U.S. patent application number 13/128910 was filed with the patent office on 2012-01-05 for process for upgrading heavy oil and bitumen products.
Invention is credited to Wayne Brown, Ross Holuk, Gerard Monaghan, Stephen Porter, Robert Sugiyama.
Application Number | 20120000830 13/128910 |
Document ID | / |
Family ID | 42169557 |
Filed Date | 2012-01-05 |
United States Patent
Application |
20120000830 |
Kind Code |
A1 |
Monaghan; Gerard ; et
al. |
January 5, 2012 |
PROCESS FOR UPGRADING HEAVY OIL AND BITUMEN PRODUCTS
Abstract
A process for upgrading bitumen recovered from an oil reservoir
without hydrogen production is particularly useful in field
upgrading applications. In this process, recovered bitumen enters a
fractionator and is contacted with heated gases from a fluidized
bed reactor. The bitumen and heated gases are fractionated into
segregated products including at least a liquid pitch, unstable
fractions, and an upgraded liquid product. The liquid pitch is
introduced into the reactor to produce a vapor phase liquid
product; the reactor comprises solid particles moving through the
reactor and a fluidizing gas fluidizing the solid particles at a
conversion temperature which is suitable for facilitating the
conversion of at least some of the liquid pitch into the vapor
phase liquid product. The heated gases comprising the vapor phase
liquid product and fluidizing gas are directed from the reactor to
the fractionator to contact the bitumen stream. In this process,
enough of the segregated unstable fractions are burned that the
liquid product and any remaining unstable fractions meets pipeline
specifications without hydrogen treatment of any of the remaining
unstable fractions.
Inventors: |
Monaghan; Gerard; (Calgary,
CA) ; Porter; Stephen; (Hunter River, CA) ;
Holuk; Ross; (Calgary, CA) ; Sugiyama; Robert;
(Calgary, CA) ; Brown; Wayne; (Calgary,
CA) |
Family ID: |
42169557 |
Appl. No.: |
13/128910 |
Filed: |
November 14, 2008 |
PCT Filed: |
November 14, 2008 |
PCT NO: |
PCT/CA08/02022 |
371 Date: |
July 12, 2011 |
Current U.S.
Class: |
208/308 |
Current CPC
Class: |
C10G 9/00 20130101; C10G
1/02 20130101; C10G 2400/02 20130101; C10G 70/00 20130101; C10G
11/18 20130101; C10G 51/023 20130101; C10G 7/00 20130101; B01J 8/36
20130101; C10G 1/002 20130101; C10G 9/32 20130101 |
Class at
Publication: |
208/308 |
International
Class: |
C10G 31/06 20060101
C10G031/06 |
Claims
1. A process for upgrading bitumen recovered from an oil reservoir
without hydrogen treatment comprising: (a) in a fractionator,
contacting the recovered bitumen with heated gases from a fluidized
bed reactor and fractionating the bitumen and heated gases into
segregated products including at least a liquid pitch, unstable
fractions, and an upgraded liquid product; (b) introducing the
liquid pitch into the reactor to produce a vapor phase liquid
product, the reactor comprising solid particles moving through the
reactor and a fluidizing gas fluidizing the solid particles at a
conversion temperature which is suitable for facilitating the
conversion of at least some of the liquid pitch into the vapor
phase liquid product; (c) directing the heated gases comprising the
vapor phase liquid product and fluidizing gas from the reactor to
the fractionator to contact the bitumen stream; and (d) burning
enough of the segregated unstable fractions that the liquid product
and any remaining unstable fractions meets pipeline specifications
without hydrogen treatment of any of the remaining unstable
fractions.
2. A process as claimed in claim 1 wherein during the step of
fractionating the bitumen and heated gases, there is also produced
a non-condensable gas at least some of which is used as the
fluidizing gas in the reactor.
3. A process as claimed in claim 1 wherein the reactor produces
coke when the liquid pitch is converted into the vapor phase
product liquid, and the process further comprises using at least
some of the coke to generate steam for use in recovering the
bitumen.
4. A process as claimed in claim 1 wherein in the step of burning
unstable fractions, steam is generated for use in recovering the
bitumen.
5. A process as claimed in claim 4 wherein the unstable fractions
include cracked naphtha at least some which is recovered as liquid
naphtha for use as an upgraded liquid product.
6. A process as claimed in claim 3 or 4 wherein the bitumen is
recovered by steam assisted gravity drainage or cyclic steam
stimulation.
7. A process as claimed in claim 3 or 4 wherein the steam is
generated by a circulating fluidized bed steam generator and clean
up facility.
8. A process as claimed in claim 7 further comprising partially
oxidizing at least some of the coke to generate heat, directing
flue gas generated as a result of the partial oxidation to the
circulating fluidized bed steam generator and clean up facility,
and contacting the flue gas with lime to clean the flue gas.
