U.S. patent application number 14/564057 was filed with the patent office on 2016-06-09 for integrated vacuum distillate recovery process.
The applicant listed for this patent is Gary R. Martin. Invention is credited to Gary R. Martin.
Application Number | 20160160130 14/564057 |
Document ID | / |
Family ID | 56093740 |
Filed Date | 2016-06-09 |
United States Patent
Application |
20160160130 |
Kind Code |
A1 |
Martin; Gary R. |
June 9, 2016 |
Integrated Vacuum Distillate Recovery Process
Abstract
A system for recovering diesel products from a feed stream
comprises an atmospheric crude unit, a vacuum crude unit, and a
vacuum distillate recovery unit. The atmospheric crude unit
comprises a crude feed inlet line, a diesel product outlet line, an
atmospheric gas oil product outlet line, and a residual product
outlet line. The vacuum crude unit comprises a residual product
inlet line in fluid communication with the residual product outlet
line from the atmospheric crude unit, a light vacuum gas oil
product outlet line, and an overhead vapor outlet line. The vacuum
distillate recovery unit comprises a gas oil inlet line, an
overhead product line, and a second diesel product outlet line. The
gas oil inlet line is in fluid communication with the atmospheric
gas oil product outlet line from the atmospheric crude unit and the
light vacuum gas oil product outlet line from the vacuum crude
unit.
Inventors: |
Martin; Gary R.; (Grapevine,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Martin; Gary R. |
Grapevine |
TX |
US |
|
|
Family ID: |
56093740 |
Appl. No.: |
14/564057 |
Filed: |
December 8, 2014 |
Current U.S.
Class: |
208/354 ;
196/100 |
Current CPC
Class: |
C10L 1/08 20130101; C10G
7/06 20130101; C10L 2290/543 20130101; C10L 2270/026 20130101; C10L
2200/0446 20130101 |
International
Class: |
C10G 7/06 20060101
C10G007/06; C10G 53/02 20060101 C10G053/02; C10L 1/08 20060101
C10L001/08 |
Claims
1. A system for recovering diesel products from a feed stream, the
system comprising: an atmospheric crude unit, wherein the
atmospheric crude unit comprises a crude feed inlet line, a diesel
product outlet line, an atmospheric gas oil product outlet line,
and a residual product outlet line; a vacuum crude unit, wherein
the vacuum crude unit comprises a residual product inlet line, a
light vacuum gas oil product outlet line, and an overhead vapor
outlet line, wherein the residual product inlet line is in fluid
communication with the residual product outlet line; and a vacuum
distillate recovery unit, wherein the vacuum distillate recovery
unit comprises a gas oil inlet line, an overhead product line, and
a second diesel product outlet line, wherein the gas oil inlet line
is in fluid communication with the atmospheric gas oil product
outlet line from the atmospheric crude unit and the light vacuum
gas oil product outlet line from the vacuum crude unit.
2. The system of claim 1, further comprising: a vacuum system,
wherein the vacuum system is in fluid communication with the
overhead vapor outlet line from the vacuum crude unit and the
overhead product line from the vacuum distillate recovery unit.
3. The system of claim 1, further comprising: a vacuum system,
wherein the vacuum system is in fluid communication with the
overhead vapor outlet line from the vacuum crude unit, and wherein
the overhead product line from the vacuum distillate recovery unit
is in fluid communication with the vacuum crude unit.
4. The system of claim 1, further comprising: a first vacuum system
in fluid communication with the overhead vapor outlet line from the
vacuum crude unit, and a second vacuum system in fluid
communication with the overhead product line from the vacuum
distillate recovery unit.
5. The system of claim 1, wherein the vacuum distillate recovery
unit comprises a distillation column comprising the gas oil inlet
line, the overhead product line, and the second diesel product
outlet line, wherein the distillation column comprises a side draw
line in fluid communication with the second diesel product outlet
line and a cooling circuit, wherein the cooling circuit comprises a
heat exchanger configured to cool at least a portion of a fluid
stream drawn from the distillation column through the side draw
line and return the cooled portion of the fluid stream to the
distillation column.
6. The system of claim 1, wherein the vacuum distillate recovery
unit comprises a distillation column comprising the gas oil inlet
line, the overhead product line, and the second diesel product
outlet line, wherein the distillation column further comprises a
reboiler configured to vaporize a portion of a liquid in the lower
portion of the distillation column and return a vapor to the
distillation column.
7. The system of claim 6, wherein the distillation column further
comprises a light gas oil outlet line.
8. The system of claim 7, wherein the light gas oil outlet line is
located above the gas oil inlet line and below the second diesel
product outlet line.
9. A method of recovering diesel from a crude oil feed stream, the
method comprising: separating a crude oil feed stream into a
plurality of streams in an atmospheric crude unit, wherein the
plurality of streams comprise a first diesel product stream, an
atmospheric gas oil stream, and a residual product stream;
receiving the atmospheric gas oil stream and a light vacuum gas oil
stream at a distillation column; and separating the atmospheric gas
oil stream and the light vacuum gas oil stream into a plurality of
product streams in the distillation column, wherein the plurality
of product streams comprise an overhead vapor stream, a second
diesel product stream, and a medium gas oil stream.
10. The method of claim 9, further comprising: separating the
residual product stream in a vacuum crude unit into a plurality of
product streams, wherein the plurality of product streams comprise
the light vacuum gas oil stream.
11. The method of claim 10, wherein the vacuum crude unit is in
fluid communication with a vacuum system while separating the
residual product stream.
12. The method of claim 11, wherein the distillation column is in
fluid communication with the vacuum system while separating the
atmospheric gas oil stream and the light vacuum gas oil stream.
13. The method of claim 11, wherein the distillation column is in
fluid communication with a second vacuum system while separating
the atmospheric gas oil stream and the light vacuum gas oil stream,
wherein the vacuum system and the second vacuum system are separate
vacuum systems.
14. The method of claim 9, further comprising combining the
atmospheric gas oil stream and the light vacuum gas oil stream
before separating the atmospheric gas oil stream and the light
vacuum gas oil stream into the plurality of product streams.
15. The method of claim 9, wherein separating the atmospheric gas
oil stream and the light vacuum gas oil stream comprises:
introducing the atmospheric gas oil stream and the light vacuum gas
oil stream into the distillation column; removing a fluid stream
from the distillation column during the separation; passing a first
portion of the fluid stream back to the distillation column;
passing a second portion of the fluid stream to a heat exchanger;
cooling the second portion of the fluid stream in the heat
exchanger to create a cooled fluid; passing the cooled fluid back
to the distillation column; and removing a third portion of the
fluid stream as the second diesel product stream.
16. The method of claim 15, wherein separating the atmospheric gas
oil stream and the light vacuum gas oil stream further comprises:
removing a second fluid stream from the distillation column during
the separation, wherein the second fluid stream is removed from
below the fluid stream and above a location at which the
atmospheric gas oil stream and the light vacuum gas oil stream are
introduced into the distillation column, wherein the second fluid
stream comprises a light gas oil product stream.
17. The method of claim 16, wherein separating the atmospheric gas
oil stream and the light vacuum gas oil stream further comprises:
reboiling a portion of a liquid stream in a lower portion of the
distillation column during the separating.
18. A method of recovering diesel, the method comprising;
separating a crude oil feed stream into a plurality of product
streams in an atmospheric crude unit, wherein the plurality of
product streams comprises a first diesel product stream, an
atmospheric gas oil stream, and a residual product stream;
separating the residual product stream into a plurality of second
product streams in a vacuum crude unit, wherein the plurality of
second product streams comprises a light vacuum gas oil and an
overhead stream; receiving the atmospheric gas oil stream and the
light vacuum gas oil stream at a distillation column; and
separating the atmospheric gas oil stream and the light vacuum gas
oil stream into a plurality of third product streams in the
distillation column, wherein the plurality of third product streams
comprises a second diesel product stream.
19. The method of claim 18, wherein the plurality of third product
streams comprises a second overhead stream, and wherein the
overhead stream from the vacuum crude unit and the second overhead
stream from the distillation column are in fluid communication with
a vacuum system.
20. The method of claim 18, wherein the plurality of third product
streams comprises a second overhead stream, and wherein the second
overhead stream is in fluid communication with the vacuum crude
unit, and wherein the overhead stream from the vacuum crude unit is
in fluid communication with a vacuum system.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] Not Applicable.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not applicable.
