Ali and Mohammed A. B. Siddiqui Petroleum and Gas Technology Division, The Research institute, King Fahd University of Petroleum and Minerals, Dhahran 31261, Saudi Arabia (Received 1 I January 1994; revised 26 August 1994)

This paper presents results of pilot plant evaluation of two commercial hydrodesulfurization (HDS) catalysts and demonstrates the use of trace sulfur analysis and distribution of sulfur compounds for reliable and better catalyst evaluation. Straight-run naphtha (SRN) and a blend of SRN and hydrocracked naphtha containing 897 and 534ppm sulfur respectively were analysed for sulfur compound distribution by gas chromatography with flame photometric detection and hydrocarbon type composition by a PONA analyser. G.c.-f.p.d. analysis indicated the presence of 52 sulfur compounds, including mercaptans (55.7%), thiophenes and sulfides (43.1%), disulfides (1.l%) and traces of polysulfides, hydrogen sulfide and elemental sulfur. Pilot plant experiments were carried out with two catalysts at 220-35O”C,space velocities of 10 and 13h-’ and gas rates of 67 and 80 11-l. Total and mercaptan sulfur in the product passed through a minimum with increasing temperature. The optimum temperature was 320°C for SRN and 300°C for the blend naphtha. Thiophenes, forming a major portion of the sulfur in the product, could be removed by hydrotreating at >28O”C.At higher temperatures, methyl mercaptan increased, owing to hydrogen sulfide recombination reactions. One of the catalysts performed better than the other. (Keywords:naphtha; hydrodesalfurization;catalysts)

Hydrodesulfurization (HDS) of naphtha is required to prepare the feedstock for catalytic reforming, to protect the expensive Pt-Rh reforming catalyst. Catalyst lifetime, gasoline yield and stability can be dramatically improved by prior sulfur reduction. Selection of an HDS catalyst depends on several factors, including feedstock properties, product specifications and process economics. Pilot plant testing of naphtha HDS catalysts is complicated by the need for accurate trace sulfur analysis (< 1 ppm), slow deactivation and high initial catalyst activity. Characterization of sulfur compounds in naphtha is important in determining the difficulty of processing and operating conditions. It can also provide better understanding of the function of catalysts and helps in the selection of a suitable catalyst on the basis of selectivity of removal of sulfur compounds. The amounts and types of sulfur compounds present in naphtha are determined by the source of the crude and the pretreatment of the naphtha in the refinery. These sulfur components include elemental sulfur, hydrogen sulfide, disulfides, sulfides, mercaptans and thiophenes. The organic sulfur compounds, particularly the thiophenes, are the most difficult to remove. Characterization of sulfur compounds in naphtha is difficult because no standard technique is available and quantitative analysis is tedious. Many methods are described in the literature for the determination of sulfur compounds in petroleum fractions. A simulated distillation method based on gas

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Fuel 1995 Volume 74 Number 9

chromatography using flame photometric detection (g.c.f.p.d.) has been used to determine the boiling-range distribution of sulfur containing compounds in middle-toAt British Petroleum’, heavy petroleum distillates’. simultaneous simulated distillation with gas chromatography and microwave-induced plasma atomic emission detection was used. This method can accurately quantify the sulfur content as a function of boiling point, rather than by molecular formula. G.c.-f.p.d. is becoming an acceptable technique for detailed sulfur compound analysis3-‘. In this study, g.c.-f.p.d. was used to investigate the effect of HDS on changes in distribution of sulfur compounds in naphtha.

EXPERIMENTAL Materials and analyses Two commercial CO-MO HDS catalysts were used. Their physical properties, chemical composition, thermal behaviour and mechanical strength are listed in Table 1. Two types of feedstock were used: straight-run naphtha (SRN) and a blend containing 60% SRN and 40% hydrocracked naphtha (HCN), obtained from a refinery in Saudi Arabia. Their properties and those of the hydrotreated blend from the same refinery, are presented in Table 2. Density was measured at 15°C with a Paar density

HDS catalysts by distribution

Table 1 Catalyst characterization”

Physical properties Average length (mm] Bulk density (kg mBET surface area (ml g-l) Pore volume (cm3 g-r) Mean pore radius (A) Attrition loss (%) Crushing strength (Nmm-‘)

