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

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This is governed by the unit system pressure set by the pressure required at

the hydrogen product export header.

11.3.5.5. Feed Type

Light hydrocarbons constitute suitable feed to the steam reformer.

Table 11.1 shows the reformer outlet composition (on dry basis) for several

feeds.

The light hydrocarbons in the feed are first converted to methane. Then

the methane–steam reforming reactions take place. A methane rich feed

gives higher hydrogen purity.

11.3.5.6. Space Velocity

Lower space velocity favours the reaction as residence time increases.

However, this leads to reduced output gas.

11.3.5.7. Catalyst Activity

Higher catalyst activity favours the reforming reaction. The catalyst is

poisoned by sulphur, chloride and arsenic. The catalyst is poisoned by

sulphur due to slippage of mercaptan and hydrogen sulphide along with

the feed. There is also the possibility of catalyst poisoning due to sulphate

carry-over with water mist in steam and dissolved H

S in impure boiler feed

water. The catalyst can also be poisoned by carry-over of arsenic present in

ZnO. Chlorine and phosphorous poisoning can come from boiler feed

water.

As the steam reforming reaction decreases over time due to catalyst

poisoning, the hydrogen purity can be maintained by increasing the furnace

outlet temperature and increasing the steam to carbon ratio.

11.3.6. Reformer Process Simulation

Process simulators have become essential tools for the design and perfor-

mance evaluation of petroleum refining processes and process equipment.

In this section the process simulator UNISIM (UNISIM, 2007) will be

Table 11.1 Reformer outlet composition for different feeds at 850



C, 24 bar and

steam to carbon ratio of 4

Feedstock Methane Natural gas LPG Naphtha

Composition (vol%)

3.06 2.91 2.39 2.12

CO 12.16 12.62 13.62 14.17

9.66 10.40 12.73 14.19

75.12 73.98 71.86 69.52

– 0.38 – –

294 Chapter 11

utilized to simulate the reformer furnace as an equilibrium reactor. This is a

reasonable assumption, since the reforming reactions are essentially equilib-

rium reactions. The following example illustrates such simulation.

Example E11.3

Calculate the outlet reformer temperature, synthesis gas composition and the

heat transferred in the reformer furnace for natural gas feed. The composition of

the feed is:

mol%

94.1

4.0

0.8

1.0

0.1

Inlet temperature is 550



C. The steam to carbon ratio is 2.5. Steam is available

at 600



C. Pressure is 20 bar. Assume no pressure drop in the furnace. The outlet

temperature of the reforming synthesis gas is 850



Solution:

On the basis of 100 kmol/h of natural gas feed,

Steam ﬂow rate ¼(2.5)(100)(0.941 þ20.04 þ3  0.008) ¼261.25 kmol/h

Using UNISIM simulator, deﬁne the natural gas stream and the steam. Use the

Peng–Robinson equation of state as the thermodyn amic package. Deﬁne the

reaction set; that is the reactions involved in the process. Enter the stoichiomet-

ric coefﬁcients for each reaction. The process is modelled as a mixer followed by

an equilibrium reactor as shown in Figure E11.3.

A summary of the results is presented in Table E11.3.

The heat transferred in the reformer is 2.258  10

kJ/h.

Mixer

Reformer

Figure E11.3 Simulation of the reformer

Hydrogen Production 295

11.4. Product Purification

The CO in the reformed gas is converted to CO

according to

reaction (11.2). Due to thermodynamic and kinetic considerations, this is

accomplished to two stages: High Temperature Shift Converter (HTSC)

and Low Temperature Shift Converter (LTSC), Since the reaction is

exothermic the equilibrium yield is favoured by lower temperature; how-

ever, the reaction needs a catalyst and the reaction rate favours high

temperature.

11.4.1. High-Temperature Shift Converter

Carbon monoxide reacts with steam at high temperature 300–560



(572–1040



F) in the presence of CuO/FeO or Fe

/Cr

catalyst.

Most of the CO in the process gas is converted to CO

. The remaining

CO in the outlet gas is between 2 and 3%. The reaction is exothermic and is

carried out in a fixed-bed reactor. Temperature affects shift converter

operation in two ways: a higher temperature increases the catalyst activity

and the reaction proceeds closer to equilibrium. At each catalyst activity

level there is an optimum operating temperature. Higher temperature

increases CO in the outlet gas due to equilibrium. Lower temperatures

also increase CO in the outlet gas due to the decrease in catalyst activity.