REFERENCE TO A MICROFICHE APPENDIX
[0003] Not applicable.
BACKGROUND
[0004] Diesel engines are widely used in a number of applications.
Environmental concerns have led to many nations setting strict
regulations that set minimum cetane number, sulfur content,
aromatics content, as well as other diesel fuel specifications.
These along with a shift in gasoline and diesel consumption require
reassessing refinery configurations. The demand for diesel has been
increasing worldwide. Countries outside of the U.S. are heavily
reliant on diesel fuel. Strong international demand for diesel in
rapidly developing countries like China and India has placed a
premium on diesel imports. While the U.S. is a gasoline dominant
motor fuels market, the demand for gasoline peaked in 2007 and has
been decreasing since. Demand for diesel has been increasing.
Comparing October 2010 demand to that of October 2012, demand for
on-road diesel fuel increased 11.8% while gasoline demand decreased
by 3.4%. The U.S. Energy Information Administration's Annual Energy
Outlook 2014 publication provides the projections of Motor gasoline
and diesel fuel consumption through the year 2040. Figure MT-57 of
this publication shows these fuels trending in opposite directions
with motor gasoline consumption falling by 2.1 MMbpd from 2012 to
2040, while diesel fuel consumption increases by 0.9 MMbpd. The
bulk of the predicted changes in consumption occur prior to 2030.
Too meet the growing demand for diesel it is expected that new
refinery projects will involve shifting production from gasoline to
diesel fuels.
SUMMARY
[0005] In an embodiment, a system for recovering diesel products
from a feed stream comprises an atmospheric crude unit, a vacuum
crude unit, and a vacuum distillate recovery unit. The atmospheric
crude unit comprises a crude feed inlet line, a diesel product
outlet line, an atmospheric gas oil product outlet line, and a
residual product outlet line. The vacuum crude unit comprises a
residual product inlet line, a light vacuum gas oil product outlet
line, and an overhead vapor outlet line. The residual product inlet
line is in fluid communication with the residual product outlet
line. The vacuum distillate recovery unit comprises a gas oil inlet
line, an overhead product line, and a second diesel product outlet
line. The gas oil inlet line is in fluid communication with the
atmospheric gas oil product outlet line from the atmospheric crude
unit and the light vacuum gas oil product outlet line from the
vacuum crude unit.
[0006] In an embodiment, a method of recovering diesel from a crude
oil feed stream comprises separating a crude oil feed stream into a
plurality of streams in an atmospheric crude unit, receiving the
atmospheric gas oil stream and a light vacuum gas oil stream at a
distillation column, and separating the atmospheric gas oil stream
and the light vacuum gas oil stream into a plurality of product
streams in the distillation column. The plurality of streams
comprise a first diesel product stream, an atmospheric gas oil
stream, and a residual product stream. The plurality of product
streams comprise an overhead vapor stream, a second diesel product
stream, and a medium gas oil stream.
[0007] In an embodiment, a method of recovering diesel comprises
separating a crude oil feed stream into a plurality of product
streams in an atmospheric crude unit, separating the residual
product stream into a plurality of second product streams in a
vacuum crude unit, receiving the atmospheric gas oil stream and the
light vacuum gas oil stream at a distillation column, and
separating the atmospheric gas oil stream and the light vacuum gas
oil stream into a plurality of third product streams in the
distillation column. The plurality of product streams comprises a
first diesel product stream, an atmospheric gas oil stream, and a
residual product stream. The plurality of second product streams
comprises a light vacuum gas oil and an overhead stream, and the
plurality of third product streams comprises a second diesel
product stream.
[0008] These and other features will be more clearly understood
from the following detailed description taken in conjunction with
the accompanying drawings and claims.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] For a more complete understanding of the present disclosure
and the advantages thereof, reference is now made to the following
brief description, taken in connection with the accompanying
drawings and detailed description:
[0010] FIG. 1 illustrates a simplified process flow diagram of an
embodiment of an atmospheric crude unit and a vacuum crude unit. In
this configuration diesel is only produced from the atmospheric
crude column.
[0011] FIG. 2 illustrates another simplified process flow diagram
of an embodiment of an atmospheric crude unit and a vacuum crude
unit, where the vacuum column is configured for diesel
recovery.
[0012] FIG. 3 illustrates still another simplified process flow
diagram of an embodiment of an atmospheric crude unit and a vacuum
crude unit with the addition of a vacuum preflash column configured
for diesel recovery.
[0013] FIG. 4 illustrates a simplified block flow diagram of an
embodiment of a vacuum distillate recovery process integrated with
an atmospheric crude unit and a vacuum crude unit.
[0014] FIG. 5 illustrates a simplified process flow diagram of an
embodiment of the vacuum distillate recovery process integrated
with a vacuum crude unit.
[0015] FIG. 6 illustrates another simplified process flow diagram
of an embodiment of the vacuum distillate recovery process
integrated with a vacuum crude unit.
[0016] FIG. 7 illustrates still another simplified process flow
diagram of an embodiment of the vacuum distillate recovery process
integrated with a vacuum crude unit.
DETAILED DESCRIPTION OF THE EMBODIMENTS
[0017] In the drawings and description that follow, like parts are
typically marked throughout the specification and drawings with the
same reference numerals, respectively. The drawing figures are not
necessarily to scale. Certain features may be shown exaggerated in
scale or in somewhat schematic form and some details of
conventional elements may not be shown in the interest of clarity
and conciseness. Specific embodiments are described in detail and
are shown in the drawings, with the understanding that the present
disclosure is to be considered an exemplification of the principles
of the invention, and is not intended to limit the invention to
that illustrated and described herein. It is to be fully recognized
that the different teachings of the embodiments discussed infra may
be employed separately or in any suitable combination to produce
desired results.
[0018] Unless otherwise specified, any use of any form of the terms
"connect," "engage," "couple," "attach," or any other term
describing an interaction between elements is not meant to limit
the interaction to direct interaction between the elements and may
also include indirect interaction between the elements described.
In the following discussion and in the claims, the terms
"including" and "comprising" are used in an open-ended fashion, and
thus should be interpreted to mean "including, but not limited to .
. . ". The various characteristics mentioned above, as well as
other features and characteristics described in more detail below,
will be readily apparent to those skilled in the art with the aid
of this disclosure upon reading the following detailed description
of the embodiments, and by referring to the accompanying
drawings.
[0019] The term "True Boiling Point" (TBP) refers to the test
method for determining the boiling point of hydrocarbons which
corresponds to ASTM D2892 for the production of a liquefied gas,
distillate fractions, and residuum of standardized quality on which
analytical data can be obtained, and the determination of yields of
the above fractions by both mass and volume from which a graph of
temperature versus mass % distilled is produced using fifteen
theoretical plates in a column with a 5:1 reflux ratio.
[0020] The term "diesel" or "diesel fuel" refers to hydrocarbons
having boiling points in the range of from about 270.degree. F. to
about 750.degree. F. using the True Boiling Point method.
[0021] The term "virgin diesel" refers to diesel or diesel fuel
removed from the crude feed, where the diesel is not the product of
a chemical transformation of another hydrocarbon component.
[0022] The terms "gas oils", Atmospheric Gas Oil ("AGO"), Light
Vacuum Gas Oil ("LVGO"), Heavy Vacuum Gas Oil ("HVGO"), Light Gas
Oil ("LGO"), and Medium Gas Oil ("MGO") refer to hydrocarbon
streams having boiling points that can range anywhere from about
270.degree. F. to about 1150.degree. F. using the True Boiling
Point method. However, the gas oil hydrocarbons, with diesel
components removed, have boiling points in the range of about
750.degree. F. to about 1150.degree. F. using the True Boiling
Point method.
[0023] The term "column" means a distillation column for separating
one or more components of different volatilities.