9. A process as claimed in claim 8 further comprising partially
oxidizing at least some of the coke to generate heat, and wherein
the heat is used to heat one or more of the solid particles,
fluidizing gas, and low grade steam.
10. A process as claimed in claim 9 wherein the reactor output is
selected such that the amount of coke or naphtha produced is
sufficient to meet all the energy requirements of the circulating
fluidized bed steam generator and clean up facility.
11. A process as claimed in claim 10 wherein the reactor output is
selected such that the amount of coke or naphtha produced is
sufficient to meet all the energy requirements for sufficiently
heating the solid particles and fluidizing gas for use in the
reactor.
12. A process as claimed in claim 1 wherein in the fractionator,
the heated gases are contacted with the bitumen such that the
boiling temperature of volatile material in the bitumen is reduced,
thereby enabling fractionation without use of atmospheric and
vacuum columns.
13. A process as claimed in claim 1 wherein oil is recovered from
an oil sands reservoir.
14. A process as claimed in claim 1 wherein the reactor is a
cross-flow fluidized bed reactor.
15. A process as claimed in claim 1 wherein all of the unstable
fractions are burned that only liquid product remains which meet
pipeline specifications.
Description
FIELD OF THE INVENTION
[0001] This invention relates generally to oil processing, and in
particular, to a system for upgrading heavy oil and bitumen
products.
BACKGROUND
[0002] As conventional access to crude oil declines, more emphasis
has been placed upon devising ways to economically exploit the
abundant ultra-heavy oil (also known as "bitumen") reserves present
most notably in Venezuela, Canada and the United States. Depending
upon the reserve, some of this oil is not recoverable by
conventional means, as the oil will not flow at the ambient
temperature. In Canada, and specifically in Alberta the majority of
bitumen is present as a semi-homogenous mixture of solid
hydrocarbon and inorganic sand and clay, referred to as "oil sand".
The recovery of bitumen in Canada introduces an additional
challenge, as the heavy oil/bitumen must first be recovered from
the sand aggregate prior to introduction into upgrading units. One
popular method of oil recovery from oil sands is thermal recovery,
which involves in situ heating of the oil/sand aggregate, often
using steam as the heating medium. The thermal energy in the steam
liquefies the heavy oil/bitumen, which can then be collected and
pumped to the surface. Examples of thermal recovery processes
include steam assisted gravity drainage (SAGD) and cyclic steam
stimulation (CSS).
[0003] Additional processing is required for bitumen and heavy oils
before they can be introduced into refining infrastructure for
light crude oil; such processing is known as "upgrading". The
degree of upgrading depends upon how far the oil to be processed
("feedstock") deviates from light oil, when compared using standard
refining metrics. In a conventional upgrading system for converting
a heavy, low quality material into a conventional light oil analog,
the feedstock is usually introduced into a plant where it is
usually separated into a pitch and non-pitch fraction. "Pitch" as
generally understood in the industry means the fraction of the oil
boiling above approximately 975.degree. F., as measured by the
standard ASTM method. This physical separation does not introduce
any chemical changes to the molecules in the oil, but rather
separates any higher quality oil from the heavier, low quality
fraction. The heavier pitch fraction, representing typically 30-50%
by weight of the feed mixture is then introduced into a primary
upgrading (PUG) facility where it is subjected to conditions where
the large molecules "crack" into smaller ones, resulting in a
liquid with a lower boiling point than the starting material.
Typically, a boiling point of less than 975.degree. F. is targeted
for the product liquid, based on producing an acceptable feedstock
for conventional downstream refining equipment. Significant sulfur
is released from the oil as part of this processing step. Depending
upon the technology employed in the PUG facility, elemental
hydrogen may also be introduced to the oil to remove nitrogen and
any remaining sulfur, and to increase the hydrogen content of the
oil. In addition to producing a hydrocarbon stream that is liquid
at ambient conditions (the "liquid products"), the PUG facility
will also produce a non-condensable, sour, gaseous hydrocarbon
stream (the "gas"), and a hydrogen-deficient solid byproduct which
is often coke. If a catalytic process is employed in the PUG
facility, a purge of catalyst will also be required, upon which
some of the coke resides.
[0004] The liquid products produced by the PUG facility are then
subjected to secondary upgrading (SUG) in a SUG facility. In this
facility, elemental hydrogen is added catalytically to the liquid
products to increase the hydrogen content of the hydrocarbon
therein, and sulfur, nitrogen and metals are removed from the
liquid products. Typically, the SUG facility utilizes fixed-bed
catalytic reactors.
[0005] A significant amount of infrastructure is required to
support the PUG and SUG facilities in prior art systems. For
example, steam methane reforming (SMR), gasification or other
hydrogen generation means must be provided to generate the hydrogen
required by both the SUG and possibly the PUG facilities.
