Background
Document
Clarifying
the
Scope
of
Petroleum
Hazardous
Waste
Listings:
Supplemental
Information
Regarding
Petroleum
Hydroprocessing
Units
May
2002
Prepared
for
U.
S.
Environmental
Protection
Agency
Office
of
Solid
Waste
Ariel
Rios
Building
1200
Pennsylvania
Avenue,
N.
W.
Washington,
DC
20460
Prepared
by
Science
Applications
International
Corporation
11251
Roger
Bacon
Drive
Reston,
VA
20190
EPA
Contract
No.
68­
W­
02­
006,
Work
Assignment
No.
3
SAIC
Project
No.
06­
6312­
08­
3006­
000
i
Table
of
Contents
Glossary
and
Acronyms
........................................................
iii
1.
Introduction
................................................................
1
2.
Overview
of
Hydrotreating,
Hydrorefining,
and
Hydrocracking
Processes
................
3
3.
Ebullated
Bed
(Dual
Purpose)
Processes..........................................
7
3.1
H­
Oil
..............................................................
7
3.2
LC­
Fining
..........................................................
13
3.3
T­
Star
.............................................................
13
3.4
Population
.........................................................
17
3.5
Conclusions
........................................................
17
4.
Mild
Hydrocracking.........................................................
18
4.1
MHUG
............................................................
19
4.2
Population
.........................................................
21
4.3
Conclusions
........................................................
21
5.
Single­
and
Multi­
Stage
Hydrocracking
Processes
.................................
22
5.1
IFP
Technology
Hydrocracking
.........................................
24
5.2
MAKFining
........................................................
25
5.3
Shell
Hydrocracking
Process
...........................................
27
5.4
Isocracking
Technology
...............................................
27
5.5
Population
.........................................................
29
5.6
Conclusions
........................................................
31
6.
Lube
Oil
Processes..........................................................
32
6.1
Hybrid
............................................................
32
6.2
Yukong
UCO
Lube
Process
............................................
32
6.3
Mobil
Selective
Dewaxing
Process
......................................
33
6.4
Conclusions
........................................................
33
7.
Recycling
Spent
Catalysts
....................................................
34
7.1
Quantity
Data
.......................................................
34
7.2
Cost
Data
..........................................................
38
7.3
Recycling
Trends
Analysis
.............................................
38
8.
Discussion
................................................................
39
8.1
Characteristics
of
Hydroprocessing
Units
.................................
39
8.2
Performance
Summary
of
Hydroprocessing
Units
...........................
40
8.3
Conclusions
........................................................
45
9.
Bibliography...............................................................
48
ii
List
of
Tables
Table
2B1.
Population
of
U.
S.
Hydroprocessing
Units
.................................
6
Table
3B1.
Typical
H­
Oil
Process
Operating
Conditions
...............................
8
Table
3B2.
H­
Oil
Process
Performance.............................................
9
Table
3B3.
Yields
and
Operation
for
Two­
stage
H­
Oil
Processing
of
Arabian
Medium
Vacuum
Resid
.................................................................
9
Table
3B4.
H­
Oil
Processing
of
Arabian
Heavy
Resid
................................
10
Table
3B5.
Typical
H­
Oil
Process
Results
.........................................
11
Table
3B6.
H­
Oil
Processing
of
Arabian
Crude:
Typical
Product
Properties
...............
11
Table
3B7.
Product
Quality
for
H­
Oil
Conversion
of
Arab
Light/
Heavy
Vacuum
Residue
....
12
Table
3B8.
Feedstock
Inspections
for
Isthmus/
Maya
Feed.............................
13
Table
3B9.
Typical
Properties
of
LC­
Fining
Process
Feedstock.........................
13
Table
3B10.
Husky
Oil
Trial
Feed
Properties
for
T­
Star
Reactor
........................
14
Table
3B11.
T­
Star
Commercial
Demonstration
.....................................
14
Table
3B12.
T­
Star
Reactor
Feedstock
Components
and
Properties
.....................
15
Table
3B13.
T­
Star
FCCU
Feed
Yields
at
30
Percent
Conversion
.......................
15
Table
3B14.
T­
Star
Reactor
Feedstock
Properties
...................................
16
Table
3B15.
T­
Star
Mild
Hydrocracking
Yields
at
55
Percent
Conversion
................
16
Table
3B16.
Summary
of
U.
S.
Refineries
Using
Ebullated
Bed
Technology
...............
17
Table
4B1.
Typical
Mild
Hydrocracking
Feedstock
Characteristics......................
19
Table
4B2.
Typical
Mild
Hydrocracking
Performances
Based
on
Arabian
Light............
19
Table
4B3.
Test
Results
for
MHUG
Application
to
Mild
Hydrocracking
of
FCC
Feed
.......
20
Table
4B4.
Test
Results
of
LCO
Upgrading
Using
MHUG
............................
21
Table
5­
1.
Single
or
Two­
Stage
Hydrocracking
Operating
Conditions
...................
23
Table
5­
2.
Sulfur
and
Nitrogen
Reduction
from
IFP
Hydrocracking
Process
..............
25
Table
5­
3.
Sulfur
and
Nitrogen
Reduction
Through
MAKFining
Technology
.............
26
Table
5­
4.
Typical
Isocracking
Catalysts
..........................................
28
Table
5­
5.
Feed
and
Product
Data
for
Isocracking
...................................
29
Table
5­
6.
Chevron­
Designed
Hydrocracking
Plants
.................................
30
Table
5­
7.
Other
Single
and
Multi­
Stage
Hydrocracking
Processes
......................
31
Table
7­
1.
K171/
K172
Waste
Generation
Data
in
1992/
1999
..........................
35
Table
7­
2.
Waste
Management
Data
for
Spent
Catalyst
(1992/
1999)
....................
36
Table
7­
3.
Unit
Costs
for
Common
Management
Methods
............................
38
Table
8­
1.
Sulfur
Reduction
in
Named
Processes
....................................
41
Table
8­
2.
Nitrogen
Reduction
in
Named
Processes
.................................
42
Table
8­
3.
Metals
Reduction
in
Named
Processes
...................................
43
Table
8­
4.
Feed
Conversions
in
Named
Processes
...................................
44
List
of
Figures
Figure
2B1.
Typical
Petroleum
Refining
Process
Flow
Diagram.........................
5
Figure
7B1.
Waste
Management
Destinations
for
Spent
Catalyst
(1992
vs.
1999)
..........
37
iii
Glossary
and
Acronyms
atm
Atmospheres
(unit
of
measure
for
pressure)
Barrel
Equal
to
42
gallons
BPSD
Barrels
per
Stream
Day
CCR
Conradson
Carbon
Residue
Co
Cobalt
cSt
Centistokes
EP
End
boiling
point
EPA
U.
S.
Environmental
Protection
Agency
FCCU
Fluid
catalytic
cracking
unit
Gravity,
°API
Unit
of
measure
for
density
of
hydrocarbon
fractions.
A
heavy
liquid
will
have
a
low
°API
gravity.
H2
Hydrogen
HDN
Hydrodenitrogenation
HDS
Hydrodesulfurization
HDT
Hydrotreating
HDW
Hydrodewaxing
HVGO
Heavy
vacuum
gas
oil
IP
Initial
boiling
point
K171
Spent
hydrotreating
catalyst
from
petroleum
refining
operations,
including
guard
beds
used
to
desulfurize
feeds
to
other
catalytic
reactors
(this
listing
does
not
include
inert
support
material).
K172
Spent
hydrorefining
catalyst
from
petroleum
refining
operations,
including
guard
beds
used
to
desulfurize
feeds
to
other
catalytic
reactors
(this
listing
does
not
include
inert
support
material).
LCO
Light
Cycle
Oil
LHSV
Liquid
hourly
space
velocity.
This
is
an
indication
of
the
flow
velocity
through
the
reactor.
A
relatively
low
number
indicates
relatively
slow
movement
of
hydrocarbon.
LPG
Liquid­
Petroleum
Gas
MHUG
Medium­
Pressure
Hydro
Upgrading
Mo
Molybdenum
Naphtha
A
light
fraction
used
for
gasoline
production
Ni
Nickel.
A
catalyst
ingredient
and
an
impurity
in
hydrocarbon
feedstock.
Nm
3
/m
3
Normal
cubic
meter
gas
per
cubic
meter
hydrocarbon
feed.
Normal
conditions
are
0°
C
and
1
bar
pressure.
ppmw
parts
per
million
by
weight
PSA
Department
of
Energy's
Petroleum
Supply
Annual
Resid
The
heaviest
fraction
from
atmospheric
or
vacuum
distillation
scfb
Standard
cubic
feet
of
gas
per
barrel
hydrocarbon
feed.
Standard
conditions
are
70°
F
and
1
atmosphere
pressure.
UCO
Unconverted
oil
iv
Glossary
and
Acronyms
(cont.)

V
Vanadium
VGO
Vacuum
gas
oil
vol
%
percent
by
volume
W
Tungsten
wt
%
percent
by
weight
1
U.
S.
EPA,
Office
of
Solid
Waste,
"Study
of
Selected
Petroleum
Refining
Residuals,
Industry
Study,"
August
1996
(EPA530­
R­
96­
018).

1
1.
Introduction
On
August
6,
1998,
the
Environmental
Protection
Agency
(EPA)
published
final
hazardous
waste
listing
determinations
for
particular
solid
wastes
generated
at
petroleum
refineries
(63
FR
42110).
In
that
final
rule,
EPA
listed
spent
hydrotreating
catalysts
(K171)
and
spent
hydrorefining
catalysts
(K172)
as
hazardous
wastes.
(The
final
rule
also
included
final
listing
determinations
for
several
other
petroleum
refining
wastes.)
EPA
took
no
action
regarding
a
listing
determination
in
the
case
of
a
third
type
of
spent
hydroprocessing
catalyst,
spent
hydrocracking
catalyst.
However,
the
regulatory
docket
supporting
the
August
6,
1998
final
rule
did
present
available
data
characterizing
spent
hydrocracking
catalysts
in
a
Hazardous
Waste
Identification
Study.
1
Prior
to
publishing
its
final
listing
determinations
for
particular
wastes
generated
at
petroleum
refineries,
EPA
collected
a
wide
variety
of
facility­
and
waste­
specific
information
relative
to
a
number
of
different
petroleum
refining
processes.
Information
collection
activities
included
an
industry
survey
and
waste
sampling
and
analyses.
The
listing
determination
decisions
made
by
EPA
and
published
on
August
6,
1998,
including
the
Agency's
decisions
to
list
spent
hydrotreating
and
spent
hydrorefining
catalysts
as
hazardous
waste,
were
based
upon
the
results
of
these
information
collection
activities.
In
the
case
of
some
refinery
wastes,
including
spent
hydrocracking
catalysts,
EPA
presented
available
data
without
finalizing
a
regulatory
determination.

The
preamble
to
the
August
1998
final
rule
provides
definitions
for
three
types
of
petroleum
refinery
hydroprocessing
units
from
which
spent
catalysts
may
be
generated
and
removed.
The
definitions
are
provided
both
to
identify
the
two
types
of
spent
catalyst
that
are
listed
as
hazardous
waste
and
to
aid
in
distinguishing
spent
hydrotreating
and
hydrorefining
catalysts
from
spent
hydrocracking
catalysts.
These
definitions
are
based
on
the
categories
used
in
the
Department
of
Energy's
(DOE's)
Petroleum
Supply
Annual
(PSA)
to
differentiate
between
hydrocracking
units
and
hydrotreating
(treating/
refining)
units
(63
FR
42155,
August
6,
1998)
for
the
purpose
of
reporting
refinery
production
capacities
to
DOE.
By
the
PSA's
definition,
catalytic
hydrotreating
is:

A
refining
process
for
treating
petroleum
fractions
from
atmospheric
or
vacuum
distillation
units
(e.
g.,
naphthas,
middle
distillates,
reformer
feeds,
residual
fuel
oil,
and
heavy
gas
oil)
and
other
petroleum
(e.
g.,
cat
cracked
naphtha,
coker
naphtha,
gas
oil,
etc.)
in
the
presence
of
catalysts
and
substantial
quantities
of
hydrogen.
Hydrotreating
includes
desulfurization,
removal
of
substances
(e.
g.,
nitrogen
compounds)
that
deactivate
catalysts,
conversion
of
olefins
to
paraffins
to
reduce
gum
formation
in
gasoline,
and
other
processes
to
upgrade
the
quality
of
the
fractions.
2
In
the
1998
final
rule,
EPA
defined
catalytic
hydrorefining
as
a
refining
process
similar
to
hydrotreating
that
uses
higher
temperatures
and
pressures
than
hydrotreating.
The
purpose
of
hydrorefining
is
to
treat
heavier
molecular
weight
petroleum
fractions
(hydrorefining
is
not
defined
in
the
PSA).
EPA
also
adopted
the
PSA
definition
of
hydrocracking
in
the
1998
final
rule.
Catalytic
hydrocracking
is
defined
by
the
PSA
as:

A
refining
process
that
uses
hydrogen
and
catalysts
with
relatively
low
temperature
and
high
pressures
for
converting
middle
boiling
residual
material
to
high­
octane
gasoline,
reformer
charge
stock,
jet
fuel,
and/
or
high
grade
fuel
oil.
The
process
uses
one
or
more
catalysts,
depending
upon
product
output,
and
can
handle
high
sulfur
feedstocks
without
prior
desulfurization.

Although
the
preamble
to
the
1998
final
rule
referred
to
the
general
definitions
used
by
DOE
for
the
purposes
of
PSA
reporting,
the
final
rule
did
not
include
unit­
or
reactor­
specific
definitions
or
regulatory
determinations
for
specific
types
of
catalysts.
When
the
final
rule
was
published,
EPA
lacked
information
about
certain
types
of
hydroprocessing
reactors
may
serve
multiple
functions.
The
Agency
subsequently
received
inquiries
regarding
the
regulatory
status
of
spent
catalysts
removed
from
"dual
purpose"
reactors.
Dual
purpose
petroleum
hydroprocessing
reactors
are
reactors
that
conduct
hydrotreating
(or
hydrorefining)
and
hydrocracking
in
the
same
reactor.

In
response
to
inquiries
regarding
the
regulatory
status
of
dual
purpose
hydroprocessing
reactors,
EPA
issued
guidance,
in
the
form
of
two
memoranda,
clarifying
that
spent
catalysts
removed
from
dual
purpose
reactors
are
listed
hazardous
wastes.
In
a
memorandum
issued
November
29,
1999,
EPA
stated
that
spent
catalysts
from
petroleum
hydroprocessing
units
performing
hydrotreating
or
hydrorefining
operations
are
listed
hazardous
wastes
regardless
of
whether
hydrocracking
also
occurs
in
the
same
reactor
using
a
single
catalyst.
EPA
clarified
in
the
memorandum
that
the
final
rule
defines
a
spent
catalyst
generated
from
a
petroleum
hydroprocessing
reactor
on
the
basis
of
the
type
of
hydroprocessing
operation
in
which
the
catalyst
was
used.
If
a
spent
catalyst
is
removed
from
a
reactor
that
conducts
hydrotreatment
or
hydrorefining,
the
spent
catalyst
is
a
listed
hazardous
waste.
The
memorandum
further
stated
that
refineries
may
not
classify
"dual
purpose"
reactors
as
hydrocracking
reactors
based
solely
on
the
fact
that
some
hydrocracking
takes
place
in
the
presence
of
the
catalyst
and
then
subsequently
claim
the
spent
catalyst
to
be
non­
hazardous.

In
a
second
memorandum
that
was
issued
on
June
1,
2000,
EPA
clarified
that
spent
catalysts
removed
from
hydroprocessing
reactors
that
are
designed
primarily
to
hydrocrack
previously
treated
petroleum
feedstock,
and
that
perform
no
more
than
minimal
and
incidental
hydrotreatment
are
not
listed
hazardous
wastes.
EPA
issued
this
second
memorandum
in
response
to
concerns
raised
by
the
regulated
community
over
the
wording
used
in
the
November,
1999
memorandum.
Members
of
the
regulated
community
asserted
that
a
strict
reading
of
the
November
1999
memorandum
would
render
all
spent
catalysts
from
hydrocracking
units
as
listed
hazardous
wastes
due
to
the
fact
that
some
small
amount
of
hydrotreating
can
occur
in
any
hydrocracking
reactor.
As
a
result,
the
June
1,
2000
memorandum
clarifies
that
spent
catalysts
from
hydroprocessing
reactors
that
perform
a
hydrocracking
function
(i.
e.,
hydrocrack
previously
2
The
literature
generally
does
not
use
the
term
hydrorefining.
In
general
the
characteristics
of
hydrotreating
identified
below
are
also
applicable
to
hydrorefining.