Multiple catalyst beds with external cooling are used to control the reaction

temperature. When the catalyst is new and the catalyst activity is high, the

optimum temperature is lower for any given flow and composition. This

Table E11.3 Summary of results

Stream 3 Stream 4

Temperature (



C) 579.16 850.00

Molar ﬂow rate (kmol/h) 361.25 529.18

Composition (mol%)

0.26048 0.03880

0.01107 0.00000

0.00222 0.00000

0.00277 0.05223

0.00028 0.00019

O 0.72318 0.28468

CO 0.0 0.10833

0.0 0.51577

296 Chapter 11

lower temperature also prolongs the catalyst life. As the catalyst ages, the

CO conversion can be maintained by increasing inlet temperature, increas-

ing steam flow or reducing space velocity. Thermodynamically, the shift

conversion reaction is not affected by pressure since the number of moles of

reactants and products are equal. At design conditions, CO content at

HTSC outlet is reduced to 2.61 vol%.

11.4.2. Low-Temperature Shift Conver ter

The product gas from HTSC is routed to a boiler feed water pre-heater.

The gas temperature is reduced to 230



C (446



F). Most of the CO is

converted to CO

leaving the CO content less than 0.2 vol%. The catalyst is

CuO/ZnO which is very expensive. It must be protected from sulphur and

both high and low temperatures. Any condensation in the presence of

carbon oxides damages this catalyst. The catalyst temperature should not

exceed 288



C (550



F).

11.4.3. Carbon Dioxide Removal

The gases from the shift converter contain 16–20% CO

, which is removed

by selective absorption in an amine or carbonate solution. Amine absorption

is an effective technique to remove CO

; however, this technique has notable

disadvantages. First, once the amine solution is saturated, the process to

reactivate the solution (i.e., remove the bound CO

from the amine groups

in the solution) for reuse requires a high amount of energy. Second, this

process has a tendency to corrode equipment. Third, over a short period of

time, the amine solution loses viability through amine degradation and loss.

11.4.3.1. Amine Treating

The amine absorber system is designed for the removal of carbon dioxide from

the product gas. The system is highly efficient and results in a single operation

requiring less equipment than other multiple absorbent systems. The carbon

dioxide removal system consis ts principally of an absorber, regenerator and

heat exchangers. CO

in the incoming gas is removed by scrubbing in an

aqueous amine solution. Rich amine solution is regenerated by reboiling. The

heat for reboiling is supplied by the process gas exiting the LTSC.

The amine solution removes CO

by chemical absorption; that is

bonds with the amine. Monoethanolamine (MEA) is usually used.

However, it has two drawbacks: first, it requires higher energy for desorp-

tion of CO

, secondly, carbamates which are very corrosive, are formed

(equation 11.10).

þ 3H

Amine

! OHC

NCOO

Carbamates

þ 2H

OH ð11:10Þ

Hydrogen Production 297

Methylethanolamine (MDEA) has replaced MEA in many units. The

weaker bond created between the amine and CO

, without any carbamates

being formed, makes the regeneration less energy-intensive and the amine

solution less corrosive.

After cooling, the synthesis gas from LTSC flows to the bottom of the

absorber. The CO

content of the process gas is removed by scrubbing

with 15–30% aqueous amine solution.

Rich amine solution from the bottom of the absorber at 65



C (149



is heated to 100



C (212



F) in amine exchangers. Then it is flashed into the

top of the amine regenerator where CO

is stripped from the solution. The

overhead stream (CO

þ water vapour) from the regenerator flows to

the condenser. It is cooled and most water vapour present is condensed.

The CO

vapour stream is vented to the atmosphere. The desorption

efficiency of the regeneration can be measured by the residual CO

of the lean solution. A simplified process flow diagram is shown in

Figure 11.3. Operating variables for the absorption section are absorption

temperature, flow rate and concentration of lean amine solution. Amine

regeneration is affected by heat input in the reboiler, pressure and reflux.