[0024] The systems and methods described herein enable refineries
with vacuum crude units an economical means to improve the
production of virgin diesel. In the present system, a single
distillate recovery column can be integrated with the low pressure
operation of a vacuum crude unit, eliminating the need for an
additional overhead vacuum system. A pump-around heat removal
section provides for condensing of the diesel product and the
diesel/gas oil fractionating zone hydrocarbon reflux stream. The
high reflux to distillate ratio of the fractionating bed below the
vacuum column diesel draw provides for good separation between the
diesel and gas oil hydrocarbons enabling good diesel yields. The
feed stock fed to the separation unit is comprised of refinery
streams with hydrocarbon components that boil in the diesel through
gas oil range (i.e. AGO, LVGO, etc.). The prior removal of lighter
and heavier boiling range components from these feedstock streams
provide significant benefits to the ability to fractionate diesel
out of the feedstock. Charging of the feeds to the vacuum
distillate recovery column at a relatively high temperature from
the other units combined with low pressure operation normally
eliminates the need for feed preheat or a reboiler system. Feed
preheat and/or reboiler systems with a stripping section below the
feed is optional to provide for flexibility of feed enthalpy and
improve diesel recovery.
[0025] The present system and methods enable refineries with
atmospheric and vacuum crude units to increase diesel recovery from
crude by integrating these process units with the vacuum distillate
recovery unit described herein. The novel processing schemes
described herein are advantageous in that they do not negatively
affect the reliability and operability of the atmospheric and
vacuum crude units, they provide a method to convert vacuum units
to one that can achieve maximum recovery of virgin diesel, they are
simple in design, and they are economical.
[0026] A design of the atmospheric crude unit 2 and a vacuum crude
unit 6 are shown in the system 150 of FIG. 1. The atmospheric crude
unit and the vacuum crude unit are generally designed to separate a
crude oil feed stream into a number of product streams. The
separation process generally begins by desalting the crude oil to
remove salts which can be harmful to downstream equipment. The
salts are generally removed from the crude oil stream by mixing the
crude oil with water and heating the mixture to a temperature
between about 200.degree. F. and about 300.degree. F. Various types
of heaters, heat exchangers, and/or heat integration schemes (e.g.,
heat exchangers using hot process streams) can be used to raise the
crude oil to this temperature range. The salt may then be absorbed
into the aqueous phase. The mixture can then be passed to a
desalter, where the water containing the salts is separated from
the crude oil. The crude oil having the majority, if not all, of
the salt removed can then be further heated to a temperature
between about 650.degree. F. and about 750.degree. F. using a
heater (e.g., a furnace), heat exchanger, and/or heat integration
schemes.
[0027] The heated crude can then pass to the atmospheric crude
column 101 in the atmospheric crude unit 2 to produce a plurality
of outlet product streams. The atmospheric crude unit 2 generally
comprises a distillation column where the crude can partially
vaporize and separate within the column. The vapor can pass upwards
through the column and contact a liquid descending within the
column to separate the various components within the crude oil feed
into different boiling range fractions. The higher molecular weight
or higher boiling components may pass to the lower portion of the
column where a portion of the liquid may be vaporized. Steam may be
used to provide the heat to vaporize a portion of the crude within
the column. At various stages along the length of the column,
liquid can be extracted from trays and sent to side draws or side
strippers to produce an outlet product stream. Various additional
devices or units can also be used with the atmospheric crude unit 2
such as pump-arounds, heat exchangers, and the like. The overhead
stream can be at least partially compressed and/or condensed and a
portion of the liquid returned to the column as reflux. The
resulting overhead product from the atmospheric crude unit 2
comprises light ends/naphtha. Separate side stream draws can result
in a product stream comprising several fractions such as a kerosene
fraction, a diesel fraction, and an atmospheric gas oil
fraction.
[0028] The bottoms product from the atmospheric crude unit 2
includes the residual heavy components, generally referred to as
residue. The residue may be further separated in the vacuum crude
unit 6. The residue can be sent directly to the vacuum crude unit 6
and/or cooled and stored in a storage unit such as one or more
storage tanks. In some embodiments, additional streams from other
atmospheric crude units can be transferred to the vacuum crude unit
6, directly and/or from a storage location. The stream passing to
the vacuum crude unit can be reheated as needed prior to being sent
to the vacuum crude unit 6.
[0029] In order to separate the residue, the bottoms stream from
the atmospheric crude unit 2 can be heated in a furnace 52 and
passed to the column 56. The upper limit of the temperature of the
residue in the furnace 52 is set by the temperature at which
excessive cracking of the oil occurs. In general, the residue
stream is heated to a temperature below the excessive cracking
temperature to avoid fouling and high tube metal temperatures. The
column 56 is in fluid communication with a vacuum system through an
overhead line 62, which sets the pressure at the top of the column
56. The pressure changes in each section along the column 56
determine the pressure at the bottom of the column 56. In general,
a vacuum crude unit 6 does not use side strippers, but a plurality
of streams can be taken off the column along its length.
[0030] The heated residue is passed to the vacuum crude column 56
in the vacuum crude unit 6 where a portion of the residue
vaporizes. As the vapors rise, one or more condensation sections
can be used to condense various fractions that can be withdrawn
from the column. At least a portion of the withdrawn liquid can be
cooled and returned to the column as liquid. The resulting
separation of the residue within the vacuum crude column 56 can
result in a number of outlet streams. The overhead stream can
include the lighter components in the residue, coil steam,
stripping steam, light hydrocarbons generated from cracking of the
oil in the heater, and/or air from leakage. An upper side stream
comprising the light vacuum gas oils and a lower side stream
comprising the heavy vacuum gas oils can be taken out of the column
56. The bottoms stream includes the vacuum tower bottoms, which are
generally heavier components that can be sent to a coker or
visbreaker unit to produce higher value products. The vacuum crude
unit 6 may have other product streams such as Medium Vacuum Gas Oil
(MVGO), a slop wax product, and/or one or more additional streams.
In some embodiments, one or more of the streams passing out of the
vacuum crude column 56 illustrated in FIG. 1 may not be
present.
[0031] Since the U.S. has had a gasoline dominate motor fuels
market, most U.S. refineries are built to maximize gasoline
production with diesel being a secondary product. As shown in the
system 150 illustrated in FIG. 1, the design of the atmospheric
crude unit and vacuum crude unit are of a design such that the only
diesel product is from the atmospheric crude unit 2. The
Atmospheric Gas Oil (AGO) and the Light Vacuum Gas Oil (LVGO)
streams from these units normally retain a significant quantity of
diesel boiling range components. In some cases, the combined diesel
boiling range components in these streams can include approximately
6,000 to 8,000 barrels per day (bpd) on a 150,000 bpd (i.e., 150
Mbpd) crude unit. Based on the reasoning that these refineries were
originally designed to maximize gasoline production, this
configuration was logical at that time. The gas oil streams can be
further processed in a Fluid Catalytic Cracking Unit (FCCU) to
convert the majority of these streams to gasoline range components.
It should be further noted that the diesel range hydrocarbons
produced from the downstream FCCU and coker unit is of a poor
quality. In particular, the cetane value of these streams is
insufficient for diesel sales. These units also increase the
aromatic content and produce olefins, which has become more of an
environmental concern and normally requires further processing to
reduce or eliminate these components. This processing unit
configuration is inefficient in meeting the current refining
industry needs of shifting yields from gasoline to high quality
diesel.
[0032] FIG. 2 illustrates another crude separation unit design such
as those in many European refineries as well as refineries in other
overseas countries. This crude separation unit configuration is
built according to process flow schemes developed to improve the
diesel production. The typical design of the Atmospheric and Vacuum
Crude Units in these refineries are of such a design that diesel is
produced from the atmospheric crude unit 2 as well as the vacuum
crude unit 6. The high reflux to distillate ratio of the
fractionating bed below the vacuum crude column 56 diesel draw
provides for good separation between the diesel and gas oil
hydrocarbons enabling good diesel yields.
[0033] Some vacuum units in the U.S. have incorporated similar
vacuum crude unit designs to those found overseas. However, the
vacuum crude unit designs of the U.S., which were not designed to
produce diesel, normally are mechanically limited from conversion
to enable diesel production. It is also not economical to replace a
vacuum column with a design similar to those in Europe. The
extended down time and expensive capital costs cannot be justified
by the increase in diesel yield alone.
[0034] There are two other design practices that can be used to
increase virgin diesel production. The first is addition of a
vacuum preflash column, and the second incorporates modifications
associated with the atmospheric crude column to enable increased
diesel production. While virgin diesel yields can be increased by
both of these design practices there are underlying issues which
make both poor design choices for most refineries, several of which
are discussed below.