3
treated
feed)
and
only
a
minimal
and
incidental
hydrotreating
function
are
not
within
the
scope
of
the
hazardous
waste
listing.
In
two
letters
written
in
response
to
specific
questions
posed
by
industry,
EPA
clarified
the
regulatory
status
of
spent
catalysts
removed
from
two
different
types
of
hydroprocessing
reactors.
In
the
November
29,
1999
Memorandum
and
the
subsequent
memorandum
and
letters,
EPA
maintained
that
spent
catalysts
removed
from
dual
purpose
hydroprocessing
units
are
listed
hazardous
wastes
(K171
and
K172).

In
February
2000,
API
filed
a
lawsuit
in
the
D.
C.
Circuit
challenging
the
validity
of
the
November
29,
1999
memorandum.
API
v.
EPA,
Docket
No.
00­
1069.
In
June
2001,
API
and
EPA
entered
into
a
settlement
agreement
in
regard
to
the
second
lawsuit.
Under
the
terms
of
the
settlement
agreement
EPA
published
a
Federal
Register
notice
(July
5,
2001;
66
FR
35379)
announcing
EPA's
intention
to
accept
comment
on
whether
to
maintain,
and
possibly
clarify,
the
policy
expressed
in
the
memoranda
regarding
the
regulatory
status
of
spent
dual
purpose
catalysts
or
to
change
it.
After
reviewing
public
comments
received
on
the
initial
notice,
EPA
agreed
to
publish
a
second
notice
in
the
Federal
Register.

This
background
document
summarizes
the
results
of
a
literature
review
and
technical
assessment
identifying
and
characterizing
petroleum
hydroprocessing
reactors,
emphasizing
dual
purpose
reactors.
Three
specific
types
of
dual
purpose
reactors
are
identified
and
described.
A
summary
of
other
types
of
petroleum
hydroprocessing
processes
also
is
provided.

2.
Overview
of
Hydrotreating,
Hydrorefining,
and
Hydrocracking
Processes
The
term
hydroprocessing
is
used
to
denote
processes
by
which
molecules
in
petroleum
feedstocks
are
split
or
saturated
in
the
presence
of
hydrogen
gas
while
reducing
boiling
ranges
of
and
removing
impurities
from
petroleum
feedstocks.
Hydroprocessing
is
a
broad
term
that
includes
hydrocracking,
hydrotreating,
and
hydrorefining.
In
addition
to
the
terminology
(presented
above)
that
EPA
used
in
the
preamble
to
the
1998
final
rule,
the
literature
identifies
specific
characteristics
for
each
type
of
process.
2
Reactions
that
take
place
during
hydrotreating
include
the
following
(none
greatly
reduce
the
resulting
molecular
weight
of
the
product)
(Scherzer,
1996):

$
Hydrodesulfurization
(i.
e.,
the
conversion
of
organo­
sulfur
compounds
to
H2
S
and
similar
weight
organic
compounds).
$
Hydrodenitrogenation
(i.
e.,
the
conversion
of
organo­
nitrogen
compounds
to
NH3
and
similar
weight
organic
compounds).
$
Hydrodemetallation
(i.
e.,
the
precipitation
of
metal
on
catalyst
in
sulfide
form).
$
Hydrodeoxygenation
(i.
e.,
the
removal
of
­OH
from
molecule).
$
Olefin
hydrogenation
(i.
e.,
the
hydrogenation
of
olefins
to
aliphatic
compounds).
4
The
PSA
definition
of
hydrotreating
(as
cited
in
the
preamble
of
EPA's
August
1998
final
rule)
identifies
sulfur,
nitrogen,
and
other
impurity
removal
as
characteristics
relevant
to
hydrotreating
units.
As
a
result,
data
on
sulfur,
nitrogen,
and
metals
feed
concentrations,
and
reactor­
specific
removal
efficiencies,
are
presented
in
the
following
sections
as
available;
such
data
are
generally
presented
near
the
top
of
tables.
However,
other
characteristics
of
hydrotreating
units
identified
from
the
PSA
definition
(e.
g.,
olefin
conversion)
generally
were
found
not
to
be
well
documented
in
the
open
literature,
and
therefore
generally
do
not
appear
in
the
tables
provided
below.

Reactions
that
take
place
during
hydrocracking
include
the
following
(Scherzer,
1996):

$
Monoaromatics
hydrogenation
(i.
e.,
hydrogenation
of
phenyl
rings).
$
Hydrodealkylation
(i.
e.,
the
separation
of
aliphatic
chain
from
phenyl
ring).
$
Hydrodecyclization
(i.
e.,
breaking
of
saturated
ring
compounds).
$
Isomerization
of
paraffins
(i.
e.,
molecular
rearrangement
of
aliphatic
compounds).

Polyaromatics
hydrogenation
(i.
e.,
the
saturation
of
polycyclic
aromatic
compounds)
takes
place
during
both
hydrocracking
and
hydrotreating).

Figure
2­
1
presents
a
flow
diagram
of
a
refinery;
this
diagram
is
intended
to
show
approximately
where
hydroprocessing
occurs
in
a
refinery.
Streams
that
undergo
hydroprocessing
include
resid,
naphtha,
diesel,
and
lube
oil.
5
Crude
Unit
Atmospheric
Distillation
Vacuum
Distillation
HydroTreating
Naphtha
Reforming
C
1
To
C
4
Reformate
HydroTreating
Alkylation
Alkylate
Diesel
and
Jet
Fuel
FCC
Feed
HydroRefining
Hvy
Atm
Gas
Oil
Fluidized
Catalytic
Cracking
Gasoline
Fuel
Oil
Lt
Vac
Gas
Oil
Hvy
VGO
Resid
Thermal
Processing
Fuel
Gas
and
Coker
Gasoline
Coke
Sulfur
Complex
Sulfur
Hydrogen
Sulfide­
containing
Gas
Hydrocracking
Figure
2­
1.
Typical
Petroleum
Refining
Process
Flow
Diagram
The
different
types
of
streams
that
can
undergo
hydroprocessing
range
from
heavy
feedstocks
of
resid
and
vacuum
gas
oil
to
lighter
feedstocks
of
naphtha
and
distillate.
Naphtha,
or
gasoline,
is
hydroprocessed
to
remove
contaminants
such
as
sulfur,
which
is
harmful
to
downstream
operations
(such
as
precious
metal
reforming
catalyst).
Diesel
hydroprocessing
removes
sulfur
to
meet
fuel
requirements,
and
saturates
aromatics.
The
purpose
of
resid
and
VGO
hydroprocessing
is
to
remove
metals,
sulfur,
and
nitrogen
(e.
g.,
hydrotreating),
as
well
as
to
convert
high
molecular
weight
hydrocarbons
into
lower
molecular
weight
hydrocarbons
(e.
g.,
hydrocracking).

Several
different
types
of
heavy
end
hydroprocessing
include
hydrotreating,
mild
hydrocracking,
high
pressure
hydrocracking,
and
medium
pressure
hydrocracking;
all
can
be
used
with
essentially
similar
feeds
but
with
major
differences
in
product
quality.
Mild
hydrocracking
operates
at
relatively
low
pressure
(30B60
atm)
to
achieve
partial
conversion
of
feedstocks
(i.
e.,
where
the
majority
of
the
feed
is
not
converted
to
lighter
components).
High
pressure
hydrocracking
achieves
high
conversion
of
pretreated
feeds
(90
to
100
percent)
using
a
combination
of
catalysts
at
high
pressure
(100
to
130
atm).
As
the
name
suggests,
medium
6
pressure
hydrocracking
has
operating
parameters
and
product
characteristics
between
mild
and
high
pressure
hydrocracking
(Marion,
1998).

Data
regarding
the
prevalency
of
hydroprocessing
operations
in
U.
S.
refineries
are
provided
in
Table
2­
1.

Table
2B1.
Population
of
U.
S.
Hydroprocessing
Units
Process
Type
Total
Capacity,
BPSD
No.
of
Refineries
with
Process
2
Heavy
Gas
Oil
Hydrotreating
2,316,160
54
Naphtha
Reformer
Feed
Hydrotreating
4,276,664
120
Distillate
Hydrotreating
3,942,220
101
Other/
Residual
Hydrotreating
904,660
41
Hydrocracking
1,575,800
42
Total
U.
S.
Distillation
1
17,393,070
158
Source:
U.
S.
Department
of
Energy,
2000.
Data
do
not
include
Puerto
Rico
and
U.
S.
Virgin
Islands.
1.
Presented
for
context;
includes
refineries
with
and
without
hydroprocessing
capacity.
2.
A
single
refinery
may
have
more
than
one
unit
within
each
process
type.

Petroleum
hydroprocessing
reactors
use
catalysts
to
assist
with
chemical
reactions
necessary
to
remove
sulfur
and
metals
from
feedstocks
and
reduce
the
boiling
range
of
the
feed.
Amorphous
and
zeolite­
based
catalysts
generally
are
used
in
hydrocracking
reactors.
The
zeolitebased
catalysts
are
high
activity
catalysts
with
high
ammonia
tolerance,
and
offer
higher
gasoline
selectivity
than
do
amorphous
catalysts.
Zeolites
are
microporous,
crystalline
aluminosilicates
with
ion
exchange,
sorption,
and
molecular
sieving
properties.
Most
zeolites
are
synthesized
from
a
mixture
of
silica
and
alumina
sources
and
caustic.
Active
catalysts
are
obtained
by
modifying
the
synthesized
zeolite
with
ionic
exchange
and
thermal
or
chemical
treatment.
High
zeolite
content
catalysts
rely
primarily
on
the
zeolite
for
their
hydrocracking
function.
In
low
zeolite
content
catalysts,
both
the
zeolite
and
acidic
amorphous
content
are
responsible
for
the
cracking
activity.
Zeolite­
based
hydrocracking
catalysts
have
certain
advantages
over
amorphous
catalysts
such
as
greater
acidity
which
results
in
greater
cracking
activity.
They
also
possess
better
thermal/
hydrothermal
stability,
naphtha
selectivity,
and
resistance
to
nitrogen
and
sulfur
compounds
than
amorphous
catalysts.
In
addition
to
these
advantages,
the
zeolite­
based
catalysts
also
have
a
low
coke­
forming
tendency
and
can
be
more
easily
regenerated
(Scherzer,
1996,
p.
15).

Catalysts
used
in
hydrotreating
reactors
include
cobalt
and
molybdenum
oxides
on
alumina,
nickel
oxide,
nickel
thiomolybdate,
tungsten
and
nickel
sulfides,
and
vanadium
oxide.
Cobalt­
molybdenum
and
nickel­
molybdenum
are
the
most
commonly
used
catalysts
for
hydrotreating.
Both
types
of
catalyst
remove
sulfur,
nitrogen
and
other
contaminants
from
7
petroleum
feed.
Cobalt­
molybdenum
catalysts,
however,
are
selective
for
sulfur
removal,
while
nickel­
molybdenum
catalysts
are
selective
for
nitrogen
removal.
(Gary,
1994,
p.
189)

Initial,
or
"guard,"
reactors
can
be
placed
in
front
of
hydrocracking
reactors
to
remove
contaminants,
particularly
metals,
prior
to
hydrocracking.
Guard
reactors
may
employ
a
very
inexpensive
catalyst
(five
percent
of
the
cost
of
CoMo
catalyst)
to
remove
metals
from
expanded
bed
feed.
Spent
demetallization
catalyst
can
be
loaded
to
more
than
30
percent
vanadium.
A
catalyst
support
having
large
pores
preferentially
demetallizes
with
a
low
degree
of
desulfurization.
The
opposite
is
true
of
catalyst
supports
having
small
pores
(McKetta,
1992,
p.
688­
689).

3.
Ebullated
Bed
(Dual
Purpose)
Processes
Catalyst
beds
within
petroleum
hydroprocessing
units
may
be
fixed
or
moving.
Most
hydroprocessing
reactors
are
fixed­
bed
reactors.
Hydroprocessing
units
with
fixed­
bed
reactors
must
be
shut
down
to
remove
the
spent
catalyst
when
catalyst
activity
declines
below
an
acceptable
level
(due
to
the
accumulation
of
coke,
metals,
and
other
contaminants).
There
are
a
few
types
of
hydroprocessing
reactors
with
moving,
or
ebullating
catalyst
beds.
In
ebullated
bed
hydroprocessing,
the
catalyst
within
the
reactor
bed
is
not
fixed.
In
such
a
process,
the
hydrocarbon
feed
stream
enters
the
bottom
of
the
reactor
and
flows
upward
through
the
catalyst;
the
catalyst
is
kept
in
suspension
by
the
pressure
of
the
fluid
feed.
Ebullating
bed
reactors
are
capable
of
converting
the
most
problematic
feeds,
such
as
atmospheric
resids,
vacuum
resids,
and
heavy
oils
(all
of
which
have
a
high
content
of
asphaltenes,
metals,
sulfur,
and
sediments)
to
lighter,
more
valuable
products
while
simultaneously
removing
contaminants.
The
function
of
the
catalyst
is
to
remove
contaminants
such
as
sulfur
and
nitrogen
heteroatoms,
which
accelerate
the
deactivation
of
the
catalyst,
while
cracking
(converting)
the
feed
to
lighter
products.
Because
ebullating
bed
reactors
perform
both
hydrotreating
and
hydrocracking
functions,
EPA
also
refers
to
them
as
dual
purpose
reactors.
Ebullating
bed
catalysts
are
made
of
pellets
that
are
less
than
one
millimeter
in
size
to
facilitate
suspension
by
the
liquid
phase
in
the
reactor
(Generalizations
from:
Scherzer,
1996;
Gary,
1994;
Colyar,
1997).

Licensed
ebullating
bed
processes
include:

$
LC­
Fining.
Licensed
by
ABB
Lummus
Global
Inc.,
Oxy
Research
and
Development
Co.,
and
BP
Amoco
Corporation.
$
H­
Oil.
Licensed
by
IFP
North
America
and
Texaco.
$
T­
Star.
Licensed
by
IFP
North
America
and
Texaco.

LC­
Fining
and
H­
Oil
both
use
similar
technologies
but
offer
different
mechanical
designs.

3.1
H­
Oil
H­
Oil
is
used
to
convert
resid
and
heavy
oils
to
upgraded
petroleum
products
such
as
LPG,
gasoline,
middle
distillates,
gas
oil,
and
desulfurized
fuel
oil.
Stable
operation
is
achieved
through
a
high
operating
pressure
which
ensures
a
sufficient
reactor
outlet
hydrogen
partial
8
pressure.
Typical
operating
conditions
for
the
H­
Oil
process
are
shown
in
Table
3B1
(Colyar,
1997).

Table
3B1.
Typical
H­
Oil
Process
Operating
Conditions
Parameter
Value
Temperature,
°C
415B440
Pressure,
atm
168B207
LHSV,
h
­1
0.4B1.3
Catalyst
Replacement
Rate,
kg/
ton
feed
1
0.3B2.0
Single
Train
Throughput,
bpsd
up
to
34,000
Source:
Colyar,
1997.
1.
For
a
40,000
BPSD
design,
this
removal
rate
results
in
the
generation
of
2
to
13
tons
of
spent
catalyst
per
day.

Tables
3­
2
and
3­
3
present
performance
data
for
H­
Oil
operation.
Typical
process
performances
for
two
different
catalysts
are
shown
in
Table
3B2
for
two­
stage
operation
(in
twostage
operation,
two
H­
Oil
reactors
are
used
in
series).
Other
catalysts
are
available,
for
example
a
different
second
generation
catalyst
achieving
conversions
greater
than
80
percent
(Colyar,
1997).
Table
3B2
shows
that
sulfur,
nitrogen,
and
metals
are
reduced
between
the
feed
and
the
product
(up
to
92
percent
for
sulfur,
50
percent
for
nitrogen,
and
90
percent
for
metals),
and
that
conversion
up
to
90
percent
is
achieved.

