Fahim M.A., Sahhaf T.A., Elkilani A.S. Fundamentals of Petroleum Refining

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Coke +

Water

Coke grinding

Gasifier

Slag

Fuel Gas

Sulphur

Removal

Fuel Gas

Sulphur

recovery

Sulphur

Gas turbine

Steam

turbine

Boiler

Water feed

Exhaust

Gas

Power

Plant

Power

Figure 13.7 IGCC plant

334 Chapter 13

The following reactions are involved:

Gasification with O

C þ 1=2O

! CO; DH ¼123:1kJ= mol ð13:1Þ

Combustion with O

C þ O

! CO

; DH ¼405:9kJ=mol ð13:2Þ

Gasification with CO

C þ CO

! 2CO; DH ¼ 159:7kJ=mol ð13:3Þ

Gasification with steam:

C þ H

O ! CO þ H

; DH ¼ 118:9kJ=mol ð13:4Þ

Most of the O

fed to the gasifier is consumed in reactions (13.1) and

(13.2). These reactions generate heat to increase temperatures at which

chemical bonds are broken and gasification reactions (13.3) and (13.4)

become favourable. If the gas is considered for a subsequent synthesis, the

water-gas shift reaction is involved:

CO þ H

O ! H

þ CO

; DH ¼40:9kJ=mol ð13:5Þ

A water-gas shift reaction becomes important for adjusting the H

/CO

ratio. Otherwise, the primary objective is to maximize the content of

combustibles such as CO and H

.CH

can also be formed at low gasifica-

tion temperatures. Sulphur in the feed is mainly converted to H

S, and a

small amount of COS. Traces of S

and CS

can also be formed. Most of the

nitrogen in the feed is converted to N

. However, small amounts of HCN

and NH

are also formed. HCl is the main Cl-containing product formed

during gasification.

The role of the gasifier in a typical refinery is shown in Figure 13.8.

Table 13.3 Sulphur and nitrogen compounds emissions (Phillips

and Liu, 2002)

Air emissions (mg/normal m

)

Typical IGCC

European standard for

conventional power station

10 130

30 150

Particulates 10 16

Residue Upgrading 335

Crude

NHT Reformer

ISO

Alkylation

DSL HT

MTBE

GO HT

FCC

Coker

Gasifier

LSR

HSR

Diesel

VGO

Pitch

Steam

Power

FCC

Gasoline

Fuel Oil

Diesel

MTBE

Gasoline

Crude Distillation Unit

Figure 13.8 Refinery flowsheet with gasi fication (note that there is no final residue in the products)

336 Chapter 13

Example E13.3

Fuel (C

) at 800



C is combusted in a gasiﬁer at 1200



C. Air is available at

200



C. 10 kmol/h steam, available at 150



C, is also introduced to the gasi ﬁer.

The dry basis ﬂue gas analysis is as follows: 12 mol% CO

, 5 mol% CO, 2 mol%

, 80 mol% N

and 1 mol% SO

. On the basis of 100 kmol/h of dry ﬂue gas,

ﬁnd the chemical formula of the fuel burned C

and calculate the gasiﬁer

heat load.

Solution:

Basis 100 kmol/h dry gas

From S-balance moles of S in the fuel (o) ¼ 1 kmol/h

From C-balance moles of C in the fuel (n) ¼ 12 þ 5 ¼ 17 kmol/h

in ¼ N

out ¼ 80 kmol/h

in ¼ 80/0.79 (0.21) ¼ 21.265 kmol/h

O-balance:

for carbon burn ¼ 12 þ 2.5 ¼ 14.5 kmol

remain for H burn ¼ 21.26 5  14.5  2 ¼ 4.765 kmol/h

H-balance:

2H þ 0:5O

¼ H

H ¼ 4:765ð2Þ=ð0:5Þ¼19:06 kmol = h

Then the chemical formula of the fuel is C

¼ C

S. UNISIM can be

used to ﬁnd th e heat capacity and other properties of this hypothetical com-

pound needed for calculation of the burner heat load.