[0035] FIG. 3 illustrates a crude separation system having a vacuum
preflash column 93. The use of the vacuum preflash column 93 can be
used to increase the virgin diesel recovery from the system.
However, increasing the cut point prior to the vacuum crude column
56 (e.g., removing lighter boiling range components from the vacuum
column feed) has a negative effect on the process unit's
reliability and heavy vacuum gas oil (HVGO) cut point. Vacuum crude
unit 6 feed stocks have a thermal limit before excessive oil
cracking occurs, leading to the formation of coke and components
that lead to fouling and/or plugging of the process equipment. Oil
cracking is a function of oil temperature and residence time.
Increasing the HVGO cut point in the vacuum crude unit is
determined by the column flash zone temperature and pressure.
Pressure is set by the column vacuum system (e.g., the overhead
ejector system pressure) and the column pressure drop. The
temperature is set by the heater firing, which is limited by
thermal stability of the vacuum crude unit feed. For a given flash
zone temperature and pressure, a heavier feed changes the flash
zone vapor and liquid equilibrium such that less oil is vaporized.
Thus, adding a vacuum preflash column 93 yields a heavier feed to
the vacuum column 56 resulting in lowering the maximum obtainable
HVGO cut point. At the lower cut point, the yield of lower value
VTB product is increased at the expense of the higher value HVGO
product. In addition, the heavier feed to the vacuum column feed
heater 52 decreases the vaporization of the feed in the heater 52,
which increases the heater oil residence time. Heater reliability
as well as downstream equipment reliability is reduced due to the
formation of coke and consequential equipment fouling. Vacuum
heater 52 fouling is a primary cause of short vacuum crude unit 6
run times. Refinery operating experience has shown that coking in
the bottom of a vacuum preflash column 93 can also be a problem.
The column itself increases the oil residence time and at the high
operating temperatures can lead to oil instability and coke
formation. Oil cracking can produce light ends, which increases the
load on the vacuum column ejector system. This increases the column
pressure and further reduces the HVGO cut point. In addition, as a
result of the high temperature and large volume of feed, a vacuum
preflash column 93 and its associated peripheral equipment is
expensive compared to the system described herein. Very few crude
separation systems have been modified to this design configuration
due to these problematic issues.
[0036] Modifications to existing atmospheric crude columns and
their peripheral equipment can be made to increase virgin diesel
yield. Some of the modifications include increasing the atmospheric
column feed enthalpy by increasing feed heater firing and/or feed
preheat train modifications, increasing the atmospheric tower
bottoms (ATB) stripping steam rate, increasing the AGO stripper
steam rate, and/or increasing the theoretical fractionating stages
in the Diesel/AGO, Wash Zone, and stripping sections. The addition
of extra theoretical fractionating stages is often limited due to
limited amount of available space in an existing facility. These
changes typically require modifications to the upper atmospheric
crude column 101 internals up through the condensing zones to
accommodate the additional vapor and liquid loadings and additional
heat removal requirements as well as modifications to the
associated pumparound circuit/crude preheat train. Even with all of
these modifications, a significant amount of diesel range material
cannot normally be recovered. It should be noted that compared to
the system described herein, the fractionating zone for separation
of the diesel from the gas oils in the atmospheric crude column 101
has inherently lower liquid to vapor (LN) ratios due to the large
quantity of light ends, naptha, kerosene, and steam in the vapor
phase, making the recovery of diesel much easier in the present
system processing scheme. Also, increasing the ATB cut point, which
may result in a heavier vacuum column feed composition, can lead to
the same problems noted with the vacuum preflash column 93 above
including a reduction in the vacuum crude unit 6 reliability and a
decreased HVGO cut point (e.g., resulting in downgrading the gas
oils to the lower value VTB product). More importantly, these
changes increase the atmospheric crude column 101 vapor and liquid
loadings and consume atmospheric crude column capacity. This
processing capacity could alternatively be used to expand refinery
throughput. The atmospheric crude column 101 capacity is a high
capital cost limitation for expansion of a refineries capacity. As
a result of these shortcomings, this approach to increasing diesel
recovery is usually not recommended especially when considering the
long term objectives of the refinery.
[0037] Research has been conducted in the last 35 years to increase
total refinery diesel yield. The primary focus has been on the use
of hydrocracker conversion units. Additional information on
hydrocracker conversion units can be found in U.S. Pat. Nos.
8,840,854, 7,892,418, 6,676,828, 6,210,563, and 6,204,426, each of
which is incorporated herein by reference in its entirety. These
references provide information regarding conversion units used to
increase diesel production. These high pressure and temperature
units are beneficial in maximizing total refinery diesel yields.
However, they are expensive to build and operate. As a result, it
would be beneficial to remove all of the quality virgin diesel from
the crude oil feed and utilize the conversion units to convert low
value gas oils to higher value products.
[0038] FIG. 4 show simplified process flow diagrams of an
embodiment of a system 8 of using a vacuum distillate recovery unit
4. The atmospheric crude unit 2 and the vacuum crude unit 6 can
include units as described above, and the vacuum distillate
recovery unit 4 can be integrated with these units. Variations in
the atmospheric crude unit 2 and the vacuum crude unit 6 are
generally described in more detail herein. Further, additional
equipment associated with the various units such as pumps, control
valves, and other basic equipment as well as the distillation
column internals design necessary for the operation of the unit are
not shown in the drawings, but would be understood by one of
ordinary skill in the art with the aid of this disclosure.
[0039] The system 8 comprises an atmospheric crude unit section 2,
a vacuum crude unit section 6, and a vacuum distillate recovery
column section 4. The system 8 also includes a vacuum system 64 in
fluid communication with the vacuum crude unit 6 and the vacuum
distillate recovery unit 4. The vacuum system 64 is normally
considered a part of the vacuum crude unit 6 but is illustrated as
a separate unit in FIGS. 4-7 for clarity and purposes of
discussion. The operating pressure of the vacuum unit, and
therefore the vacuum crude unit 6 and the vacuum distillate
recovery unit 4, varies due to the design and operation of each
unit. In an embodiment, the vacuum system 64 may provide a low
pressure source having a pressure between about 2 mmHg to about 100
mmHg absolute. The vacuum system 64 can include any suitable type
of vacuum devices such as a multi-stage vacuum ejector system and
possibly a liquid ring pump, or the like. In an embodiment, a low
pressure vacuum crude unit 6 operating in wet mode can use a
three-stage ejector system and may also have a liquid ring pump on
the backend to further compress the non-condensable components. To
obtain very low operating pressures, the ejectors can consume a
significant amount of steam and the exchangers can use a
significant quantity of cooling water. Steam generation and cooling
water towers can be used to supply the utility streams. The cost of
the ejector system and the offsite utilities is generally high.
[0040] As described in more detail herein, the vacuum distillate
recovery unit 4 serves to separate a gas oil fraction into one or
more outlet fractions including a diesel fraction. As shown in FIG.
4, the vacuum distillate recovery unit 4 may be coupled to the
vacuum system 64 in order to operate at a low pressure. In an
embodiment, the vacuum distillate recovery unit 4 is in fluid
communication with the vacuum system 64 through an overhead line
20. The overhead line 20 is shown to split into lines 22 and 24,
one or both of which may be used in any particular implementation.
Line 22 is in direct fluid communication with the vacuum system 64,
and line 24 is in fluid communication with an upper portion of a
vacuum column in the vacuum crude unit 6. The use of line 22 and/or
line 24 allows for low pressure operation of the vacuum distillate
recovery process 4 by sharing the resources of the vacuum system
64. In an embodiment, overheard line 20 can be in fluid
communication with the vacuum crude unit 6 through line 24 instead
of line 22. A pressure control valve may be present in line 20 that
may be used to control the pressure within the vacuum distillate
recovery process.
[0041] In an embodiment, the feed to the vacuum distillate recovery
unit 4 includes the AGO fraction from the atmospheric crude unit 2
as well as a LVGO fraction from the vacuum crude unit. In some
embodiments, a pump may not be present between the vacuum crude
unit 6 and the vacuum distillate recovery unit 4 in line 12 or line
16. In order to provide the LVGO fraction to the vacuum distillate
recovery unit 4, the pressure within the vacuum distillate recovery
unit 4 at the line 16 inlet location may be lower than the pressure
of line 12 at the point it joins line 16 and/or enters the
distillation column within the vacuum distillate recovery unit
4.