ASTM method

Catalyst A

Catalyst B

D-4164 D-3663 D-4222 D-4222 D-4058 D-4179

7.2 740 193 0.45 47.3 1.65 10.6

4.9 700 233 0.54 46.3 0.70 24.3

15.00 4.00 74.70 0.08 0.09 0.02 0.07 0.15 <0.02 0.07 <0.02 0.03 0.07 4.6

19.50 4.60 68.00 0.13 <0.05 0.07 0.04 0.46 <0.02 0.16 <0.02 0.02 1.83 5.3

Chemical analysis (wt% db) Moo3 coo A1203

NarO R20 CaO MgO SiOz Fe203 so4 vzo5

NiO w5

Loss on ignition at 1000°C b ’ Both catalysts in the form of 1.6 mm extrudate b Wet basis

Table 2

Characterization

of sulfur compounds

in naphtha: J. A. Anabtawi

et al.

meter. Total carbon and hydrogen contents were determined with an elemental analyser. The major hydrocarbon components were determined by gas chromatography using a dedicated PONA (paraffinsolefins-naphthenes-aromatics) analyser, the specifications and operating conditions of which are given elsewhere6. The boiling range distribution was determined using a simulated distillation analyser according to ASTM method D-3710. Total sulfur was determined using Raney nickel reduction by the UOP-357 method and using a sulfur analyser (ASTM D-4045). Mercaptan sulfur was determined by potentiometry (ASTM D-3227), and disulfides by the UOP-202 method. The disulfides were reduced to mercaptan sulfur by digestion. Both acid reflux and acid stirring procedures were used for this determination. Polysulfides were determined qualitatively by polarography7, and elemental sulfur by the UOP-286 method. A gas chromatograph equipped with a flame photometric detector was used for analysis of sulfur compounds with a DB-1 fused silica capillary column, 0.53 mm i.d. x 30m long. This column is known to be the most suitable for high-resolution separation of sulfur compoundss9. The f.p.d. sensitivity was optimized by adjusting the air, hydrogen, carrier and make-up gas flow rates to detect a minimum of 50ppb sulfur. It was tested by using a standard of carbon disulfide in pure isooctane. Hydrocarbons in the naphtha sample are known to have a quenching effect on f.p.d. response,

of naphtha feedstocks and product ASTM or UOP method

SRN

HCN

Blend

Product’

Density (kg rnm3)

D-4052

740.5

761.9

749.5

748.9

Refractive index

D-1218

Boiling range (“C)

D-3710

Physical properties

1.4194

1.4288

1.4257

1.4248

1.b.p.

66

62

65

58

10%

93

93

93

93

30%

112

114

112

113

50%

128

129

128

128

70%

146

146

146

147

90%

165

168

167

168

F.b.p.

187

194

194

195

Chemical analysis (wt%) Paraffins

69.3

42.8

58.6

0.1

0.2

0.1

0.2

18.8

43.4

28.3

28.7

Olefins Naphthenes

58.0

Aromatics

12.0

13.5

13.0

13.2

Carbon

85.8

85.9

87.7

85.5

Hydrogen

15.6

15.1

14.7

15.1

Sulfur analysis @pm) Total sulfur

D-4045

897

2.2

534

Mercaptans

D-3227

500

2.0

297

Disulfides

UOP-202

10

Sulfides + thiophenes Elemental sulfur + H2S

387 tr

tr

232

tr

UOP-286

tr

tr

tr

tr

tr

tr

tr

Polysulfides

trc

5

0.30 0.29 tr

’ Hydrotreated blend naphtha b By difference ’Trace

Fuel 1995 Volume 74 Number 9

1255

HDS catalysts by distribution

of sulfur compounds

Table 3 Optimized compound analysis

gas chromatographic

Column

Fused silica capillary column, DB- 1, 0.53 mm i.d., 30m long Initial temp. 45°C 0.5 min Isotime 1 Heating rate 1 l.SKmin-’ to 110°C Isotime 2 0.5min Heating rate 2 6 K mitt-’ to 200°C Helium 5 ml min-’ Helium 5 ml mitt-’ 1~1 splitless 250°C F.p.d. sigma 2000 50 ml min-’ 95 mlmin-’ 250°C 2.0 High