The
H­
Oil
reactor
is
flexible
in
that
it
can
handle
feedstock
with
either
high
or
low
metals
concentrations,
although
it
is
particularly
efficient
in
treating
and
cracking
heavier
feedstocks
(e.
g.,
vacuum
resid).
Table
3­
3
shows
intermediate
product
yields
from
two­
stage
H­
Oil
processing
of
vacuum
resid
from
Arabian
Medium
crude
at
two
conversion
rates,
65
percent
and
90
percent
(Hydrocarbon
Processing,
1998).
Although
typical
nickel
and
vanadium
concentrations
of
Arabian
Medium
crude
are
not
particularly
high
(9.5
and
46
ppm,
respectively;
Environment
Technology
Center,
2000),
the
vacuum
resid
derived
from
the
crude
will
have
higher
concentrations
of
these
metals
because
metal
compounds
accumulate
in
the
heavier
fractions.
The
H­
Oil
reactor
is
designed
particularly
for
the
processing
of
these
heavier
fractions.
Table
3­
3
also
shows
the
high
desulfurization
rates
that
can
be
achieved
in
an
H­
Oil
reactor.
9
Table
3B2.
H­
Oil
Process
Performance
Parameter
Results
1
st
Generation
Catalyst
2
nd
Generation
Catalyst
Hydrodesulfurization,
wt%
55B80
75B92
Nitrogen
Removal,
wt%
25B35
30B50
Metals
Removal,
wt%
65B90
(similar
for
each)

Residue
Conversion,
vol%
45B90
45B85
CCR
Conversion,
wt%
45B65
65B75
H2
Consumption,
Nm
3
/m
3
130B300
(similar
for
each)

Source:
Colyar,
1997.
The
1
st
Generation
catalyst
is
the
standard
catalyst.
The
2
nd
Generation
Catalyst
is
a
new
catalyst
available
for
the
H­
Oil
Process
which
is
claimed
to
result
in
higher
process
performance
and
improved
product
quality
affecting
both
the
H­
Oil
distillates
and
unconverted
residue.

Table
3B3.
Yields
and
Operation
for
Two­
stage
H­
Oil
Processing
of
Arabian
Medium
Vacuum
Resid
Parameter
Product
Results
65
%
Conversion
90
%
Conversion
Removal
Rates
Desulfurization,
wt
%
removal
91
84
CCR
Conversion,
wt
%
removal
69
82
Yields
H2
S
&
NH3
,
wt
%
5.6
5.1
C1
to
C3
,
wt
%
3.1
6.7
C4
to
221°
C,
vol
%
17.6
23.8
205°
C
to
371°
C,
vol
%
22.1
36.5
371°
C
to
566°
C,
vol
%
34.0
37.1
566
°C
+
,
vol
%
33.2
9.5
Operating
Parameters
H2
consumption,
scfb
1,410
1,860
Source:
Hydrocarbon
Processing,
1998.
10
Table
3B4
summarizes
the
feed
properties
and
operating
data
for
the
H­
Oil
processing
of
vacuum
resid
derived
from
Arabian
Heavy
crude
at
two
different
conversion
rates,
65
percent
and
85
percent
conversion.
Again,
the
heaviest
feedstocks
(e.
g.,
vacuum
resids)
generally
are
found
to
contain
the
highest
concentration
of
metals
(Nongbri,
1992).
The
following
conclusions
are
evident
from
Table
3­
4:

$
High
levels
of
sulfur
and
nitrogen
removal
(90
percent
and
66
percent,
respectively),
similar
to
the
previous
table.
$
High
levels
of
nickel
and
vanadium
removal
(81
percent
and
91
percent,
respectively).
$
High,
but
not
complete,
conversion
(up
to
85
percent).
$
Higher
conversions
of
the
feedstock
result
in
slightly
lower
levels
of
desulfurization
and
metal
removal.

Table
3B4.
H­
Oil
Processing
of
Arabian
Heavy
Resid
Parameter
Feed
Properties
Reduction
(%)
in
Product
65%
Conversion
85%
Conversion
Sulfur,
wt%
6.00
90.1
88.0
Nitrogen,
ppmw
4,800
57.3
65.7
Nickel,
ppmw
64
81.2
78.4
Vanadium,
ppmw
205
91.4
88.4
538°
C+,
vol%
95.0
65.0
85.0
CCR,
wt%
27.7
69.3
75.3
Hydrogen,
wt%
9.86
C
C
Gravity,
°API
3.0
C
C
Carbon,
wt%
83.63
C
C
Hydrogen
Consumption,
scfb
1,550
2,440
Number
of
Stages
2
2
Source:
Nongbri,
1992.

Tables
3­
5
and
3­
6
present
sulfur
content
data
for
products
resulting
from
the
H­
Oil
process.
Table
3­
5
presents
data
from
a
Russian
vacuum
resid
for
a
two­
stage
H­
Oil
process
(where
the
two
reactors
are
in
series),
operating
at
68
volume
percent
conversion
(Colyar,
1997).
Table
3B6
presents
typical
product
qualities
obtained
from
a
Heavy
Arabian
crude
using
the
HOil
process
(Scherzer,
1996).
Colyar
(1997)
identified
the
H­
Oil
process
as
demonstrating
good
selectivity
to
middle
distillates
and
vacuum
gas
oil.
Higher
conversion
rates
show
an
increase
in
the
selectivity
towards
lighter
products
including
light
gases.
The
unconverted
resid
can
be
used
11
as
feed
to
a
resid
FCC
Unit,
or
for
other
uses.
Both
tables
demonstrate
that
the
sulfur
content
of
the
products
decrease
as
the
products
become
`lighter.
'
Additionally,
the
data
in
Table
3­
6
show
that
the
sulfur
content
of
all
products
(including
the
heaviest)
exiting
the
H­
Oil
unit
are
less
than
the
concentration
in
the
crude
oil
(note
that
the
sulfur
content
of
the
actual
feed
to
the
H­
Oil
is
most
likely
even
greater
than
the
sulfur
content
of
the
crude,
because
the
feed
to
the
unit
is
heavier
than
the
crude).

Table
3B5.
Typical
H­
Oil
Process
Results
Fraction
Yield,
wt%
Yield,
vol%
Sulfur,
%

C1BC4
C5B180°
C
180B370°
C
370B538°
C
538°
C
3.5
6.3
25.5
33.9
28.8
C
8.7
29.8
36.3
28.9
C
<
0.01
0.05
0.21
0.91
Source:
Colyar,
1997.
Two­
stage
H­
Oil
process
using
vacuum
resid
as
feed,
operating
at
68
volume
percent
conversion.

Table
3B6.
H­
Oil
Processing
of
Arabian
Crude:
Typical
Product
Properties
Fraction/
Property
Virgin
Crude
H­
Oil
Products
Naphtha
Middle
distillate
Vacuum
gas
oil
Sulfur,
wt
%
2.7
0.06B0.15
0.26B0.59
0.71B1.55
Gravity,
°API
22.5
62.0B62.2
34.4B34.5
16.4B19.8
Source:
Scherzer,
1996.
Table
14.10.
Low
conversion
70%.
High
conversion
90%.

Tables
3­
7
and
3­
8
present
data
regarding
the
metals
content
of
feedstock
to
the
H­
Oil
process.
Nickel
and
vanadium
are
the
two
metals
most
often
presented
in
the
literature
as
typical
feed
contaminants.
These
two
metals
generally
appear
at
higher
concentrations
than
other
metals
in
crude
oil
and
can
have
deleterious
effects
on
certain
catalysts
and
fuel
products.

Table
3­
7
compares
the
products
obtained
from
two
different
conversion
rates,
65
volume
percent
and
85
volume
percent,
for
a
vacuum
residue
(38,000
bpsd
of
a
nominal
565°
C
vacuum
residue
was
processed).
The
feedstock
is
Arab
Light/
Heavy
vacuum
residue
obtained
from
a
50/
50
blend
of
Arabian
Light
and
Heavy
crudes,
and
is
a
standard
for
many
company
studies.
The
H­
Oil
process
consisted
of
a
single
train
with
two
H­
Oil
reactors
in
series.
Table
3B7
illustrates
the
feed
characteristics
and
product
quality
as
a
measure
of
sulfur
content
(Wisdom,
1997).
Table
3B7
shows
that
the
sulfur
content
of
products
exiting
the
H­
Oil
reactor
is
less
than
the
sulfur
content
of
the
feed.
However,
there
is
a
tradeoff
between
conversion
and
sulfur
content:
a
higher
conversion
results
in
lower
sulfur
removal
(i.
e.,
greater
sulfur
concentrations
reside
in
the
products
as
conversion
increases).
The
relatively
high
nickel
and
vanadium
feed
concentration
is
demonstrative
of
the
H­
Oil
unit's
capability
to
process
feeds
with
high
metal
concentrations.
12
Table
3­
8
presents
characteristics
of
a
vacuum
resid
(nominal
565°
C)
derived
from
a
60/
40
blend
of
Isthmus
and
Maya
crude
processed
in
an
H­
Oil
reactor
(Wisdom,
1997).
As
above,
the
H­
Oil
process
to
which
the
vacuum
resid
was
fed
consisted
of
a
single
train
with
two
H­
Oil
reactors
in
series
operated
at
38,000
bpsd.
The
feed
had
a
sulfur
content
of
4.71
percent
and
a
metals
concentration
of
707
ppmw.
Other
feed
properties
are
identified
in
Table
3B8.
The
H­
Oil
product
fractionator
bottoms
(expected
to
have
the
highest
sulfur
content
of
any
fraction)
had
a
sulfur
content
of
1.0
percent
at
moderate
conversion
(65
volume
percent)
and
a
sulfur
content
of
1.5
percent
at
high
conversion
(85
volume
percent).
These
results
demonstrate
the
treatment
capability
of
the
H­
Oil
reactor.
As
in
the
previous
table,
the
high
metal
concentration
of
the
feed
is
indicative
of
the
H­
Oil
unit's
processing
capabilities.

Table
3B7.
Product
Quality
for
H­
Oil
Conversion
of
Arab
Light/
Heavy
Vacuum
Residue
Parameter
Value
Feed
Sulfur,
wt%
5.33
Nickel
+
Vanadium,
ppmw
221
Gravity,
°API
4.7
CCR,
wt%
24.6
Sulfur
Content
of
Products,
wt%

Naphtha
(moderately
high
conversion)
0.02
Mid­
distillate
(moderate
conversion)
0.90
Mid­
distillate
(high
conversion)
0.20
Vacuum
Gas
Oil
(moderate
conversion)
0.23
Vacuum
Gas
Oil
(high
conversion)
1.04
Source:
Wisdom,
1997.
Moderate
conversion:
65%;
High
conversion:
85%.
13
Table
3B8.
Feedstock
Inspections
for
Isthmus/
Maya
Feed
Parameter
Value
Sulfur,
wt%
4.71
Nickel
+
Vanadium,
ppmw
707
Specific
Gravity
1.06
Gravity,
°API
1.5
CCR,
wt%
27.8
Source:
Wisdom,
1997.

3.2
LC­
Fining
The
LC­
Fining
ebullated
bed
process
can
achieve
desulfurization,
demetallization,
CCR
reduction,
and
hydrocracking
of
atmospheric
and
vacuum
resids.
This
process
yields
a
full
range
of
high
quality
distillates;
heavy
residuals
can
be
used
as
fuel
oil,
synthetic
crude,
or
feedstock
for
a
resid
FCC,
coker,
visbreaker
or
solvent
deasphalter.
Operating
conditions
for
the
LCFining
process
include
reactor
temperatures
of
385°
C
to
450°
C
and
H2
partial
pressure
of
68
to
184
atm.
These
can
be
compared
to
the
H­
Oil
operating
conditions
in
Table
3B1.
The
LC­
Fining
process
can
achieve
conversion
of
40
to
97
percent
(or
more),
desulfurization
of
60
to
90
percent,
demetallization
of
50
to
98
percent,
and
CCR
reduction
of
35
to
80
percent.
Table
3B9
illustrates
typical
properties
of
Arabian
Heavy/
Arabian
Light
blends
fed
to
the
LC­
Fining
Process
(Hydrocarbon
Processing,
1998).

Table
3B9.
Typical
Properties
of
LC­
Fining
Process
Feedstock
Parameter
Value
Atm.
Resid
Vac.
Resid
Sulfur,
wt
%
3.90
4.97
Ni/
V,
ppmw
18/
65
39/
142
Gravity,°
API
12.40
4.73
Source:
Hydrocarbon
Processing,
1998.
Blend
of
Arabian
heavy
and
light.

3.3
T­
Star
The
T­
Star
process
is
a
third
ebullated
bed
process.
T­
Star
units
can
maintain
conversions
in
the
range
of
20
to
60
percent
and
hydrodesulfurization
in
the
93
to
99
percent
range
for
four­
year
run
lengths
(Hydrocarbon
Processing,
2000).
The
unit
can
act
as
either
an
FCCU
pretreater
or
VGO
hydrocracker.
H­
Oil
catalyst
can
be
used
in
the
T­
Star
process.
A
TStar
reactor
can
also
be
placed
in­
line
with
an
H­
Oil
reactor
to
improve
the
quality
of
H­
Oil
14
distillate
products
such
as
virgin
distillates,
FCCU
light
or
heavy
cycle
gas
oil,
and
coker
gas
oils.

In
mild
hydrocracking
mode,
the
T­
Star
process
can
reach
conversions
up
to
the
60
volume
percent
range.
An
advantage
of
operating
the
T­
Star
unit
in
mild
hydrocracking
mode
is
that
the
T­
Star
catalyst
is
not
sensitive
to
sulfur
and
nitrogen
levels
in
the
feed
and
will
provide
constant
conversion,
product
yields,
and
product
quality.
This
consistency
in
output
is
due
to
the
reactor
catalyst
being
replaced
while
the
unit
remains
on­
line.
A
commercial
scale
demonstration
of
the
T­
Star
Process
in
conjunction
with
the
startup
of
H­
Oil
units
was
done
as
a
joint
venture
between
Husky
Oil,
Canada
and
HRI
(HRI
currently
is
IFP).
The
feed
properties
and
process
performance
for
the
T­
Star
process
are
shown
in
Tables
3B10
and
3B11
(Johns,
1993).
Table
3­
10
shows
that
high
levels
of
sulfur
and
nitrogen
may
be
present
in
the
feed
to
the
T­
Star
unit.
Table
3­
11
shows
that
high
percentages
of
sulfur
and
nitrogen
are
removed
from
the
products
as
a
result
of
T­
Star
processing.

Table
3B10.
Husky
Oil
Trial
Feed
Properties
for
T­
Star
Reactor
Parameter
Value
Sulfur,
wt%
2.8
Nitrogen,
ppmw
1,328
Carbon
Residue,
wt%
0.21
Source:
Johns,
1993.

Table
3B11.
T­
Star
Commercial
Demonstration
Parameter
Results
Hydrodesulfurization,
wt
%
91.7
Nitrogen
removal,
wt
%
80.0
343°
C+
Net
Conversion,
vol%
1
9
Hydrogen
Consumption,
scfb
642
Source:
Johns,
1993.
1.
Examples
of
products
lighter
than
343°
C
include
light
naphtha,
heavy
naphtha,
and
light
gas
oil.
An
example
of
a
product
heavier
than
343°
C
is
heavy
gas
oil.

Tables
3­
12
and
3­
13
show,
respectively,
the
properties
of
a
feedstock
processed
in
the
TStar
process
and
the
resulting
product
qualities.
The
T­
Star
process
was
operated
at
a
conversion
rate
of
30
percent
and
was
used
to
produce
FCC
unit
feed
from
a
single
stage
operation
using
a
single
catalyst
system
under
moderate
pressure
levels
(Nongbri,
1996).
The
predominant
15
feedstock
was
vacuum
gas
oil
that
was
not
treated
prior
to
being
fed
to
the
T­
Star
reactor.
Table
3­
12
shows
that,
in
this
case,
the
sulfur
and
nitrogen
levels
of
the
feed
are
relatively
high.
Table
3­
13
shows
that
the
sulfur
and
nitrogen
levels
of
the
products
(including
the
heaviest
products)
are
lower
than
the
feed
levels
as
a
result
of
T­
Star
processing.

Table
3B12.
T­
Star
Reactor
Feedstock
Components
and
Properties
Parameter
Value
Sulfur,
wt
%
1.93
Total
Nitrogen,
ppmw
1820
Nickel,
ppmw
1.6
Vanadium,
ppmw
4.4
Watson
Aromatics,
wt
%
61.7
Gravity,
°API
23.7
182°
C
and
lighter,
wt
%
182B360°
C,
wt
%
360°
C+,
wt
%
4.0
23.4
72.6
Feed
components:
Virgin
Vacuum
Gas
Oil
(71%),
Coker
Light
Gas
Oil
(9%),
Aromatic
Extracts
(9%),
Coker
Heavy
Gas
Oil
(6%),
and
Heavy
Coker
Naphtha
(5%)

Source:
Nongbri,
1996.

Table
3B13.
T­
Star
FCCU
Feed
Yields
at
30
Percent
Conversion
Feed
or
Product
Fraction
Gravity,
°API
Sulfur,
wt
%
Nitrogen,
ppmw
Feed
property
(from
previous
table)
23.7
1.93
1,820
Product
Fraction
H2
S
and
NH3
C1
B
C4
C5
B
65°
C
65
B
170°
C
170
B
360°
C
360°
C
+
C
C
85.6
59.0
33.7
25.5
C
C
0.007
0.007
0.009
0.100
C
C
C
3
46
766
Overall
Reduction
Rate
C
97
wt%
reduction
78
wt%
reduction
Source:
Nongbri,
1996.
Hydrogen
consumption
is
700
SCFB.

