Design Parameters for Diesel Hydro Desulfurization (DHDS)

 

Ashok Kumar Popuri*

Vignan’s Foundation for Science, Technology and Research, Vadlamudi, Guntur (Dist.), Andhra Pradesh, India.

 

ABSTRACT:

Apart from all gaseous contaminants in air, sulfur dioxide is considered to be the principal pollutant. The emission of sulfur dioxide is generally caused by combustion of sulfur bearing fuels. This further gets converted into sulfuric acid in atmosphere as a result of its reaction with oxygen and moisture. This air borne acid is responsible to damage steel buildings, bridges and machinery. Hence there is a major need to decrease sulfur percentage in the environment in order to lead a better and healthy living. As we can see the world runs on energy, for which fossil fuels are the main constituents. As these all are the complex network of hydrocarbons, when they are combusted or utilized, the products or effluents are somewhat harmful to the atmosphere. Sulfur is one such effluent, which seriously harms the environmental conditions. So this has to be recovered up to appreciable levels. In India diesel is mostly utilized as fuel and it is up to 70%. So in order to reduce the sulfur content diesel is chosen as fuel oil. The reduction of sulfur is done by hydro desulfurization and the process is termed as diesel hydro desulfurization (DHDS). This is achieved by converting the mercaptane state sulfur to hydrogen sulfide (H₂S) by reacting it with hydrogen alone on a cobalt molybdenum catalyst. By this the sulfur content is reduced from 1 wt% to 0.25 wt%. This is further reduced to 0.05 wt% using trickle bed reactors.

 

 

INTRODUCTION:

SRU-II is designed to recover sulfur from fuel gas, sour water stripper gas and acid amine gas¹. The LO-CAT-II system is a liquid oxidation process, which removes H₂S from gas stream by converting it to elemental sulfur². It is designed to yield 677kg/hr of elemental sulfur at removal efficiency of 99.68%³. Concentration of H₂S in sweet fuel gas is 100 ppm and in vent fuel gas is 10 ppm⁴.

 

LO-CAT Technology is low pressure and low temperature isothermal process and have high sulfur removal efficiency⁵. LO-CAT Technology has been supplied by ARI (Air Resource Incorporation) USA which earlier known as wheelabrator clean air system and now presently it is known as US-filter USA⁶. The process has derived from the name LO-CAT as the reactions are accomplished in the aqueous medium⁷.

 

The reaction is carried out in water solution containing iron⁸. Irons are capable of removal of electrons from sulfide ions to from elemental sulfur⁹. In can transfer electrons to O₂ in the regeneration process¹⁰. Iron is chosen because it is inexpensive and nontoxic¹¹. In this process iron is not consumed, but take part in the reaction for transfer of electrons for this ARI-340 is essential¹². LO-CAT process is designed to minimize thiosulfate formation¹³.

 

Nitrogen purging is required for few seconds when ever SFG is cut off to absorber otherwise reaction will takes place inside spargers thus sulfur formed will deposit inside sparger nozzles resulting chocking¹⁴. It is not only effecting unit processing efficiency but also effects upstream units operation due to high pressure drop across the spargers¹⁵.

 

FG is introduced through an inverted U bend to prevent solution back up to SFG spargers provided with neoprene hoses at the tip¹⁶. The neoprene hoses provided to avoid gas sparger in the absorber to get a plugged by sulfur practices¹⁷.

 

When air is bubbling through the solution, the ferrous iron gets oxidation into ferric icons¹⁸. Air is introduced for it only oxidation/regeneration in the oxidizer, but it will prevent all mechanical hazards¹⁹. To prevent hydrocarbons entering to oxidizer with LO-CAT solution and to prevent potential hazard excess of air above process requirement will add²⁰.

 

There streams are routed to SRU, they are SFG, SWG and amine acid gas²¹. In which SFG routed to absorber column, SWG and amine acid gases are directed to oxidizer reaction chamber²². SFG enters to KO drum and liquid water should be removed from bottom and then feed is sent to coalescer²³. It is acting as a filter to remove any traces of liquid carrier in fuel gas then feed is routed to absorber from the bottom, at the same time LO-CAT solution also enters from the top of the column²⁴. LO-CAT solution is essential for absorption of H₂S from fuel gas. Sweet fuel gas goes to wet gas knock out put where the traces of liquid settled at the bottom of the KO pot²⁵. Fuel gases go to flare LO-CAT settled at bottom of the KO pot. A fuel gas goes to flare. LO-CAT solution is routed to oxidation chamber²⁶. It consists of seven zones in the order of reactor, oxidizer-I, oxidizer-II, transition zone, oxidizer-III, de-gas zone, and absorber. Solution form flash drum enters into the reaction zone where all chemicals of ARI-340, 350, 360, 400, 600, caustic and NALCO are added²⁷.

