Note: Descriptions are shown in the official language in which they were submitted.
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IN SITU UPGRADING VIA HOT FLUID INJECTION
FIELD OF THE INVENTION
[0001] The invention relates to systems, apparatus and methods for integrated
recovery
and in-situ (in reservoir) upgrading of heavy oil and oil sand bitumens. The
systems,
apparatus and methods enable enhanced recovery of heavy oil in a production
well by
introducing a hot fluid including a vacuum or atmospheric residue fraction or
deasphalted
oil into the production well under conditions to promote hydrocarbon
upgrading. The
methods may further include introducing hydrogen and a catalyst together with
the
injection of the hot fluid into the production well to further promote
hydrocarbon
upgrading reactions. In addition, the invention relates to enhanced oil
production
methodologies within conventional oil reservoirs.
BACKGROUND OF THE INVENTION
[0002] In situ recovery methods for heavy oil or bitumen are often used in
reservoirs
where the depth of the overburden is too great for surface mining techniques
to be used
in an economical manner. Being highly viscous, heavy oil and bitumen do not
flow as
readily as lighter oil. Therefore most bitumen recovery processes involve
reducing the
viscosity of the bitumen such that the bitumen becomes more mobile and can
flow from
a reservoir to a production well. Reducing the viscosity of the bitumen can be
realized by
raising the temperature of the bitumen and/or diluting the bitumen with a
solvent.
Steam Assisted Gravity Drainage
[0003] Steam Assisted Gravity Drainage (SAGD) is a known technique to extract
bitumen from an underground reservoir. In a typical SAGD process, two
horizontal wells,
(a bottom well and an upper well) are drilled substantially parallel to and
overlying one
another at different depths. The bottom well is the recovery well and is
typically located
just above the base of the reservoir. The upper well is the injection well and
is located
about 5 to 10 meters above the recovery well. Steam is injected into the upper
well to
form a steam chamber within the formation that, over time, grows predominantly
vertically towards the top of the reservoir and downwardly towards the
recovery well.
The steam raises the temperature of the surrounding bitumen in the reservoir,
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decreasing the viscosity of the bitumen and allowing the bitumen and condensed
steam
to flow by gravity into the lower recovery well. The bitumen and condensed
steam either
flow or are pumped from the recovery well to the surface for separation and
further
processing. At surface, the separated bitumen is often blended with a diluent
such that
the bitumen and diluent can be easily transported to a refinery through a
pipeline. At the
refinery, the diluent is removed and the bitumen is subjected to various
processes to
separate and upgrade the bitumen into useful products. Principally, bitumen
will be
subjected to a vacuum distillation process to separate residual, heavy and
light
components from the bitumen for use in various upgrading processes.
[0004] SAGD is generally a very effective methodology of recovering heavy oil
or
bitumen from the formation to the surface. However, as is known, there are
high capital
and operating costs associated with SAGD, particularly with respect to the
costs of
building and operating a steam generation plant and recovery system at the
drilling site.
In addition, as large amounts of water are required for SAGD, a source of
water must be
available at the site or water needs to be transported to the site. Large
amounts of fuel
are also needed for SAGD to raise the temperature of the water to create
steam. Further
still, the production of high-quality steam from recovered water requires a
substantial
degree of conditioning at surface to clean the recovered water before
reconverting the
recovered water back to steam. This conditioning generally requires that the
recovered
water that is mixed with the produced bitumen must first be separated from the
produced
bitumen and then subjected to further cleaning to remove any residual
contaminants
from the water. Upon these cleaning steps, the produced water must then be
reheated to
produce the high-quality steam for subsequent re-introduction back into the
reservoir. As
such, the cleaning and re-heating steps require substantial inputs of
additional energy
both to drive the cleaning processes as well as to re-heat the produced water
back to
steam. While some energy from the processes can be recovered through heat
exchangers, inefficiencies in the processes result in the need for substantial
additional
energy to be input into the system.
[0005] Thus, while SAGD processes are effective, there are substantial
environmental
costs associated with large-scale SAGD production and specifically that SAGD
has a
carbon-footprint which is considerably greater than other forms of hydrocarbon
production. As a result, there is a need for heavy oil production
methodologies that
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improve the efficiency and particularly the environmental impact of heavy oil
production
from heavy oil reservoirs.
Vertical Injection/Recovery Wells
MOM Other recovery techniques include the use of one or more vertical wells as
a
means of applying heat into a reservoir to facilitate hydrocarbon mobility.
For example, a
single vertical well may be used for cyclic steam stimulation (CSS) which
includes
successive periods of steam injection, soaking and production. Similarly, two
or more
vertical wells in proximity to one another may be utilized where, after a
start-up period
where heat is introduced into the reservoir, one or wells are utilized to
apply heat to the
reservoir and one or more wells are utilized as production/recovery wells.
VAPEX
[0007] Another known in situ recovery process for bitumen or heavy oil is a
vapor
extraction process (VAPEX), which injects a gaseous solvent (i.e. propane,
ethane,
butane, etc.) into the upper injection well where it condenses and mixes with
the bitumen
to reduce the viscosity of the bitumen. The bitumen and dissolved solvent then
flow into
a lower production well under gravity where they are brought to the surface.
[0008] VAPEX is generally considered as being more environmentally friendly
and in
some circumstances more commercially viable than SAGD, as VAPEX does not
require
the large amount of water and steam generation that SAGD does. However, the
gaseous solvent generally needs to be transported to the production site, and
a lengthy
start-up interval exists with VAPEX, as it takes longer to grow a vapor
chamber with
gaseous solvents compared to steam.
[0009] In addition, as VAPEX is a non-thermal process conducted at normal
reservoir
temperatures, it is not efficient in promoting upgrading reactions.
[0010] Thus, there are also significant limitations with respect to widespread
use of
VAPEX.
Catalytic Upgrading
[0011] Certain methodologies may incorporate the use of hydrocracking
catalysts to
assist in the recovery/upgrading process for upgrading and recovering heavy
oil and
bitumen. However, hydrocracking catalyst particles do not disperse well in the
presence
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,
of water, as catalyst minerals tend to preferentially migrate to the aqueous
phase, and
once there, become less available for reactions with hydrocarbons. In
addition, water
has a limited capacity for carrying dispersed particles through sand
formations because
of the low viscosity of water. Therefore, while steam and water are not
catalyst poisons,
dispersing catalyst particles in a SAGD chamber dominated by condensate and
steam is
thought to present significant technical challenges.
[0012] Furthermore, at temperatures less than 150 C, the viscosity of bitumen,
or
vacuum residue, is generally considered to be too high for effective
incorporation of
catalyst particles and gases such as hydrogen. In other words, in highly
viscous
bitumen, reaction times are slow due to mass transfer limitations on top of
kinetic
limitations due to that relatively low energy level,
Enhanced Oil Recovery
[0013] In addition to heavy oil reservoirs, other reservoir types including
conventional
reservoirs having passed peak production and carbonate formations continue to
be
investigated for new or enhanced oil recovery (EOR) techniques. In
conventional
reservoirs with decreasing production rates, there continues to be a need for
cost-
effective methodologies to promote recovery and/or decrease the rates of
decline in
such reservoirs. In addition, techniques for hydrocarbon production from
different
carbonate formations continue to be of interest as oil companies seek to
exploit these
types of reservoirs. As such, new EOR techniques are of interest.