Tables
3­
14
and
3­
15
present
data
for
the
T­
Star
process
operating
in
mild
hydrocracking
mode
using
a
single
stage
operation
and
a
single
catalyst
system
under
moderate
pressure
levels
16
(Nongbri,
1996).
The
T­
Star
process
was
operated
at
a
conversion
rate
of
55
percent;
Table
3­
14
shows
that,
in
this
case,
the
predominant
feedstock
was
vacuum
gas
oil
without
any
type
of
prior
processing;
as
a
result
the
sulfur
and
nitrogen
levels
of
the
feed
are
relatively
high.
Table
3­
15
shows
that
the
sulfur
and
nitrogen
levels
of
the
products
(including
the
heaviest
products)
are
lower
than
the
feed
levels
as
a
result
of
T­
Star
processing.

Tables
3­
12
to
3­
15
show
that
desulfurization
was
in
excess
of
97
percent
for
each
operation
of
the
T­
Star
reactor.
For
the
two
operations
identified,
denitrogenation
was
78
percent
in
the
first
case
and
94
percent
in
the
second
(Nongbri,
1996).

Table
3B14.
T­
Star
Reactor
Feedstock
Properties
Parameter
Value
Gravity,
°API
Sulfur,
wt
%
Total
Nitrogen,
ppmw
Watson
Aromatics,
wt
%
Nickel,
ppmw
Vanadium,
ppmw
182°
C
and
lighter,
wt
%
182B360
°C,
wt
%
360°
C+,
wt
%
23.5
2.10
819
54.2
<5
<5
0
29.0
71.0
Feed
components:
Virgin
Vacuum
gas
Oil
(75%),
Light
Cycle
Oil
(13%),
Virgin
Diesel
(12%)

Source:
Nongbri,
1996.

Table
3B15.
T­
Star
Mild
Hydrocracking
Yields
at
55
Percent
Conversion
Feed
or
Product
Gravity,
°API
Sulfur,
wt
%
Nitrogen,
ppmw
Feed
property
(from
previous
table)
23.5
2.10
819
Product
Fraction
H2
S
and
NH3
C1
B
C4
C5
B
65°
C
65
B
170°
C
170
B
360°
C
360°
C+
C
C
90.0
57.5
35.0
32.2
C
C
0.01
0.02
0.03
0.08
C
C
1
4
30
90
Overall
Reduction
Rate
C
98
wt%
reduction
94
wt%
reduction
Source:
Nongbri,
1996.
Hydrogen
consumption
is
922
scfb.
17
3.4
Population
EPA
is
aware
of
two
facilities
in
the
U.
S.
that
use
ebullated
bed
technologies.
These
facilities
are
identified
in
Table
3B16.
The
two
facilities
were
identified
in
an
evaluation
of
data
collected
for
EPA's
1992
petroleum
refining
survey.
The
data
in
Table
3B16
do
not
include
facilities
which
may
have
constructed
new
units
after
1992
(the
year
for
which
EPA's
data
were
collected),
or
which
were
otherwise
not
identified
from
EPA's
data.

Table
3B16.
Summary
of
U.
S.
Refineries
Using
Ebullated
Bed
Technology
Refinery
Name
Licensor
and
Name
of
Hydroprocessing
Unit
Capacity,
BPSD
Catalyst
Type
BP
Amoco,
Texas
City
TX
C.
E.
Lummus
LC­
Fining
75,000
No
data
Motiva,
Convent
LA
Texaco
H­
Oil
40,158
Ni/
Mo
Source:
Non­
CBI
data
from
the
database
developed
from
the
1992
EPA
petroleum
refining
solid
waste
survey.

3.5
Conclusions
Based
on
the
data
presented
in
this
section,
the
following
conclusions
are
evident
regarding
ebullated
bed
processes:

$
There
are
three
different
licensed
ebullated
bed
processes:
H­
Oil,
LC­
Fining,
and
T­
Star.
In
each
of
these
processes,
the
ebullated
bed
operates
so
that
there
is
constant
withdrawal
and
replacement
of
the
catalyst.

$
Ebullated
bed
processes
use
very
heavy
feeds
such
as
vacuum
gas
oil
or
vacuum
residue.
Such
feeds
have
correspondingly
elevated
sulfur,
nitrogen,
and
metals
content
(i.
e.,
compared
to
other
crude
oil
distillation
cuts).
The
feeds
are
not
pretreated
prior
to
the
ebullated
bed
process.

$
Ebullating
bed
processes
yield
high
product
conversions,
however
the
conversion
is
not
100
percent.

$
High
sulfur
reduction
is
seen
in
all
products.
Nitrogen
is
also
significantly
reduced,
but
to
a
lesser
degree
than
the
sulfur.

$
The
process
can
accept
feedstocks
with
elevated
metals
content
(e.
g.,
up
to
700
ppm
in
one
case);
the
metals
content
of
each
product
is
less
than
the
feed
concentration
indicating
that
the
unit
is
hydrotreating
the
feed.
18
4.
Mild
Hydrocracking
The
purpose
of
mild
hydrocracking
is
to
convert
vacuum
gas
oil
to
low
sulfur
distillates
at
operating
conditions
consistent
with
those
for
hydrotreating
equipment.
Full
conversion
of
the
feedstock
does
not
occur
in
the
mild
hydrocracking
process.
Typically
the
process
yields
conversions
of
20
to
60
percent
(Marion,
1998).
The
products
obtained
through
mild
hydrocracking
are
high
quality,
low
sulfur/
nitrogen
diesel
and
unconverted
VGO
fractions.
The
VGO
fraction
is
desirable
as
FCC
feedstock
due
to
its
high
hydrogen
content
and
reduced
sulfur
and
nitrogen
levels.
The
product
properties
of
the
fractions
depends
on
the
feedstock
characteristics
and
the
process
operating
conditions
(Johns,
1996).

Most
often,
mild
hydrocracking
units
are
re­
designs
of
existing
hydrotreating
VGO
process
units.
The
process
employs
a
single
reactor
and
operates
on
a
once­
through
basis,
designed
to
partially
convert
the
VGO
into
low­
sulfur
naphtha
or
distillate.
The
feed
to
a
mild
hydrocracking
unit
is
mostly
vacuum
gas
oil
but
can
also
be
other
heavy
feedstock
(Scherzer,
1996).
Catalysts
used
in
this
type
of
unit
are
multi­
purpose
in
that
they
perform
the
hydrotreating
functions
of
desulfurization
and
denitrogenation
but
also
convert
the
heavy
fuel
oil
molecules
into
lighter
mid­
distillates
(Desai,
undated).
The
catalysts
are
mildly
acidic,
usually
consisting
of
cobalt
or
nickel
oxide
combined
with
molybdenum
or
tungsten
oxide,
supported
on
amorphous
silica­
alumina
or
mildly
acidic
zeolite
(Scherzer,
1996).

The
process
operates
under
temperature
conditions
of
350B440°
C
and
pressures
of
30B100
atm
(Scherzer,
1996).
The
hydrogen
partial
pressure
has
the
greatest
effect
on
the
mild
hydrocracking
process.
Higher
pressures
result
in
higher
reaction
rates
and
increased
catalyst
stability.
Lower
pressures
facilitate
deactivation
of
the
catalyst
due
to
the
fact
that
the
reactive
coke
precursors
are
not
hydrogenated
quickly
enough
to
prevent
coke
formation
on
the
catalyst.
Reactor
pressure
cannot
always
be
controlled,
however.
Instead,
it
is
dependent
on
the
available
pressure
of
the
hydrogen
gas,
which
would
otherwise
require
installation
of
costly
compressors
to
increase
pressure.
To
compensate
for
varying
pressures,
the
reactor
temperature
can
be
adjusted
to
achieve
similar
results
(Johns,
1996).

Table
4B1
shows
typical
feed
properties
for
a
mild
hydrocracking
process.
The
metal
concentration
of
less
than
20
ppmw
is
significantly
less
than
the
typical
metal
concentration
of
an
ebullating
bed
feedstock.
The
sulfur
and
nitrogen
levels,
however,
are
elevated.
Table
4B2
shows
typical
unit
performance
and
product
yields
and
qualities
of
mild
hydrocracking
operated
at
30
percent
conversion
(Marion,
1998).
Table
4B2
shows
high
desulfurization
rates
for
all
products,
including
the
heaviest
fractions.
19
Table
4B1.
Typical
Mild
Hydrocracking
Feedstock
Characteristics
Parameter
1
Value
Gravity,
°API
22.1
S
(wt
%)
2.7
N
(ppmw)
800
Nickel
(ppm)
2
2.5
Vanadium
(ppm)
2
16
Boiling
Point
at
5
wt%,
°C
370
Boiling
Point
at
50
wt%,
°C
460
Boiling
Point
at
95
wt%,
°C
550
Source:
Marion,
1998
unless
otherwise
indicated.
1.
Properties
of
vacuum
gas
oil
(370
to
550°
C)
derived
from
Arabian
light
crude.
2.
Source:
Environment
Technology
Center
1996B2000.

Table
4B2.
Typical
Mild
Hydrocracking
Performances
Based
on
Arabian
Light
Fraction
Yield
S,
ppmw
Gravity
°API
Polyaromatics,
wt
%
Wt
%
Vol
%

Feed
property
(from
previous
table)
C
C27,000
22.1
C
H2S
+
NH3
2.85
C
CC
C
C1
B
C4
0.70
C
CC
C
Naphtha
1.75
2.09
C
C
C
Diesel
25.23
26.71
300
C
<11
VGO
Product
70.27
72.31
<1000
26.6
C
TOTAL
100.80
101.78
C
C
C
Source:
Marion,
1998,
p.
52.
Two
year
cycle
length.
Overall
conversion:
30
wt
%.

4.1
MHUG
One
mild
hydrocracking
processes
is
called
MHUG
(Medium­
Pressure
Hydro
Upgrading)
technology.
It
is
presented
by
Technip
Benelux
in
alliance
with
RIPP/
Sinopec.
The
MHUG
process
uses
medium­
pressure,
single­
stage,
once­
through
technology
to
produce
low­
sulfur,
low­
aromatics
diesel
or
naphtha
reformer
feed.
Feedstocks
can
range
from
light
diesel­
range
feedstocks
to
heavy
vacuum
gas
oil
boiling­
range
fractions.
This
process
operates
at
a
pressure
below
100
atm,
has
low
operating
temperatures
and
hydrogen
consumption,
and
has
a
long
20
catalyst
cycle
time.
This
process
has
been
used
to
revamp
existing
processes
and
has
also
been
installed
as
a
grassroots
process
(Chen,
1999).

The
process
is
designed
such
that
two
catalysts
are
placed
in
series
within
a
single
reactor.
The
first
catalyst
(designated
RN
by
the
licensor)
is
a
hydrotreating
catalyst,
while
the
second
(designated
RT
by
the
licensor)
is
a
mild
hydrocracking
catalyst.
Both
have
Ni­
W
as
an
active
component.
The
RN
series
catalysts
are
identified
as
having
strong
hydrodenitrification,
hydrodesulfurization,
and
hydrodearomatisation
functions.
The
RT
series
catalysts
are
designed
to
promote
the
partial
saturation
of
polynuclear
aromatics,
the
ring
opening
of
naphthenic
aromatics,
and
the
ring
opening
of
naphthenes
(Chen,
1999).

Mild
hydrocracking
maintains
the
hydrotreating
advantage
of
sulfur
reduction
while
achieving
significant
conversion
of
the
feed.
Table
4B3
shows
the
pilot­
plant
test
results
for
the
mild
hydrocracking
of
an
FCC
feedstock
vacuum
gas
oil
derived
from
a
naphthenic
type
of
crude
oil
at
a
conversion
rate
of
35
percent
(Chen,
1999).
The
table
demonstrates
high
rates
of
desulfurization
and
denitrogenation
in
each
of
the
products.

Table
4B3.
Test
Results
for
MHUG
Application
to
Mild
Hydrocracking
of
FCC
Feed
Parameter
Value
in
Feed
Value
in
Product
Naphtha
Diesel
Hydroconverted
oil
Yield,
wt
%
C
7.15
26.81
64.51
Sulfur,
ppmw
10,000
16
19
9
Nitrogen,
ppmw
2,400
<0.5
<0.5
6
Initial
boiling
point,
°C
251
C
180
C
50%
Boiling
Point,
°C
447
C
CC
Final
boiling
point,
°C
503
C
350
C
Aromatics,
wt
%
39.3
56.3
(potential)
C
16.9
Hydrogen
content,
wt
%
C
CC13.34
Source:
Chen,
1999.

The
MHUG
process
also
can
be
used
to
upgrade
light
cycle
oil
(a
lighter
fraction
than
VGO)
to
low
sulfur,
low
aromatics
diesel
fuel.
The
hydrodearomatisation
function
of
the
catalyst
makes
it
an
ideal
process
for
upgrading
LCO
to
a
premium
diesel
component.
This
mode
of
operation
typically
operates
under
hydrogen
partial
pressures
of
around
65
atm
and
temperatures
in
the
range
of
350
to
365°
C.
If
diesel
is
the
desired
product,
a
diesel
yield
of
95
percent
is
typical
under
these
operating
conditions.
Table
4B4
illustrates
the
pilot
plant
test
results
for
MHUG
application
to
upgrade
LCO
(Chen,
1999).
Table
4­
4
identifies
significant
reductions
in
sulfur
content,
nitrogen
content,
and
aromatics
content
from
the
feed
to
the
diesel
product.
21
Table
4B4.
Test
Results
of
LCO
Upgrading
Using
MHUG
Parameter
Value
in
Feed
Value
in
Product
Naphtha
Diesel
Yield,
wt
%
C
7.0
93.0
Sulfur,
ppmw
10,400
C
16
Nitrogen,
ppmw
446
<0.5
1.4
Aromatics,
vol
%
48.2
C
17.8
Cetane
Index
39.0
C
52.0
Initial
Boiling
Point,
°C
203
C
C
50%
Boiling
Point,
°C
279
C
C
Final
Boiling
Point,
°C
360
C
C
Source:
Chen,
1999.

4.2
Population
From
the
information
collected,
it
was
not
possible
to
estimate
the
population
of
mild
hydrocracking
facilities
within
the
United
States.
Mild
hydrocracking
units
are
often
re­
designs
of
existing
VGO
hydrotreating
process
units;
it
is
difficult
to
identify
refineries
who
have
conducted
such
changes.

4.3
Conclusions
Based
on
the
above
information,
the
following
conclusions
are
reached
regarding
mild
hydrocracking
processes:

$
Mild
hydrocracking
processes
use
heavy
feeds
such
as
vacuum
gas
oil.
Mild
hydrocracking
does
not
accept
the
heaviest
refinery
feeds
such
as
those
used
for
some
ebullated
bed
processes.
The
feeds
are
not
pretreated
prior
to
the
mild
hydrocracking
process.

$
Facilities
will
often
`retrofit'
an
existing
reactor
to
mild
hydrocracking
mode.
For
this
reason
it
is
difficult
to
estimate
the
population
of
facilities
operating
mild
hydrocracking
units.

$
The
process
employs
a
single
fixed
bed
reactor
and
operates
on
a
once­
through
basis.
22
$
Mild
hydrocracking
bed
processes
yield
product
conversions
much
lower
than100
percent.
The
heaviest
product
is
used
for
FCC
feed,
fuel
oil,
etc.

$
Mild
hydrocracking
reduces
the
sulfur
and
nitrogen
heteroatom
concentrations
in
all
products.
Reductions
in
aromatic
content
also
were
noted
when
mild
hydrocracking
was
used
for
diesel
fuel
upgrading
(Table
4­
4).

$
Limited
data
are
available
describing
reductions
in
metals
content
achieved
via
mild
hydrocracking
processes.
The
data
available
indicate
that
feedstocks
for
mild
hydrocracking
processes
generally
have
relatively
low
metals
content.
For
example,
the
Arabian
light
crude
from
Table
4B1
has
a
total
metals
content
of
only
20
ppm.
Data
are
insufficient
to
determine
whether
feedstocks
with
higher
metals
contents
can
be
successfully
processed,
or
if
the
metals
in
the
feedstocks
are
deposited
on
the
catalyst
or
"pass
through"
to
the
products.
No
data
on
metals
removal
percentages,
or
the
metals
content
of
products,
were
identified.