 

MATERIAL AND METHODS:

In the flash drum some of the absorbed hydrocarbons in the LO-CAT solution are flashed off as a low pressure fuel gas. The dissolved hydrocarbons, which reach the oxidizer, will be insufficient quantity to be within the lower explosive limit. Therefore to minimize a potential hazard, additional air above the process requirements is added to dilute the oxidizer flue gas to approximately 25% of the explosive limit. The desorbed fuel gas flows out from top of the flash drum through demister pad and it is compressed in the LP gas compressor and routed to sweet fuel gas header or flare header depending on the load. Demister pad is provided to prevent the liquid carryover to LP compressor. The LO-CAT solution free of hydrocarbon flows out from the bottom and is delivered to oxidizer. The LO-CAT solution returning from the absorber via solution flash drum has to be regenerated. This is accomplished in the oxidizer vessel. The oxidizer is a concrete vessel with seven concreted chambers separated by vertical baffles and weirs. All the chemicals ARI-340/350/400/600 and NaOH are charged in the chamber. LO-CAT solution flows from the reaction chamber to the oxidizer-I, from oxidizer-I to oxidizer-II and from oxidizer-II to transition zone solution flow over the weirs and from the transition zone solution to the oxidizer-III. From oxidizer-III the solution overflows to the degas chamber. From degas chamber the solution flows to the absorber section and from absorber section to the reaction chamber.

 

Compressed air is discharged to oxidizer, which is distributed to three oxidizers, I, II and III. To dilute the hydrocarbon vapors entering oxidizer with LO-CAT solution and prevent potential hazard of formation of explosive mixture, additional air above the process requirement is added to dilute the oxidizer vent gas. Oxidizer is operated at 100 mmH₂O pressure. It is important that optimum oxidizer airflow should be maintained at all times. If the oxidizing air is too low Fe⁺³ regeneration will not proper and it will affect H₂S absorption.

 

The LO-CAT solution, after being oxidized, enters degassing section and DM water make up is provided at degassing section. To create a draft to vent out all unabsorbed gases in the oxidizer to stack. The AAG and SWG directly enter into the absorbing section of oxidizer. DM water flushing connection is provided for both AAG, SWG spargers to give blasts to clear any sulfur deposits in the sparer nozzles. Overhead sprays are provided in the reaction chamber, transaction chamber and degas section of the oxidizer. These are provided to wet sulfur particles floating on the LO-CAT solution in the Oxidizer. LO-CAT solution with suspended sulfur particles is drawn from the oxidizer degas chamber to the sulfur settler. In the sulfur settler the solid sulfur is separated by gravity. The sulfur is allowed to concentrate in the conical section from where it is pumped to horizontal vacuum belt filter, which filters sulfur from sulfur slurry. LO-CAT solution is separated from the slurry and is collected in the filtrate receiver plot. The sulfur cake containing some LO-CAT solutions is washed with DM water and finally gets discharged to re-slurry tank. DM water is added to re-slurry tank. A mixture is provided to maintain uniform concentration in the re-slurry tank. This re-slurry is then goes to the sulfur melter. It is maintained at a pressure of 2.5 to 3.5 kg/cm² to prevent the solution from boiling at the melter temperature. The sulfur slurry passes downward through the melter where the sulfur is melted by heat exchanger with steam. The solution and melter sulfur separated and settles to the bottom. The top solution from the separator flows to flash drum for separation. The molten sulfur is removed from the bottom of the sulfur separator and routed to the molten sulfur storage tank.

 

RESULTS:

Material Balance:

Table 1: Coalescing filter

Streams	Input	Output
Sour fuel gas	9465.78 kg	9465.78 kg
Total	9465.78 kg	9465.78 kg

 

Absorber:

The inputs are sour fuel gas from coalescing filter and LO-CAT solution from reaction chamber and outputs are solutions to flash drum, sweet gas and flare.