Prior Art ,
[0014] The prior art has many examples of various recovery techniques. For
example,
recovery techniques that utilize a combination of steam and solvent injections
have been
proposed. U.S. Patent Publication 2005/0211434 teaches a SAGD recovery process
utilizing a higher cost production start-up phase where steam and a heavy
hydrocarbon
solvent are injected into a reservoir and a lower cost later production phase
where a light
hydrocarbon solvent is injected into the reservoir to assist in the
mobilization of bitumen.
[0015] U.S. Patent 4,444,261 teaches a method to improve the sweep efficiency
of a
steam drive process in the recovery of oil with a vertical production well
spaced apart
from a vertical injection well. In this technology, steam is injected into the
formation via
the injection well until steam flooding occurs or there is a steam-swept zone
in the upper
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portion of the formation. Next, a high molecular weight hydrocarbon is
injected into the
steam-swept zone at a high temperature (500-1000 F) as a diverting fluid and
allowed to
cool until it forms an immobile slug in the steam-swept zone. Once the slug is
formed,
steam injection is resumed and the slug diverts the steam to pass below the
slug and
below the steam-swept zone, thereby mobilizing the lower portions of oil. In
another
example, United States Patent No. 6,662,872 teaches a combined steam and vapor
extraction process in a SAGD type recovery system.
[0016] As upgrading is commonly done to bitumen or heavy oil after it has been
recovered, several technologies propose the concept of in situ upgrading,
whereby
heavy oil's viscosity is permanently reduced and its API gravity is increased
as the oil is
being produced. For example, United States Patent No. 6,412,557 teaches an in
situ
process for upgrading bitumen in an underground reservoir in which an
upgrading
catalyst is immobilized downhole and an in situ combustion process is used to
provide
heat to facilitate upgrading in a "toe-to-heel" process.
[0017] In other examples, United States Patent No. 7,363,973 discloses a
method for
stimulating heavy oil production in a SAGD operation using solvent vapors In
which in
situ upgrading may be involved and United States Publication No. 2008/0017372
discloses an in situ process to recover heavy oil and bitumen in a SAGD type
recovery
system using C3+ (more specifically C3-C10) solvents. Upgrading is described
as
inherently occurring in view of the solvents contacting the bitumen.
[0018] A further example is shown in United States Patent Publication
2006/0175053
that describes a process to improve the extraction of crude oil. This process
utilizes an
insulated pipe to convey hot fluids to the formation to facilitate extraction.
The hot fluids
may include paraffins and asphaltenes.
[0019] Accordingly, while various technologies continue to be developed that
advance
upon the general methodologies of SAGD and VAPEX, there continues to be a need
for
improved in-situ recovery method in which large amounts of water or gaseous
solvents
do not need to be shipped to the production site, nor in which a large amount
of steam
and water are present in the reservoir. As well, improved forms of in situ
upgrading
techniques are generally needed that are more economical, efficient, and are
able to
recover a higher proportion of oil.
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[0020] Further still, there has been a need for improved EOR and oil recovery
techniques that may be utilized in conventional reservoirs and carbonate
formations.
SUMMARY OF THE INVENTION
[0021] In accordance with the invention, there is provided systems and methods
for in
situ upgrading of hydrocarbons within a hydrocarbon formation.
[0022] In a first aspect, a method for recovery and in situ upgrading of
hydrocarbons in a
well pair having an injection well and a recovery well within a heavy
hydrocarbon
reservoir is provided, the method comprising the steps of: a) introducing a
selected
quantity of a hot injection fluid including a heavy hydrocarbon fraction into
the injection
well to promote hydrocarbon recovery and in situ upgrading; and b) recovering
hydrocarbons from the recovery well.
[0023] In another embodiment, the heavy hydrocarbon fraction is selected from
any one
of or a combination of shale oil, bitumen, atmospheric residue, vacuum
residue, or
deasphalted oil.
[0024] In further embodiments, the hydrocarbons recovered from the recovery
well are
subjected to a separation process wherein heavy and light fractions are
separated and
wherein the heavy fraction includes a residue fraction.
[0025] In another embodiment, the residue fraction from the separation process
is mixed
with the injection fluid prior to introduction into the injection well.
[0026] In another embodiment, the method further comprises the step of mixing
make-
up heavy hydrocarbons with the injection fluid prior to introducing the
injection fluid into
the injection well and wherein the temperature and pressure of the injection
fluid is
controlled to promote downhole upgrading reactions.
[0027] In another embodiment, the injection fluid includes diluent.
[0028] In further embodiments, the temperature and pressure of the injection
fluids are
controlled to promote thermal cracking upgrading reactions.
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[0029] In yet further embodiments, the temperature of the injection fluid is
controlled to
provide a downhole sump temperature of 320 20 C and/or the downhole residence
time
of injected fluids is 24-2400 hours.
[0030] In another embodiment, the temperature of pressure of the injection
fluids are
controlled such that greater than 30% of residual heavy hydrocarbon of the
recovered
bitumen is upgraded into lighter fractions.
[0031] In another embodiment, the temperature and pressure of the injection
fluids are
controlled such the recovered hydrocarbons have a viscosity less than 500 cP
at 25 C.
[0032] In another embodiment, the recovered hydrocarbons have a viscosity less
than
250 cP at 25 C.
[0033] In yet a still further embodiment, prior to step a), steam is injected
into the
horizontal well pair to initiate connection between the injector well and the
recovery well
and formation of a downhole reaction chamber.
[0034] In another embodiment, prior to step a) the steam is progressively
replaced with
a heavy hydrocarbon fluid, selected from any one of or a combination of heavy
oil, shale
oil, bitumen, atmospheric residue, vacuum residue, or deasphalted oil.
[0035] In yet another embodiment, the method includes the step of mixing a
catalyst
into the injection fluid prior to introducing the injection fluid into the
injection well.
[0036] In another embodiment, the method further comprises the step of mixing
hydrogen into the injection fluid prior to introducing the injection fluid
into the injection
well.
[0037] In other embodiments, the temperatures and pressures of the injection
fluid are
controlled to promote any one of or a combination of hydrotreating,
hydrocracking or
steam-cracking reactions.
[0038] In another embodiment, the hydrogen is mixed with the injection fluid
to provide
excess hydrogen for the hydrotreating and hydrotreating reactions.
[0039] In yet another embodiment, the hydrogen is injected along the length of
the
injection well.
[0040] In another embodiment, approximately 1/3 of the hydrogen is mixed with
the
injection fluid at surface and approximately 2/3 is injected to the reservoir
along the
horizontal length of the recovery well.
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100411 In yet another embodiment, the hydrogen is injected from the recovery
well via at
least one liner operatively configured to the recovery well.
[0042] In various embodiments, the catalyst is any one of or a combination of
nano-
catalysts or ultradispersed catalyst wherein the nano-catalyst may have
particles with
dimensions less than 1 micron and/or less than 120 nm.
