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HYDROGEN RECOVERY STUDY IN A TYPICAL BRAZILIAN REFINERY

Ferreira, A.S.1, Souza, V.P.

1, Monteiro, C.A.A.

1, Brito, C.O.

1, Lopes, A.L.S.

1Santos, J.C.

1, Rodrigues, C. M.

1

1Petrobras S.A., Cid. Universitria, Qd. 7 Ilha do Fundo, 21949-900 Rio de Janeiro, RJ, Brazil

Abstract: Stricter fuel specifications have increased hydrogen demand in refineries as hydrogenation is the major

chemical process used to remove contaminants in petroleum fractions. The optimized production and use of

hydrogen is a key issue as hydrogen is the most expensive feedstockof hydrotreating plants. Some refinery streams

use fuel gas as a source of energy, which has a great amount of hydrogen. The objective of this study is to compare

the performance of membrane and pressure swing adsorption (PSA) processes for hydrogen recovery in refinery

streams. The study focuses on hydrogen recovery from, purged gas from methane steam reforming processes

(MRS), fuel gas from Fluid Catalytic Cracking (FCC), Catalytic Reforming (CR) and Hydrotreating (HDT) units. If

only the hydrogen recovered from all these streams is considered then the PSA unit would be the best option, but it

is necessary to make a complete economical evaluation of both processes, that will be presented in the complete

article.

Keywords: Hydrogen, recovery, refinery, membrane, pressure swing adsorption.

1. INTRODUCTION

Alternative sources of energy for fossil fuels are being intensively studied and among them hydrogen is forecast to

become a major source of energy in the future. In the last few years the interest in its production has increased in

order to use it in fuel cells or to produce high value synfuels (high cetane number and sulfur-free diesel). Another

hydrogen application is in the hydrotreating of petroleum fractions, a process largely used by refineries to reduce

contaminants in fuels, to meet stricter specifications all over the world (Armor, 1999).

In Brazil those specifications increased the demand for hydrogen by the refineries. Hydrogen is the most expensivefeedstock in a hydrogenation plant and is produced mainly by methane steam reforming. In some cases hydrogen

could be recovered as a subproduct of other process like catalytic reforming, hydrotreating and fluid catalytic

cracking. The increase in its demand and high production cost make refineries seek opportunities to optimize the

production and recover hydrogen from processes.

The objective of this paper is to present and discuss a technical proposal to recover hydrogen from refinery streams.

One specific refinery was chosen as a model for this analyse, the details of its process and condition data must be

omitted as they are classified information.

The Petrobras refineries in Brazil have been faced with an increase of processing Brazilian Campos Offshore Basin

produced oils that have very specific characteristics (low sulfur content and API, high nitrogen content and high

heavy fractions yields) and in the same time have been faced with the demand of meeting the new environmental

and quality legislation for fuels. Reductions in middle distillate product contaminants (nitrogen and sulphur) andaromatic levels have been progressively required to minimize environmental impacts caused by emissions of

particulates and exhaust gases from engines. Specifically with diesel oil, in addition to sulfur and nitrogen contents,

cetane number, density and endpoint are properties that affect engine performance and its emissions, as described in

Table 1 (Monteiro et al., 2005).

The incorporation of the unstable cracking streams in the diesel pool, such as Light Cycle Oil (LCO) from Fluid

Catalytic Cracking Units (FCCU) and Coker Gasoil (CGO) from Delayed Coking Units (DCU) adversely affects the

quality of the final fuel due to a low cetane number, the high density and aromatic contents present in the LCO, and

the CGO has high sulfur and nitrogen contents (Monteiro et al., 2005).


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Table 1. Actual and Future Brazilian Specifications for Diesel Oil

PropertiesFuture

1/ 2009 / 2007

Metropolitan Area

Density @ 20/4C, max. 0.850 / 0.850 / 0.860

Cetane Number ASTM D-613, min. 46 / 46 / 45

Sulfur, max. (wppm) 10 / 50 / 500Flash Point, min. (C) 38 / 38 / 38

T90 ASTM D-86, max. (C)2 360 / 360 / 3601Under discussion2Temperature of vaporized 90%vol. in the ASTM D-86 distillation method

As a consequence, these more stringent fuel regulations associated with the increase in demand for middle distillate

products, and Brazilian crude oil characteristics tend to raise operating cost and feedstock volumes to be

hydrotreated. All this conditions point to an increase of hydrogen consumption in Brazilian refineries Monteiro et

al., 2005).