Oven conditions

Carrier Make-up Sample volume Injector temp. Detector: Hz flow rate Air flow rate Temp. Linearity Sensitivity

conditions

for

in naphtha: J. A. Anabtawi

sulfur

resulting in negative peaks and poor sulfur sensitivity’Opll. The gas flow rates were adjusted to minimize this quenching effect. The temperature programming was optimized for the best possible separation of the large number of sulfur compounds in SRN. The optimized g.c. conditions are presented in Table 3. Pilot plant tests

The performance of the two catalysts was evaluated in a continuous-flow, fixed-bed pilot plant. The catalyst sample was calcined in a muffle furnace at 425°C for 2 h. The calcined catalyst was then diluted with a-alumina (2-3 mm size) to give a 46 cm long catalyst bed in a 2.7 cm i.d. reactor. Presulfiding of the catalyst was achieved by passing a spiked feed containing 1 wt% CS;! in SRN at 5 h-’ with a hydrogen flow of 150 11-l based on feed. The catalyst bed temperature was maintained at 200°C for 3 h, 250°C for 1 h and 300°C for 16h to complete the presulfiding process. For HDS, pure hydrogen was used in once-through mode and the pressure was maintained at 2.85 MPa 10

7

during all the runs. The pilot plant experiments were designed to investigate the effect ofi temperature (220350?+ space velocity (10 and 13 h- ), gas rate (67 and 8Olll ) and feedstock type on the performance of each catalyst. Fifty-seven runs were conducted under various conditions. The reproducibility of the results was checked by repeating some of the runs. RESULTS AND DISCUSSION Feedstock analysis

The results presented in Table 2 show that the density, refractive index and final boiling point of HCN are higher than those of SRN because of its higher aromatic and naphthenic content. The PONA results confirm that the HCN contains 24.6 wt% more naphthenes and 26.5 wt% less paraffins than SRN. Table 2 also shows the sulfur compound type distribution obtained from chemical analysis for the naphtha feedstocks and product. The sulfur composition of the feedstock is of importance in selection of a suitable catalyst. The reactivities of sulfur compounds decrease in the order: mercaptan > disulfide > sulfide > thiophene > benzothiophene > alkyl benzothiophene. The g.c.-f.p.d. chromatogram of SRN, presented in Figure 1, shows 52 sulfur compound peaks. A mixture of 24 sulfur compounds in isooctane was injected to determine their retention times. Seventeen sulfur compounds were identified in SRN and blend naphtha by matching the retention times. The DB-1 column elutes the S compounds in order of increasing boiling point. This characteristic was used to estimate the boiling points of the compounds in the unidentified peaks, which were then matched with the boiling points of known sulfur compounds. Table 4 shows the compounds identified by both methods, with their retention times, matched peak numbers and boiling points. Of the 42 identified compounds, 15 are mercaptans, 15 thiophenes, nine sulfides, and three disulfides. Chemical analysis showed that 56% of the S in SRN is represented by mercaptans;

25 2728 30 31 3435

,,I5 17,18,19 21 Ii14 2

Figure 1 Chromatogram of sulfur compounds in SRN feedstock 2

Figure 2

1256

46

7

10

Chromatograms of sulfur compounds in (A) HCN and (B) refinery product naphtha

Fuel 1995 Volume 74 Number 9

et al.

37

HDS catalysts by distribution Table 4 Serial no.

Sulfur compounds in SRN identified by

of sulfur compounds

in naphtha: J. A. Anabtawi

et al.

g.c.-f.p.d.

Compound name

Retention time (min)

Matched peak no.

Boiling point (“C)”

Identified by matching retention times

_

1

Hydrogen sulfide

1.48

2

Ethyl mercaptan

3.00

3

Isopropyl mercaptan

4.07

56

4

r-Butyl mercaptan

5.04

64.2 61.5

36

5

n-Propyl mercaptan

5.42

6

set-Butyl mercaptan

7.76

7

Diethyl sulfide

9.11

8

92

8

n-Butyl mercaptan

10.29

10

100

84

9

2-Methylthiophene

13.18

14

112.4

10

3-Methylthiophene

13.64

15

115.4

11

n-Amy1 mercaptan

16.88

19

126

12

2-Ethylthiophene

20.30

24

132.5

13

2,5_Dimethylthiophene

20.75

25

135.5

14

Di-n-propyl sulfide

22.84

28

142

15

n-Hexyl mercaptan

25.25

31

151

16

n-Heptyl mercaptan

34.18

44

176

11

Di-n-butyl sulfide

38.18

51

188

Identified by matching boiling points 1

Methyl mercaptan

1.51

2

6 (
2

Methyl disulfide

12.57

13

109.7 (110)