[0043] In another embodiment, a plurality of adjacent interconnecting well
pairs are
configured to a single well pad wherein one of the interconnecting well pairs
is an
upgrading well pair and wherein heavy hydrocarbon fluids recovered from each
well is
mixed with the injection fluid of the upgrading well pair.
[0044] In a further embodiment, the heavy hydrocarbon fluids include any one
of or a
combination of heavy oil, shale oil, bitumen, atmospheric residue, vacuum
residue, or
deasphalted oil
[0045] In another embodiment, the injection well and recovery well have
vertically
overlapping horizontal sections and the injection well is the lower of the
injection well
and the recovery well.
[0046] In a still further embodiment, the injection well and recovery well
have vertically
overlapping horizontal sections and the injection well is the upper of the
injection well
and the recovery well.
[0047] In another aspect, the invention provides a method of upgrading heavy
hydrocarbons during hydrocarbon recovery from a heavy hydrocarbon formation
comprising the steps of: a) drilling an injection well and recovery well into
the heavy
hydrocarbon formation; b) creating a hydrocarbon mobilization chamber within
the heavy
hydrocarbon formation by introducing a hot fluid into the injection well so as
to promote
hydrocarbon mobility to the recovery well; c) recovering heavy hydrocarbons
from the
recovery well to the surface; d) subjecting the recovered hydrocarbons from
step c) to a
separation process to form lighter hydrocarbon fractions and heavy residual
hydrocarbon
fractions; e) introducing a portion or all of the heavy residual hydrocarbon
fractions at a
temperature and pressure to promote hydrocarbon upgrading reactions in the
hydrocarbon mobilization chamber; and, f) recovering co-mingled and upgraded
hydrocarbons from the recovery well.
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[0048] In another embodiment, a portion of the heavy residual fraction from
the
separation is used as a fuel to produce heat to heat the injection fluids for
upgrading
reactions.
[0049] In a further embodiment, the method further comprises the step of using
a portion
of the lighter hydrocarbons to additional separation processes for
commercialization.
[0050] In another embodiment step e) includes introducing a catalyst into the
injection
well to promote catalytic upgrading within the injection well and the
hydrocarbon
mobilization chamber and/or step e) further includes introducing hydrogen into
the
injection well to promote upgrading reactions within the hydrocarbon
mobilization
chamber.
[0051] In yet another aspect, the invention provides a system for recovery and
in situ
upgrading of heavy hydrocarbons within a heavy hydrocarbon formation
comprising: an
injection well; a recovery well; the injection well and recovery well
operatively connected
to a hydrocarbon distillation column for separation of recovered fluids from
the recovery
well into heavy and light fractions; and, a mixing and hot fluid injection
system
operatively connected to the distillation column for recovering heavy
fractions from the
distillation column and for mixing the heavy fraction with additional
injection fluids for
injection into the injection well;
[0052] In another embodiment, the system further comprises a gas/liquid
separation
system operatively connected to the recovery well for separating gas and
liquids
recovered from the recovery well and for delivering separated liquids to the
distillation
column and/or a catalyst injection system operatively connected to the mixing
and hot
fluid injection system for Introducing catalyst to the mixing and hot fluid
injection system
and/or a hydrogen injection system operatively connected to the mixing and hot
fluid
injection system for introducing hydrogen to the mixing and hot fluid
injection system
and/or a diluent injection system operatively connected to the mixing and hot
fluid
injection system for introducing diluent to the mixing and hot fluid injection
system and/or
at least one additional injection and recovery well operatively connected to
the distillation
column for introducing additional heavy hydrocarbons from the at least one
additional
recovery well to the distillation column.
[0053] In yet a further aspect, the invention provides a method of upgrading
heavy
hydrocarbons during hydrocarbon recovery from a heavy hydrocarbon formation
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comprising the steps of: a) drilling an injection well and recovery well into
the heavy
hydrocarbon formation; b) creating a hydrocarbon mobilization chamber within
the heavy
hydrocarbon formation by introducing a hot fluid into the injection well so as
to promote
hydrocarbon mobility to the recovery well; c) recovering heavy hydrocarbons
from the
recovery well to the surface; d) subjecting the recovered hydrocarbons from
step c) to a
solvent deasphalting separation process to form a deasphalted oil and an
asphaltic
pitch; e) introducing deasphalted oil from step d) into the injection well at
a temperature
and pressure to promote hydrocarbon upgrading reactions in the hydrocarbon
mobilization chamber; and, f) recovering co-mingled and upgraded hydrocarbons
from
the recovery well.
[0054] In another embodiment, a portion of the asphaltic pitch is used as a
fuel to
produce heat to heat the injection fluids for upgrading reactions.
[0055] In yet another embodiment, the method further comprises the step of
using a
portion of the lighter hydrocarbons to additional separation processes for
commercialization.
[0056] In yet another aspect, the invention provides a system for recovery and
in situ
upgrading of heavy hydrocarbons within a heavy hydrocarbon formation
comprising: an
injection well; a recovery well; wherein the injection well and recovery well
operatively
connected to a solvent deasphalting system for recovering a deasphalted oil
fraction for
mixing with additional injection fluids for injection into the injection well.
[0057] In yet another aspect, the invention provides a method of upgrading
heavy
hydrocarbons during hydrocarbon recovery from a heavy hydrocarbon formation
comprising the steps of: a) drilling a well into the heavy hydrocarbon
formation; b)
introducing heat into the well to create a hydrocarbon mobilization chamber
within the
heavy hydrocarbon formation so as to promote hydrocarbon mobility within the
well; c)
recovering heavy hydrocarbons from the recovery well to the surface and
initially storing
the heavy hydrocarbons in a heated tank; d) introducing heavy hydrocarbons
from the
heated tank into the well at a temperature and pressure to promote hydrocarbon
upgrading reactions in the hydrocarbon mobilization chamber; e) sealing and
maintaining pressure in the well for a time sufficient to promote hydrocarbon
upgrading
reactions; and, f) after a sufficient time, releasing the well pressure and
recovering
upgraded hydrocarbons from the well.
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[0058] In other embodiments, the invention includes the steps of introducing
catalyst
into the well during step d); and/or introducing hydrogen into the well during
step d).
[0059] In another aspect, the invention provides a method for recovery and in
situ
upgrading of hydrocarbons in a well pair having an injection well and a
recovery well
within a heavy hydrocarbon reservoir comprising the steps of: (a) introducing
a selected
quantity of a hot injection fluid including a heavy hydrocarbon fraction
selected from any
one of or a combination of shale oil, bitumen, atmospheric residue, vacuum
residue, or
deasphalted oil into the injection well to promote hydrocarbon recovery and in
situ
upgrading; (b) recovering hydrocarbons from the recovery well; (c) subjecting
the
hydrocarbons recovered from the recovery well to a separation process wherein
heavy
and light fractions are separated to produce any one of or a combination of
shale oil,
bitumen, atmospheric residue, vacuum residue and a deasphalted oil fraction;
and, (d)
re-introducing any one of the shale oil, bitumen, atmospheric residue, vacuum
residue or
deasphalted oil fraction into the well as a hot injection fluid under
temperature and
pressure conditions to promote upgrading and repeating steps (a) to (d).