11.4.3.2. Methanation

The purpose of the methanator is to convert the residual CO and CO

methane according to the following reactions:

CO þ 3H

þ H

ð11:11Þ

þ 4H

þ 2H

ð11:12Þ

Steam

Treated Gas

Absorber

Synthesis

Gas

Regenerator

Reflux

Pump

Regenerated amine

Filtration

Fuel Gas

Rich Amine

Acid

gas

Figure 11.3 Amine treating process

298 Chapter 11

Both reactions are exothermic. Methanation is carried out in a fixed-bed

catalytic reactor at temperatures between 300 and 340



C (572 and 644



over a nickel catalyst. At these temperatures, conversion is almost complete

with residual CO and CO

less than 10 ppm. The temperature rise in the

catalytic bed is in the order of 30



C (86



F) for a CO content of 0.3% and

content of 0.1% in the inlet.

11.4.3.3. Pressure Swing Adsorption (PSA)

The reformed gas from the shift converter which contains 65–70 vol%

hydrogen can be purified by adsorption instead of amine treatment and

methanation. The process produces a higher purity hydrogen stream (99.9%).

PSA is a cyclic process involving the adsorption of impurities (CO, CO

and N

) from a hydrogen-rich gas stream at high pressure on a solid

adsorbent such as a molecular sieve. The operation is carried out at room

temperature and at the reformed gas pressure of 20–25 bar (294–368 psia).

Several adsorption vessels (adsorbers) are employed as shown in Figure 11.4.

The feed gas is switched from one adsorption vessel to another. While adsorp-

tion takes place in one vessel, the adsorbent in another vessel is being

regenerated. A complete pressure swing cycle for each adsorber goes like this:



Adsorption takes place in a fresh adsorber producing high purity gas.

The impurities are adsorbed onto the internal surfaces of the adsorbent

bed. When this adsorber reaches its adsorption capacity and no more

impurities can be removed, it is taken off-line, and the feed is switched

to another fresh adsorber.



To recover the hydrogen trapped in the adsorbent void spaces in the

adsorber, the adsorber is depressurised from the product side in the

Cocurrent

Depressurisation

Countercurrent

Depressurisation

Depressurisation Purge

Offgas

Adsorption

Feed Gas

Step 1 Step 2 Step 3 Step 4 Step 5

Figure 11.4 Pressure swing adsorption cycle (Stocker andWhysall,1998)

Hydrogen Production 299

same direction as the feed flow direction (cocurrent), and high-purity

hydrogen is withdrawn. The hydrogen is used internally in the system

to repressurise and purge other adsorbers.



The bed is then partly regenerated by depressurising in a counter-

current flow of gas from other beds, and the desorbed impurities are

rejected to the PSA off-gas.



The adsorbent is then purged with high-purity hydrogen (taken from

another adsorber on cocurrent depressurisation) at constant off-gas

pressure to further regenerate the bed.



The adsorber is then repressurised with hydrogen prior to being

returned to the feed step. The hydrogen for repressurisation is

provided from the cocurrent depressurisation and with a slipstream

from the hydrogen product. When the adsorber has reached the

adsorption pressure, the cycle has been completed, and the adsorber

is ready for the next adsorption step.

In addition to hydrogen production, PSA technology is used for purifying

hydrogen streams from other units in the refinery, in petrochemical

units, the steel industry and hydrogen for fuel cells. The advantages of the

PSA process are:



High purity of hydrogen: 99.9%. Conventional units with amine

treating and methanation seldom achieve purity higher than 98%.



Purity in conventional units depends on the quantity of inerts in the feed.

The PSA process yields over 99.9% purity regardless of feed quality.



The conventional process requires severe steam reforming operating

conditions in the reformer furnace to get over 97% H

purity. The

PSA process allows less severe operating conditions and still achieves

high purity. However, this results in 3–8% unreacted methane in the

purge stream.



Purity can be increased on request.



High efficiency of hydrogen recovery: up to 90%.



PSA technology is more reliable and requires less capital cost.



Operating costs in the PSA process are lower due to lower energy

expenditures. The PSA purge is used as furnace fuel. Considerable

steam is produced and can be exported to other units in the refinery.

11.5. New Developments in Steam Reforming

As the demand for hydrogen increases, and as energy costs increase,

hydrogen manufacture by steam reforming is undergoing continuous

improvements. Some of these recent developments are highlighted below

(Rostrup-Nielsen, 2005):

300 Chapter 11



Development work is focused on new steam reforming catalysts with

higher activity and lower pressure drops. The catalyst will also be less

resistant to heat transfer, resulting in more heat to the reaction at a

lower tube skin temperature and a closer approach to equilibrium

conversion.