5.
Single­
and
Multi­
Stage
Hydrocracking
Processes
Several
licensors
provide
staged
hydrocracking
technologies.
Hydrocracking
is
typically
classified
as
single­
stage
or
two­
stage
unit
operations.
While
nomenclature
and
design
objectives
differ
for
each
licensor
and
application,
several
similarities
are
evident.
These
include
the
following:

$
Catalysts
are
present
within
a
fixed
bed
reactor,
or
series
of
reactors.
$
Heavy
feeds,
such
as
vacuum
gas
oil,
are
typically
processed.
$
Lighter,
more
valuable
products
such
as
naphtha,
jet
fuel,
and
distillate
are
produced.
$
Some
or
all
of
the
heaviest
product
can
be
recycled
to
the
reactors.
$
Objectives
typically
include
sulfur/
nitrogen
removal
and
conversion
to
lighter
fuels.
Such
objectives
often
require
the
use
of
different
types
of
catalysts
at
different
points
in
the
process.

In
single­
stage
processing,
one
or
more
reactors
are
used.
If
one
reactor
is
used,
multiple
catalysts
can
still
be
employed
by
using
a
stacked
bed
arrangement
of
different
catalysts.
Heavy
hydrocarbon
and
hydrogen
is
fed
to
the
first
reactor
that
generates
hydrogen
sulfide
and
ammonia
gases
as
a
result
of
hydrodesulfurization
and
hydrodenitrification
reactions.
However
there
is
no
separation
of
products
between
the
first
and
second
reactors,
so
that
the
second
reactor
receives
the
gases
and
light
products
generated
from
the
first
reactor
(George,
1994).
Typically
40
to
80
percent
of
the
feed
volume
is
converted
in
one
pass.
If
the
fractionator
bottoms
are
not
recycled,
higher
conversion
(90
percent)
can
be
achieved
with
lower
temperatures
and
lower
hydrogen
partial
pressures
(Scherzer,
1996).

In
two­
stage
processing,
light
gases
and
relatively
light
petroleum
products
(such
as
naphtha)
are
removed
between
the
two
reactors.
The
remaining
feed
then
proceeds
to
the
second
reactor
(George,
1994).
An
advantage
to
this
configuration
is
that
better
conversion
(i.
e.,
cracking)
results
are
achieved
in
the
second
reaction
because
the
reaction
occurs
in
the
absence
of
23
ammonia;
ammonia
inhibits
the
activity
of
hydrocracking
catalyst
(Criterion,
1998).
A
second
advantage
of
two­
stage
operation
is
that
the
capacity
of
the
second
reactor
is
essentially
increased:
greater
quantities
of
heavier
feedstock
can
be
fed
to
the
second
reactor
as
the
light
gases
and
products
are
separated
from
the
feed
after
being
treated
in
the
first
reactor.
Table
5­
1
illustrates
typical
operating
conditions
for
conventional
one
or
two­
stage
hydrocracking
(Scherzer,
1996).

Table
5­
1.
Single
or
Two­
Stage
Hydrocracking
Operating
Conditions
Parameter
Value
Conversion,
wt%
70­
100
Temperature,
°C
350­
450
H2
partial
pressure,
atm
100­
200
LHSV,
h
­1
0.5­
2.0
Hydrogen
Feed
Rate,
Nm
3
/m
3
1000­
2000
Source:
Scherzer,
1996
(Chapter
12).

In
the
case
of
most
two­
stage
units,
the
different
reactors
have
different
functions.
One
way
this
is
illustrated
is
through
the
type
of
catalyst(
s)
used
in
each
reactor.
For
example,
one
catalyst
can
be
designed
for
primarily
sulfur
and
nitrogen
reduction,
and
a
second
catalyst
designed
primarily
for
cracking.
A
single
catalyst
can
have
multiple
effects,
or
a
single
reactor
or
series
of
reactors
can
contain
multiple
catalysts
(as
shown
in
the
example
presented
in
Section
5.2
below).
In
cases
where
multiple
catalysts
are
used,
the
initial
catalyst
is
used
for
(1)
pretreating
the
feed
to
remove
nitrogen
and
sulfur,
and
(2)
aromatics
saturation.
These
are
followed
by
cracking
catalysts
which
convert
heavy
oil
to
either
gasoline
or
distillate
fuels
(Criterion,
1998).
Criterion
(1998)
also
describes
post­
treat
catalysts
that
may
be
used
to
stabilize
the
product
by
preventing
reactions
between
hydrogen
sulfide
and
olefins
that
form
mercaptans.

Guard
reactors
are
used
in
hydrocracking
processes
to
protect
catalysts
in
subsequent
reactors,
including
precious
metals
hydrocracking
catalysts,
from
contaminants
in
feedstocks
that
are
not
previously
hydrotreated.
If
a
hydrocracking
unit
is
designed
to
accept
feedstocks
that
have
not
been
hydrotreated
previously,
a
guard
reactor
precedes
the
first
hydrocracking
reactor
in
the
process
flow.
The
purpose
of
the
guard
reactor
is
to
convert
organic
sulfur
and
nitrogen
compounds
to
hydrogen
sulfide
and
ammonia.
Guard
reactors
also
serve
the
purpose
of
reducing
the
metals
content
in
the
feed
to
the
hydrocracking
units.
Catalysts
used
in
guard
reactors
are
usually
modified
hydrotreating
catalysts
such
as
CoMo
on
silica­
alumina.
Most
of
the
metals
in
the
feed
will
be
deposited
on
the
catalyst
in
the
guard
reactor
and
there
will
be
a
substantial
reduction
in
the
Conradson
and
Ramsbottom
carbons,
resulting
in
a
feed
to
the
hydrocracking
reactors
that
is
low
in
metals
and
carbon
forming
precursors
(Gary,
1994,
p.
156,
174­
176).

An
example
of
a
two­
stage
hydrocracking
unit,
consisting
of
two
separate
reactors
and
a
fractionator,
was
described
for
a
Kuwait
refinery
(Maheshri,
2000).
The
feed
is
vacuum
gas
oil,
3
A
typical
sulfur
content
of
Kuwait
crude
is
2.52
percent
(ETC,
2000).
The
sulfur
content
of
the
actual
unit
feed
in
this
case
may
be
higher
or
lower
depending
on
the
specific
crude
source,
the
degree
that
sulfur
is
`concentrated'
in
the
bottom
fractions,
and
the
severity
of
upstream
desulfurization
in
this
instance.

24
where
some
sulfur
reduction
has
already
taken
place:
crude
unit
residue
is
hydrotreated
and
fed
to
a
vacuum
rerun
unit,
where
VGO
is
drawn
off
to
become
hydrocracking
feed.
3
The
two­
stage
hydrocracking
unit
normally
is
operated
such
that
feed
enters
the
first
stage,
light
products
and
gas
are
removed,
and
the
majority
of
the
fractionator
bottoms
are
continuously
recycled
to
the
second
stage
to
achieve
an
overall
conversion
of
95
percent.

The
MDQ
Unionfining
process
is
an
example
of
a
process
that
can
be
constructed
as
either
a
single
or
two­
stage
operation.
Single­
stage
typically
uses
one
or
two
reactors.
These
reactors
use
base­
metal
catalysts
that
may
be
the
same
or
different
for
each
reactor.
The
twostage
process
uses
noble­
metal
catalysts
in
the
second­
stage
reactor
where
there
is
a
much
lower
contaminant
concentration
due
to
interstage
gas
stripping
(Heckel,
1998).

Licensed
single­
and
two­
stage
hydrocracking
units
include:

C
IFP
Technology.
IFP,
North
America.
C
MAKFining.
Licensed
by
Kellog
Brown
&
Root.
C
Shell
Hydrocracking
Process,
Shell
International
Oil
Products
B.
V.

Examples
of
these
processes
are
discussed
in
Sections
5.1,
5.2,
and
5.3,
respectively.

5.1
IFP
Technology
Hydrocracking
IFP
hydrocracking
is
used
for
the
purpose
of
upgrading
straight
vacuum
gas
oil
or
VGO
blended
with
LCO,
deasphalted
oil,
visbreaker,
or
coker
gas
oil.
Three
different
process
arrangements
are
available:
single­
stage,
single­
stage
with
recycle,
and
two­
stage
hydrocracking.
Organic
heteroatom
removal
is
a
major
part
of
single
and
two­
stage
hydrocracking.
Therefore,
in
two­
stage
processing,
this
process
uses
a
hydrorefining
catalyst
followed
by
a
zeolite­
type
hydrocracking
catalyst
(Hydrocarbon
Processing,
November
2000).
Table
5­
2
demonstrates
the
sulfur
and
nitrogen
reduction
of
a
50/
50
Arabian
light/
heavy
blend
using
IFP
fixed­
bed
hydrocracking
technology
(Hydrocarbon
Processing,
November
1998).
The
data
show
that
sulfur
and
nitrogen
in
the
two
products
removed
from
the
IFP
hydrocracking
unit
are
much
lower
than
the
feed
levels.
However,
the
data
are
incomplete
because
sulfur
and
nitrogen
levels
in
the
heaviest
fraction
(where
the
highest
levels
are
expected)
were
not
presented
in
the
source
literature.
25
Table
5­
2.
Sulfur
and
Nitrogen
Reduction
from
IFP
Hydrocracking
Process
Parameter
Feed
HVGO
(50/
50
Arabian
light/
heavy)
Product
Jet
Fuel
Diesel
Sulfur,
ppm
31,700
<10
<20
Nitrogen,
ppm
853
<5
<5
Metals
1
C
C
Source:
Hydrocarbon
Processing,
November
1998.
1.
The
nickel
and
vanadium
content
of
Arabian
Light
crude
oil
are
2.5
ppm
and
16
ppm,
respectively
(Environment
Canada
2000).
The
HVGO
feedstock
is
expected
to
have
higher
levels
of
metals
because
it
is
derived
from
a
blend
of
light
and
heavy
crude
(where
the
heavy
crude
is
expected
to
have
higher
metals
concentrations),
and
the
VGO
fraction
is
expected
to
concentrate
these
metals
somewhat.

5.2
MAKFining
The
Kellogg
MAKFining
process
is
capable
of
converting
feedstocks
such
as
vacuum
gas
oil,
coker
gas
oils,
and
FCC
cycle
oils
into
high­
quality,
low­
sulfur
fuels.
This
process
can
be
operated
as
a
single­
pass
or
extinction
(i.
e.,
complete
recycle
of
fractionator
bottoms)
process.
Multi­
bed
reactors
using
multiple
catalysts
are
used
in
this
process
(Hydrocarbon
Processing,
November
2000).

Table
5­
3
shows
the
sulfur
and
nitrogen
levels
in
the
feed
that
can
be
processed
using
MAKfining
technology.
This
table
was
developed
from
operations
where
VGO
derived
from
a
50/
50
blend
of
Arabian
light
and
heavy
was
processed
in
the
MAKFining
unit.
The
sulfur
content
of
the
diesel
product
is
reduced.
26
Table
5­
3.
Sulfur
and
Nitrogen
Reduction
Through
MAKFining
Technology
Parameter
Feed
Product
Naphtha
Kerosene
Diesel
Gas
Oil
Sulfur,
ppm
29,000
C
C<
50
C
Nitrogen,
ppm
900
C
C
CC
Yield,
%
C
12.9­
22.6
14.1­
24.5
31.8­
32.5
30­
50
Operation
mode
Single
pass
Temperature,
°C
370­
430
Pressure,
atm
70­
140
Source:
Hydrocarbon
Processing,
November
1998.
Range:
bound
from
low
conversion
(50%)
to
high
conversion
(70%).
Higher
conversion
gives
higher
yields
of
lighter
products.

One
refinery
in
Austria
converted
its
existing
VGO
HDS
reactor
into
a
two
reactor
system
(using
MAKFining
Technology).
The
two
reactors
are
in
series,
with
no
intermediate
separation
or
fractionation,
and
would
be
considered
a
`single
stage'
system
according
to
the
above
terminology
by
George
(1994).
The
unit
is
not
designed
to
achieve
complete
conversion;
only
33
percent
conversion
is
achieved
with
the
heavier
product
being
fed
to
the
FCC.
The
following
catalysts
were
identified
for
use
in
the
initial
start­
up
in
1997
(Danzinger,
1999):

$
For
the
first
reactor,
three
catalysts
were
used
together:
$
Akzo
Nobel
KF­
647.
An
HVGO
demetallization
catalyst
with
high
hydrodenitrogenation
(HDN),
hydrodesulfurization
(HDS),
and
hydrogenation
activity.
$
Akzo
Nobel
KF­
840.
A
high
activity
catalyst
for
HDN
$
Akzo
Nobel
KF­
901H.
A
Ni/
Co/
Mo
catalyst
with
high
HDS
and
HDN
activity.
$
For
the
second
reactor,
only
one
catalyst
was
used:
Akzo
Nobel
KC­
2602.
A
zeolytic
Co/
Mo
catalyst
combining
hydrocracking
activity
for
HGO
conversion
with
high
HDS
performance.

These
catalysts
suggest
that
the
first
reactor
is
used
to
achieve
nitrogen
and
sulfur
removal.
Sulfur
removal
also
appears
to
be
an
objective
of
the
second
reactor,
in
addition
to
hydrocracking.
Criterion
(1998)
also
verifies
that
some
two
stage
hydrocracking
designs
are
exposed
to
elevated
hydrogen
sulfide
levels
in
the
second
stage,
but
not
to
ammonia.
Overall
sulfur
reduction
(Danzinger,
1999)
is
from
0.63
wt
percent
to
0.0047
wt
percent
in
the
FCC
feed;
overall
nitrogen
reduction
is
from
1700
ppmw
to
454
ppmw
in
the
FCC
feed.
The
first
reactor
temperature
is
410°
C
and
the
inlet
pressure
is
71
atm.
No
data
are
available
to
identify
differences
in
feed
characteristics
between
the
two
reactors.
27
5.3
Shell
Hydrocracking
Process
The
Shell
hydrocracking
process
converts
heavy
VGO
and
other
cracked
and
extracted
feedstocks
to
products
such
as
low­
sulfur
diesel
and
jet
fuel,
high­
octane
light
gasoline,
and
reformer,
cat
cracker
or
lube
oil
feedstocks.
The
process
can
be
either
a
single­
stage
or
two­
stage
unit.
A
single
reactor
stacked
catalyst
bed
is
best
suited
for
capacities
up
to
10,000
tons
per
day
(about
65,000
barrels
per
day)
in
either
partial
or
full
conversion
modes.
In
this
process,
heavy
hydrocarbons
are
mixed
with
fresh
hydrogen
and
passed
through
multi­
bed
reactor(
s)
which
contain
proprietary
pre­
treat,
cracking,
and
post­
treat
catalysts
(Hydrocarbon
Processing,
November
2000).

EPA
visited
one
refinery
with
a
two­
stage
hydrocracking
process
using
Shell
technology
during
its
development
of
the
1995
proposed
rule.
This
refinery
(Equilon,
formerly
Shell,
in
Wood
River
Illinois)
uses
a
two
stage
process,
wherein
the
first
stage
catalyst
conducts
a
hydrotreating
function
(Ni/
Mo
catalyst)
and
the
second
stage
catalyst
conducts
a
hydrocracking
function
(Ni/
W
on
zeolite).
Operating
conditions
of
the
second
stage
are
315
to
343°
C,
and
approximately
125
atm
(U.
S.
EPA,
1995a).

5.4
Isocracking
Technology
Chevron's
Isocracking
Technology
is
another
example
of
a
licensed
hydrocracking
process.
Three
options
exist
for
the
design
of
an
Isocracking
unit:
single­
stage
once
through
(SSOT),
single­
stage
recycle
(SSREC),
and
two­
stage.
These
options
are
very
similar
to
those
discussed
above
for
stage
hydrocracking
processes
in
general.

The
most
common
Isocracking
unit
configuration
is
the
two­
stage
unit
consisting
of
two
reactor
stages
and
a
product
distillation
section.
Generally,
the
first
stage
catalyst
performs
denitrification
and
desulfurization
of
the
hydrogenated
gas
oil
feed
with
minimal
hydrocracking.
Before
the
feed
is
sent
to
the
second
reactor
stage,
it
is
passed
through
a
product
fractionator
which
removes
the
conversion
products
of
the
first
stage
to
avoid
recracking
in
the
second
stage.
Hydrocracking
of
the
feed
occurs
in
the
second
stage
reactor.
The
relatively
low
operating
temperatures
of
this
stage
result
in
good
selectivity
and
product
quality.
Complete
conversion
of
the
feed
is
accomplished
by
recycling
all
unconverted
material
back
to
the
second
stage
reactor
(Dahlberg,
1995).