BRIEF DESCRIPTION OF THE DRAWINGS
[0060] The invention is described with reference to the accompanying figures
in which:
Figure 1 is a schematic diagram of a residue assisted in situ upgrading
(RAISUP) process in accordance with a first embodiment of the invention;
Figure 2 is a schematic diagram of a residue assisted in situ catalytic
upgrading
(RAISCUP) process in accordance with a second embodiment of the invention;
Figure 2A is a schematic plan view of a RAISUP process utilizing multiple well
pairs;
Figure 2B is a schematic cross view of various RAISUP processes using one or
more vertical wells as injection/production wells;
Figure 3 is a schematic diagram of a recovery chamber in accordance with one
embodiment of the invention;
Figure 4 is a schematic diagram of a typical temperature gradient in an
upgrading well pair and recovery chamber in accordance with one embodiment
of the invention;
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Figure 5 is a schematic diagram of surface facilities for an upgrading well
pair in
accordance with another embodiment of the invention;
Figures 6 is a schematic diagram of surface facilities for an upgrading well
pair
in accordance with another embodiment of the invention utilizing deasphalted
oil;
Figure 7 is a schematic diagram of the upgrading zones in accordance with the
invention; and,
Figure 8 is a schematic diagram of another embodiment of the invention using a
huff and puff methodology.
DETAILED DESCRIPTION OF THE INVENTION
Overview
[0061] In accordance with the invention and with reference to the figures,
systems,
apparatus and methods for in situ upgrading of hydrocarbons in hydrocarbon
recovery
operations are described. In particular, the methods enable upgrading of heavy
oils and
bitumen within a production well bore and formation chamber using hot
injection fluids.
In a first embodiment, the hot injection fluid includes a residue fraction. In
a second
embodiment, the injection fluid includes deasphalted oil. In both cases,
hydrogen gas
and a catalyst can be injected together with the hot residue or deasphalted
oil to
promote in situ upgrading and recovery of the heavy oils and bitumen.
[0062] In accordance with the invention and in the context of this
description, the
following general definitions are provided for the terms used herein. Extra
heavy
hydrocarbons are generally defined as those hydrocarbon fractions that are
distilled
above temperatures of 500 C (atmospheric pressure) or have an API gravity less
than
(greater than 1000 kg/m3). Heavy hydrocarbons are distilled between
temperatures of
350 C and 500 C or have an API gravity between 10 and 22.3 (920 to 1000
kg/m3).
Medium hydrocarbons are distilled between temperatures of 200 C and 350 C and
are
generally defined as having an API gravity between 22.3 API and 31.1 API (870
to 920
kg/m3). Light hydrocarbons are defined as having an API gravity higher than
31.1 API
(less than 870 kg/m3) and are distilled below 200 C.
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[0063] A residue fraction is the fraction that distills at temperatures higher
than 540 C. A
deasphalted oil (DAD) fraction is a crude fraction produced in a deasphalting
unit (DAU)
that separates asphalt from bitumen.
Residue Assisted In situ Upgrading (RAISUP)
[0064] In a first embodiment, as shown in Figure 1, the invention provides a
system for
Residue Assisted In situ Upgrading (RAISUP) in an in situ upgrading chamber 12
having
an upgrading well pair 13. In accordance with this embodiment, one of the
wells of the
upgrading well pair is an injection well 16 and the other well is a recovery
well 18. Well
pairs may be horizontal, vertical or inclined and may comprise combinations of
such
wells as shown in Figure 2b. For the purposes of description, a horizontal
well pair is
described although it is understood that other combinations of well pairs may
be utilized.
Initially, hot fluid or steam is injected into the injection well, causing a
chamber 12 to
grow at and around the injection point 16a. The recovery well 18 serves to
collect the
recovered fluids, from which the recovered fluids flow or are pumped to the
surface. At
the surface, the recovered fluids enter an atmospheric and/or vacuum
distillation column
20 where the heavy oil is separated into fractions by weight, leaving at the
bottom of the
distillation column a heavy vacuum or atmospheric residue fraction 20a (the
"residue
fraction"), and at higher levels of the column, lighter oil fractions 20b,
recovered gases
20c and recovered diluent 20d (if utilized).
[0065] In accordance with the invention, the hot fluids injected into the
injection well
include the residue fraction 20a from the distillation column, additional
bitumen 20e from
another source and/or diluent 20f and/or other hot fluids including steam.
Importantly,
injecting the residue fraction promotes in situ thermal cracking/upgrading
reactions to
occur within the formation. In addition, the injection of a residue fraction
affects the
overall efficiency of upgrading reactions as the heavy oil fractions are most
reactive to
heat driven upgrading reactions.
[0066] Importantly, the "re-injection" of the hot residue fraction into the
injection well is
also an effective source of introducing heat into the chamber 12. Further
still, while it is
preferred that the residue is recovered from an at-site distillation column
20, it is
understood that the residue fraction 20a may be formed elsewhere at the
surface
including being pumped to the site from other wells or processing centers that
may be
adjacent to or near the well as shown in Figures 2A and 2B.
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[0067] Accordingly, in a preferred operation, the hot residue is produced in
the
distillation column 20 and re-injected into the injection well at around 350
20 C which
ideally provides an average reservoir sump temperature of 320 20 C.
Importantly, as
the injected hot residue temperature is thus generally higher than that of
steam, the hot
residue will cause the chamber to more rapidly expand during start-up
operations and/or
more rapidly maintain a steady state size.
[0068] In addition, a sump temperature of around 320 20 C promotes in situ
thermal
upgrading of the bitumen in the injection well and oil reservoir by increasing
the
temperature of the bitumen to a temperature at which upgrading reactions can
occur (eg.
thermal cracking), as well as decreasing the viscosity of the bitumen to
improve the
overall mobility of the bitumen in the reservoir.
[0069] Under steady state conditions, the residence time for the injected
residue may
vary between approximately 24-2400 (normal upper limit about 500) hours
depending on
the size of the chamber and the permeability of the porous media as understood
by
those skilled in the art Recovered bitumen will be partially but significantly
upgraded to
produce a number of heavy oil products having a typical viscosity less than
300 cPoises
60 F and 14-15 API gravity as compared to a typical API gravity of 8-10 for
recovered
bitumen at similar conditions. Under typical conditions, a residence time of
24-48 hours
will result in more than 30% of the recovered bitumen being upgraded.
[0070] A further advantage of hot residue injection in accordance with the
invention is
that the recovered oil is at a higher temperature and contains much less water
than with
steam injection. Accordingly, injecting hot residue can effectively eliminate
the injection
of water into the reservoir, such that the only water in the reservoir will be
connate water.
As a result, water treatment and/or water disposal costs will be eliminated or
substantially reduced.
[0071] However, during start-up, steam can be injected into the injection well
to begin
growing the chamber during the start-up phases, in which case the steam is
then
progressively replaced with hot residue over time. Thus, during start-up,
water treatment
and recovery may be required. However, it should also be noted that steam use
at this
step could be replaced using heated oil from a storage tank and enabling
recirculation of
hot oil within the wells until the wells achieve connectivity. The selection
of either steam
- 14 -
CA 02810022 2013-03-19
and/or heated oil to effect connectivity can be made based on the specifics of
a series of
wells and the economics of those wells.