[0006] The conventional upgrading system is energy and resource
intensive, complex, and expensive to set up and maintain. Reasons
include: the remote and localized nature of oil sand reservoirs
result in expensive labour costs; the use of expensive diluent (a
low molecular weight hydrocarbon) to assist in the separation of
the heavy oil from the mixture of bitumen and water that is
initially recovered at surface by the thermal recovery process;
and, SAGD, CSS and other thermal recovery processes are very energy
intensive, requiring high pressure steam that is typically produced
by combusting natural gas.
[0007] Both hydrogen addition and coking processes have been
incorporated into known systems for the processing of heavy oil and
bitumen. The benefits derived from the PUG processes based on
hydrogen addition are derived at the expense of significant
incremental capital and operating expense. Many of these costs are
the result of incorporating hydrogen production equipment and
processes, expensive and complex bitumen/heavy oil conversion
reactors in hydrogen service, as well as costs associated with
catalyst and incremental feedstock for hydrogen production. The
economic penalties applied to realize the benefits of SUG are
similar to those associated with PUG.
[0008] Because of these high expenses, conventional upgrading
(whether full or partial upgrading) systems are economic only at
higher production outputs, typically in the order of above
.about.60,000 bbl/d. This limits the degree of integration that can
be achieved with thermal production, which typically boasts
.about.20,000-30,000 bbl/d of production. "Field upgrading" is a
concept used to refer to upgrading on a relatively small scale,
usually constructed adjacent to the SAGD or other production
facility. This is of particular interest to the many small scale
bitumen/heavy oil producers operating a single SAGD facility, or
"pod". To date there have been no commercial applications of the
field upgrading concept, as no system utilizing PUG technology has
proven economic at such smaller scales.
SUMMARY OF INVENTION
[0009] It is an objective of the invention to provide a solution to
at least some of the deficiencies in the prior art.
[0010] One particular objective of the invention is to provide an
improved system for upgrading heavy oil and bitumen.
[0011] According to one aspect of the invention, there is provided
a process for upgrading bitumen recovered from an oil reservoir
without hydrogen treatment. This process comprises the following
steps: [0012] (a) in a fractionator, contact the recovered bitumen
with heated gases from a fluidized bed reactor and fractionate the
bitumen and heated gases into segregated products including at
least a liquid pitch, unstable fractions, and an upgraded liquid
product; [0013] (b) introduce the liquid pitch into the reactor to
produce a vapor phase liquid product, the reactor comprising solid
particles moving through the reactor and a fluidizing gas
fluidizing the solid particles at a conversion temperature which is
suitable for facilitating the conversion of at least some of the
liquid pitch into the vapor phase liquid product; [0014] (c) direct
the heated gases comprising the vapor phase liquid product and
fluidizing gas from the reactor to the fractionator to contact the
bitumen stream; and [0015] (d) burning enough of the segregated
unstable fractions that the liquid product and any remaining
unstable fractions meets pipeline specifications without hydrogen
treatment of any of the remaining unstable fractions.
[0016] During the step of fractionating the bitumen and heated
gases, there can also produced a non-condensable gas at least some
of which is used as fluidization gas in the reactor. The reactor
can also produce coke when the liquid pitch is converted into the
vapor phase liquid product, in which case the process further
comprises using at least some of the coke to generate steam for use
in recovering the bitumen.
[0017] During the step of fractionating the bitumen and heated
gases, there can also be produced cracked naphtha, in which case
the process further comprises using at least some of the cracked
naphtha to generate steam for use in recovering the bitumen. At
least some of the cracked naphtha can be recovered as liquid
naphtha for use as an upgraded product. The amount of cracked
naphtha included in the liquid product depends upon the fraction of
this liquid that is unstable, and the ability of the resulting
mixture to meet pipeline specifications.
[0018] The bitumen can be recovered by steam assisted gravity
drainage or cyclic steam stimulation or other known steam recovery
techniques. The steam used for such recovery techniques can be
generated by a circulating fluidized bed steam generator and clean
up facility.
[0019] In this process, at least some of the coke can be partially
oxidizing to generate heat; in such case, flue gas generated as a
result of the partial oxidation is directed to the circulating
fluidized bed steam generator and clean up facility. Sulfur is
removed from the combustion gas generated in the process through
contact with lime.
[0020] Also, at least some of the coke partially oxidized to
generate heat can be used to heat one or more of the solid
particles, fluidizing gas, and low grade steam.
[0021] The reactor output and bitumen input can be selected such
that the amount of coke and naphtha produced is sufficient to meet
all the energy requirements of the circulating fluidized bed steam
generator and clean up facility. The reactor output can be selected
such that the amount of coke and naphtha produced is also or
additionally sufficient to meet all the energy requirements for
sufficiently heating the solid particles and fluidizing gas for use
in the reactor.
[0022] In the fractionator, the heated gases can be contacted with
the bitumen such that the boiling temperature of volatile material
in the bitumen is reduced, thereby enabling fractionation without
use of atmospheric and vacuum columns, which are elements of a
traditional upgrading flowsheet.