3

Diisopropyl sulfide

15.60

17

120.7 (120.5) 122.5 (122.5)

4

n-Butyl methyl sulfide

16.15

18

5

Ethyl methyl disulfide

18.51

21

130 (130)

6

Isopropyl propyl sulfide

19.75

23

132 (132)

I

2-methyl butyl sulfide

22.11

21

139.5 (139.5)

8

3,4-Dimethylthiophene

23.38

29

144 (144) 149 (148)

t-Butyl sulfide

24.37

30

10

9

2-Isopropylthiophene

25.25

31

152 (152)

11

Ethyl disulfide

25.19

32

153 (152.5) 154 (154.5)

12

2-Hydroxyethyl mercaptan

25.79

33

13

3-Isopropylthiophene

27.01

35

156 (156)

14

Cyclohexyl mercaptan

28.05

36

159 (159)

15

2-Ethyl 3-methyl thiophene

28.85

31

161 (161.5)

16

3-t-Butylthiophene

31.59

41

169 (169)

17

2,3,4_Trimethylthiophene

32.65

42

172.7 (172.5)

18

1,3-Dithiacyclopentane

33.5-i

43

175 (175)

19

2-Benzothiozole thiol

34.85

45

179 (178)

20

2-Methyl, 5-propylthiophene

35.25

46

179.5 (179.5)

21

2-n-Butylthiophene

35.65

47

181 (180.5)

22

2,5_Diethylthiophene

35.89

48

181 (181)

23

3-a-Butylthiophene

36.48

49

183 (183)

24

3,4_Diethylthiophene

37.18

50

185 (185)

25

2,3,4,5_Tetramethylthiophene

38.13

51

186 (187)

’ Values in parentheses are those estimated from peak position

thiophenes and sulfides are the major constituents of the remaining 44%. The chromatogram in Figure 2 shows the presence of some six S compounds in HCN and four in the hydrotreated product. The major part of the sulfur present in HCN is represented by five mercaptans (peaks 2,4,6,7, 10) and one thiophene (peak 51). The presence of methyl mercaptan, isopropyl mercaptan, n-butyl mercaptan and 2,3,4,%etramethylthiophene (peak 51) in the product shows that these compounds are more difficult to

remove. Another reason for the presence of mercaptans in refinery product naphtha may be recombination reactions between H2S and olefins. HDS reactions are limited at extremely low sulfur (< 1 ppm), as a result of the following reaction: Mercaptans * Olefins + H2S

(1)

This reaction, which shifts to the left at higher HDS activity, is a function of H$S partial pressure,

Fuel 1995 Volume 74 Number 9

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HDS catalysts by distribution of sulfur compounds in naphtha: J. A. Anabtawi et al.

Table 5

Comparison of catalyst performance for HDS Sulfur content Catalyst A Total (ppm)

Blend naphtha Feed Product at (“C) 220 250 280 300 320 350 SRN Feed Product at (“C) 220 250 280 300 320 350

Catalyst B

Mercaptan (ppm) W)

Total (ppm)

Mercaptan (ppm) W)

534 297 72 4.0 9.5 0.67 1.06 0.27 0.69 0.25 0.76 0.43 0.89 0.51

56 6 7 26 36 57 57

534 58 4.7 0.52 0.32 0.54 0.75

297 56 7.7 13 1.00 21 0.16 31 0.21 66 0.33 61 0.60 80

897 500 184 8.7 31 1.80 0.79 0.28 0.52 0.20 0.37 0.33 0.87 0.73

56 5 6 35 39 89 84

897 16 0.36 0.38 0.42 0.69

500 1.1 0.15 0.27 0.27 0.64

56 7 42 71 64 93

1.4 -

1.2 -

2 ,o

t 4 e a

Total

Mercaptans

Sulfur

b

1.0 -

= 5 l?l

??

.