[0072] Alternatively, hot oil (bitumen, Deasphalted oil, Vacuum Gas oil etc..)
can be
injected during the start-up phases and used to-grow the chamber from the
beginning if
the economics of a particular project support this approach.
[0073] It should be noted that the use of hot residue to grow the chamber
generally
results in greater horizontal expansion of the chamber instead of vertical
expansion due
to the generally greater horizontal permeability of heavy oil formations in
comparison to
vertical permeability. Importantly, a more laterally expanded chamber may
result in more
complete recovery than the typical vertical chamber of SAGD processes, as
greater
horizontal expansion will result in a greater overall volume of the recovery
chamber.
Residue Assisted in-situ Catalytic Upgrading (RAISCUP) Process
[0074] In accordance with another aspect of the invention and with reference
to Figures
2-8, systems and methods for Residue Assisted In situ Catalytic Upgrading
(RAISCUP)
in a hydrocarbon recovery operation are described. In particular, these
methods enable
catalyst-assisted upgrading of heavy oils and bitumen within a production well
bore and
formation chamber having a well pair.
[0076] As shown in Figure 2, in this embodiment, catalyst 30 and hydrogen 28
are
injected into the injection well to further promote upgrading reactions
including
hydrotreating and hydrocracking reactions in addition to thermocracking
reactions. As in
Figure 1, the system includes an upgrading well pair 13 consisting of an
injection well 16
and a recovery well 18 in which the injection well serves as a point of entry
for injected
fluids 38 and the recovery well collects recovered fluids 44 which flow or are
pumped to
the surface. As explained in greater detail below, either well from the well
pair may serve
as the injection well. However, for the purposes of illustration in situations
with one or
more horizontal well pairs, Figures 2-5 illustrate the top well as the
injection well 16 and
the bottom well as the recovery well 18.
[0076] In one embodiment, the system is designed for use with a plurality of
horizontal
well pairs served by one well pad 50 in which one of the adjacent well pairs
(50a, b, c, d)
is used for upgrading reactions (Figure 2A). For example, bitumen recovered in
adjacent
well pairs (50 b, c, d) may be upgraded in well pair 50a in which all the
bitumen
-15-
CA 02810022 2013-03-19
=
recovered from the adjacent well pairs (approximately 500 to 1000 barrels per
day per
well pair) could be upgraded in one upgrading well pair for efficiency
reasons.
[0077] In this embodiment as shown in Figure 2, the injected fluids 38
preferably
comprise hydrogen 28, column recovered residue fraction 20a, other bitumen
20e,
diluent 20f (optional) and catalyst 30. As noted, the other bitumen 20e may
include
recovered bitumen from surrounding well pairs and/or other sources.
[0078] Initially, during start-up typically 10 to 15% diluent (condensate) 20f
(Figure 1)
may be added to hot bitumen to assist in the transport and mobility of bitumen
into the
well during start-up and explained in greater detail below. Once the upgrading
well pair
is undergoing steady in situ upgrading operation the diluent can be removed
for
recycling and no more bitumen is injected to the reservoir and instead the
residual
fraction from the distillation column is used.
[0079] During steady-state operation, incoming bitumen 20e and diluent 20f
will be
blended with hot residue 20a along with recovered and makeup hydrogen 28 and
makeup catalyst 30 together with recovered hydrogen and gases 32 prior to
injection
into the upgrading well pair. Recovered fluids 44 are subjected to appropriate
gas/fluid
separation to recover some hydrogen for re-injection.
[0080] The catalyst is preferably a nano-catalyst or ultradispersed catalyst,
as described
in United States patent 7,897,537 incorporated herein by reference. The
catalyst may be
produced on site by transporting the catalyst precursors to the site, or a pre-
manufactured catalyst may be transported to the site. The hydrogen may be
initially
shipped to the site and produced with small units (hydrogen generators) as the
hydrogen
pressure and its consumption is much lower than typically needed in
conventional
surface upgrading, and after production has started, as noted above, the
unreacted
hydrogen dissolved in the produced oil coming to the surface can be recovered
from the
distillation process and gas/fluid separation 32.
[0081] In the case where the average residence time of the injected fluids 38
in the
upgrading zone is more than 150 hours, upwards of 45% of the heavy oil
fractions can
be converted to upgraded oil with 14-16 API. After a sufficient residence
time, the
recovered fluids 44 from the recovery well 18 are introduced into the column
20 for
separation. Lighter fraction oil products 20b are removed and residual
catalyst, residue
- 16-
CA 02810022 2013-03-19
fraction separated from the vacuum/atmospheric residue to recover and recycle
the
catalyst particles, resulting in upgraded oil 32 with more than 20 API. The
recovered
fluids 44 are composed of excess hydrogen, upgraded 14-16 API oil,
unconverted
bitumen and atmospheric/vacuum residue, other produced gases (C1-14, H2S and
H20
from connate water), and catalyst not retained in the upgrading zone.
[0082] At the surface, excess hydrogen and other gases 32 are separated and
recycled.
The remaining recovered liquids 44 are sent to the distillation column 20 for
vacuum/atmospheric residue and catalyst recovery. Generally, it is preferred
that the
upgrading zone 40 retains a proportion of catalyst particles because it
minimizes the
scope of catalyst recovery and reduces the amount of on-going catalyst
injection that
occurs, thereby reducing catalyst costs. In the distillation column, diluent
24 may be
recovered and recycled to adjacent or other well pairs if desired. Upgraded
oil 34 derived
from the residue is sent to market. Recovered catalyst and the residue
fraction 20a are
returned to the upgrading well pair.
[0083] Catalyst will generally be retained in the reservoir until it starts to
rise in the
recovered fluids and will reach a plateau amount at a concentration lower than
the
amount being injected. A steady concentration of catalyst will come up to the
surface. As
the catalyst is heavier (in terms of density) than the heaviest upcoming oil
molecules, it
will generally remain in the residue during distillation. Entrainment in
particles and/or
carry-over is unlikely as the distillation columns are generally designed to
prevent
entrainment and carry-over. However, filters will normally be incorporated
downstream of
the bottom of the distillation column to retain any large particle in the
residue (either
sand or agglomerated particles including catalyst that may come up to the
surface).
Moreover, it is also noted that the heaviest distillates from a vacuum
distillation column
will generally carry no particles of lighter density carbonaceous material
(micro coke
particles) that could eventually be entrained by distillation, which indicates
that these
columns are effective for particle separation. Moreover, the catalyst
concentration at
injection will be low (less than 1000 ppm in the residue (<0.1% by weight) and
it will be
substantially lower in the produced fluids; a typical norm BWS (bottom water
and
sediments) specifies 0.5% wt for example.
[0084] That is, the catalyst particles are effectively separated at the lowest
cost from the
upgraded produced oil by remaining in the fraction that is recycled to the
reservoir. As a
- 17 -
CA 02810022 2013-03-19
result, the produced lighter oil from the distillation column is generally
ready to be
transported without containing catalyst particles. In addition, re-injected
residue fraction
will ultimately be fully converted to lighter fractions and the un-upgradable
heaviest
fractions will be eventually left back in the reservoir if desired.