[0023] The process and system according to the above aspects of the
invention provides advantages over prior art systems and processes
by reducing the capital scope beyond eliminating the need for
hydrogen generation, and providing additional benefits as will be
described.
BRIEF DESCRIPTION OF DRAWINGS
[0024] FIG. 1 is a flowsheet of a system for producing an upgraded
oil product from heavy oil or bitumen according to one embodiment
of the invention.
[0025] FIG. 2 is a schematic view of a cross-flow fluid bed reactor
used in the system of FIG. 1.
[0026] FIG. 3 is a schematic view of the fractionation process used
in the system in FIG. 1.
DETAILED DESCRIPTION OF EMBODIMENTS OF THE INVENTION
[0027] Any terms not directly defined in this description shall be
understood to have the meanings commonly associated with them as
understood within the art of the invention.
[0028] According to one embodiment of the invention and as shown in
FIGS. 1 to 3, a system 10 is provided which upgrades heavy oil and
bitumen without using hydrogen injection. As this system 10 does
not incorporate the equipment, processes, and materials associated
with hydrogen injection, this system 10 can be economically
deployed for smaller scale "field upgrading" applications, wherein
the upgrader feed rate is approximately equal to the production
rate of a single pod oil sands thermal recovery facility such as
SAGD or CSS, which is typically in the order of 20,000-30,000
bbl/day of a heavy oil/bitumen feedstock. The system is located at
an oil sands reservoir and is used to extract and upgrade bitumen
into an intermediate product which meets pipeline specifications,
and may also meet refinery specifications for refining by a light
crude oil refinery (not shown). In this embodiment, the system 10
is designed for operation at an oil sands reservoir in Alberta,
Canada in which bitumen is recovered using SAGD techniques, and
details of the operating parameters, inputs and outputs of
components in the system 10 are provided for this specific
application; however, it is to be understood that such disclosed
operating parameters, inputs and outputs are provided merely to
illustrate one specific application of the system 10 and that
different operating parameters, inputs and outputs can be specified
depending on the particular application of the system 10.
[0029] Referring now to FIG. 1, bitumen is produced by SAGD in a
bitumen production facility 12. Bitumen is comprised of a mixture
of virgin heavy gas oil and pitch. For brevity the term "bitumen"
is used in this description to conveniently refer to both bitumen
and heavy oil. Steam used by the SAGD process is generated by a
steam generator and gas clean-up facility ("steam generator") 14
which is fluidly coupled to the bitumen production facility 12 by
steam line 13. In this embodiment, bitumen production is rated at
20,000 bbl/day which can be met by well known SAGD techniques.
However, other bitumen recovery techniques such as CSS can be
employed within the scope of this invention. In this SAGD
application, 874,000 lb/hr steam, saturated at 1,300 psig, is
injected into the ground through a vertical injection wellbore (not
shown). The injection wellbore changes direction and continues
horizontally through the reservoir, where holes in the wellbore
permit the steam to escape, creating a heated "steam chamber"
around the injector wellbore. The steam provides the energy
required to melt the bitumen contained in the oil sand within the
steam chamber; the melted bitumen drains by gravity into a
collection wellbore (not shown) that runs parallel to the injector
wellbore. The bitumen and condensed steam, contaminated with some
particulate matter are pumped to the surface. The water and solids
are separated from the oil in a gravity settler (not shown). An
oil-soluble diluent is added to the mixture at a rate of 5,000
bbl/d prior to entry into the separation vessel, in order to assist
in the separation. "Diluent" refers to a light, virgin oil that is
used to dilute heavy oil in order to reduce its density and
viscosity.
[0030] The diluent/bitumen mixture ("diluted bitumen") is then fed
to a diluent splitter 16 at a rate of 25,000 bbl/d, where it is
heated through indirect heat exchange with light and heavy gas oil
from a fractionation apparatus 18, steam from the steam generator
14, and diluent from the diluent splitter 16 to a temperature of
235.degree. C. (conduits for these fluids to the diluent splitter
16 are not shown in FIG. 1). The diluent splitter 16 includes a
fractionator column (not shown) designed to separate the diluent
from the bitumen in the diluted bitumen stream in a manner that is
known in the art. Steam (9,000 lb/hr at 55 psig) from the steam
generator 14 is introduced into the bottom of the fractionator
column to assist in the separation (steam supply conduit not
shown). The column contains components as known in the art to
effect contacting between the vapour and liquid streams within the
column. The liquid streams consist almost entirely of hydrocarbon,
while the vapour is comprised of water and hydrocarbon. The
column's components include an overhead receiver in which condensed
steam is separated from the condensed diluent by gravity. The
separated liquid diluent (about 5,000 bbl/d) is recycled via a
return diluent stream 22 to the bitumen production facility 12 for
reuse. The separated bitumen (about 20,000 bbl/d) is fed to the
fractionation apparatus 18 as a liquid bitumen stream 20. The
condensed steam is returned to the bitumen production facility 12
to be de-oiled (water return line not shown). After de-oiling, the
water is returned to a water treatment facility 32 for purification
before being transported to the steam generator 14 for conversion
to steam.