An
SSOT
Isocracking
unit
is
similar
to
the
first
stage
of
the
two­
stage
process.
In
such
a
unit,
the
feedstock
is
not
completely
converted
into
lighter
products.
The
typical
product
of
this
type
of
unit
is
a
highly
refined
heavy
oil
(McKetta,
1992).

An
SSREC
Isocracking
unit
completely
converts
heavy
oils
to
lighter
products
as
in
the
second
stage
of
the
two­
stage
unit
design
(i.
e.,
where
the
heaviest
fraction
is
recycled
to
the
reactor)
(McKetta,
1992).

Different
catalysts
are
used
in
these
units
depending
upon
the
feed
available,
products
required,
and
the
number
of
process
stages
in
the
design
of
the
unit.
Table
5­
4
lists
typical
hydrocracking
catalysts
used
in
Isocracking
process
units
(McKetta,
1992).
28
Table
5­
4.
Typical
Isocracking
Catalysts
Catalyst
Number
Use
in
Isocracking
Units
Single
Stage
Design
Two
Stage
Design
ICR
106
and
ICR
120
High
ratio
of
mid­
distillate
to
naphtha
First
stage
denitrification
and
cracking
Second
stage
hydrocracking
for
mid­
distillate
emphasis
ICR
113
Used
for
hydrocracking
heavy
oils
like
DAO
First
stage
denitrification
ICR
117
High
ratio
of
naphtha
to
mid
distillate
First
stage
denitrification
and
cracking
Second
stage
hydrocracking
for
naphtha
and
mid­
distillate
ICR
201
Hydrocracking
naphtha
or
raffinate
to
LPG
Second
stage
hydrocracking
for
LPG
from
naphtha
or
raffinate
ICR
202
C
Second
stage
hydrocracking
for
naphtha
or
jet
fuel
ICR
204
C
Second
stage
hydrocracking
for
naphtha,
aromatics,
and
jet
fuel
Source:
Chevron
Research
Co.
From
McKetta,
1992
(pg.
603).

As
can
be
seen
from
this
table,
the
same
catalyst
can
perform
different
or
multiple
functions
within
an
Isocracking
unit,
depending
upon
the
process
stage
in
which
it
is
used.
For
example,
Chevron's
catalyst
ICR
113
is
used
for
hydrocracking
heavy
oils
if
used
in
a
singlestage
Isocracking
unit.
In
such
a
unit
the
catalyst
performs
both
the
hydrotreating
and
hydrocracking
functions.
But
its
primary
function,
when
used
in
the
first
stage
of
a
two­
stage
Isocracking
unit,
is
denitrification
(a
hydrotreating
function).
Therefore,
the
classification
of
a
catalyst
within
an
Isocracking
unit
as
either
hydrotreating
or
hydrocracking
is
dependent
upon
the
function
of
the
catalyst
within
a
given
process
stage.

An
example
of
Chevron's
mild
Isocracking
catalyst
system
being
used
to
upgrade
an
exiting
process
is
at
the
Nippon
Petroleum
Refining
Co.
's
(NPRC)
Muroran,
Japan
facility.
The
facility's
hydroprocessing
system
originally
was
designed
for
desulfurization
of
Arabian
VGO.
In
the
early
1980's,
Muroran
shifted
to
severe
desulfurization,
using
the
existing
hydrodesulfurization
catalyst.
Chevron's
mild
Isocracking
catalyst
system
was
installed
in
1982,
and
the
Muroran
unit
continues
to
operate
in
this
mode
(as
of
1992).
Table
5­
5
provides
a
comparison
of
product
yields
and
properties
for
three
modes
of
operation
for
the
Isocracking
system
yielding
Isomate
distillates.
The
light
Isomate
distillate
product
meets
Japanese
diesel
specifications
for
sulfur,
cetane
index,
pour
point,
and
distillation
and
the
heavy
Isomate
bottoms
product
is
used
as
a
fuel
oil
blend
stock
or
FCC
feed.
The
nitrogen
reduction
achieved
in
the
29
Isocracking
system
leads
to
improved
FCC
catalyst
activity,
conversion,
and
yields
(McKetta,
1992).

Table
5­
5.
Feed
and
Product
Data
for
Isocracking
Parameter
Conventional
Desulfurization
Severe
Desulfurization
Mild
Isocracking
%
HDS
90.0
99.8
99.6
Sulfur,
wt%
of
feed
2.67
2.67
2.57
Nitrogen,
ppm
of
feed
720
720
617
Gravity,
°API
of
feed
22.6
22.6
23.0
Light
Isomate
Product
Sulfur,
wt%
0.07
0.002
0.005
Nitrogen,
ppm
18
20
20
Gravity,
°API
30.9
37.8
34.0
Heavy
Isomate
Product
Gravity,
°API
27.1
29.2
30.7
Sulfur,
wt%
0.26
0.009
0.013
Nitrogen,
ppm
400
60
47
Source:
McKetta
(1992).

5.5
Population
Data
regarding
the
population
of
single­
stage
or
two­
stage
hydrocracking
(including
isocracking)
processes
are
identified
from
Hydrocarbon
Processing
(November
1998
and
November
2000).
Worldwide,
there
are
over
forty
such
units
currently
operating
(including
revamps
of
pre­
existing
processes).
Data
specific
to
the
U.
S.
are
available
for
Chevron­
designed
hydrocracking
(Isocracking)
units
only.
Table
5­
6
lists
Chevron­
designed
hydrocrackers
in
operation
in
the
U.
S.
as
of
1991
(McKetta,
1992).
The
Ferroalloys
Association
provided
the
names
of
facilities
that
perform
all
types
of
single
and
multi­
stage
hydrocracking
processes.
The
non­
Isocracking
facilities
are
listed
in
table
5­
7.
30
Table
5­
6.
Chevron­
Designed
Hydrocracking
Plants
Company
(as
of
1991)
Location
Major
Products
Start­
up
Year
Capacity
(BPSD)

Sohio
Ohio
N
1962
12,000
Chevron
Mississippi
N
1963
28,000
Tosco
California
N
1963
22,000
Chevron
California
N/
K/
F
1966
30,000
Chevron
California
N/
K
1966
50,000
Sohio
Ohio
N/
F
1966
25,000
Mobil
California
N
1967
16,000
Tenneco
Louisiana
N
1968
16,000
Mobil
Texas
N
1969
29,000
Chevron
California
N/
K
1969
50,000
Sohio
Ohio
N/
L
1970
20,000
Chevron
Mississippi
N/
K
1971
32,000
BP
Oil
Pennsylvania
N
1975
20,000
Hawaiian
Independent
Hawaii
K
1981
12,000
Chevron
California
L
1984
18,500
Chevron
California
L
1984
12,000
Total
Isocracking
Capacity
392,500
Total
2000
Hydrocracking
Capacity*
1,575,800
Source:
Chevron
Research
Company
in
McKetta,
1992.
D=
diesel,
F=
FCC
feed,
G=
LPG,
K=
kerojet,
L=
lubes,
N=
naptha
*For
comparison.
From
U.
S.
DOE
(2000).
Note:
In
comments
from
The
Ferroalloys
Association
(September
4,
2001),
the
commenter
provided
the
names
of
eight
facilities
that
perform
Isocracking.
It
appears
that
the
facilities
identified
in
this
table
overlap
with
the
Association's
list.
31
Table
5­
7.
Other
Single
and
Multi­
Stage
Hydrocracking
Processes*

Company
Location
Process
Type
Arco
Carson,
CA
UOP
Unicracking
Arco
Cherry
Point,
WA
UOP
Unicracking
Excel
Paralubes
Lake
Charles,
LA
UOP
Unicracking
Equilon
Wilmington,
CA
UOP
Unicracking
Equilon
Wood
River
Shell
Exxon
Baton
Rouge,
LA
UOP
Unicracking
Exxon
Baytown,
TX
UOP
Unicracking
Exxon
Billings,
MT
UOP
Unicracking
Tesoro
Kapolei,
HI
UOP
Unicracking
Tosco
Rodeo,
CA
UOP
Unicracking
Tosco
Wilmington,
CA
UOP
Unicracking
*Information
in
this
table
was
derived
from
comments
from
The
Ferroalloys
Association
(September
4,
2001)

5.6
Conclusions
Based
on
the
above
information,
the
following
conclusions
are
reached
regarding
staged
hydrocracking
processes:

$
Single
stage
hydrocracking
processes
offer
no
H2
S
or
NH3
removal
between
reactors,
while
two
stage
processing
employs
interstage
gas
and
light
products
removal.
All
reactors
are
fixed
bed.

$
First
stage
units
conduct
hydrotreating
functions
such
as
nitrogen
and
sulfur
removal.
Second
stage
units
also
may
conduct
sulfur
removal,
but
little
to
no
nitrogen
removal.
Second
stage
units
are
designed
for
cracking.

$
Due
to
the
fact
that
single­
stage
units
offer
no
H2
S
or
NH3
removal
between
reactors,
the
subsequent
cracking
reactors
must
use
a
catalyst
specifically
designed
to
operate
in
the
presence
of
high
contaminant
levels
such
as
high
activity
or
nitrogen/
NH3
resistant
zeolite
catalysts.

$
Complete,
or
near
complete,
conversion
of
the
feed
can
be
achieved
through
the
addition
of
a
recycle
stream
which
passes
the
uncracked
material
repeatedly
over
the
cracking
catalyst
to
the
point
of
extinction.
32
$
High
sulfur
and
nitrogen
removal
rates
are
identified.
Although
sources
indicate
most
nitrogen
is
removed
in
the
first
stage
of
a
multi
stage
process,
data
are
unavailable
to
confirm
this.
Sources
also
indicate
that
sulfur
reduction
occurs
in
both
stages,
although
again
stage
specific
removal
rates
were
not
found
in
the
literature.

6.
Lube
Oil
Processes
There
are
five
basic
steps
to
manufacturing
lube
oil
base
stocks
from
crude
oil:
distillation,
deasphalting,
refining,
dewaxing,
and
finishing.
The
first
two
steps
prepare
the
feedstocks,
while
hydroprocessing
may
take
place
in
any
of
the
following
three
steps.
Collectively,
these
five
steps
serve
the
purpose
of
improving
the
viscosity
index,
quality,
temperature
properties,
color,
and
stability
of
the
lube
base
stock.
Refining
is
achieved
through
the
use
of
solvents
or
hydrogen.
Dewaxing
processes
use
either
solvents
or
catalysts.
Clay
or
hydrogen
is
used
for
product
finishing.
The
most
common
lube
oil
manufacturing
process
route
is
that
which
consists
of
solvent
refining,
solvent
dewaxing,
and
hydrogen
finishing
(McKetta,
1992).
Licensed
lube
oil
processes
include:

$
Shell
Hybrid.
Licensed
by
Shell
Global
Solutions
International
B.
V.
$
Yukong
UCO
Lube
Process.
Licensed
by
Washington
Group
International,
Petroleum
and
Chemicals
Technology
Center,
under
exclusive
arrangement
with
SK
Corporation.
$
Mobil
Selective
Dewaxing
(MSDW)
Process.
Licensed
by
Mobil.

These
are
discussed
in
the
following
sections,
but
should
not
be
assumed
to
be
a
comprehensive
listing
of
all
technologies.

6.1
Hybrid
The
Shell
Hybrid
base
oil
process
is
a
combination
of
solvent
extraction
and
one­
stage
hydroprocessing.
It
can
be
installed
as
a
revamp
to
an
existing
solvent
extraction
lube
oil
plants
in
order
to
increase
capacity
(by
up
to
60
percent).
Process
feeds
can
be
derived
from
a
wider
range
of
crudes
than
those
feeds
used
with
solvent
extraction
alone.
Yields
and
capacity
are
less
sensitive
to
feedstock
when
solvent
extraction
is
used
in
conjunction
with
hydroprocessing
(Hydrocarbon
Processing,
November
2000).

The
Hybrid
base
oil
process
consists
of
two
separate
upgrading
units,
a
solvent
extractor
and
a
one­
stage
hydroprocessor.
The
types
of
solvent
extraction
and
hydroprocessing
depend
upon
the
feedstock
and
manufacturing
objectives.
Hydrotreating
within
the
process
yields
higher
quantities
of
low­
sulfur,
low­
pour­
point
gas
oil
byproducts
which
reduces
the
quantity
of
lowvalue
byproducts
produced
(Hydrocarbon
Processing,
November
2000).

6.2
Yukong
UCO
Lube
Process
The
purpose
of
the
Yukong
UCO
Lube
Process
is
to
produce
higher
quality
lube
base
stocks
from
unconverted
oil
(UCO).
UCO
from
a
fuels
hydrocacker
is
used
as
feed
to
the
33
Yukong
UCO
Lube
process
due
to
its
characteristically
low
sulfur,
oxygen,
and
metals
content.
This
feed
requirement
is
due
to
the
deactivation
effect
these
impurities
have
on
the
lube
process
catalyst.
The
pilot
plant
used
in
conjunction
with
the
development
of
the
Yukong
UCO
Lube
Process
consists
of
three
sections:
feed
preparation,
reaction,
and
product
separation.
The
feed
preparation
section
is
a
vacuum
distillation
column.
The
reaction
section
consists
of
two
independently
controlled
and
operated
units.
The
first
reactor
is
for
the
purpose
of
hydrodewaxing
(HDW)
and
the
second
is
for
hydrotreating
(HDT).
Both
reactors
have
operating
conditions
of
0
to
205
atm
or
higher.
The
product
separation
section
consists
of
two
columns.
The
first
column
removes
light
material
by
fractionation
for
the
purpose
of
feeding
the
bottom
to
a
vacuum
distillation
column.
The
bottom
stream
of
the
second
column
is
the
final
lube
base
oil
product
(Andre',
1996).

6.3
Mobil
Selective
Dewaxing
Process
Catalytic
dewaxing
is
a
shape
selective
kinetic
process
which
selectively
cracks
and/
or
isomerizes
wax
molecules.
The
Mobil
Selective
Dewaxing
Process
(MSDW)
provides
improved
lube
yields
and
viscosity
index
and
requires
either
severely
hydrotreated
or
hydrocracked
feeds.
The
process
is
based
on
a
catalyst
that
combines
isomerization
and
selective
cracking
resulting
in
dewaxed
oil
yield
and
the
viscosity
index
being
equivalent
or
higher
than
for
solvent
dewaxing.
Noble
metals
can
be
incorporated
into
the
catalyst
due
to
the
use
of
"clean"
(i.
e.,
low
in
sulfur,
nitrogen,
and
coke
precursors)
feedstocks.
Increased
catalyst
activity
and
cycle
length
are
realized
with
the
addition
of
the
metal
component
due
to
its
reduction
affect
on
the
rate
of
coke
formation.
Operating
pressures
vary
between
27
to
205
atm.
Higher
operating
pressures
result
in
increased
cycle
length
and
higher
yield
and
viscosity
index.
The
MSDW
process
can
handle
light
and
heavy
neutral
hydrorefined
feedstocks
(Baker,
1995).

6.4
Conclusions
Based
on
the
information
presented
in
this
section,
the
following
conclusions
can
be
made
in
regard
to
lube
oil
hydroprocessing:

$
Lube
oil
hydroprocessing
units
require
a
"clean"
feed.
Such
feeds
have
low
sulfur,
nitrogen,
and
metals
concentrations.
Typically
these
feeds
are
the
products
of
fuel
hydrocracking
units.

$
Lube
oil
hydroprocessing
catalysts
can
incorporate
noble
metals
witch
enhance
the
quality
of
the
product
but
are
also
sensitive
to
feed
impurities.

$
The
above
mentioned
licensed
process
units
use
hydroprocessing
to
increase
the
quality
of
the
lube
stock
produced.
Other
licensed
process
units
not
identified
from
the
literature
may
have
similar
characteristics.
Not
all
lube
oil
processes
use
hydroprocessing.

$
Using
hydroprocessing
in
conjunction
with
traditional
solvent
extraction
methods
of
dewaxing
allows
for
processing
of
a
wider
range
of
feedstocks
than
would
be
possible
with
solvent
extraction
alone.
34
7.
Recycling
Spent
Catalysts
EPA
wants
to
encourage
recycling
and
reclamation
of
hazardous
wastes,
as
well
as
to
conserve
resources
that
would
alternatively
be
used
if
hazardous
waste
recycling
did
not
occur.
This
section
provides
a
summary
of
information
currently
available
to
EPA
regarding
the
quantities
of
spent
catalyst
managed
by
different
management
practices,
and
the
costs
of
these
management
practices,
both
prior
to
and
following
the
promulgation
of
the
K171
and
K172
listings.
Moreover,
this
section
assesses
trends
in
activities,
or
factors
affecting
management
alternatives.
For
spent
catalysts,
the
principal
waste
management
options
are
recycling
practices
and
disposal
practices.
Section
7.1
presents
EPA's
waste
management
data
concerning
the
quantities
of
K171
and
K172
wastes
being
landfilled
or
recycled.
Section
7.2
provides
EPA's
current
cost
data
for
various
waste
management
practices
or
steps,
including
recycling.
Section
7.3
discusses
the
recycling
trends
shown
in
the
data.