[0085] Furthermore, bitumen contains naphthenic molecules that may undergo
repeated
cycles of dehydrogenation and hydrogenation in the upgrading zone 40.
Therefore,
naphthenic molecules may contribute to the redistribution of hydrogen to
larger residue
molecules, thereby improving residue conversion efficiency as per the
following chemical
equation:
CC,r 'ma' CO + H2
equation 1
Upgrading and Recovery Chamber
[0086] The RAISCUP process also results in recovery of bitumen from the
formation
hosting the upgrading well pair. As shown in Figures 2, 3 and 4, the
upgrading/recovery
chamber 12 generally includes two zones namely the upgrading zone 40 and the
recovery zone 42. The upgrading zone is generally the interwell zone 50
through which
the injected fluids flow. It is generally maintained at around 350 C by the
heat of the
upgrading reaction.
[0087] Above the upgrading zone is the recovery zone. As shown in Figure 3,
heat from
the upgrading zone 40 is transferred by conduction and warms surrounding
bitumen,
reducing its viscosity. Very hot hydrocarbon vapors, produced by the upgrading
reaction,
and augmented by diluent and distillate recycling from the surface if needed,
rise into the
recovery zone, transferring additional heat by convection. The hot hydrocarbon
vapors
dissolve into the formation bitumen and further reduce the viscosity of the
formation
bitumen. Gravity drainage, supported by the displacement of rising gases 52,
including
hydrogen, hydrocarbon vapors, water vapor, and other gases, mobilizes and
recovers
bitumen 54 through the recovery well, This process results in the upgrading of
bitumen
produced by adjacent well pairs as well as recovery and upgrading of bitumen
from the
upgrading well pair. In the upgrading well pair, preferably no steam is
injected but
hydrogen can be. Hence, bitumen is recovered through vapor extraction, gravity
- 18-
CA 02810022 2013-03-19
drainage and gas displacement along with a much lower contribution to recovery
(with
respect to SAGD) of steam from connate water.
Start Up
[0088] To start the RAISUP or RAISCUP processes, in one embodiment two
horizontal
wells are drilled, vertically spaced approximately 5 m apart, with the length
of the
horizontal section subject to optimization. A longer length will generally
increase the
daily rate of bitumen and residue upgrading. At a temperature of 350 C, up to
1000
barrels (-160 m3) per day per 100 m of well length comprising 50% bitumen and
50%
residue can be injected. For example, 5000 barrels per day of bitumen could
flow
through a 1000 m long upgrading well pair, providing enough capacity to
upgrade
bitumen produced by 3 to 4 adjacent SAGD well pairs each producing 500 to 1000
barrels per day, as well as recycled residue fraction.
[0089] As noted, the wells are optionally/preferably preheated by the
recirculation of
steam or hot oil inside the wells. As is known, during steam pre-heating it
will typically
take approximately 4 months to establish hot fluids communication between the
wells
wherein the interwell region 50 should reach a temperature of approximately
160 C.
Alternatively to steam injection as noted above, a low viscosity oil (vacuum
gas oil, VGO)
at about 300 C can be recirculated inside the wells to establish hot fluids
communication
between the wells wherein the interwell region 50 should reach a temperature
of
approximately 160 C. As noted above, this procedure can eliminate the use of
steam
and water treatment needs, however It requires a certain storage capacity for
startup
VGO. That is, a volume higher than the volume of the well bores being heated
would be
required depending on the use (or not) of VGO for the next phase.
[0090] After the preheat phase, low viscosity oil at 350 C (i.e. atmospheric
residue or
VGO used during preheating) is injected and circulated using the top well for
injection,
and the bottom well for recovery. The injected oil is saturated with hydrogen
and nano-
catalysts to protect it from coking. When the temperature of the interwell
region reaches
approximately 250 C, bitumen is injected in place of low viscosity oil. The
purpose of this
phase is to heat the interwell zone to the desired upgrading temperature of
350 C.
[0091] At the same time, the volume of hydrogen in the injection fluid is
gradually
increased until excess hydrogen conditions required for effective upgrading
are reached,
- 19-
CA 02810022 2013-03-19
,
increasing the fractional volume occupied by gas in the well pair and in the
interwell pore
space.
[0092] The injection pressure is typically limited to the range 2,000-3500 kPa
(-300-500
psi) to remain below formation fracture pressure and ensure gas containment
for most
oil sands reservoirs. Obviously for deeper reservoirs the injection pressure
to be used
needs to be higher and this would further increase the efficiency of the in
situ upgrading
process of the invention.
Steady State Operations
[0093] Once an intentiell temperature of 350 C is reached, injection of
bitumen and
vacuum residue with hydrogen and hydrocracking catalysts commences.
[0094] Surface hydrocracking catalysts generally operate at high residue
conversion
rates, as high as 90%, and consume 200-250 standard m3 of hydrogen per m3 of
residue, with inlet hydrogen concentrations at an excess of approximately 3
times the
consumption rate (-650 standard m3 of hydrogen per m3 of residue). The
upgrading
conditions outlined are for a 50% residue conversion, requiring hydrogen
consumption of
only 40-60 standard m3 of hydrogen per m3 of residue. Injected hydrogen is
also
estimated at 3 times the consumption rate, or 150 standard m3 of hydrogen per
m3 of
bitumen. Hydrogen injection in the process of the invention can be injected
all at once
with the catalyst containing residue, or split into two fractions wherein
typically about 1/3
of the total injected with the residue and 2/3 bubbling from a liner that
would be attached
at the top of the producing well in order to enrich the upgrading zone with
bubbling
hydrogen.
[0095] Ideally, hydrogen partial pressure is maintained higher than 2,500 kPa
(360 psi)
for effective reaction kinetics. The excess hydrogen conditions described
above will
ensure sufficient hydrogen partial pressure in the injection well, the
upgrading zone and
the production fluids.
[0096] At injection conditions of 350 C and 3,450 kPa, gas volumes are reduced
by
approximately 15 times from standard conditions. In addition, 5 to 10% of the
injected
hydrogen volume is expected to dissolve in oil. Thus, assuming that the
mixture will flow
as a dispersion of gas in the oil (i.e. a bubbling regime) or in a mixed
bubbling-slug flow
regime, then the gas holdup fraction will be around the same as the flowing
fraction of
- 20 -
CA 02810022 2013-03-19
oil. Therefore, the fractional volume occupied by gas in the injection well
will be 50% or
lower.
[0097] In the upgrading zone, approximately one third of injected hydrogen is
consumed. Other gases are produced by various mechanisms (particularly:
methane, oil
vapors, steam from connate water and hydrogen sulphide). Therefore, the
fractional gas
volume can be expected to increase through the upgrading zone. The fractional
gas
volume in the interwell upgrading zone will be higher than 25%.
[0098] The gas to liquids ratio in the production well is also expected to be
similar to the
conditions in the injection well.
[0099] The shape of the upgrading and recovery chamber 12 is expected to be a
more
elliptical shape than a conic shape as in SAGD processes. Given that vertical
permeability is generally only 0.2 to 0.5 of horizontal permeability within
the formation,
the lateral dimension of the interwell upgrading zone will normally be greater
than the
vertical interwell distance. Factors governing the growth rate and shape of
the chamber
can be assessed by numerical and physical modeling.