[0031] The fractionation apparatus 18 is comprised of two primary
vessels: a scrubber and a fractionator column (both not shown in
FIG. 1). The two vessels can alternatively be combined into one, as
is often done industrially, but are kept separate in this
embodiment for convenience and layout considerations. The incoming
bitumen stream 20 is preheated to 300.degree. C. through indirect
contact in conventional heat transfer equipment with a heavy gas
oil pump-around loop 27 (see FIG. 3) drawn from the bottom of the
fractionator column; as will be described below, heavy gas oil is a
liquid product from a primary upgrader reactor 24 that is condensed
in the fractionation apparatus 18 The warmed bitumen stream 20 is
then introduced into the scrubber vessel, where it is distributed
onto the top of internal components that are designed to operate in
a fouling service, which may be, for instance shed decks (not
shown). These internal components are designed to effect contacting
of the relatively heavy bitumen stream 20 with heated gases from
the primary upgrader reactor 24 that is introduced into the
scrubber below the internal components. The contacting will remove
particulate solids that are entrained and carried over from the
reactor 24. The heated reactor gases (77 MMSCFD) substantially
consists of all of the fluidization gas (56 MMSCFD), unreacted
vaporized pitch, vaporized cracked naphtha, cracked light gas oil,
cracked heavy gas oil, non-condensable gas, water vapour and some
suspended coke fines from the reactor 24.
[0032] The heated reactor gases are hot and act as a stripping
medium, assisting in the separation of pitch from non-pitch content
in the bitumen stream 20. The separated pitch materials, in liquid
form, along with some gas oil exit the bottom of the scrubber and
are introduced as a reactor feed (pitch) stream 25 into the primary
upgrader reactor 24 at 350.degree. C. The remaining components of
the bitumen stream, combined with the heated gaseous reactor
products, form the non-pitch materials and comprise potential
liquid products (which are gases in the scrubber). The potential
liquid product, along with the non-condensable gas and fluidization
gas (81.5 MMSCFD), exit a wash grid (not shown) at the top of the
scrubber, and are introduced near the bottom of the fractionator
column at 370.degree. C. FIG. 3 illustrates the flow of fluids into
and out of the fractionator 18.
[0033] For the non-pitch material the fractionator column condenses
the liquid products and separates them into a number of
subfractions based on boiling point. The fractionator column is
equipped with standard internal components known in the art for
this purpose. Steam (3,300 lb/hr at 55 psig) is fed from the steam
generator 14 to the fractionator column to assist in the separation
(shown in FIG. 3 but not FIG. 1), as is common practice. A side
stream stripper (not shown) is also incorporated as a means of
sharpening the cut point between the gas oil and naphtha cuts. A
number of pump-around loops are included in an effort to capture as
much of the energy as possible, and to achieve the desired
separation, as per conventional fractionator design practices.
[0034] The fractionation apparatus 18 produces 7,650 bbl/d of heavy
gas oil and 9,650 bbl/d of light gas oil as liquid products,
collected as a single liquid product stream 26. The combined
product meets pipeline specifications on both density and viscosity
metrics, and is discharged from the fractionation apparatus 18 as a
liquid products stream 26 for refining. Vapour off the top of the
fractionator column is cooled, condensing the steam contained
therein into water, which is then recycled via a water conduit 28
to the bitumen production facility 12 for de-oiling. A small
portion of naphtha (100 bbl/d) in the pitch free vapour is also
condensed, although the majority (>98%) of the cracked naphtha
remains vaporized due to the large amount of non-condensable gas in
the system 10. Both the vaporized and condensed naphtha streams are
routed via cracked naphtha conduit 30 to the steam generator where
it is combusted for energy. Since there is no capacity in the
system 10 to add hydrogen, the unstable cracked liquid naphtha is
not stabilized by hydrogen injection to meet pipeline
specifications and is instead combusted on site to produce energy
for the upgrading process. The heat contained in the gas oil
product leaving the fractionation apparatus 18 is used to preheat
the diluted bitumen feed to the diluent splitter 16 by means of
conventional heat transfer equipment, and the water to a water
treatment apparatus 32. The water treatment apparatus 32 serves to
purify water for use by the steam generator 14 (via purified water
conduit 34), and receives water for this purpose from the bitumen
production facility 12 in the form of deoiled water via line 59,
and from a make up water source 36.