 

Table 2: Sour fuel gas composition (input)

Components	Weight (kg)	Weight %
H2S	90.24	0.9533
CO2	399.77	4.2233
H2	202.95	2.144
CO	77.244	0.8160
C1	1327.99	14.0294
C2	809.52	8.5521
C2	997.91	10.5423
C3	1004.044	10.61
C3	756.07	7.9874
C4	120.809	1.2763
n-C1	698.04	7.3744
1-C4	493.68	5.2154
C3	626.14	6.6148
N2	1861.3686	19.66
Total	9465.78	99.99

 

Table 3: Solution to absorber (input)

Components	Weight (kg)	Weight %
H2O	1156419.9	84.76
Fe	1080.04	0.079
NaOH	0.28021	0.00002
NaHCO3	3.22163	2.36
Na2S2O3	162856.9	11.93
Sulfur	5450.33	6.399
Total	1364266.5	99.98

 

Table 4: Solution to flash drum (output)

Components	Weight (kg)	Weight %
H2O	1156243.03	84.85
C2O	118.233	8.676x10-3
H2	2.627	1.93x10-4
CO	1.0838	7.953x10-5
C1	21.788	1.6x10-3
C2’	36.915	2.71x10-4
C3’	48.147	3.53x10-3
C3	11.358	8.335x10-4
C4’	4.164	3.056x10-4
n-C1	9.14	6.71x10-4
1-C4	4.3663	2.8x10-4
C3”	11.841	8.7x10-4
N2	31.3824	2.303x10-3
Fe	1080.042	0.079
NaHCO3	30536.1	2.241
Na2S2O3	6200.46	0.46
Total	1362756.4	100.0

 

Table 5: Sweet gas (output)

Components	Weight (kg)	Weight %
H2O	177.055	1.87
H2S	1.3393	0.014
CO2	202.35	2.138
H2	200.33	2.113
C0	76.27	0.806
C1’	1306.20	13.802
C2’	772.54	8.163
C2	980.07	10.355
C3’	993.206	10494
C4’	117.15	4.202
n-C1	688.9	7.27
1-C4	489.89	5.176
C3”	614.30	6.49
N2	1858.0	19.63
Total	9183.2	99.9

 

Table 6: Percentages of components absorbed

Components	% Absorbed
H2O	0.015
H2S	98.5
CO2	49.38
H2	1.29
N2	0.1809
Other hydrocarbons	24.0043
NaHCO3	5.215
Na2CO3	0.675

Moles of H₂S in = 2.6481; Moles of sweet = 0.0393; Moles of H₂S out = 2.6088; % of H₂S absorbed = 2.6088 / 2.64981 x 100 = 98.5%

 

Flash Drum:

The input is solution to flash drum and outputs are low pressure fuel, solution to oxidizer and flare.

 

Table 7: Solution to flash drum (input)

Components	Weight (kg)	Weight %
H20	1156243.03	84.85
CO2	118.233	8.676x10-3
H2	2.627	1.93x10-4
CO	1.0838	7.9523x10-5
C1’	21.788	1.6x10-3
C2’	36.915	2.71x10-3
C2	18.45	2.50x10-4
C3’	11.358	8.335x10-4
C4’	4.164	8.056x10-4
n-C1	9.14	6.7x10-4
1-C4	4.3663	2.8x10-4
C3”	11.841	8.7x10-4
N2	31.3824	2.303x10-3
NaHCO3	30536.1	2.241
Na2CO3	6200.46	0.46
Na2S2O3	162856.96	11.951
H	5.266	3.86x10-4
S	5530.71	0.4058
Fe	1080.042	0.079
Total	1362756.4	100.00

Sulfur to storage = 631.4 kg

 

Absorber

 

Moles of H₂S in = 2.6481; Moles of sweet = 0.0393; Moles of H₂S out = 2.6088

 

Flash Drum

 

Moles of H₂S in = moles of H₂S out = 2.608

 

Oxidizer

 

Moles of H₂S in = 2.608; Moles of H₂S = 0.3103

 

Gas in (Sour water stripper gas)

 

Moles of H₂S in amine = 0.0683; Total = 2.9865 moles; Total moles of H₂S in = 2.9865

 

Total moles of H₂S out = 2.9338; % of sulfur recovered = (2.9338/2.9865) x 100 = 98.24%

 

Energy Balance:

Basis: One hour of operation.