The objective of this paper is to present and discuss a technical proposal to recover hydrogen from refinery streams.

One specific refinery was chosen as a model for this analyse, the details of its process and condition data must be

omitted as they are classified information.

2. POTENCIAL GASEOUS REFINERIES STREAMS FOR HYDROGEN RECOVERY

2.1 PSA Process

The steam reforming of hydrocarbons, predominantly methane, is generally the most economical way to produce

hydrogen. This process produces a mixture of hydrogen, carbon monoxide, carbon dioxide and methane. The

reactions are strongly endothermic. (Rostrup-Nielsen, 1993)..

CH4 + H2O 3 H2 + CO H298 = + 206 kJ/mol (1)

CO + H2O CO2 + H2 H298 = - 41 kJ/mol (2)

The only case considered was the methane steam reforming. A simplified process diagram is shown in Figure 1, toillustrate the principal unit operations. Hydrodesulfurization is performed in the pre-treatment section, this is

necessary because the steam reforming catalysts are very sensitive to sulfur. . The hydrogen is formed in the steam

reforming section, together with carbon monoxide, according to the reactions (1) and (2), with the last contributing

less than the first. Part of the produced hydrogen is recycled into the pre-treatment section. Additional hydrogen and

carbon dioxide is produced in the subsequent HTS (High Temperature Shift) section with reaction (2) only.

The effluent mixture of water, hydrogen, carbon monoxide, carbon dioxide and methane leaving the HTS section

has to be cooled to separate the water. The mixture of gases is fed into the Pressure Swing Adsorption (PSA) unit

where the hydrogen is purified to a 99.99 %mol stream. A small part of this hydrogen is recycled to the pre-

treatment unit. Periodically the PSA unit is cleaned using hydrogen which produces another stream called purged

gas with typical composition 24,2 %m H2, 2,4 %m N2, 0,3 %m O2, 17,1 %m CH4, 5,2 %m CO and 50,7%m CO2.

. This stream is sent as a fuel to be burned in the reformer. The purged gas stream is a mixture with the same

components as the PSA feed, but in different proportions.


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Steam

Natural gas

Hydrogen

PSA

Purge gas toburner

Hydrogenproduct

H2O

Hydrogen

recycle

Pre-treatmentSteam

reforming HTS

Steam

Natural gas

Hydrogen

PSA

Purge gas toburner

Hydrogenproduct

H2O

Hydrogen

recycle

Pre-treatmentSteam

reforming HTS

Figure. 1. Simplified block diagram for steam reforming.

2.2 Diesel Hydrotreating

Among the processes used to severely reduce sulfur, nitrogen and aromatic contents from middle distillates, catalytic

hydrotreating (HDT) continues to be the most important options to meet stricter diesel fuel specifications. The HDT

process consist of a heterogeneous catalyst operating under high hydrogen partial pressures, temperatures and liquid

hourly space velocities, whereby the organic sulfur and nitrogen compounds are converted to H2S, NH3 and the

corresponding hydrocarbons (hydrodesulfurization-HDS and hydrodenitrogenation-HDN, respectively). In addition,

some aromatics can be saturated to form naphthenes, in the hydrodearomatization process (HDA). The HDT process

is characterized by a large hydrogen consumption that is responsible for its high operational costs.

In order to meet new fuels specifications, to reduce the sulfur content to about 10 wppm and improve cetane

number,it will be necessary retrofit the existing hydrotreating units. (Bej, 2003).

In industrial units, to guarantee the life cycle of the HDT catalyst a higher hydrogen feed to consumption ratio is

necessary. The excess hydrogen is recycled and due to the exothermic reactions, it is also used to control the catalyst

bed temperature (quench stream). Significant amounts of hydrogen (88,6 %m hydrogen, 4,2%m methane, 2,9 %m

ethane, 1,8 %m propene, 0,3 %m iso-butane, 0,71 %m n-butane, 0,3 %m iso-pentane,0,3 %m n-pentane and 1,0%m

pentane+) contained in the fuel gas is an additional stream of hydrogen recovered in the stripper unit together withhydrogen sulfide, steam vapour and light hydrocarbons (Figure 3).