0.8 -

0.6 -

results, presented in Table 5 and Figure 3, indicate that product total sulfur decreased from 72 ppm at 220°C to a minimum of 0.69ppm at 3OO“C,above which the sulfur increased with increasing temperature up to 350°C. This increase in sulfur was caused by hydrogen sulfide-olefin recombination reaction to form mercaptan sulfur. Table 5 shows that the sulfur as mercaptans in the blend naphtha feedstock, -55.6% of the total sulfur, was reduced to 5.6% at 220°C but increased to 57.3% at 350°C. These results show that the optimum operating temperature for catalyst A using blend naphtha is 300°C. The effect of temperature on the performance of catalyst B for SRN and blend naphtha under similar conditions is shown in Table 5 and Figure 4. For blend naphtha the total sulfur decreased from 58 ppm at 220°C to 0.32 ppm at 300°C. The mercaptan sulfur followed the same trend as the total sulfur, but its proportion increased from 13 to 80% of the total sulfur as the temperature increased from 220 to 350°C. Similar trends were observed for SRN. Figure 5 shows the chromatograms of blend naphtha and its products obtained with catalyst A at five temperatures. It is seen that at 25O”C, some twelve sulfur compounds are present after hydrodesulfurization, three of which are mercaptans, two sulfides, and the others thiophenes. Thiophenes, a major portion of the S compounds, are difficult to remove at 25O”C, but at >28O”C they are removed almost completely with catalyst A, as shown by peaks 41-51 in Figure 5. Methyl mercaptan, easily formed at higher temperatures, is present in all the products obtained at temperatures between 250 and 350°C. The concentration of this compound increased at 320°C (peak 2) owing to an unavoidable recombination reaction due to unstripped, dissolved H2S in the product naphtha.

1 14 -

0.4 1.2 -

??

Total

.

Mercaptans

Sulfur

0.2 10 -

01 250

i 215

300 Temperature

325

350

37!

PC)

Figure 3 Effect of temperature on total and mercaptan sulfur contents of product from blend naphtha using Catalyst A

temperature, feedstock type, gas rate, space velocity and reactor configuration. From this discussion, it is clear that 2,3,4,5_tetramethylthiophene constitutes the major portion of the residual sulfur in the product. Effect of temperature

The effect of temperature on the performance of catalyst A was investigated for SRN and blend naphtha at 220-35O”C, space velocity 10 h-‘, pressure 2.85MPa and gas rate 67 11-l. The data showed that changes in density, PONA contents and boiling point distribution were insignificant within this temperature range. The

1258

Fuel 1995 Volume 74 Number 9

-E % = 2 t

0.8 -

2 a

0.6 -

‘c

s

Id:::

0.1, -

0.2 -

01 250

215

300 Temperature

325 PC)

350

375

Figure 4 Effect of temperature on total and mercaptan sulfur contents of product from blend naphtha using Catalyst B

HDS catalysts by distribution

of sulfur compounds

in naphtha: J. A. Anabtawi

et al.

I..

m

18

Figure 5 Chromatograms (E) 320°C and (F) 350°C

21

of sulfur compounds in (A) the blend naphtha and its products with catalyst A at (B) 25o”C, (C) 28o”C, (D) 3OO”C,

of the blend naphtha and on other measures of product quality (density, PONA and boiling point distribution). The temperature for minimum product sulfur was 300°C at both gas rates.

I 1L -

12

-

.

Blend

.

Straight

Naphtha Run

Eflect of feedstock type

Naphtha

J

250

215

300 Temperature

Figure 6

25 27

325

350

315

(“Cl

Performance of catalyst A with SRN and blend naphtha

Eflects of space velocity and gas rate

The effect of space velocity on the performance of both catalysts was investigated at gas rates of 67 and 80 1l-‘, temperatures between 280 and 350°C and a pressure of 2.85MPa using SRN and blend naphtha. The data showed that product sulfur reached a minimum at 300°C with a space velocity of 10 h-’ and at 350°C with a space velocity of 13 h-l. In general the performance of catalyst A was better at the lower space velocity. The effect of gas rate was investigated at a space velocity of lOh-‘, a pressure of 2.85MPa and temperatures between 280 and 350°C. The results indicated that the gas rate had an insignificant effect on the desulfurization