Heat capacity ¼ 0.236 kJ/kmol



Heat of formation ¼ 511,950 kJ/kmol

Molecular weight ¼ 255.4 kg/kmol

Liquid density ¼ 881.97 kg/m

Heat load on the reactor ¼ q ¼

out



There are three reactions that take place

C þ O

! CO

; DH

¼393:5  10

kJ=kmol

H þ 0:25 O

! 0:5H

O; DH

¼241:8  10

kJ=kmol

S þ O

! SO

; DH

¼296:9  10

kJ=kmol

C þ 0:5O

! CO; DH

¼110:52 kJ=kmol



12ð393:5Þþ19ð241:8Þþð296:9Þþ5ð110:52Þ





ð1000Þ¼1:017  10

¼ 0:03611 kJ=mol; Cp

¼ 0:02895 kJ=mol; Cp

¼ 0:0291 kJ=mol

Residue Upgrading 337

¼ 0:029 kJ=mol; Cp

¼ 0:03891 kJ=mol; Cp

¼ 0:03346 kJ=mol

out

CpðT

out

 T

ref

Þ¼½12ð0:03611Þþ5ð0:02895Þþ

2ð0:0291Þþ80 ð0:029Þþ1ð0:03891Þþ

19:06ð0:03346Þð1000 Þð1200  25Þ¼4:269  10

¼ n

steam

CpðT

T

ref

Þ¼10ð48; 168Þþ

80ð0:029Þð1000Þð200 25Þþ21:265ð 1000Þð0:0291Þð200 25Þþ

ð17 þ 19 þ 1Þð1000Þð0:236Þð800  25Þ¼6:76 10

q ¼1:017  10

þ 4:269  10

 6:76  10

¼1:3  10

13.4. Catalytic Processes

Table 13.4 summarizes the catalytic hydroconversion processes.

13.4.1. Residue-fluidized Catalytic Cracking

Residue-fluidized catalytic cracking (RFCC) is essentially an evolution of

the well-proven FCC process. To accommodate residue, licensors and

catalyst suppliers have modified the traditional FCC technology in key

areas, including:



Catalyst design



Feed injection



Riser design



Catalyst/oil product separation



Regenerator design



Overall reactor/regenerator design

The design of catalysts for residue cracking requires that both the zeolite

and matrix components offer high stability, low coke, and good metal

tolerance properties compared to the VGO operation.

Each major licensor has its own proprietary nozzle design for injecting

feed into the base of the riser. Efficient mixing of feed with a catalyst is

particularly important when residue is processed. Modern catalysts allow

a substantial reduction in residence time in the riser, providing greater

selectivity and control over required distillate product.

338 Chapter 13

Efficient catalyst regeneration is the key to FCC process performance.

Two approaches are usually considered:



Two-stage regeneration, allowing improved regenerator temperature

control and combustion air distribution



Catalyst cooling in which a portion of the catalyst is cooled externally

to the regeneration, thereby preventing excessively high regenerator

temperatures which could harm the catalyst

Figure 13.9 shows a simplified flowsheet of the RFCC process. RFCC

consists of an absorber, debutaniser, depropaniser and propane-propylene-

splitter. A three-cut gasoline splitter is used to produce light and heavy

gasoline, with the bottom stream of the gasoline splitter alternatively sent to

LCO or to HCO. Adip, caustic and Merox treatments, propylene drying,

polishing units and sour water stripper are installed within the RFCC

complex.

Table 13.4 Residue hydroconversion processes (Scheffer et al., 1998; Ancheyta and

Speight, 2007)

Reactor

type Process Licenser

Fixed bed Continuous catalyst replacement

(OCR)

Chevron Lumus

Global (CLG)

UFR, Up-ﬂow reactor Shell (Bunker ﬂow)

Hycon, Bunker type reactor Axen (Swing

reactor)

Hyvahl, swing reactor concept Shell

IFP (Axen)

Ebullated

bed

H-oil Axen (HRI/IFP)

T-star Chevron

LC-ﬁning ABB Lummus

Amoco oil (BP)

Slurry

system

Microcat-RC ExxonMobil

Veba combi-cracking Veba

Hydrocracking distillation

hydrotreating (HDH)

Oel

Cash, Chevron activated slurry

hydroprocessing

Intevep

EST, Eni slurry technology Technologies

CanMet Energy Research

Laboratories, Canada

Eni

Chevron

Snamprogetti

Residue Upgrading 339

Fluidized bed

Reactor

Feed

Fractionator

Heavy gas oil

Light gas oil

Absorber

Debutaniser

Depropanizer

splitter

Gases

Propylene

Propane

Butane / Butene

Light catalytic gasoline

Heavy catalytic gasoline

Gasoline Striper

Figure 13.9 RFCC process flowsheet

340 Chapter 13

Example E13.4

The capacity of a RFCC unit is 40,000 BPD, and the API of the feed oil is 22.

The RFCC unit works at a conversion of 70%. The following operating data

were obtained from a RFCC regeneration unit:

Catalyst

Regenerator

Spent Catalyst +

coke from the RFCC

550

°C

Regenerated

Catalyst

720

°C

Air

200

°C

Flue gas

720

°C

Composition of the regenerator ﬂue gas (dry basis: excluding water fraction):

0.5 mol%

0.2 mol%

CO 3 mol%

81.3 mol%

15 mol%

(A) Calculate the amount (kmol/h) of the flue gas.

(B) Estimate the flow rate of the catalyst (ton/min).