 

Sample Calculations:

 

Hydrogen sulfide (H₂S):     C_P / R= {A+BT + CT² + DT^-2}dT = 164.74 cal/mol.⁰K

 

There are two inputs to the absorber

 

Table 8: Sour fuel gas from the coalescing filter

Components	Mass flow rate	CP∆T	Enthalpy(kcal/ok)
H2O	164.74	2.6781	456.25
CO2	9.0838	179.63	1631.7
H2	100.473	136.4	13704.7
CO	3.3570	138.4	464.6
C1’	82.741	24.4866	6994.11
C2’	24.4866	106.9	2617.6
C2	33.1755	128.07	4248.8
C3’	23.8547	156.62	3736.12
C4’	17.1407	181.31	3107.8
1-C4	8.34913	217.04	1842.95
N2	66.43	135.17	8979.3

Total enthalpy = 47680.56 kcal/⁰k

 

Table 9: LO-CAT Solution from reaction chamber

Components	Mass flow rate	CP∆T	Enthalpy (kcal/ok)
H2O	64174.25	180.3	11570617.2
Fe	19.4532	120.47	2343.53
NaOH	0.0070	443.8	3.1066
NaHCO3	383.481	211.15	80972.24
Na2HCO3	58.9001	28.9	17022
S	170.0043	110.66	18812.7

Total Enthalpy = 11678046.05 kcal/⁰k; Total inlet enthalpy (H₁) = 11725726.61 kcal/⁰k

 

There are three streams coming out of the absorber.

 

Table 10: Solution to flash drum

Components	Mass flow rate	CP∆T	Enthalpy (kcal/ok)
H2O	61464.73	541.6	34741455.2
CO2	2.6865	548.2	1472.74
H2	1.3004	409.73	532.8
CO	0.0471	415.8	19.58
C1’	1.3575	258.24	350.56
C2’	1.1166	327.78	365.99
C2	0.6133	404.24	247.9
C3’	0.2575	557.8	143.6
C4’	0.0742	737.5	54.7
1-C4	0.0751	669.17	50.25
Fe	19.4532	365.23	7104.9
NaHCO3	363.4821	644.3	234191.57
Na2O3	58.5004	28.9	1690.66
Na2S2 O3	1030.883	34.9	35950.08
H	5.2137	4.97	25.9
S	172.5112	335.8	57929.26
N2	1.12	406.12	454.8

Total Enthalpy = 35082590.35 kcal/⁰k

 

Table 11: Sweet gas

Components	Mass flow rate	CP∆T	Enthalpy (kcal/ok)
H2O	9.8254	541.6	5321.4
H2S	0.0393	496.4	190.51
CO2	4.598	548.2	2520.26
H2	99.1734	409.73	40634.31
CO	3.3149	415.8	1378.3
C1’	81.3837	258.24	21016.5
C2’	23.368	327.78	7659.56
C2	32.5822	404.24	13171.03
C3’	15.9967	557.8	8922.9
C4’	2.0875	737.5	1539.5
1-C4	8.4262	669.17	5638.6
N2	66.3099	406.12	26929.77

Total Enthalpy = 14628.177 kcal/⁰k; Total inlet enthalpy (H₁) = 35228858.53 kcal/⁰k

 

Table 12: Flare

Components	Mass flow rate	CP∆T	Enthalpy (kcal/0k)
CO2	1.7993	548.2	986.37
H2	0.0005	409.73	0.20448
CO	0.005	415.8	2.079
C1	0.0001	258.24	0.258
C2’	0.002	327.78	0.655
C3	0.8865	557.8	494.48
n-c1	9.9999

Total Enthalpy = 1483.8243kcal/⁰k

 

Total output enthalpy (H₂) = 35230242.35 kcal/⁰k

 

Input-Output = H₁- H₂ = 11725726.61-352303423.35 = -23504615.74 kcal/⁰k

 

H₂S moles                                                ∆H

 

2 moles                                                    - 23504615.74 kcal/⁰k

 

1 mole                                                     - 8876365.461 kcal/⁰k

 

∆H = -8876365.461 kcal/⁰k                       

 

Melter

 

There is only one input and three outputs.