Figure 3: . Simplified block diagram for hydrotreating process


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2.3 Fluid Catalytic Cracking

Fluid Catalytic Cracking (FCC) is a conversion process the objective of which is to crack a heavy feed such as

vacuum gasoil into liquid petroleum gas (LPG) and/or gasoline but it also yields heavier hydrocarbons and coke.

The gaseous effluent from this FCC process is a mixture that must be fractioned in a distillation column, producing

cracked naphtha, LPG and fuel gas as top products, Light Cycle Oil (LCO) and Heavy Cycle Oil (HCO) drawn off

as side products, and a bottom product consisting of heavy residuum and catalyst fines. This bottom product can be

separated into clarified oil and sludge. Figure 4 shows a FCC unit diagram.

The FCC unit is the major source of fuel gas, which consist of mainly hydrogen, methane, ethane and ethene. The

typical fuel gas composition is 1,2,4%m hydrogen, 50,0%m methane, 6,8 %m ethene, 16,8 %m ethane, 3,5%m

propane, 1,6%m propene, 0,3 %m n-butane, 0,4 %m iso-butane, 0,4 %m n-butene, 0,4%m iso-butene, 0,2%m

pentane, 1,4 %m carbon monoxide, 0,8 %m carbon dioxide, 2,0%m nitrogen, 0,1%m sulfur and 0,7 %m water.

blower

preheater

regenerator

reactordistillation

columngas

recovery

DEA

DEA

MEROX

MEROX

COBoiler

air

feed

water vapor

Flue Gas

Fuel Gas

Acid Gas

LPG

Cracked

Naphta

LCO

HCO

blower

preheater

regenerator

reactordistillation

columngas

recovery

DEA

DEA

MEROX

MEROX

COBoiler

air

feed

water vapor

Flue Gas

Fuel Gas

Acid Gas

LPG

Cracked

Naphta

LCO

HCO

Fig. 4: . Simplified process diagram for FCC Unit

2.4 Catalytic Reforming

Catalytic reforming is a process to produce aromatic compounds. These products are applied as an octane booster.

The process consists of putting a light hydrocarbon feed (in the naphtha distillation range) and hydrogen in contact

with a catalyst usually made of platinum associated with a noble metal such as rhenium or germanium supported in

alumina. Aromatic and isoparaffinic compounds are produced, as well as light products such as LPG, hydrogen and

coke residue.

Figure 5 shows a simplified diagram of a catalytic reforming process. As the reforming catalyst is very sensitive to

contaminants, before entering the unit the feed is processed in a hydrotreater. To prevent coke formation, the feed is

mixed with hydrogen before heating and the reforming catalytic reactor process. As reforming reactions are

endothermic, the catalyst is placed in a sequence of reactors interspersed with heat units, to provide the necessaryenergy. The reactor effluent is separated and the gas is recycled to the hydrotreating unit and the first reforming

catalyst reactor. Liquid products are stabilized in a debutanizer, yielding the reformate at the bottom and LPG and

fuel gas at the top. This fuel gas has typically 80 %molar of hydrogen and its typical composition is 80,1 %m

hydrogen, 8,0%m methane, 4,9%m ethane, 3,6%m propane, 1,0%m iso-butane, 0,8%m n-butane, 0,5%m iso-

pentane, 0,3 %m n-pentane, 0,8 %m pentane+.


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Fig. 5. . Simplified block diagram for catalytic reforming

3 HYDROGEN RECOVERY NETWORK AND METHODOLOGY

This study proposes different hydrogen recovery configurations, which will be individually evaluated in terms of

hydrogen volume produced and its cost. The best configuration will be compared to a new methane steam reforming

unit to produce the same hydrogen volume. Membrane separation system is an alternative to conventional processes

(for instance, PSA) for hydrogen purification and recovery and has been widely studied (Adhikari et al., 2006).

The two simplest options studied are shown in the Figure 6. In both, all the possible streams, the purged gas from

MSR and the fuel gas from HDT, FCC and CR processes, are mixed and then sent to a recuperation unit either a

PSA or a commercial membrane. The PSA recovery factor was obtained from operational experience and the

membrane from the literature If only the hydrogen recovered is considered, the PSA unit would be the best option,

but the study included a economical parameter to define a optimized configuration. In this initial evaluation, the

need for auxiliary equipment for either process were not considered.