[00100] Residence time in the well bores will typically be approximately 1
hour
each, but will depend on the flow rate of injected bitumen. However, in the
interwell
region residence time will depend on factors such as:
a. Porosity (typically about 30%)
b. Fractional liquids volume (typically about 75%)
c. Lateral movement of injected liquids (typically about 5 to 10 m in each
direction); and
d. Flow rate of injected bitumen and atmospheric residue.
[00101] Residence time in the interwell reaction zone will be approximately
50 to
500 hours (typical), matching or exceeding the requirements of the reaction
kinetics for
the current hydrocracking catalyst as in US Patent 7,897,537.
[00102] The injection rate is a constant volumetric rate but production is
generally
set to maintain constant pressure in the reaction chamber. Normally, the
liquids
- 21 -
CA 02810022 2013-03-19
4 ,
production rate will be higher than the injection rate because of oil volume
expansion
from hydrogen addition and incremental recovery from the upgrading formation.
[00103] Some upgrading will occur in the wells, but most will
occur in the
upgrading zone. Hydrogen addition upgrading is an exothermic process and can
typically increase the oil temperature by approximately 40 C in the reaction
zone. This
exothermic process more than compensates for local heat losses and maintains
the
upgrading zone at upgrading temperatures. The heat of hydrocracking reactions
ranges
from 42 to 50 kJ per mole of hydrogen and is also exothermic.
[00104] The upgrading zone at 350 C will, over time, heat by
conduction the
surrounding bitumen formation, reducing the viscosity of the surrounding
bitumen and
making the bitumen mobile. Some of the surrounding bitumen, particularly from
zones
above the chamber, will flow by gravity through the upgrading zone to the
production
well and will be replaced by rising hydrogen and produced gas. Therefore, the
recovery
zone will grow in size from incremental recovery.
[00106] Importantly, during catalytic upgrading processes, as a
result of increased
chamber temperatures and the upgrading reactions, a greater proportion of the
heaviest
molecules that would otherwise remain adhered to the formation sand during
recovery
by conventional methods such as a SAGD process will be mobilized for recovery.
[00106] Upgrading will generate light oil fractions that will
rise above the
upgrading zone with hydrogen and produced gas. These very hot hydrocarbon
vapors
will act as solvents and further reduce bitumen viscosity in addition to
causing thermal
effects. The amount of hydrocarbon vapors available may be augmented by
recycling
distillates from the column.
[00107] Incremental recovery and chamber growth will be driven
by vapor
extraction, gravity drainage, and gas displacement. Heat losses and
availability of
hydrocarbon vapors are two factors that will drive incremental recovery. A
typical
estimate of bitumen recovery from the upgrading formation is 50 barrels per
day per 100
m of well length as known to those skilled in the art.
[00108] Heat losses will be significantly less than typical SAGD
heat losses
because:
- 22-
CA 02810022 2013-03-19
4
a. latent heat of hydrocarbons is less than that of steam; in addition, most
of
the heat transfer Will be by conduction which is less effective than
convection;
b. the vapor chamber above the upgrading zone will have light gases (eg.
H2, CH4) and condensed water that form an insulation layer between the
upgrading zone and the overburden; and,
c. the vapor chamber size and surface area for heat transfer will be typically
less than in a comparable SAGD system.
[00109] Furthermore, gas in the production fluid will provide
gas lift, and no water
is injected and no typical SAGD chamber is formed. At the end of upgrading or
during
interrupted upgrading operations, bitumen in the upgrading well pair can be
recovered
by SAGD (if implemented) due to the presence of the horizontal well pair and
pad level
steam generation capacity (if implemented).
1001101 Alternatively, the location of the upgrading well pair
may be in a
neighboring thin bitumen zone that would not be otherwise utilized or
recovered.
Mass Balance Considerations
[00111] In considering the mass balance of the system based on
typical operating
conditions as described above, vacuum residue is injected and circulated
through the
interwell reaction zone at an oil rate of up to 10 times faster than the flow
rate of steam
of a typical SAGD process. However, the absence of condensed steam means that
the
liquids rate is only 2.5 times SAGD.
[00112] Hydrogen injected at three times excess over consumption
requirements
ensures sufficient hydrogen partial pressure (2600 kPa) for effective reaction
kinetics.
Hydrogen incorporation gradually reduces hydrogen concentration and volume by
up to
one third. Excess hydrogen conditions and production of other gases offset
hydrogen
consumption and maintain fractional gas volume at approximately 90%.
[00113] Injected catalyst flows with the injected oil. Some
catalyst particles will be
deposited on sand in the upgrading zone while some exit with produced fluids.
- 23 -
CA 02810022 2013-03-19
[00114] Bitumen made mobile by vapor extraction, heat losses and gas
displacement flows downward under the effect of gravity. Hydrogen, light
hydrocarbon
vapors and other gases (CH4, H2S and steam from connate water) rise into the
recovery
zone.
[00115] Liquids production is composed of upgraded bitumen and atmospheric
residue, swelled by hydrogen addition and recovered bitumen. Therefore,
liquids
production is greater than liquids injection.
Energy Balance Considerations
[00116] For surface processing, thermal energy is required to heat bitumen
to
320 C, operate the distillation column and deliver residue at 320 C (Figure
5). Heat
exchangers are deployed to maximize energy efficiency by cooling hot fluids
(i.e.
upgraded oil being sent to the market) with cold fluids (i.e. incoming
bitumen). Further
surface energy requirements include:
a. energy to operate the recycled gas compressor and to re-establish
pressure and flow in the recycled gas;
b. energy for hydrogen production and gas treatment;
c. energy to compress make up hydrogen to injection pressure if required;
and,
d. heat losses in the injection well.
[00117] The thermal energy supply includes bitumen and atmospheric residue
at
300 C being circulated through the upgrading zone. A fraction of the thermal
energy
contained in the circulating fluid is lost due to formation by conduction and
convection
(vaporization of light oil fractions). These heat losses heat surrounding
bitumen and
drive incremental bitumen recovery. Furthermore, upgrading reactions in the
reaction
zone generate thermal energy that offset heat losses and maintain the reaction
zone at
the desired temperature of 280-320 C.
[00118] In situ thermal energy requirements include maintenance of the
upgrading
zone at 280-320 C; vaporization of light oil fractions; heating of porous
media and
-24 -
CA 02810022 2013-03-19
bitumen for mobilization; heating of recovered bitumen to the upgrading
temperature;
and vaporization of connate water.
Temperature Distribution Considerations
[00119] Figure 4 shows the temperature distribution considerations for the
RAISUP and RAISCUP processes. The surrounding formation 56 has a temperature
gradient ranging from 10 C closest to the surface to bitumen mobilization
temperature
(-100 C) near the recovery zone. The recovery zone 42 ranges in temperatures
from
bitumen mobilization temperature to 300 C. The upgrading zone 40 is typically
maintained at a temperature between 280 C and 320 C. Exotherrnic reactions
generate
thermal energy and the temperature increases from the heat of the reaction.