[0042] The LVGO stream in line 12 from the vacuum crude unit 6 can
be combined with the AGO stream in line 10 from the atmospheric
crude unit 2 and/or another component stream in line 14 prior to
introducing the mixture into the vacuum distillate recovery unit 4.
The temperature of the AGO stream may be greater than the
temperature of the LVGO stream, and the combination of the streams
may provide an inlet stream in line 16 to the vacuum distillate
recovery unit 4 that does not require feed preheat. In some
embodiments, the LVGO stream in line 12 and/or another component
stream in line 14 may be introduced into the vacuum distillate
recovery unit 4 separately from the AGO stream in line 10.
[0043] In an embodiment, a feed preheater may be used to preheat
the LVGO stream in line 12, the AGO stream in line 10, the optional
stream in line 14, and/or the combined inlet stream in line 16. The
AGO stream in line 10 may generally have a sufficient enthalpy that
it does not need preheating unless it is cooled prior to being fed
to vacuum distillate recovery unit 4. The feed preheat of these
lines can be provided by a feed pre-heater. In some embodiments,
heat exchange with another stream may be used to pre-heat any of
these streams. For example, the MGO stream in line 38 may be heat
exchanged with the LVGO stream in line 12, the optional stream in
line 14, the AGO stream in line 10, and/or the combined inlet
stream in line 16.
[0044] In operation, a method of operating the system 8 may begin
with the crude feed in line 100. The crude feed is first fed to the
atmospheric crude unit 2 in line 100. As described above, various
treatment processes such as desalting and heating using heat
integration and/or furnaces can be carried out before the crude
feed reaches the atmospheric crude unit 2 and/or as a part of the
processing within the atmospheric crude unit 2. Within the
atmospheric crude unit 2, the crude feed can be separated into a
plurality of product streams, which can comprise a light
ends/naphtha fraction through line 102, a stream comprising a
kerosene fraction in line 103, a stream comprising a diesel
fraction in line 104, a stream comprising an AGO fraction in line
10, and a stream comprising an atmospheric tower bottoms product
fraction (e.g., a residue fraction) in line 50. In some
embodiments, all of the product streams from the atmospheric crude
unit 2 may not be present, and/or other product and feed streams
not shown may be used depending on the design of the atmospheric
crude unit 2. In an embodiment, the atmospheric crude unit 2 may
comprise side stripper columns from which the outlet lines 10, 104,
and 103 may be drawn.
[0045] The Atmospheric Tower Bottoms (ATB) Product fraction (e.g.,
a residue fraction) in line 50 can pass to the vacuum crude unit 6
for further recovery of one or more gas oil fractions. In some
embodiments, all or a portion of the ATB stream as well as
potential ATB streams from other atmospheric crude units can be
stored and sent from the storage to the vacuum crude unit 6 at a
later time. A furnace may be used with the atmospheric tower
bottoms product fraction in line 50 to pre-heat the feed to the
vacuum crude unit 6. The vacuum system 64 may be in fluid
communication with the upper portion of the vacuum crude unit 6
through line 62, which may determine the operating pressure profile
within the vacuum crude unit 6. In an embodiment, the vacuum crude
unit 6 may operate at a less than atmospheric pressure. Within the
vacuum crude unit 6, the atmospheric tower bottoms product fraction
(e.g., a residue fraction) in line 50 can be separated into a
plurality of product streams, which can comprise a stream
comprising an off-gas product in line 62, a stream comprising a
LVGO fraction in line 12, a stream comprising a HVGO fraction in
line 60, and a stream comprising a vacuum tower bottoms (VTB)
product in line 58. As noted above, one or more of the streams
illustrated in FIG. 4 may not be present and/or one or more
additional streams such as a MVGO stream or a slop wax product
stream may pass out of the vacuum crude unit 6. The off-gas product
stream may pass to the vacuum system 64 through line 62. The stream
comprising the LVGO fraction in line 12 may pass to the entrance of
the vacuum distillate recovery unit 4 as described above.
[0046] The stream comprising the AGO fraction from the atmospheric
crude unit 2, the stream comprising the LVGO fraction in line 12,
and optionally, an additional component stream in line 14 may be
introduced into the vacuum distillate recovery unit 4 in one or
more lines (e.g., in line 16). In an embodiment, the additional
component stream in line 14 may originate with one or more other
separation units. For example, the additional components may
originate from another crude unit, purchased gas oils, and/or other
refinery units. The vacuum distillate recovery unit 4 may be in
fluid communication with the vacuum system 64 as described above so
that the vacuum distillate recovery unit 4 may operate at a less
than atmospheric pressure. In some embodiments, the inlet location
of the feed in line 16 may be at a lower pressure than the LVGO in
line 12 from the vacuum crude unit 6.
[0047] The stream fed to the vacuum distillate recovery unit 4 may
be separated to produce one or more product streams, which may
comprise an overhead vapor stream in line 20, a stream comprising a
diesel product fraction in line 32, optionally a stream comprising
a Light Gas Oil (LGO) fraction in line 46, and a stream comprising
a Medium Gas Oil (MGO) fraction in line 38. In an embodiment, fewer
product streams may be present, and in some embodiments, additional
product streams can be produced from the vacuum distillate recovery
unit 4. Since the feeds to the atmospheric crude unit 2 and the
vacuum distillate recovery unit 4 are different, the resulting
diesel fractions produced in each column may also be different.
While each diesel fraction may fall within the specifications for
diesel fuel, the diesel fraction in line 32 may have a higher
average molecular weight than the diesel fraction in line 104. The
two diesel fraction streams 104, 32 can be used separately or
combined in any amount, as described in more detail herein. In some
embodiments, the diesel fraction in stream 32 comprises diesel
range components but can also comprise other lighter distillate
components such as jet fuel and kerosene fractions. A refinery
configuration can include a distillate hydrotreater with a
distillation column downstream of the vacuum distillate recovery
unit 4 that can receive the diesel fraction in stream 32 and
recover hydrotreated diesel as well as other products (e.g.,
naphtha, jet fuel, etc.).
[0048] Another embodiment of a crude separation system 48 is
illustrated in FIG. 5. The system 48 comprises an atmospheric crude
unit 2, a vacuum crude unit 6, and vacuum distillate recovery
column 4. The atmospheric crude unit 2 may be the same or the
similar to the atmospheric crude unit 2 described above. As
described above, the atmospheric crude unit 2 can comprise
associated equipment such as a desalter, a feed preheat train using
one or more exchangers, one or more feed heaters, and a
distillation column for separating the crude feed. The distillation
column 101 may comprise various associated equipment such as side
stripper columns, pump-around heat removal circuits, and/or
overhead condensing and compression system. The atmospheric crude
unit 2 distillation column 101 may generally operate at a pressure
between about 5 psig and about 45 psig, where the pressure varies
within the distillation column 101. In general, the pressure may be
the lowest at the top of the column 101 and the highest at the
bottom. The pressure differential may drive a vapor phase stream
upwards in the column while a descending liquid may contact the
vapor to effect a product separation. The temperature profile
within the column 101 may depend on the pressure profile and the
composition of the vapor and/or liquid along the length of the
column 101. In some embodiments, the temperature within the column
101 may be between about 230.degree. F. and about 740.degree. F.
Various internal separation devices such as trays, structured
packing, side draws, and the like can be used within the
distillation column 101.
[0049] The distillation column 101 may produce a plurality of
product streams representing different fractions of the crude feed.
The product streams may have overlapping boiling point ranges to
some extent, though the boiling point ranges will generally include
higher temperatures as the outlet location descends down the column
101. In an embodiment, the crude feed can be separated into a
plurality of product streams within the atmospheric crude unit 2
distillation column 101 including a light ends/naphtha fraction in
line 102, a stream comprising a kerosene fraction in line 103, a
stream comprising a diesel fraction in line 104, a stream
comprising an AGO fraction in line 10, and a stream comprising an
atmospheric tower bottoms product fraction (e.g., a residue
fraction) in line 50. The stream comprising the AGO fraction in
line 10 will normally be stripped in a side stripper column. The
stream comprising the AGO fraction in line 10 may comprise a number
of components having boiling points in the diesel range. The
conditions of the stream comprising the AGO fraction may vary based
on the design and operation of the atmospheric crude unit 2
distillation column 101. In an embodiment, the stream comprising
the AGO fraction may be at a pressure between about 10 psig and
about 45 psig, or much higher if a pump is used, and have a
temperature between about 600.degree. F. and about 725.degree. F.
unless the stream is cooled. This temperature allows for a high
feed enthalpy of the combined feed to the vacuum distillate
recovery unit 4, which may beneficially provide feed vaporization
in the flash zone of the distillation column 18 of the vacuum
distillate recovery unit 4.