HDT

FCC

CR

SRM

320.103 Nm3/d

24,21% v/v H2

88,63% v/v H2

72.103 Nm3/d

80.10% v/v H2

130.103 Nm3/d

Membrane

12,4% v/v H2

390.103 Nm3/d

294.103 Nm3/d H2

176.103 Nm3/d H2

Recoveryfactor 60%

HDT

HDT

HDT

FCC

FCC

FCC

CRCRCR

SRM

SRM

320.103 Nm3/d

24,21% v/v H2

88,63% v/v H2

72.103 Nm3/d

80.10% v/v H2

130.103 Nm3/d

Membrane

12,4% v/v H2

390.103 Nm3/d

294.103 Nm3/d H2

176.103 Nm3/d H2

Recoveryfactor 60%

HDT

FCC

CR

SRM

320.103 Nm3/d

24,2% v/v H288,6% v/v H2

72.103 Nm3/d

80.1% v/v H2

130.103 Nm3/d

12,4% v/v H2

390.103 Nm3/d

PSA Recoveryfactor 83%

294.103 Nm3/d H2

244.103 Nm3/d H2

HDT

HDT

HDT

FCC

FCC

FCC

CRCRCR

SRM

SRM

320.103 Nm3/d

24,2% v/v H288,6% v/v H2

72.103 Nm3/d

80.1% v/v H2

130.103 Nm3/d

12,4% v/v H2

390.103 Nm3/d

PSA Recoveryfactor 83%

294.103 Nm3/d H2

244.103 Nm3/d H2 Fig. 6. Preliminary process configuration for hydrogen recovery


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Even though Figure 6 configurations are not optimized the possible hydrogen volume recovered is considerable and

on the same scale as some industrial steam reforming units.

A mathematical simulation of membranes separation unit and PSA was developed to define the optimal design for

hydrogen recovery. In the case of hydrogen selective membranes, permeability values for species commonly found

in refinery streams were collected from literature (Table 2). A computational routine were built to solve the problem

under steady state conditions. Figure 7 show another configurations options studied, which main characteristic were

the use of multistage membrane to compensate its lower recovery factor compared to PSA recovery factor. All

configurations considered for technical-economical evaluation aim a rich-hydrogen stream with 99.99% purity.

Table 6: Permeability data for Polydimetilsiloxane membranes (Brandrup et al., 1999)1

Compounds Permeabilities (barrer2)

H2 705

N2 353

O2 695

CO2 3489

CH4 1002

C2H6 3150

C3H8 63381101.3 kPa and 308 K2 1 barrer = 3.30x10-17 kmol.cm/(m2.Pa.s)

H2-Pour Gas

feed

compressor cooler

Multi-stageMembrane

system

PSA

feed

H2-Rich Gas (+99.99%)

compressor

Knock-outDrum

Knock-outDrum

cooler

H2-Pour Gas

recicle

H2-Rich Gas (+99.99%)

H2-Pour Gas

feed

compressor cooler

Multi-stageMembrane

system

PSA

feed

H2-Rich Gas (+99.99%)

compressor

Knock-outDrum

Knock-outDrum

cooler

H2-Pour Gas

recicle

H2-Rich Gas (+99.99%)

Fig. 7: Process configurations options considered for technical-economical evaluation.

REFERENCES

Adhikari S. and Fernando, S.(2006). Hydrogen membrane separation techniques. Industrial Engineering Chemical

Resource, v. 45, p. 875-881.

Armor, J.N. (1999). The multiple roles for catalysis in the production of H2. Applied Catalysis A: General, v.176,

1999, p159-176.

Bej, S. K. (2004). Revamping of diesel hydrodesulfurizers: options available and future research needs. Fuel

Processing Technology, v.85, p.1503-1517.

Brandrup, J.; Immergut, E. H.and Grulke, E. A.(1999). Polymer Handbook. 4. ed. New York: Wiley.

Monteiro, C. A. A., Alt, B. D. R, Gomes, L. C., Dias, B. S. and Silva, R. M. C. F. (2005). Modeling of

Hydrotreating Process to Produce High Quality Diesel Oil. In: 2th Mercosur Congress on Chemical Engineering

and 4th Mercosur Congress on Process Systems Engineering Proceedings (CD version).

Rostrup-Nielsen, J.R. (1993). Production of synthesis gas., Catalysis Today, v. 18, p305-324.

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