 

Table 13: Reslurry to melter (input)

Components	Mass flow rate	CP∆T	Enthalpy (kcal/0k)
H2O	29.6184	834.6	24719.51
Fe	0.0003	1301.6	039048

 

Table 14: Separator flash (output)

Components	Mass flow rate	CP∆T	Enthalpy (kcal/0k)
H2O	1.881	867.4	1631.57

 

Table 15: Separator flash (output)

Components	Mass flow rate	CP∆T	Enthalpy (kcal/0k)
H2O	27.7	867.4	24026.98
Fe	0.0003	1354.9	0.4067

Total heat out            = 24027.38 + 1631.57 + 1794.72 = 27453.67 kcal/⁰k

 

Heat in – Heat out = (Heat of reaction) = 24719.9 - 27453.67 = - 2733.77 kcal/⁰k

 

∆H = H₁- H₂ = -2733.77 kcal/⁰k

 

Design of Heat Exchanger:

4473 kg/hr of sulfur at 45⁰C enters and is heated to 132⁰C by exchanger with steam at a temp of 135⁰C to 110⁰C. ( MCp∆T)_{hot fluid} = ( MCp∆T)_{cold fluid}; M_h = 52352.3 kg / hr; Q = 73220.524 J/s

 

LP steam = Shell side hot fluid; K = 0.0324 w/m k; C_P = 0.2014 J/g k; = 0.1 Ns/m; = 115 kg/m³; Sulfur slurry = Tube side cold fluid; K = 0.29 w/m k; C_P = 0.71 J/g k; = 0.1 Ns/m; = 115 kg/ m³; Assume U₀ = 20 w/ m² k

 

 

 

 

 

Area of 1 tube = 0.2992 m²; No. of tubes per pass = 235 for 2 passes; Tube cross sectional area _; Area per pass = 235 x 0.0001727 = 0.04058 m²

 

Volumetric flow rate (tube side) = = 0.01008 m³/sec

 

Tube side velocity, u₁ =

 

Bundle and shell diameter for 2 tube passes and for triangular pitch

 

k₁= 0.249m n₁ = 2.207; D_b = 581.05 mm

 

For a split ring floating heat exchanger the shell clearance is 61 mm

 

D_s = 581+61=642 mm

 

Tube side heat transfer coefficient

 

J_h = 3.5 x 10^-3

 

 

Shell side heat transfer coefficient

 

Baffle spacing = D_s/5 = 642/5= 128 mm

 

 

 

Volumetric flow rate on shell side

 

Shell side velocity

 

 

 

As it is a 25% cut segmental baffle

 

J_h = 2.1 x 10^-3

 

Nu = J_h Re (Pr) ^0.33 = 2.1 x 10^-3x85171.19x (0.8702)^0.33 = 170.838

 

 = 409.40 w/m² k

 

Overall heat transfer co efficient

 

 

Fouling resistance Rd_o for shell side fluid = 0.0001

 

Fouling resistance Rd_i for tube side fluid = 0.0001

 

 

 

As the fraction lies in between 0 and 0.30, it is accepted.

 

For shell side

 

Friction factor = 3.6 x10^-2 = j_f

 

Tube side pressure drop

 

 

Friction factor j_f = 6 x 10^-3

 

N_p = no of passes = 2

 

 

DISCUSSION:

Split ring floating head 1 shell side and 2 tube side passes, 470 mild steel tubes each 5m long, ¾" outer diameter with 2mm thick and 14.83mm internal diameter; Training pitch with P_t = 23.18mm; Heat transfer area = 140.66 m²; Shell internal diameter = 642 mm = D_s; Baffle sparing l_b = 128.4mm – 25% cut segmental baffle; Tube side heat transfer coefficient h_i = 180.52 w/m²k; Shell side heat transfer coefficient h_o = 409.40; Overall coefficient, U_0,cal = 20.6w/m² k; Fouling factor for tube side = 0.0001 m²k/w; Fouling factor for shell side = 0.0001 m²k/w; Pressure drop on shell side, ; Pressure drop on tube side,

 

CONFLICT OF INTEREST:

The authors declare no conflict of interest.

 

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Accepted on 07.09.2019           © RJPT All right reserved

Research J. Pharm. and Tech 2020; 13(5):2413-2419.