The performance of catalysts A and B for SRN and blend naphtha was compared at a space velocity of 10 h-l, a pressure of 2.85MPa, a gas rate of 6711-l and temperatures between 220 and 350°C. Figure 6 shows that it is easier to desulfurize SRN than blend naphtha, the former giving product of 0.37 ppm S at the optimum temperature of 320°C. At higher temperatures, the H2S recombination reactions increased the mercaptan sulfur formation. The blend naphtha gave a product with a minimum sulfur content of 0.69ppm at 300°C. Hence catalyst A is more effective for SRN than for blend naphtha in spite of the higher initial sulfur content. Figure 7 shows that catalyst B is capable of desulfurizing SRN feedstock, giving a total sulfur between 0.38 and 0.69ppm, compared with 0.32 to 0.75ppm for blend naphtha. At 250°C -98% desulfurization is achieved for SRN and 99% for blend naphtha. This shows the effectiveness of catalyst B for both feedstocks. Comparison of catalyst performance

The chemical analysis showed that catalyst B has higher loadings of MO, Co and P oxides than catalyst A. Catalyst B has a higher crushing strength and abrasion resistance and a lower density, which makes it superior to catalyst A in physical properties. In addition, it has a larger pore volume and surface area, which further enhance its activity. However, the loss on ignition for the catalyst B is slightly higher than that of catalyst A. Although these results show the superiority of catalyst B, it is to be noted that catalyst selection based on characterization alone is not sufficient. The choice is generally based on actual performance with different feeds and operating conditions. The performance of the two catalysts with blend naphtha and SRN was compared at a space velocity of

Fuel 1995 Volume 74 Number 9

1259

HDS catalysts by distribution of sulfur compounds in naphtha: J. A. Anabtawi et al. 52 sulfur compounds (mercaptans, sulfides, disulfides, thiophenes and polysulfides), whereas HCN contains only six (mercaptans and one thiophene). Product sulfur content as a function of temperature passes through a minimum, independent of operating conditions. This minimum (at 300°C for blend naphtha and 320°C for SRN) is attributed to HzS recombination reactions to form mercaptans at higher temperatures. Increased space velocity slightly increases the product sulfur content. The gas rate has an insignificant effect on product sulfur. SRN is easier to hydrotreat than hydrocracked naphtha with both catalysts. In terms of characterization and pilot plant performance, catalyst B is better than catalyst A under all operating conditions.

1.L -

1.2 -

.

Blend Naphtha

??

Straight

Run Naphtha

0.1 -

ACKNOWLEDGEMENTS 02-

“I 250

215

300 Temperature

Fignre 7

325

350

375

PC1

The authors wish to acknowledge the support of the Research Institute of King Fahd University of Petroleum & Minerals. The work is a part of KFUPM/RI Project No. 21101 funded by a Saudi refinery. The authors also wish to thank Dr Abdallah A. Shaikh, Mr Javaid Zaidi and Mr Altaf H. Siddiqui for their contributions.

Performance of catalyst B with SRN and blend naphtha

10 h-l, a pressure of 2.85 MPa and a gas rate of 67 11-l (Table 5). The desulfurization activity of catalyst B passes through a maximum (minimum product sulfur) at -300°C for blend naphtha and 320°C for SRN. At higher temperature, desulfurization activity decreases as a result of HzS recombination reactions. Both catalysts were ineffective in significantly changing the density, PONA contents and boiling point distribution. Hence, both characterization and performance data indicate that catalyst B is better than catalyst A.

REFERENCES 1 2 3

Bradley, C. and Schiller, D. J. Anal. Chem. 1986,58, 3017 Buteyn, J. L. and Kosman, J. J. Chromarogr. Sci. 1990,28,47 Farwell, S. 0. and Barinaga, C. J. J. Chromatogr. Sci. 1986, 24, 483

Hyver, K. J. and Diubaldo, D. HP-GC Application Brief 1986 McGaughey, J. F. and Gangwal, S. K. Anal. Chem. 1980,52,2079 Kosal, N., Bhairi, A. and Ali, M. A. Fuel 1990,69, 1012 Karchmer, J. H. Anal. Chem. 1958,30,80 Ali, M. F., Perzanowski, H. and Koreisk, S. Fuel Sci. Technol. Znt. 1991,9,397

CONCLUSIONS 1. HCN is higher in aromatics and naphthenes but lower in paraffins and sulfur than SRN. The SRN contains

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Fuel 1995 Volume 74 Number 9

9

Hutte, R. S., Johansen, N. G. and Legier, M. F. J. High Resolut. Chromatogr. 1990, 13,421

10 11

Marcelin, G. J. Chromatogr. Sci. 1977, 15, 560 Seluky, M. L. Chromatographia 1971,4,425