[0035] The non-condensable gases exiting the fractionation
apparatus 18 is routed to a gas compressor 38 via a non-condensable
gas conduit 40. The gas compressor 38 operates to increase the
pressure of the gas from 5 psig to 50 psig by means of a
centrifugal single stage compressor. Non-condensable gas not
required for fluidization (7.3 MMSCFD) in the primary upgrader
reactor 24 is routed to the steam generator 14 via pressurized gas
conduit 42 where it is combusted to produce steam. Gas required for
fluidization is supplied to the upgrader reactor 24 via
fluidization gas conduit 43. As would be known to one skilled in
the art, vaporized naphtha could be recovered from the
non-condensable gas with the use of suitable equipment. However,
due to the instability of this fraction and the absence of hydrogen
addition in the system 10, the capital cost is not justified in the
system 10 of this embodiment. Therefore, all of the non-condensable
gas and most of the vaporized cracked naphtha in excess of that
required for fluidization is combusted to generate steam by the
steam generator 14. The balance (56 MMSCFD) is routed to a heater
46 where it is heated to 500.degree. C. in tubes inserted into a
partial oxidizer (POX) vessel (not shown).
[0036] In this embodiment, all of the cracked naphtha is separated
from the pipeline-bound liquid product stream 26; in other words,
the liquid product is substantially free of unstable fractions. As
noted above, the separated unstable fractions (cracked naphtha) can
be burned to produce energy for generating steam for the system 10;
an additional benefit for separating the unstable fractions from
the liquid product is to ensure that the liquid product has
sufficient stability to meet pipeline specifications. However, some
present pipeline specifications can tolerate liquid product having
some amount of unstable fractions; therefore, a lesser amount of
liquid naphtha and other unstable fractions can be separated from
the product liquid, with the remaining unstable fractions being
left in the liquid products for pipeline transport, provided that
the liquid product meets pipeline specification. Should the liquid
product be transported directly to a refinery, the liquid product
may also have to meet refinery specifications. Operation of the
fractionation apparatus 18 can be adjusted to change the percentage
of unstable fractions that is separated from the liquid product; a
bromine test, or equivalent detection methods as known in the art
can be used to measure the stability of the liquid product and
calculate the minimum amount of unstable fraction that must be
fractionated and removed from the liquid product.
[0037] The heavy pitch stream 25 from the fractionator apparatus
18, along with some gas oil is fed into the primary upgrading
reactor 24 at a rate of 13,700 bbl/d. A primary upgrading reactor
suitable for use with the system 10 is disclosed in Applicant's
Canadian patent 2,505,632. Referring to FIG. 2, the reactor 24
comprises a cross-flow fluidized bed 50 which receives the liquid
pitch stream 25. The fluidized bed 50 comprises moving hot solid
particles 51 fluidized by the fluidization gas from the
fluidization gas conduit 43; the solid particles 51 in the
fluidized bed 50 can be coke particles or sand particles and have a
bulk horizontal velocity which is generally perpendicular to the
vertical upward flow of fluidization gas. The fluidization gas is
introduced into the bottom of the reactor 24 at a rate of 56 MMSCFD
such that bubbling conditions are achieved in the fluidized bed 50.
As noted above, the fluidization gas is comprised of a mixture of
non-condensable gas and cracked naphtha, although there may be also
small concentrations of vaporized light gas oil and water.
[0038] The liquid pitch stream 25 is introduced into the fluidized
bed 50 by means of nozzles (not shown). The liquid pitch engulfs
the solid particles 51 which move horizontally through the reactor
24. The energy contained in the fluidized solids support the
chemical conversion of the pitch into lower boiling hydrocarbon
products that continue until all of the feed material has been
exhausted. The solid particles 51 drop in temperature as the feed
liquid reacts. The cooled solid particles 51 exit the reactor 24
and are transported through cooled solids transfer lines 56 to the
heater 46. The cooled solids are heated in the heater 46 and are
returned to the reactor 24 via heated solids transfer line 57 to
maintain a mean operating temperature of 500.degree. C. The heated
reactor gases, containing fluidization gas, unconverted pitch,
non-condensable gas and the liquid products that are gaseous at
reactor conditions, are passed through a series of cyclones to
remove any entrained solids. The mixture of heated reactor gases is
then routed to the fractionation column of the fractionator
apparatus 18 via conduit 58.
[0039] The primary function of the heater 46 is to heat the cooled
solid particles 51 back up from 490.degree. C. to the temperature
required at the reactor inlet conditions to create a mean operating
temperature of 500.degree. C. In this embodiment, the heater 46 is
a partial oxidizer (POX) vessel (not shown) that partially oxidizes
a portion of the coke; alternatively, other heaters known to those
skilled in the art that are suitable for heating the solid
particles can also be used. The POX vessel is a fluidized vessel in
which the coke is partially combusted under oxygen limiting
conditions, at a temperature of 650.degree. C. The POX vessel is
also used to preheat the fluidization gas to the reactor 24, and to
partially meet the site demand for superheating low grade steam
(8,750 lb/hr at 55 psig). The POX vessel is equipped with two
different sets of heat exchange coils through which fluidization
gas and steam are circulated and heated. The heated solid particles
51 are returned from the POX vessel to the reactor 24 via heated
solids transfer line 57, while flue gas (66 MMSCFD) resulting from
the partial combustion process of the coke is directed via flue gas
line 59 into the steam generator 14 for gas cleanup before
discharge by flue gas lines 61 through a flare. The coke generated
in the reactor that is not consumed in the POX vessel 46 is
introduced into an Elutriator vessel (not shown), which separates
the solids below a critical size from the larger particles, and
returns them to the POX vessel. The balance of the coke (12,000
lb/hr) is routed to the steam generator 14 via coke line 63.