[0050] The atmospheric tower bottoms product fraction in line 50
may pass to a heater 52 where the stream in line 50 may be heated
to a temperature in the range of from about 730.degree. F. to about
795.degree. F. As noted above, all or a portion of the ATB stream
as well as potential ATB streams from other atmospheric crude units
can be stored and sent from the storage to the vacuum crude unit 6
at a later time. In this embodiment, the streams can pass to a
heater to be heated. Various types of heaters can be used to heat
the stream in line 50, and any suitable heater may be used. In an
embodiment, the heater 52 may comprise a furnace. The heated stream
may pass out of the heater 52 and into the vacuum crude column
56.
[0051] The vacuum crude unit 6 may be the same or the similar to
the vacuum crude unit 6 described above. As described above, the
vacuum crude unit 6 can comprise associated equipment such as a
feed heater and a vacuum crude unit distillation column. The
distillation column 56 may comprise various associated equipment
such as one or more pump-around heat removal circuits. The vacuum
crude unit 6 distillation column 56 may generally operate at a
pressure less than atmospheric. For example, the vacuum crude unit
6 distillation column 56 may operate at a pressure between about 2
mmHg and about 100 mmHg absolute, where the pressure varies within
the distillation column 56. The pressure may be reduced to below
atmospheric using the vacuum system 64 which is coupled to the
upper portion of the distillation column 56 through line 62. In
general, the pressure may be the lowest at the top of the column 56
and the highest at the bottom. The temperature profile within the
column 56 may depend on the pressure profile and the composition of
the vapor and/or liquid along the length of the column 56. In some
embodiments, the temperature within the column 56 may be between
about 110.degree. F. and about 790.degree. F. Various internal
separation device such as trays, structured packing, side draws,
and the like can be used within the distillation column 56.
[0052] The vacuum crude unit 6 distillation column 56 may produce a
plurality of product streams representing different fractions of
the atmospheric tower bottoms product fraction. The product streams
may have overlapping boiling point ranges to some extent, though
the boiling point ranges will generally include higher temperatures
as the outlet location descends down the column. In an embodiment,
the atmospheric tower bottoms product fraction fed to the
distillation column 56 can be separated into a plurality of product
streams within the vacuum crude unit 6 distillation column 56
including an off-gas product in line 62, a stream comprising a LVGO
fraction in line 12, a stream comprising a HVGO fraction in line
60, and a stream comprising a vacuum tower bottoms (VTB) product in
line 58. As noted above, one or more of the streams illustrated in
FIG. 4 may not be present and/or one or more additional streams
such as a MVGO stream or a slop wax product stream may pass out of
the vacuum crude unit 6.
[0053] The stream comprising the LVGO fraction in line 12 may
comprise a number of components having boiling points in the diesel
range. As a result, the LVGO fraction stream may be passed to the
vacuum distillate recovery unit 4 for further separation. The
stream comprising the LVGO fraction may be at a pressure between
about 5 mmHg and about 105 mmHg absolute at the point of draw-off
and increase to near atmospheric pressure due to the static head of
liquid in the outlet piping prior to a pump, if one is present. The
temperature of the stream comprising the LVGO in line 12 may vary
due to the design of the vacuum crude unit distillation column 56,
though the temperature will generally be in the range of from about
220.degree. F. to about 350.degree. F. The stream comprising the
VTB fraction in line 58 and/or the stream comprising the HVGO
fraction in line 60 may leave the system 48 for further processing
such as being sent to a coker unit or an FCC unit respectively.
[0054] As shown in FIG. 5, the vacuum distillate recovery unit 4
can comprise a distillation column 18. The distillation column 18
may comprise various associated equipment such as side stripper
columns, pumparound heat removal circuits, side reboilers,
reboiler, feed preheat, bottoms/feed exchanger, feed surge/flash
drum, and/or overhead vacuum system. Various internal separation
device such as trays, structured packing, side draws, and the like
can be used within the distillation column 18. A reboiler system
may or may not be present depending on the feed enthalpy, the
column operating pressure, and the reflux ratio necessary to obtain
the selected recovery of diesel.
[0055] The distillation tower 18 can be coupled to the vacuum
system 64 through the overhead line 20, which can be coupled to
line 24 and/or line 22 as described above. As a result of being in
fluid communication with the vacuum system 64, the pressure within
the distillation column 18 may be less than atmospheric. In an
embodiment, the vacuum distillate recovery unit 4 distillation
column 18 may generally operate at a pressure between about 5 mmHg
and about 600 mmHg absolute, where the pressure varies within the
distillation column 18. The temperature profile within the column
18 may depend on the pressure profile and the composition of the
vapor and/or liquid along the length of the column. In some
embodiments, the temperature within the column 18 may be between
about 100.degree. F. and about 600.degree. F. In an embodiment, the
overhead temperature in the distillation column 18 can be
controlled to be about the same temperature or a lower temperature
than the temperature at the top of distillation column 56 in the
vacuum crude unit 6.
[0056] In some embodiments, a pump may not be present between the
vacuum crude unit 6 and the vacuum distillate recovery unit 4 in
line 12 or line 16. In order to provide the LVGO fraction to the
vacuum distillate recovery unit 4, the pressure within the vacuum
distillate recovery unit 4 at the line 16 inlet location may be
lower than the pressure of the LVGO in line 12 from the vacuum
crude unit 6. While the outlet pressure of the LVGO stream from the
vacuum crude column 56 may in some instances be lower than the
pressure at the line 16 inlet location, the outlet location of line
12 from the vacuum crude column 56 may be above the inlet location
of line 16 into the distillation column 18. The height difference
may contribute to a static fluid head pressure that accounts for
the differences in pressure to drive the LVGO stream to the inlet
location of line 16.
[0057] In an embodiment, the feed to the vacuum distillate recovery
unit 4 includes the AGO fraction in line 10 from the atmospheric
crude distillation column 101, the LVGO fraction in line 12 from
the vacuum crude distillation column 56, and optionally, one or
more additional streams in line 14. In an embodiment, the AGO
fraction in line 10 can be mixed with the LVGO fraction in line 12
and potentially with other gas oil streams in line 14 to form a
combined inlet stream in line 16. A surge/flash drum may be present
in line 16 if the flow stability of the feeds to line 16 is not
sufficiently stable. The surge/flash drum may also be used to
control the conditions (e.g., the temperature, pressure, flowrate,
etc.) of the inlet stream fed into the distillation column 18. For
example, a control valve can be included in line 16 with or without
a surge/flash drum to control the inlet flow rate and pressure into
the column 18. In some embodiments, a feed preheater can be used to
preheat the LVGO stream in line 12, the AGO stream in line 10, the
optional stream in line 14, and/or the combined inlet stream in
line 16. In this configuration, a feed pre-heater and/or heat
exchange with another stream (e.g., heat exchange with the MGO
stream in line 38) may be used to increase the enthalpy of the feed
to the distillation column 18.
[0058] The combined inlet stream in line 16 can be separated within
the distillation column 18 into a plurality of outlet streams. In
an embodiment, the distillation column 18 in the vacuum distillate
recovery unit 4 may separate the inlet stream into an overhead
vapor stream in line 20, a product stream comprising a diesel
fraction in line 32, and a product stream comprising a MGO fraction
in stream 38. In an embodiment, fewer product streams may be
present, and in some embodiments, additional product streams can be
produced from the vacuum distillate recovery unit 4. The stream
comprising the MGO fraction in line 38 may leave the system 48 for
further processing such as being sent to an FCC unit and/or a
hydrocracking unit.