Available information:

¼ 34:777 kJ=kmol



C; Cp

¼ 41:014 kJ=kmol



¼ 86:62 kJ=kmol



¼ 32:92 kJ=kmol



C; Cp

¼ 54:4kJ=kmol



¼ 32:48 kJ=kmol



air

¼ 29:88 kJ=kmol



C; Cp

catalyst

¼ 1:11 kJ=kg K;

coke

¼ 21:1kJ=kg K; T

ref

¼ 15



Coke heat of combustion ¼ 0.393  10

kJ/kmol

Sulphur heat of combustion ¼ 0.293  10

kJ/kmol

Hydrogen heat of combustion ¼ 0.237  10

kJ/kmol

Residue Upgrading 341

Solution:

(A) Using Table 8.6

Coke wt% ¼ 0.05356 (%conv)  0.18598 (API

) þ 5.966975 ¼ 5.6246 wt%

Feed amount ¼ 40,000 (13.45) ¼ 538,000 lb/h ¼ 1,186,085 kg/h

Carbon in feed ¼ 66,712.5 kg/h ¼ 5,559.4 kmol/h

Flue gas analysis: 15 mol% CO

and 3 mol% CO

Carbon balance on the ﬂue gas

5559:4 ¼ 0:15 flue þ 0:03 flue

Then, Flue gas ﬂow rate ¼ 30,885 kmol/h

ðBÞ N

¼ 0:813ð30; 885:6Þ¼25; 110 kmol = h

Air in ¼ 25,110/0.79 ¼ 31,785 kmol/h

in ¼ 6,675 kmol/h

used in C burn ¼ 0.15(30,885) þ 0.03(30,885)/2 ¼ 5096 kmol/h

used in S burn ¼ 0.002(30,885) ¼ 61.77 kmol/h

remain for H

O ¼ 6,675  5096  61.77  0.005(30,885) ¼ 1,363 kmol/h

O produced ¼ 2(1,363) ¼ 2726 kmol/h

Flue gas heat ¼

ðT  T

ref

ð720  15Þ½0:005ð30; 885Þð34:777Þþ4633ð54:4Þþ927ð32:92Þ

þ61:777ð86:62Þþ25 ; 110ð32:48Þþ2726ð41:014 Þ

¼ 866; 361:350 kJ=h

Energy balance around regenerator:

Heat in ¼ Heat out ¼ Flue gas heat þ m

cat

ð1:11Þð720  15Þ

Heat in ¼ 31; 785ð29:88Þð200  15Þþm

cat

ð1:11Þð550  15Þþ66; 713ð21:1Þ

ð550  15Þþ2726 ð0:237  10

Þþ5559ð0:393  10

þ61:777ð0:293  10

Þ¼3; 850; 548; 172 þ 593:85 m

cat

3; 850; 548; 172 þ 593:85 m

cat

¼ 886; 361; 350 þ m

cat

ð1:11Þð720  15Þ;

cat

¼ 296:7 ton=min

13.4.2. Hydroprocessing

Hydroprocessing (refer to Chapter 7) consumes a substantial amount of

hydrogen and is relatively high in investment and operating costs compared

with thermal processes. However, it has a high product selectivity of light

products. In addition, hydroprocessing offers better selectivity of liquid yield

(85% and higher) than any other process discussed above. The residue HDT

improves the quality of liquid products, and residue HCR is the most

rigorous form of residue hydroprocessing. Various HDT processes (e.g.,

342 Chapter 13

HDS, HDN, HDM and HCR) developed over the years now provide the

necessary toolbox, at the disposal of industry, to achieve its objectives.

Furthermore, the technology continues to improve and diversify consider-

ably. Therefore, not only the better product selectivity is one characteristic of

hydroprocessing, but we can also obtain cleaner fuel specifications. However,

the race to high activity per volume unit for a long run is still a matter of

catalyst formulation and some process parameter optimizations. Figure 13.10

shows typical residue upgrading processes, including hydroprocessing.

Example E13.5

1000 kg/h VR, with the following properties: CCR ¼ 10 wt%, Nickel con-

centration is 150 wppm, Vanadium concentration is 400 wppm and 5 wt%

coke, is introduced to a hydrotreating (HDT) process. 10 kg of cat alyst with a

surface area of 140 m

/g and a void volume of 0.8 cm

/g are used. Knowing

that the vanadium component’s density is 4700 kg/m

, the nickel component’s

density is 5500 kg/m

and the carbon density is 1900 kg/m

, calculate the

maximum contaminant removal efﬁciency.

Solution:

Volume occupied by coke ¼ 0.05 (1000)/1900 ¼ 0.0263 m

Volume occupied by nickel ¼(150/1 10

) (1000)/5500 ¼2.727 10

5

Volume occupied by vanadium ¼(400/1 10

) (1000)/4700 ¼8.5 10

5

Total volume ¼ 0.02643 m

Available void volume ¼0.8 cm

/g(10,000g)(1m

/1 10

) ¼0.008 m

% removal ¼ (0.008/0.02643) ¼ 30%

CDU

Crude

Gas

Hydroprocessing

SDA

Gasification

Hydroisomerization

Fisher Tropesch

Synthesis

High Value Middle Distillate

Asphalt

Ash

VR or AR

Figure 13.10 Combination of residue upgrading processes including hydroprocessing

Residue Upgrading 343