New shift conversion catalysts operating at lower steam to carbon

ratios and lower temperatures are being developed.



In recent years, the energy efficiency of the process has improved

significantly. The operating cost (feed and fuel – steam export)

amounts to two-thirds of the hydrogen production cost. Old hydrogen

plants operate at reforming temperatures well below 900



C (1652



and high steam to carbon ratio. These plants have poor energy

efficiency as large quantities of steam have to be condensed. In addi-

tion, their investment costs are high as they require large flows.

Modern plants are designed with reforming temperatures above

900



C (1652



F) and steam to carbon ratios below 2.5. The new

developments include utilizing the more energy-efficient side-fired

reforming furnace and using medium temperature shift catalyst.



New improved tube materials with a design skin temperature up to

1050



C (1922



F) are utilized in reforming furnaces. New reformer

designs with smaller tube diameters have a smaller size but twice the

heat flux of older designs.

Questions and Problems

11.1. For a reformer feed of methane and steam at a ratio of 3.5 at 20 bar,

study the effect of the reaction temperature on the hydrogen purity on

dry basis in the range 500–900



11.2. Calculate the synthesis gas composition in the reformer furnace for

natural gas feed. The composition of the feed is: 97 mol% CH4 and

3 mol% CO

. The steam to carbon ratio is 2.5. Pressure is 20 bar. The

outlet temperature of the reforming synthesis gas is 850



REFERENCES

Bourbonneux, G. (2001) ‘‘Hydrogen production,’’ Chapter 14, In Conversion Processes,

Petroleum Refining, Vol. 3, Leprince P. ed., TECHNIP, France.

Crew, M.A., and Shumake, B. (2006) ‘‘Hydrogen Production and Supply: Meeting

Refiners’ Growing Needs in Practical Advances in Petroleum Processing,’’ Hsu, C.S.,

and Robinson, P.R. ed., Vol. 1, Chapter 25, Springer, New York.

Elliot and Lira (1999) ‘‘Introductory Chemical Engineering Thermodynamics,’’ Prentice-Hall.

Hydrogen Production 301

Rostrup-Nielsen, T. (2005) ‘‘Manufacture of Hydrogen,’’ Catalysis Today, 106, 293–296,

Elsevier.

Stocker, J., Whysall, M., and Miller, C. Q. (1998). ‘‘30 Years of PSA Technology for

Hydrogen Purification,’’ www.uop.com.

UNISIM Design Suite R370, (2007). Honeywell Process Solutions, Calgary, Alberta,

Canada.

302 Chapter 11

CHAPTER TWELVE

Clean Fuels

12.1. Introduction

Environmental awareness had been continuously increasing in many

places in the second half of the last century, whether governmental wise or

public wise. Environment Protection Agencies (EPAs) worldwide set reg-

ulations to forbid or control the pollution of the environment. Petroleum

fuels are considered one of the main pollution problems. Clean fuels are free

of impurities (sulphur and benzene) but sometimes work is needed to

improve their properties (e.g. octane number for gasoline, cetane number

for diesel and freezing point for jet fuels) if possible. The main ways of

producing clean fuels are:



Deep desulphurization of fossil fuels (produced from crude oil)



Natural gas and gasification of coal



Biofuel from available biological sources like wood, vegetable oil

and seeds



Alkylation

12.2. Specifications of Clean Fuels

Clean fuels are fuels that contain very few of components that may

harm the environment, like sulphur, nitrogen, and organometallic com-

pounds. Benzene can also be included along with polycyclic aromatic

hydrocarbons (PAH). Tables 12.1 and 12.2 list gasoline and diesel specifica-

tions, respectively (Chauhan, 2002). In addition, Tables 12.3 and 12.4 list

ASEAN gasoline and diesel specifications, respectively (Chauhan, 2002).

The increase in octane, required as a result of lead phase out, has

involved refineries investing in a wide range of octane boosting processes,

including isomerization, reforming, alkylation, MTBE and other oxygenated

compounds.

Fundamentals of Petroleum Refining

2010 Elsevier B.V.

303