[0059] In an embodiment, a pump-around system may be present and
the diesel fraction in line 32 may be drawn from this system. In
this system, outlet line 26 may draw fluid from the column 18 and
split the stream into a plurality of lines including line 28, which
can be reintroduced to the diesel/gas oil fractionating bed as a
reflux stream, and line 30. Line 30 can be further split into a
plurality of lines including line 32 comprising the diesel product
fraction, and line 34. Line 34 can be cooled by a heat exchanger 35
to form the cooled stream in line 36 before being reintroduced into
the column 18. In some embodiments, line 32 may be separated from
line 36 after the heat exchanger 35 when cooling of the product
stream is desired. The heat exchanger 35 can include any device
suitable for removing heat from the stream in line 34. In an
embodiment, the heat exchanger 35 can comprise a fin fan cooled
exchanger, a cooling water exchanger, or a combination of both. The
total heat removal duty of the heat exchanger 35 can be determined
by the duty required to condense the diesel product stream in line
32, the amount of reflux in line 28, and the quantity of vapors
flowing overhead into line 20. The reflux rate in line 28 can be
controlled to produce the distillation specifications for the
diesel product stream in line 32. In some embodiments, the reflux
ratio as liquid reflux to vapor (LN) ratio at the top of the
fractionating zone, below the diesel draw, may be between about 0.2
and about 0.8 on a volume basis.
[0060] In operation, a method of operating the system 48 may be
similar to the operation of the system 8 described with respect to
FIG. 4, and the full operation of the atmospheric crude unit 2 and
the vacuum crude unit 6 are not repeated in the interest of
clarity. To begin, the crude feed can be fed to the atmospheric
crude unit 2 through line 100. The crude unit feed in line 100 can
be desalted and heated by a fired heater and/or preheat train
exchangers before entering the atmospheric crude unit 2
distillation column 101 to separate the crude feed into a light
ends/naphtha stream in line 102, a stream comprising a kerosene
fraction in line 103, a stream comprising a diesel fraction in line
104, a stream comprising an AGO fraction in line 10, and a stream
comprising an atmospheric tower bottoms product fraction in line
50. Additional feed streams and/or product streams may be fed to
the distillation column 101, and/or one or more of the product
streams may not be present depending on the design of the
atmospheric crude unit 2. The stream comprising the AGO fraction in
line 10 can be stripped in a side stripper column.
[0061] The atmospheric tower bottoms product fraction (e.g., a
residue fraction) in line 50 can pass to the vacuum crude unit 6
for further recovery of one or more gas oil fractions. As noted
above, all or a portion of the ATB stream as well as potential ATB
streams from other atmospheric crude units can be stored and sent
from the storage to the vacuum crude unit 6 at a later time. A
furnace 52 may be used with the atmospheric tower bottoms product
fraction in line 50 to pre-heat the feed to the vacuum crude unit 6
in line 54. The vacuum system 64 may be in fluid communication with
the upper portion of the vacuum crude unit 6 through line 62. In an
embodiment, the vacuum crude unit 6 may separate the various
components at a less than atmospheric pressure. Within the vacuum
crude unit 6, the atmospheric tower bottoms product fraction (e.g.,
a residue fraction) in line 50 can be separated into a plurality of
product streams, which can comprise a stream comprising an off-gas
product in line 62, a stream comprising a LVGO fraction in line 12,
a stream comprising a HVGO fraction in line 60, and a stream
comprising a vacuum tower bottoms (VTB) product in line 58. As
noted above, one or more of the streams illustrated in FIG. 5 may
not be present and/or one or more additional streams such as a MVGO
stream or a slop wax product stream may pass out of the vacuum
crude unit 6. The off-gas product stream may pass to the vacuum
system 64 through line 62. The stream comprising the LVGO fraction
in line 12 may pass to the entrance of the vacuum distillate
recovery unit 4 as described above.
[0062] The stream comprising the AGO fraction in line 10 from the
atmospheric crude unit 2, the stream comprising the LVGO fraction
in line 12, and optionally, an additional component stream in line
14 may be introduced into the vacuum distillate recovery unit 4 in
one or more lines (e.g., in line 16, or as one or more separate
lines into the column 18). The AGO fraction in line 10 may be at a
higher temperature than the LVGO fraction in line 12. The combined
inlet stream in line 16 may have an enthalpy that is sufficient to
avoid the need for a heater in line 16, or between the atmospheric
crude unit distillation column 101 and the vacuum distillate
recovery unit distillation column 18, or between column 56 and
column 18. As noted above, feed preheat may be used in some
configurations and can be provided by a feed pre-heater and/or heat
exchange with another stream or streams.
[0063] The vacuum distillate recovery unit 4 may be in fluid
communication with the vacuum system 64 as described above so that
the unit 4 may operate at a less than atmospheric pressure. A
reboiler system may or may not be present with the distillation
column 18 depending on the feed enthalpy, the column 18 operating
pressure, and the reflux ratio necessary to obtain the selected
recovery of diesel. In some embodiments, additional boil-up can be
provided by a reboiler, side reboiler, or the like. The stream fed
to the distillation column 18 may be separated to produce one or
more product streams, which may comprise an overhead vapor stream
in line 20, a stream comprising a diesel product fraction in line
32, and a stream comprising a Medium Gas Oil (MGO) fraction in line
38. In an embodiment, fewer product streams may be present, and in
some embodiments, additional product streams can be produced from
the vacuum distillate recovery unit 4.
[0064] The overhead line 20 from the distillation column 18 can be
in fluid communication with the vacuum system 64 through line 22,
which is in direct fluid communication with the vacuum system 64,
and/or through line 24, which is in indirect fluid communication
with the vacuum system 64 through the vacuum crude unit 6
distillation column 56. In some embodiments, only one of the lines
22, 24 is present, while in others both lines may be present. In an
embodiment, the distillation column 18 may be in fluid
communication with the vacuum system through line 24. This may
allow the overhead stream in line 20 to pass through the vacuum
crude unit 6 distillation column 56. The pressure of the
distillation column 18 can be controlled through the use of a
control valve between the vacuum system 64 and the distillation
column 18. For example, a control valve can be located in line 20
and used to control the pressure within the top of the distillation
column 18. The internal structures within the distillation column
18 may then determine the pressure profile along the length of the
column.
[0065] Line 26 can be withdrawn from the distillation column 18.
Line 26 can be separated into line 28, which can be refluxed to the
distillation column 18, and line 30. Various equipment such as one
or more control valves and the like can be used to control the
relative flowrate of the streams into each of lines 28 and 30. Line
30 can be separated into a plurality of lines including the diesel
product stream in line 32 and a pump-around stream in line 34.
Various equipment such as one or more control valves and the like
can be used to control the relative flowrate of the streams into
each of lines 32 and 34. Line 34 can be cooled in the heat
exchanger 35 and return to the distillation column 18 from the heat
exchanger 35 through line 36. In some embodiments, line 32 may be
separated from line 36 after the heat exchanger 35 when cooling of
the product stream is desired. Line 32 can then exit the system 48
to provide a diesel product stream. As described in more detail
herein, the diesel fraction in line 32 may fall within the diesel
boiling point range, and may have a different composition than the
diesel product stream in line 104. In some embodiments, the diesel
fraction in stream 32 comprises diesel range components but can
also comprise other lighter distillate components such as jet fuel
and kerosene fractions. A refinery configuration can include a
distillate hydrotreater with a distillation column downstream of
the vacuum distillate recovery unit 4 that can receive the diesel
fraction in stream 32 and recover hydrotreated diesel as well as
other products (e.g., naphtha, jet fuel, etc.).
[0066] FIG. 6 illustrates another embodiment of a system 68 for
recovering diesel from a crude stream. The system 68 may be similar
to the system 8 described with respect to FIG. 4 and the system 48
described with respect to FIG. 5. Like components will not be
described again in the interest of clarity. The main difference
between the system 68 and the previously described systems is the
presence of a Light Gas Oil (LGO) recovery stream in the vacuum
distillate recovery unit 74. The LGO recovery stream may exit the
distillation column 18 through line 46. In an embodiment, the LGO
product stream in line 46 may be taken from the distillation column
18 at a location below the diesel/gas oil fractionating bed and
above the distillation column 18 feed location (e.g., above the
inlet line 16 location). The recovery of a separate LGO stream may
allow the distillation column 18 to produce an LGO stream and a
medium boiling range gas oil stream, which may improve the ability
to selectively provide the product streams to various downstream
processing units.