7.1
Quantity
Data
EPA
initially
collected
waste
management
data
for
spent
hydrotreating
and
hydrorefining
catalysts
in
its
1992
RCRA
§3007
survey
(EPA,
1995).
These
data
were
presented
in
EPA's
background
document
for
the
1998
final
rule,
and
represent
management
practices
prior
to
implementation
of
the
listings.

The
K171
and
K172
listings
became
effective
in
February
1999
(i.
e.,
six
months
after
the
publication
date
of
August
6,
1998).
Therefore,
most
refineries
generating
spent
hydrotreating
and
hydrorefining
catalysts
in
1999
were
required
to
manage
them
as
hazardous
wastes,
consistent
with
the
Subtitle
C
program
and
land
disposal
restrictions.
Such
data
subsequently
were
recorded
in
the
1999
Biennial
Reporting
System
(BRS).
The
BRS
provides
a
good
way
to
assess
the
generation
and
management
of
K171
and
K172,
and
to
see
how
the
quantities
generated
and
the
management
methods
compare
to
data
collected
by
EPA
in
1992,
prior
to
the
listing.

Table
7­
1
compares
the
quantities
of
spent
hydrotreating
and
hydrorefining
catalysts
generated
by
refineries
in
1992
and
1999.
Observations
include
the
following:

°
There
was
a
25
percent
increase
in
the
total
quantity
of
K171/
K172
(combined)
generated
from
1992
to
1999.

°
The
quantities
of
K171
and
K172
generated
in
1999
have
almost
a
reverse
profile
from
that
generated
1992.
In
1992,
the
quantity
of
K172
was
much
larger
than
K171,
while
in
1999
the
opposite
was
true.

°
A
few
refineries
(20
percent
of
the
quantity)
identify
the
waste
as
either
ignitable
(D001)
or
reactive
(D003)
in
addition
to
the
listed
hazardous
waste
codes
(see
table
footnote).
35
Table
7­
1.
K171/
K172
Waste
Generation
Data
in
1992/
1999
Waste
Type
Number
of
Refineries
Generating
Waste
Quantity
Generated
(short
tons)

1999
1992
1999
1
1992
Total
106
2
—
34,445
26,701
K171
95
92
20,841
6,204
K172
13
38
7,067
20,497
Both
K171
and
K172
3
7
0
6,537
0
Data
are
limited
to
wastes
generated
by
petroleum
refineries.
Additional
waste
quantities
`generated'
by
facilities
outside
the
refining
industry
(e.
g.,
waste
treatment
and
disposal)
are
not
included
in
this
table.
1
Eighteen
refineries
reported
generating
a
total
of
6,787
tons
(20
percent
of
the
total)
of
hazardous
waste
coded
as
D001/
D003
in
1999,
in
addition
to
the
codes
reported
in
the
table.
This
data
is
not
included
in
the
table
because
it
would
`double
count'
the
quantities
already
presented.
2
Not
equal
to
sum
of
the
numbers
below,
because
some
refineries
generate
more
than
one
type
of
waste.
3
Refers
to
waste
identified
as
`K171
and
K172,
'
as
one
waste
shipment.
1999
data
source:
BRS,
GM
Form.
1992
data
source:
1995
EPA
Listing
Background
Document
(U.
S.
EPA,
1995b).

Table
7­
2
identifies
the
management
practices
used
in
1992
and
1999
for
spent
hydrotreating
and
spent
hydrorefining
catalysts.
The
data
are
illustrated
graphically
in
Figure
7­
1.
The
total
quantities
given
in
Table
7­
2
for
1999
are
slightly
different
than
those
in
Table
7­
1,
because
slightly
different
source
data
were
used
within
BRS
for
1999.
The
quantities
in
Table
7­
2
include
only
those
wastes
received
directly
from
refineries.
Quantities
such
as
those
generated
by
waste
treatment
facilities
and
further
managed
by
waste
disposal
facilities
are
not
included
in
these
tables.
Table
7­
2
illustrates
the
following:

°
Most
spent
catalyst
hazardous
waste
is
listed
as
K171
rather
than
as
K172.
This
is
consistent
with
Table
7­
1.

°
The
vast
majority
of
listed
waste
received
by
incineration
and
reclamation/
regeneration
facilities
is
K171.
Conversely
the
majority
of
listed
waste
received
by
stabilization/
landfill
facilities
is
K172.

°
Incineration,
a
negligible
management
technique
in
1992,
accounted
for
a
small
but
significant
quantity
of
waste
management
in
1999.

°
Both
the
total
quantity,
and
the
percentage
of
total
volume
of
spent
catalyst,
landfilled
between
1992
and
1999
increased.

°
Recycling/
reclamation
was
still
a
significant
management
technique
in
1999,
although
the
percentage
of
spent
catalyst
managed
in
this
manner
decreased
from
82%
in
1992
to
55%
in
1999.
36
Table
7­
2.
Waste
Management
Data
for
Spent
Catalyst
(1992/
1999)

Waste
Code
Quantity
Managed
(short
tons)

Reclamation/
Regeneration
Stabilization/
Landfill
Other
Total
1992
1999
1992
1999
1992
1999
1992
1999
K171
4,701
15,634
1,165
1,692
339
1,686
6,205
19,012
K172
16,926
879
3,571
8,291
0
57
20,497
9,227
Both
K171
and
K172
­­
573
­­
1,343
­­
724
­­
2,640
Total
21,850
17,086
4,805
11,326
47
2,467
26,702
30,879
Data
are
limited
to
wastes
received
from
petroleum
refineries.
Additional
waste
quantities
"received"
from
facilities
outside
the
refining
industry
(e.
g.,
waste
treatment
and
disposal)
are
not
included
in
this
table.

Ten
facilities
reported
receiving
a
total
of
5,912
tons
(19
percent
of
the
total)
of
hazardous
waste
coded
as
D001/
D003
in
1999,
in
addition
to
the
codes
reported
in
the
table.
This
data
is
not
included
in
the
table
because
it
would
"double
count"
the
quantities
already
presented.

1999
data
source:
BRS,
WR
Form.

1992
data
source:
1995
EPA
Listing
Background
Document
(U.
S.
EPA,
1995b)..
37
Incineration
(8.00%)

Stabilization/
Landfill
(37.00%)
Reclamation/
Regeneration
(55.00%)

1999
Other
(0.20%)

Stabilization/
Landfill
(17.80%)
Reclamation/
Regeneration
(82.00%)

1992
Figure
7­
1.
Waste
Management
Destinations
for
Spent
Catalyst
(1992
vs.
1999)
4
Cost
and
Economic
Impact
Analysis
of
Listing
Hazardous
Wastes
from
the
Petroleum
Refining
Industry.
September
21,
1995.

38
7.2
Cost
Data
For
the
petroleum
listing
final
rule,
EPA
performed
an
Economic
Analysis
of
the
costs
of
managing
catalyst
wastes.
4
Table
7­
3
identifies
the
costs
of
reclamation
versus
treatment
and
disposal
prior
to
and
following
the
listing.
There
were
many
management
options
envisioned
in
the
Economic
Analysis,
but
Subtitle
C
disposal
and
recycling
represent
some
of
the
most
common
alternatives.
See
Section
8.3
for
further
discussion.

Table
7­
3.
Unit
Costs
for
Common
Management
Methods
Management
Practice
EPA
Data
1
API
Estimates
2
Reclamation/
regeneration
Pre­
listing:
$725/
MT
Post­
listing:
Assumed
5
percent
increase
in
price
due
to
Subtitle
C
storage,
transportation,
and
management
costs.
Pre­
listing:
$250/
ton
Post­
listing:
$500­
800/
ton
LDR
treatment
and
Subtitle
C
disposal
Pre­
listing:
Off­
Site
Subtitle
C
disposal:
$233/
MT
(no
LDR
treatment
occurred)

Post­
listing:
LDR
Treatment:
$240/
MT
Off­
Site
Subtitle
C
Disposal:
$233/
MT
Pre­
listing:
$130/
ton
Post­
listing:
$200/
ton
1.
The
EPA
figures
are
provided
in
1992
dollars.
Source:
Cost
and
Economic
Impact
Analysis
of
Listing
Hazardous
Wastes
from
the
Petroleum
Refining
Industry.
September
21,
1995.
2.
API
Estimates
were
provided
in
public
comments
to
the
July
5,
2001
Federal
Register
Notice,
dated
September
4,
2001.
The
estimates
are
drawn
from
API's
primary
comments
as
well
as
comments
to
the
1998
final
rule.
The
estimates
assume
a
volume
of
900
tons
of
spent
catalyst.

7.3
Recycling
Trends
Analysis
EPA
data
and
API
data
and
information
indicate
that
recycling
is
significantly
lower
than
the
recycling
rate
prior
to
the
listing
decision.
As
shown
in
section
7.1,
the
data
collected
by
the
agency
can
be
used
to
compare
recycling
rates
from
1992
to
1999
(the
year
in
which
the
listing
came
into
effect).
EPA's
data
indicates
that
recycling
rates
decreased
from
82
percent
to
55
percent.
API
also
indicated
in
its
comments
that
recycling
rates
are
down
throughout
the
industry,
although
the
comment
did
not
provide
specific
rates
or
data
to
support
the
information.

There
are
many
reasons
that
the
recycling
rate
may
have
dropped
so
dramatically.
The
drop
could
be
attributable
to
the
change
in
recycling
costs
after
the
listing
came
into
effect
(illustrated
in
section
7.2).
EPA
has
not
collected
data
on
recycling
costs
after
the
listings
went
5
U.
S.
Geological
Survey
data
for
vanadium.
Mineral
Commodity
Summaries.

39
into
effect.
In
the
economic
analysis
to
the
final
rule,
EPA
estimated
a
five
percent
increase
in
costs
due
to
the
increased
cost
of
transporting
and
storing
hazardous
wastes.
The
cost
of
storage
was
not
considered
a
significant
issue
because
most
recycling
facilities
had
acquired
a
Subtitle
C
permit
pre­
listing
for
the
storage
of
catalysts
that
exhibit
a
characteristic.
API's
estimates
for
the
cost
of
recycling
appear
to
be
inconsistent
with
the
economic
data
collected
by
the
Agency.
In
particular,
the
EPA
estimates
for
the
cost
of
recycling
prior
to
the
1998
final
rule
are
almost
three
times
the
estimates
provided
by
API.
Since
the
post­
listing
estimates
are
relatively
close
to
one
another,
the
increase
in
price
is
far
more
dramatic
from
the
perspective
of
the
API
estimates,
but
may
also
better
explain
the
reason
for
the
decrease
in
recycling
rates.

The
cost
increase
may
be
at
least
partially
explained
by
a
depressed
vanadium
market.
In
the
past,
the
value
of
recycled
vanadium
allowed
the
recycling
facilities
to
pass
back
the
benefits
to
refineries
by
reducing
costs.
However,
it
appears
that
there
is
substantial
variation
in
the
market
price
for
vanadium.
USGS
data
for
vanadium
identifies
that
annual
average
prices
between
1994
and
1997
were
roughly
$3
to
$4
per
pound.
Between
1999
and
2001,
annual
average
prices
were
only
$1
to
$2
per
pound.
5
8.
Discussion
8.1
Characteristics
of
Hydroprocessing
Units
General
characteristics
of
hydroprocessing
technologies,
including
hydrotreating
and
hydrocracking,
were
discussed
in
Section
2.
Hydrocracking
is
a
catalytic
petroleum
refining
process
that
converts
heavy,
high
boiling
feedstock
molecules
to
smaller,
lower
boiling
products
through
carbon­
carbon
bond
breaking
accompanied
by
simultaneous
or
sequential
hydrogenation
(Scherzer,
1996,
p.
1).
Hydrotreating
is
a
process
whose
primary
purpose
is
to
saturate
olefins
and/
or
reduce
sulfur
and/
or
nitrogen
content
(and
not
to
change
the
boiling
range)
by
reacting
the
feed
with
hydrogen
(Gary,
1994,
p.
187).
Hydrorefining,
while
present
in
EPA's
regulatory
definition
of
K172,
is
a
term
generally
not
used
in
literature
and
instead
is
encompassed
within
"hydrotreating."
In
virtually
all
cases
presented
in
this
report,
hydrocracking
is
accompanied
with
or
preceded
by
hydrotreating
reactions.
This
is
due
to
the
deactivating
effect
that
sulfur
and
nitrogen
compounds
have
on
hydrocracking
catalysts
(Scherzer,
1996,
p.
174).

The
feedstocks
used
in
the
hydrocracking
process
contain
sulfur,
nitrogen,
and,
in
the
case
of
resid
feedstocks,
metals
such
as
nickel
and
vanadium.
The
function
of
the
hydrocracking
catalyst
is
to
promote
hydrocracking
reactions
with
acid
sites
and
promote
hydrogenation
with
metal
sites
(McKetta,
1992,
p.
601).
The
composition
of
the
catalyst
is
dependent
upon
the
feed
material,
specific
process,
and
desired
product
of
the
process.
Most
hydrocracking
catalysts
are
a
crystalline
mixture
of
silica­
alumina
with
small
amounts
of
rare
earths
contained
within
the
crystal
lattice.
The
silica­
alumina
performs
the
cracking
while
the
rare
earths
promote
hydrogenation.
The
most
commonly
used
rare
earths
are
platinum,
palladium,
tungsten,
and
nickel
(Gary,
1994,
p.
156­
157).
Acidic
support
consists
of:
amorphous
oxides
(e.
g.,
silicaalumina
a
crystalline
zeolite
(mostly
modified
Y
zeolite)
plus
binder
(e.
g.,
alumina),
or
a
40
mixture
of
crystalline
zeolite
and
amorphous
oxides.
Cracking
and
isomerization
reactions
take
place
on
the
acidic
support.
Metals
can
be
noble
metals
(palladium,
platinum),
or
nonnoble
metal
sulfides
from
group
VIA
(molybdenum,
tungsten)
and
group
VIIA
(cobalt,
nickel)
(Scherzer,
1996,
p.
13­
15).

In
the
hydrotreating
process,
sulfur­
containing
hydrocarbons
are
converted
into
low­
sulfur
liquids
and
hydrogen
sulfide.
Nitrogen
and
oxygen
compounds
also
are
dissociated
by
hydrotreating.
This
process
is
operated
under
high
temperatures
and
pressures.
The
purpose
of
the
hydrotreating
catalyst
is
to
promote
hydrogenation
reactions
using
metal
sites
(McKetta,
1992,
pp.
81,
601).
Hydrogenation
is
the
addition
of
hydrogen
to
a
carbon­
carbon
double
bond
(Gary,
1994,
p.
150).
Typical
catalyst
compositions
include
cobalt
and
molybdenum
oxides
on
alumina,
nickel
oxide,
nickel
thiomolybdate,
tungsten
and
nickel
sulfides,
and
vanadium
oxide.
CoMo
catalysts
are
selective
for
sulfur
removal
and
NiMo
catalysts
are
selective
for
nitrogen
removal
(Gary,
1994,
p.
189).

8.2
Performance
Summary
of
Hydroprocessing
Units
Throughout
this
report
there
are
many
instances
where
reduction
in
sulfur,
nitrogen,
and
metals
content
are
demonstrated
between
feed
and
product.
This
type
of
reduction
is
an
integral
part
of
hydroprocessing,
not
only
because
of
the
demand
for
"cleaner"
fuels
but
also
because
of
the
harmful
effect
that
sulfur
and
nitrogen
heteroatoms
and
metals
such
as
vanadium
and
nickel
have
on
expensive
hydrocracking
catalysts.
Most
hydrocracking
processes
employ
both
hydrotreating
and
hydrocracking
steps
for
this
reason.
The
significant
sulfur,
nitrogen,
and
metals
content
reductions
are
characteristics
of
hydrotreating.

The
following
tables
reiterate
the
information
and
examples
previously
given
in
the
report
for
specific
hydroprocessing
units.
Here,
however,
the
specific
reductions
are
organized
according
to
property
(sulfur,
nitrogen,
metals).
Conclusions
from
these
tables
are
discussed
in
Section
8.3.
Table
8­
1
presents
data
on
sulfur,
Table
8­
2
presents
data
for
nitrogen,
and
Table
8­
3
presents
data
for
metals.
Data
are
presented
as
available
for
these
constituents
in
feed,
products,
and
overall
reductions.
While
Section
2
discussed
other
characteristics
of
hydrotreating
(e.
g.,
olefin
hydrogenation),
operating
data
were
typically
unavailable
to
quantitatively
demonstrate
such
processes
within
these
units.