[0040] The CFB steam generator 14 has two primary purposes: to
produce high quality pressurized steam for multiple applications in
the system 10 and to remove sulfur released from the flue gas,
coke, naphtha and fuel gas that are combusted in the process. In
this embodiment the steam generator 14 produces 901,000 lb/hr at
1300 psig of which 875,000 lb/hr is routed to the SAGD facility and
27,000 lb/hr are routed to the PUG. Of course, the steam generator
14 output can be varied depending on the needs of the system 10.
The steam generator 14 comprises a circulating fluid bed boiler
(CFB) of a type that as can be obtained from a number of vendors.
The CFB is a fluidized bed unit designed to combust a number of
fuels in liquid, gaseous or solid form supplied to the steam
generator via fuel lines 30, 42, 63 and 65 and the flue gas line
(not shown). One particularly suitable fuel is natural gas.
[0041] The primary features of the steam generator 14 are: [0042]
limestone (14,500 lb/hr) is introduced into the steam generator 14
via limestone supply line 62 to convert oxidized sulfur into
calcium sulfate; [0043] high pressure steam is produced by
circulating treated water through coils located in the fluid bed;
[0044] heat is produced by combustion of the fuel gas and small
amount of condensed naphtha from the fractionation apparatus 18,
and the flue gas (66 MMSCFD) and coke from the heater 46. The
balance of the energy requirements are met with imported natural
gas (19,000 lb/hr) via natural gas supply line 65 which is much
less than a conventional steam generator which operates entirely on
natural gas; [0045] particulates are separated from the fuel gas
and retained in the system 10 using a series of conventional
separation steps, which, depending upon the vendor may include
U-beams, cyclones, and bag filters; and [0046] ash is removed
periodically from the CFB.
[0047] Most of the steam produced from the steam generator 14 is
directed to the bitumen production facility 12 via steam supply
line 13, with a small portion used to heat the diluent splitter 16
and preheat the diluted bitumen entering the fractionation
apparatus 18 (steam supply line not shown).
[0048] A water treatment facility 32 is provided to process water
from the bitumen production facility 12, making the water suitable
for steam production in the steam generator 14. In this embodiment,
falling film evaporator technology is provided for this purpose;
however other water treatment technologies suitable for this
purpose can be used as is known to those skilled in the art.
Falling film evaporator technology is available from a number of
vendors and has found utility in SAGD service. In particular, a
three-effect evaporation system is used in this embodiment, with a
single vapour recompression stage, which provides the energy
required for evaporation. The water treatment facility 32 accepts
de-oiled water (787,000 lb/hr) from bitumen production facility 12,
along with an amount of fresh water makeup (142,000 lb/hr) through
line 36. Caustic and scale inhibitor are added in a mixing tank.
Air is removed in a de-aerator vessel (not shown), after which the
water is introduced into the cascading three effect evaporator
system. The purified water generated by the water treatment
facility 32 is introduced to the steam generator 14 via purified
water supply line 34, while the evaporator condensate is disposed
of by deep well injection.
[0049] Some notable features of the system 10 include: [0050] A
cross-flow fluid bed primary upgrading (PUG) reactor 24 is used
instead of a conventional furnace type delayed coking, or
well-mixed fluid bed PUG units. The cross-flow fluid bed PUG
reactor 24 generates more liquid products, produces less coke, and
retains more of the native hydrogen than conventional coking
technologies. [0051] The coke produced in the cross-flow fluid bed
PUG reactor 24 is in a readily-consumable form and can thus be used
as fuel to generate steam. [0052] The volume of fluidization gas
required by the cross-flow fluid bed PUG reactor 24 is larger than
other fluid bed technologies. When an inert gas is put into contact
with a volatile material its boiling point temperature is reduced,
a process known as "stripping". The principle of stripping is
applied in the system by contacting the fluidization gas with a
whole barrel of bitumen, separating the pitch fraction from the
non-pitch liquids. This configuration eliminates the need for the
traditional atmospheric and vacuum columns, and the associated
furnaces, that collectively perform this function; [0053] A
circulating fluidized bed (CFB) steam generator and gas clean up
facility 14 is used in the system 10 which is capable of consuming
a number of fuels, including coke, hydrocarbon liquids, and fuel
gas. This unit 14 is used to produce the high pressure steam
required for the thermal production of bitumen. [0054] The unstable
fraction of the naphtha can be consumed in the CFB steam generator
and gas clean up facility 14 for energy, increasing the stability
of the remaining product liquids while harnessing residual value in
the unstable liquids as steam, and reducing the amount of natural
gas or other imported fuel required to generate steam. [0055] Lime
as limestone is fed to the CFB steam generator and gas clean up
facility 14 to capture the sulfur released by system operation.