[0067] Depending on the design of the system, the use of the
distillation column 18 to perform the additional separation of the
LGO stream may require a greater feed enthalpy than is present in
the feed stream in line 16. In this embodiment, a reboiler 42 may
be associated with the distillation column 18 to provide the
additional heat input. The reboiler may draw a stream of liquid
phase hydrocarbons from the stripping section zone and vaporize at
least a portion of the liquid to produce a heated stream in line
44. The heated stream can then be returned to the distillation
column 18. In some embodiments, a side reboiler may be used to draw
a stream from the distillation column 18 at any point along its
length to provide additional boil-up. The reboiler 42 and/or a side
reboiler can comprise any suitable device for heating and at least
partially vaporizing the liquid stream such as a heat exchanger, a
heater (e.g., a furnace, etc.) or the like. In some embodiments, a
base heater may be used within the distillation column to vaporize
a portion of the liquids within the column prior to allowing the
product stream comprising a MGO fraction to pass out of the
distillation column 18 through line 38.
[0068] The operation of the system 68 may be the same or similar to
the operation of the system 8 described with respect to FIG. 4 and
the system 48 described with respect to FIG. 5. The operation of
similar components is not repeated in the interest of clarity. As
shown in FIG. 6, the stream comprising the AGO fraction in line 10
from the atmospheric crude unit 2, the stream comprising the LVGO
fraction in line 12, and optionally, an additional component stream
14 may be introduced into the vacuum distillate recovery unit 74 in
one or more lines (e.g., in line 16). The stream fed to the
distillation column 18 may be separated to produce one or more
product streams, which may comprise an overhead vapor stream in
line 20, a stream comprising a diesel product fraction in line 32,
a stream comprising a LGO fraction in line 46, and a stream
comprising MGO fraction in line 38.
[0069] Within the distillation column 18, a liquid stream may be
withdrawn from the lower portion of the column (e.g., from the
stripping section) and passed through line 40 to a reboiler 42. The
liquid can be at least partially vaporized to create heated stream
in line 44, which can be returned to the distillation column 18 to
create a rising vapor phase. If a side reboiler is present, the
vapor from the side reboiler can be introduced into the
distillation column 18 to form a portion of the rising vapor phase.
A LGO stream can be withdrawn from the column through line 46,
which may be located above the feed. The resulting LGO stream in
line 46 can leave the system 68 for further processing such as
being sent to an FCC unit, a hydrocracking unit, and/or a
hydrotreater. The remainder of the system 68 may operate as
described above with reference to the system 48 described with
respect to FIG. 5.
[0070] FIG. 7 illustrates still another embodiment of a system 78
for recovering diesel from a crude stream. The system 78 may be
similar to the system 8 described with respect to FIG. 4, the
system 48 described with respect to FIG. 5, and/or the system 68
described with respect to FIG. 6. Like components will not be
described again in the interest of clarity. The main difference
between the system 78 and the previously described systems is the
presence of a separate vacuum system 49 for use with the vacuum
distillate recovery unit 4. In this embodiment, the overhead vapor
product stream in line 20 can flow into the separate vacuum system
49. The vacuum system 49 may comprise any of the components
described with respect to the vacuum system 64. The vacuum system
49 may be the same or similar to the vacuum system 64, or the
vacuum system 49 may be different than the vacuum system 64. For
example, the capacity of the vacuum systems may be different
depending on the expected throughput of each unit. In an
embodiment, the use of the separate vacuum system 49 may be used
with any of the previous described embodiments including the
embodiment of FIG. 6 with the LGO outlet line and the reboiler
associated with the distillation column 18.
[0071] The use of the separate vacuum system 49 may be advantageous
in some situations. For example, the use of a separate vacuum
system could enable the vacuum distillate recovery unit 4 to
process other gas oil streams having kerosene and lighter boiling
range materials. For example, the optional inlet stream in line 14
may comprise lighter boiling components. When lighter components
are present, the use of a single vacuum system 64 associated with
the vacuum crude unit 6 may have a negative effect on the operating
pressure achievable in both the vacuum crude unit 6 distillation
column 56 and the vacuum distillate recovery unit 4 distillation
column 18. Specifically, the light boiling range material would
pass to the vacuum system 64 and limit the ability of the vacuum
system to reduce the pressure in the columns. This would increase
the operating pressure within the distillation columns 56, 18 and
consequently decrease the product yields of the vacuum crude unit 6
and the vacuum distillate recovery unit 4. Thus, using the separate
vacuum system 49 may allow the vacuum system 49 to handle a lighter
hydrocarbon feed composition.
[0072] The operation of the system 78 may be the same or similar to
the operation of the system 8 described with respect to FIG. 4, the
operation of the system 48 described with respect to FIG. 5, and/or
the operation of the system 68 described with respect to FIG. 6.
However, the use of a separate vacuum system 49 may allow the
pressure in each column 18, 56 to be independently adjusted. In
this embodiment, the pressure profile may vary between each column
18, 56. If the pressure within the distillation column 18 in the
vacuum distillate recovery unit 4 is higher than the pressure
within the distillation column 56 in the vacuum crude unit 6, then
a pump may be used to increase the pressure of the LVGO stream in
line 12.
[0073] The systems and methods described herein result in the
production of a plurality of diesel streams including the diesel
product stream in line 104 from the atmospheric crude unit 2 and
the diesel product stream in line 32 from the vacuum distillate
recovery unit 4. The two diesel product streams may have different
compositions due to the order in which the two streams are
separated. While most of the components may overlap to some degree,
the proportion of the components may be different. It is expected
that the diesel product stream in line 104 will have a higher
proportion of light boiling range hydrocarbons than the diesel
product stream in line 32, and the diesel product stream in line 32
will have a higher proportion of heavier boiling range hydrocarbons
than the diesel product stream in line 104.
[0074] The production of multiple diesel product streams having
different compositions may allow a refiner to use the streams
separately, or selectively blend the streams to meet various diesel
specifications. In an embodiment, the diesel product streams can be
blended to meet various diesel product specifications such as home
heating oil, No. 1 Diesel, No. 2 Diesel, and the like.
[0075] In some embodiments, the diesel product streams, or some
portion thereof, can be used in a downstream processing unit. For
example, the production of different diesel streams may allow each
stream to be treated in separate hydrotreater to meet process unit
capacity limitations. The production of different diesel streams
with different compositions may allow the feed to the downstream
production units to be selected to produce a desired treated
product. This may beneficially improve the operation of the overall
process while producing a desired diesel product or products.
[0076] At least one embodiment is disclosed and variations,
combinations, and/or modifications of the embodiment(s) and/or
features of the embodiment(s) made by a person having ordinary
skill in the art are within the scope of the disclosure.
Alternative embodiments that result from combining, integrating,
and/or omitting features of the embodiment(s) are also within the
scope of the disclosure. Where numerical ranges or limitations are
expressly stated, such express ranges or limitations should be
understood to include iterative ranges or limitations of like
magnitude falling within the expressly stated ranges or limitations
(e.g., from about 1 to about 10 includes, 2, 3, 4, etc.; greater
than 0.10 includes 0.11, 0.12, 0.13, etc.). For example, whenever a
numerical range with a lower limit, R.sub.1, and an upper limit,
R.sub.u, is disclosed, any number falling within the range is
specifically disclosed. In particular, the following numbers within
the range are specifically disclosed:
R=R.sub.1+k*(R.sub.u-R.sub.1), wherein k is a variable ranging from
1 percent to 100 percent with a 1 percent increment, i.e., k is 1
percent, 2 percent, 3 percent, 4 percent, 5 percent, . . . 50
percent, 51 percent, 52 percent, . . . , 95 percent, 96 percent, 97
percent, 98 percent, 99 percent, or 100 percent. Moreover, any
numerical range defined by two R numbers as defined in the above is
also specifically disclosed. Use of the term "optionally" with
respect to any element of a claim means that the element is
required, or alternatively, the element is not required, both
alternatives being within the scope of the claim. Use of broader
terms such as comprises, includes, and having should be understood
to provide support for narrower terms such as consisting of,
consisting essentially of, and comprised substantially of.
Accordingly, the scope of protection is not limited by the
description set out above but is defined by the claims that follow,
that scope including all equivalents of the subject matter of the
claims. Each and every claim is incorporated as further disclosure
into the specification and the claims are embodiment(s) of the
present invention.
* * * * *