Table
8­
4
presents
information
regarding
the
conversion
of
various
processes
discussed
in
this
report.
Conversion
is
the
reduction
of
the
amount
of
material
boiling
above
a
certain
temperature.
Cuts,
or
fractions
are
characterized
by
their
boiling
ranges
(i.
e.,
by
an
initial
boiling
point
and
endpoint).
The
initial
boiling
point
and
endpoint
of
a
fraction
increases
with
the
average
molecular
weight
of
the
fraction,
as
does
the
sulfur
content
(Scherzer,
1996,
p.
2).
Therefore,
a
conversion
of
80
percent
means
that
80
percent
of
the
feed
is
broken
down
into
fractions
with
lower,
generally
more
desirable,
molecular
weights
and
boiling
ranges,
relative
to
the
feed
or
a
heavy
product
fraction.
41
Table
8­
1.
Sulfur
Reduction
in
Named
Processes
Process
Name
Sulfur
Content
in
Typical
Feed
Sulfur
Reduction,
or
Content
in
Product
Reference
Ebullating
Bed
H­
Oil
C
55­
92
wt%
reduction
Colyar,
1997
H­
Oil
C
84­
91
wt%
Hydrocarbon
Processing,
1998
H­
Oil
6.0
wt%
88.0
­
90.1
%
reduction
Nongbri,
1992
H­
Oil
2.7
wt
%
0.06
­
1.55
wt
%
(depending
on
product)
Schrezer,
1996
H­
Oil
5.33
wt
%
0.02
­
1.04
wt
%
(depending
on
product)
Wisdom,
1997
H­
Oil
4.71
wt%
C
Wisdom,
1997
LC­
Fining
3.9
­
4.97
wt%
60­
90
wt%
reduction
Hydrocarbon
Processing,
1998
T­
Star
C
93­
99
wt%
reduction
Hydrocarbon
Processing,
2000
T­
Star
2.8
wt
%
91.7
wt%
reduction,
<
70­
1,000
ppmw
(depending
on
product)
Johns,
1993
T­
Star
1.93
wt
%
97
wt%
reduction
Nongbri,
1996
T­
Star
(mild
hydrocracking
mode)
2.10
98
wt%
reduction
Nongbri,
1996
Mild
Hydrocracking
Typical
27,000
ppmw
300
to
<
1,000
ppmw
(depending
on
product)
Marion,
1998
MHUG
10,000
ppmw
(VGO)
9
­
19
ppmw
(depending
on
product)
Chen,
1999
MHUG
10,400
(LCO)
16
ppmw
(diesel)
Chen,
1999
Table
8­
1.
Sulfur
Reduction
in
Named
Processes
Process
Name
Sulfur
Content
in
Typical
Feed
Sulfur
Reduction,
or
Content
in
Product
Reference
42
Stage
Hydrocracking
IFP
Hydrocracking
Process
31,700
ppm
(HVGO)
<10
­
<20
ppm
(depending
on
product)
Hydrocarbon
Processing,
1998
MAKFining
29,000
ppm
(VGO)
<50
ppm
(diesel)
Hydrocarbon
Processing,
1998
Isocracking
25,700
ppm
50
to
130
ppm
(depending
on
product)
McKetta,
1992
Lube
Oil
No
data
Table
8­
2.
Nitrogen
Reduction
in
Named
Processes
Process
Name
Nitrogen
Content
in
Feed
Nitrogen
Reduction/
Content
in
Product
Reference
Ebullating
Bed
H­
Oil
C
25­
50
wt%
reduction
Colyar,
1997
H­
Oil
4,800
ppmw
57.3
­
65.7
%
reduction
Nongbri,
1992
T­
Star
1,328
ppmw
80
wt
%
reduction
3­
766
ppmw
(depending
on
product)
Johns,
1993
T­
Star
1,820
ppmw
78
wt
%
reduction
Nongbri,
1996
T­
Star
(mild
hydrocracking
mode)
819
ppmw
94
wt
%
reduction
Nongbri,
1996
Mild
Hydrocracking
Typical
800
ppmw
C
Marion,
1998
MHUG
2,400
ppmw
(VGO)
<0.5
­
6
ppmw
(depending
on
product)
Chen,
1999
MHUG
446
(LCO)
<0.5
­
1.4
ppmw
(depending
on
product)
Chen,
1999
Table
8­
2.
Nitrogen
Reduction
in
Named
Processes
Process
Name
Nitrogen
Content
in
Feed
Nitrogen
Reduction/
Content
in
Product
Reference
43
Stage
Hydrocracking
IFP
Hydrocracking
Process
853
ppm
(HVGO)
<5
ppm
Hydrocarbon
Processing,
1998
MAKFining
900
ppm
C
Hydrocarbon
Processing,
1998
Isocracking
617
ppm
20B47
ppm
(depending
on
product)
McKetta,
1992
Lube
Oil
No
data
Table
8­
3.
Metals
Reduction
in
Named
Processes
Process
Name
Metals
Content
in
Feed
Metals
Reduction
/
Content
in
Product
Reference
Ebullating
Bed
H­
Oil
C
65­
90
wt%
reduction
Colyar,
1997
H­
Oil
Nickel:
64
ppmw
Vanadium:
205
ppmw
Ni:
78.4
­
81.2
%
reduction
V:
88.4­
91.4
%
reduction
Nongbri,
1992
H­
Oil
Nickel
+
Vanadium
221
ppmw
C
Wisdom,
1997
H­
Oil
Nickel
+
Vanadium
707
ppmw
C
Wisdom,
1997
LC­
Fining
Nickel:
18­
39
ppmw
Vanadium:
65­
142
ppmw
50­
98
wt%
reduction
Hydrocarbon
Processing,
1998
T­
Star
Nickel:
1.6
ppmw
Vanadium:
4.4
ppmw
C
Nongbri,
1996
T­
Star
Nickel:
<5
ppmw
Vanadium:
<5
ppmw
C
Nongbri,
1996
Table
8­
3.
Metals
Reduction
in
Named
Processes
Process
Name
Metals
Content
in
Feed
Metals
Reduction
/
Content
in
Product
Reference
44
Mild
Hydrocracking
Typical
Nickel:
2.5
ppm
Vanadium:
16
ppm
C
Environment
Technology
Center,
1996

2000
Stage
Hydrocracking
No
data
Lube
Oil
No
data
Table
8­
4.
Feed
Conversions
in
Named
Processes
Process
Name
Type
of
Feed
Percent
Conversion
Reference
Ebullating
Bed
H­
Oil
Typical
Vacuum
Residue
45
­
90
vol%
Colyar,
1997
H­
Oil
Arabian
Medium
Vacuum
Resid
65
­
90
Hydrocarbon
Processing,
1998
H­
Oil
Arabian
Heavy
Resid
65
­
85
Nongbri,
1992
H­
Oil
Russian
Vacuum
Resid
68
vol%
Colyar,
1997
H­
Oil
Arabian
Crude
70
­
90
vol%
Scherzer,
1996
H­
Oil
Arabian
Light/
Heavy
Vacuum
Residue
65
­
85
vol%
Wisdom,
1997
H­
Oil
Isthmus
/
Maya
Blend
65
­
85
vol%
Wisdom,
1997
LC­
Fining
C
40­
97
vol%
Hydrocarbon
Processing,
1998
T­
Star
C
20­
60
vol%
Hydrocarbon
Processing,
2000
T­
Star
C
9
vol%
Johns,
1993
Table
8­
4.
Feed
Conversions
in
Named
Processes
Process
Name
Type
of
Feed
Percent
Conversion
Reference
45
T­
Star
Vacuum
Gas
Oil
30
Nongbri,
1996
T­
Star
Vacuum
Gas
Oil
55
Nongbri,
1996
Mild
Hydrocracking
Typical
Arabian
Light
30
wt%
Marion,
1998
MHUG
FCC
Feedstock
Vacuum
Gas
Oil
35
Chen,
1999
Stage
Hydrocracking
Typical
Single
or
Two­
Stage
Typical
Feed
(e.
g.,
VGO)
70
­
100
wt%
Scherzer,
1996
MAKFining
50/
50
Arabian
Light/
Heavy
Blend
50
­
70
Hydrocarbon
Processing,
November
1998
Lube
Oil
No
data
8.3
Conclusions
This
section
serves
as
a
summary
of
the
information
presented
in
this
report
to
identify
key
characteristics
of
hydrotreating
and
hydrocracking
processes.
It
will
show
the
property
conversion/
reduction
ranges
and
types
of
catalysts
used
and
their
purposes
for
the
four
types
of
hydroprocessing
processes
detailed
in
this
report:
ebullated
bed,
mild
hydrocracking,
single
and
multi­
stage
hydrocracking,
and
lube
oil
hydroprocessing
processes.

8.3.1
Ebullated
Bed
The
three
licensed
ebullating
bed
processes
discussed
in
Section
3
are
H­
Oil,
LC­
Fining,
and
T­
Star.
These
processes
are
capable
of
processing
very
heavy
feeds
such
as
VGO
or
vacuum
residue
that
have
not
been
pretreated
prior
to
being
fed
to
the
ebullating
bed
reactor.
Feed
conversion
for
such
processes
range
from
30
to
90
percent
depending
on
process
conditions.
Feedstock
sulfur
content
reduction
as
high
as
98
percent
can
be
achieved
in
ebullating
bed
(dual
purpose)
reactors
depending
upon
the
desired
conversion
level
of
the
process.
Significant
nitrogen
feed
content
reduction
of
up
to
94
wt
percent
is
possible
with
a
more
typical
reduction
being
about
80
wt
percent.
Feedstock
metals
reduction
also
is
achieved
in
ebullating
bed
processes.
Nickel
feed
content
reduction
is
on
the
order
of
80
percent
and
vanadium
feed
content
reduction
is
about
90
percent.
These
processes
use
catalysts
with
metals
removal,
hydrotreating,
and
cracking
activities
(Gary,
1994,
p.
178).
The
information
collected
regarding
catalyst
purpose
and
activity
from
Section
2
shows
that
significant
sulfur
and
nitrogen
reductions
46
are
characteristic
of
hydrotreating
activity
while
significant
feedstock
conversion
levels
are
indicative
of
hydrocracking
activity.
Based
on
information
presented
in
Section
2
regarding
characteristics
of
hydrotreating
and
hydrocracking,
the
conclusion
can
be
drawn
that
both
hydrotreating
and
hydrocracking
occur
in
ebullated
bed
hydroprocessing
units.
EPA
has
identified
two
U.
S.
refineries
with
ebullated
bed
processes.

8.3.2
Mild
Hydrocracking
The
mild
hydrocracking
process
is
used
to
process
heavy
feeds
such
as
vacuum
gas
oil.
As
in
the
ebullated
bed
processes,
feeds
are
not
pretreated
prior
to
being
fed
to
the
mild
hydrocracking
unit.
Examples
of
"typical"
mild
hydrocracking
processes
and
the
licensed
MHUG
process
were
investigated.
Mild
hydrocracking
operates
on
a
once­
through
basis
using
a
single
fixed
bed
reactor.
Feed
conversions
for
the
mild
hydrocracking
process
are
on
the
order
of
30
percent.
High
rates
of
sulfur
and
nitrogen
reduction
are
seen
for
the
examples
presented
in
Table
8­
1
and
8­
2,
respectively.
No
data
regarding
metals
reduction
percentages
or
product
metal
content
was
identified.
Therefore,
EPA
can
not
determine
if
demetallization
takes
place,
if
the
process
works
best
with
low
feed
metal
feedstocks
only,
or
if
metals
in
the
feed
pass
through
to
the
products.
Catalysts
used
in
the
mild
hydrocracking
process
perform
both
the
hydrotreating
functions
of
desulfurization/
denitrification
and
the
hydrocracking
function
of
feed
conversion.
These
catalysts
are
mildly
acidic.
They
usually
consist
of
cobalt
or
nickel
oxide
combined
with
molybdenum
or
tungsten
oxide
supported
on
amorphous
silica­
alumina
or
mildly
acidic
zeolite
(Scherzer,
1996).
The
high
rates
of
heteroatom
removal
realized
with
the
mild
hydrocracking
process
is
characteristic
of
hydrotreating
while
the
significant
(30
percent)
feed
conversion
is
characteristic
of
hydrocracking.
Given
these
product
conversions/
reductions
and
the
type
of
catalyst(
s)
used
in
these
types
of
processes,
the
conclusion
can
be
drawn
that
both
hydrotreating
and
hydrocracking
occur
in
the
mild
hydrocracking
process.
An
estimate
of
the
number
of
refineries
operating
mild
hydrocracking
processes
is
unavailable.

8.3.3.
Single­
and
Multi­
Stage
Hydrocracking
Processes
Single
and
multi­
stage
hydrocracking
processes
employ
one
or
more
reactors
in
series.
The
licensed
processes
discussed
in
this
report
include
IFP
Technology,
MAKFining,
and
the
Shell
hydrocracking
process.
Feedstock
conversion
using
this
type
of
process
is
in
the
range
of
50
B
100
percent
depending
on
process
conditions
and
design.
Specific
process
examples
demonstrated
very
high
sulfur
and
nitrogen
feed
content
reductions.
No
metals
reduction
percentages
or
product
content
were
identified,
most
likely
because
metals
removal
is
not
a
primary
function
of
hydrocracking
reactors.
The
types
of
catalysts
used
in
this
process
are
dependent
upon
the
number
of
reactors
used.
If
a
single
reactor
is
used,
multiple
catalysts
for
hydrodesulfurization,
hydrodenitrification,
and
conversion
reactions
can
be
used
in
a
stacked
bed
arrangement.
If
multiple
reactors
are
used,
the
first
reactor
in
the
series
typically
performs
a
hydrotreatment
function
and
removes
sulfur,
nitrogen,
and
other
heteroatoms.
The
following
reactors
in
the
series
convert
the
feed
to
lighter
products.
The
use
of
different
catalysts
or
multipurpose
catalysts
for
the
purpose
of
sulfur/
nitrogen
removal
and
feed
conversion
is
indicative
of
both
hydrotreating
and
hydrocracking
activity.
Depending
on
the
configuration
of
the
reactors,
the
hydrotreating
and
hydrocracking
reactions
may
occur
within
the
same
reactor,
or
47
may
be
located
in
different
reactors.
Even
in
a
two­
stage
process,
some
degree
of
sulfur
reduction
(a
characteristic
of
hydrotreating)
may
occur
in
the
second,
hydrocracking
stage.

8.3.4
Lube
Oil
Processes
Lube
oil
hydroprocesses
require
feeds
that
have
low
sulfur,
nitrogen,
and
metals
concentrations.
Typically
these
feeds
have
been
severely
hydrotreated
or
hydrocracked
prior
to
being
fed
to
the
lube
oil
processing
unit.
No
information
on
conversion
or
sulfur/
nitrogen/
metals
removal
percentages
was
identified
for
specific
lube
oil
process
examples.
48
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1998
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San
Francisco,
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March
15­
17,
1998.

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William
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Alain
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Henrik
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8
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96­
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the
1996
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Annual
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San
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March
17B19,
1996.

Scherzer,
Julius
and
Gruia,
A.
J.
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York.
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50
The
Ferroalloys
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66
Fed.
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35379
(July
5,
2001),
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4,
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1992B1996
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Shell
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S.
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1996
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31,
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All
of
the
above
references
are
included
in
the
RCRA
public
docket,
with
the
following
exceptions.
The
following
citations
were
not
included
because
three
are
text
books
and
the
other
three
are
available
in
electronic
format
from
other
sources.

Environment
Technology
Center.
2000.
Properties
of
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and
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Canada.
http://
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etcentre.
org/
cgiwin
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prop_
cgi.
exe?
Path=\
Website\
river\

Gary,
James
H.
and
Handwerk,
Glenn
E.
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Marcel
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Inc.,
New
York.
1994.
(Textbook)

McKetta,
John.
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Marcel
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Inc.,
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(Textbook)
51
Scherzer,
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A.
J.
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U.
S.
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1999."
Vol.
1.
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EIA­
0340(
99)/
1.
June
2000.

This
report
is
available
on
the
Internet
at:
http://
www.
eia.
doe.
gov/
oil_
gas/
petroleum/
data_
publications/
petroleum_
supply_
annual/
p
sa_
volume1/
psa_
volume1.
html
U.
S.
Geological
Survey
data
for
vanadium.
Mineral
Commodity
Summaries.
January
2002.
This
data
is
available
on
the
Internet
at:
http://
minerals.
usgs.
gov/
minerals/
pubs/
commodity/
vanadium/
index.
html#
mcs
