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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.