This enables the capture of sulfur in a single dual purpose unit.
Unlike conventional gas cleanup systems, no hydrogen addition is
necessary. In the prior art process separate units would be
required for each of steam generation, hydrogen sulfide recovery,
and two sequential units for sulfur recovery. [0056] The CFB
technology has all of the elements to be considered carbon capture
and storage (CCS) ready. [0057] Water treatment is provided by
falling film evaporators, a technology that enables the use of
packaged boilers, keeping steam quality high while minimizing
costs.
[0058] Compared to the conventional upgrader systems, the system 10
shown in FIGS. 1 to 3 provides the following advantages: [0059] A
significant reduction in the amount of natural gas imported, which
reduces one of the largest operating cost drivers. This is achieved
by: using combustible byproducts from other components in the
system 10 as fuel for the steam generator 14, eliminating the
furnaces used in the conventional PUG by using a cross-flow fluid
bed PUG 24, eliminating the furnaces in the feed topping facility
by using the fractionator apparatus 18, eliminating a separate gas
cleanup facility by using a combined steam generator and gas
cleanup facility 14, and eliminating a hydrogen production
facility. [0060] A significant reduction in capital scope, which
reduces the capital costs. This is realized through elimination of
the feed topping facility, the hydrogen generation facility (as no
hydrogen treatment is required to stabilize the unstable
fractions), the SUG, and integration of gas cleanup with the steam
generation facility.
[0061] The dramatic reduction in capital and operating costs
realized by the present system 10 can be translated into superior
project economics, as the savings more than offset any potential
discount associated with the resulting upgrader products compared
with native light oil.
[0062] The advantages introduced by the system 10 justify economic
deployment at a much smaller scale, and potentially down to at
least 20,000 bbl/d of whole bitumen feed. The application of the
current system 10 for processing bitumen from the Peace River
region of Alberta, Canada has been described. The bitumen feed
consists of 49% (volume basis) pitch. The pitch has an MCR content
of 23%. The reservoir basis using SAGD technology is a steam to oil
ratio (SOR) of three. The system 10 generates three liquid streams:
naphtha (boiling range to 177.degree. C.), light gas oil (boiling
range from 177.degree. C. to 343.degree. C.), and heavy gas oil
(boiling range from 343.degree. C. to 524.degree. C.).
[0063] The above embodiments have been described by way of example.
It will be apparent to persons skilled in the art that a number of
variations and modifications can be made without departing from the
scope of the invention as defined in the claims. For example:
[0064] In the embodiment of the invention described above and shown
in FIGS. 1 to 3 a portion of the naphtha fraction is consumed for
its energy content, since this fraction is unstable without adding
hydrogen, and there is no hydrogen production provided in the
system 10. In certain instances the naphtha may have more value as
a liquid. This may be the case if, for instance there is a SUG
facility in close proximity that can accept the liquid naphtha.
Another embodiment of the invention involves installation of
additional processing units that will allow for recovery of liquid
naphtha from the gas. This equipment is well known in the prior
art, and includes such units as Light Ends Recovery (LER), and
others. [0065] In the embodiment of the invention described above
and shown in FIGS. 1 to 3, the alternative fuels produced from the
bitumen feed to the reactor 24 may be insufficient to completely
meet the energy requirements of the SAGD facility, and in such case
natural gas is still required. In another embodiment of the
invention the upgrading reactor 24 is increased in size to the
point where the alternative fuels generated by the reactor 24 are
sufficient to completely meet all of the energy requirements of the
system 10, thereby eliminating the need to externally supply
natural gas to the system 10. The incremental bitumen required to
enable this alternative embodiment is imported into the process,
purchased on the open market. The economic benefits of completely
eliminating all natural gas requirements, and the incremental
liquid products produced from the imported bitumen are achieved
with very little incremental capital, since the majority of the
equipment does not change in size. This simple change dramatically
increases the economics of the process. [0066] In the embodiment of
the invention described above and shown in FIGS. 1 to 3,
alternative fuels are used to offset import natural gas. While the
use of alternative fuels is preferred for this embodiment, such use
is not necessary. The decision not to consume alternative fuels may
be made for environmental reasons. In another embodiment of the
invention the energy requirements are met using conventional
natural gas fired heating equipment. The solid coke byproduct is
stockpiled.
* * * * *