The
temperature is decreased by the flow of colder bitumen from the recovery zone.
[00120] The inlet temperature of the injection well 16 is that of the
injected fluids,
i.e. approximately 300 C. The outlet temperature of the recovery well 18 is
that of the
produced fluids, i.e. approximately 280 C.
Surface Process and Facilities
[00121] Figure 5 is a schematic diagram of the layout of potential surface
facilities
in accordance with the invention. As shown, two well pairs are included with a
layout as
described by Figure 2A. That is a first well pair 13a is a typical SAGD well
pair that is
subjected to standard steam injection by steam plant 60. A second well pair
13b is
subjected to the RAISCUP process. Fluids recovered from the first well pair
can be
combined with the fluids from the second well pair.
[00122] Most of the gas stream from the production well, predominantly
excess
hydrogen, is recirculated 32 with a purge gas stream 60 sent to gas treatment
62. The
purge gas stream 60 is used to control the concentration of produced gas
components
(i.e. C1-C4 gases, H2S, CO-0O2) in the recycled gas. Water may need to be
removed
prior to recompression.
[00123] Liquids are sent to the distillation column 20. Upgraded oil 34,
with higher
than 20 API is sent to the market 34a. Diluent 34b, 64 may be added to the
upgraded
oil.
- 25 -
CA 02810022 2013-03-19
[00124] Alternatively, or in addition, distillates/diluent stream 64 can be
recovered
separately and recycled to the upgrading well pair in order to increase the
amount of
hydrocarbon vapors available for vapor extraction and control the extent of
bitumen
recovery. In addition, distillates/diluent may be recovered for sales 64a.
[00125] The distillation column 20 produces residue 26 that was unconverted
in
the upgrading chamber together with recovered catalyst that was not retained
within the
upgrading chamber. This residue 26 is recycled to the upgrading well pair
through
residue conditioning 26a.
[00126] Bitumen 22, from adjacent SAGD well pairs 13a is mixed with residue
26
with hydrogen 28 and catalyst 30. The combined stream is added to recycled gas
32,
and injected into the upgrading well pair 13b.
[00127] A heat exchanger may be used to pre-heat the incoming bitumen 22
and
diluent 24 with the upgraded oil 34 being sent to the market.
[00128] A recycle gas compressor 68 is required to re-establish appropriate
pressure and flow rates in the recycled gas. A compressor 28a for makeup
hydrogen
may also be required.
Process Control Elements and Improvements
Rate of Bitumen Injection
[00129] The rate of bitumen injection determines the volume upgraded but
also
the rate of thermal energy addition to the formation. Thermal energy comes
from heat
losses incurred by bitumen-residue injected at 350 C, but also by heat
generated in situ
by hydrocracking reactions. This variable also determines the rate of light
oil fractions
available for solvent extraction. Therefore, this variable controls:
a. the production rate of upgraded oil;
b. the rate of incremental recovery; and
c. the growth rate of the reaction chamber.
- 26 -
CA 02810022 2013-03-19
Location of Injection and Production
[00130] The start-up configuration is injection from the top well and
production
from the bottom well. However, this configuration can be reversed and cycled
to control:
a. temperature distribution in the reaction chamber;
b. catalyst distribution;
c. shape of the reaction chamber; and
d. the rate of incremental recovery.
Top Injection Well and Bottom Production Well
[00131] After start-up, the conventional configuration for a well pair is a
top
injection well and a bottom production well because this configuration
minimizes the
amount of pay zone that is below the production well. As is understood, pay
zone below
the production well is not recovered as the movement of oil and catalyst from
the
injection well to the production well follows the direction of gravity. Oil
vapors produced
in the interwell region are allowed to rise in the recovery zone.
Bottom Injection Well and Top Production Well
[00132] In an alternate embodiment, a bottom injection well and top
production
well configuration maximizes the temperature of the interwell reaction zone.
Formation
bitumen that is mobilized from zones above the chamber is at temperatures
lower than
350 C because mobilization starts at temperatures as low as 150 C. Excessive
incremental bitumen recovery may quench the temperature of the reaction zone.
With
the top well being the producer, recovered bitumen is produced immediately
when it
reaches the top producing well and does not cool the interwell region. The
temperature
of the interwell region may rise higher than the injection temperature because
of the heat
generated by the upgrading reactions, and a hotter interwell zone maximizes
upgrading.
Furthermore, hydrogen rises through the interwell reaction zone.
Hydrogen injection from a Tubing String inside the Bottom Production Well
[00133] Excess hydrogen conditions are specified to ensure that sufficient
hydrogen is present throughout the process. However, hydrogen is a very light
gas and
the amount that may flow down from the top injector to the bottom producer may
be less
than required. In this event, secondary hydrogen injection can be provided
through a
-27 -
CA 02810022 2013-03-19
tubing string inserted in the bottom producer, thereby replenishing hydrogen
supply in
the wellbore surrounding the bottom producer and inside the production well.
Electrical Heating
[00134] In a further embodiment, electrical or other heating technologies
may be
used to increase the amount of supplied thermal energy if this would result in
improved
performance.
Shutdown and Restart Strategies
[00135] Unplanned interruption of operations would likely cause liquids to
accumulate at the bottom of the vertical well where they could cool and
solidify in the
event of an extended interruption. Therefore, effective temperature
measurement and
control is desired throughout both injector and production wells. Prompt
injection of VG0
during an unplanned interruption of operation would likely avoid adverse
consequences
and also allows steam replacement as indicated above.
Modeling Results
[00136] Modeling results of the RAISUP and RA1SCUP processes show that at
350 C, upwards of 50% of the vacuum residue can be upgraded based on a
residence
time longer than 16 hours. The resulting recovered and upgraded oil has a
specific
gravity of 16 API or greater, with a viscosity lower than 200 cP (at 25 C).
Table 1 shows
mass balance data for a typical catalytic upgrading process with a residence
time of less
than 24 hours at 50% vacuum residue conversion, with hydrogen consumption of 9
Nm3/bbl and catalyst consumption of 0.10 tpd, excluding catalyst recovery.
Table 1- Mass Balance Data for Catalytic Upgrading Process (Modeled)
Characteristic Bitumen Product Upgraded Oil
Volume (bpd) 2625 2690
- API gravity 8 16
Viscosity at 40 C (cP) 20,000 225
Sulfur (w%) 5 3
Metal (ppm) 600 20
Asphalt (w%) 16 14
Microcarbon, (w%) 11 9
Total Acid Number (mg KOH/g) 5 <1
- 28 -
CA 02810022 2013-03-19
. ,
[00137] Table 2 shows modeled heat balance data for a catalytic
upgrading
process.
Table 2- Heat Balance Data for Catalytic Upgrading Process (Modeled)
Variable Vacuum Residue at Start Recovered Bitumen
Volume (bpd) 2500 1000
Volumetric Flow Rate (mrisi 0.0046 0.00184
Specific Heat Capacity @ 2346.2 1997.104
300 C (J/kg C)
Average Density (kg/m3) 1077.8 920
Temperature in ( C) 380 10
Temperature out ( C) 296.6 297.0
Rate of Heat Transfer (W) 970,192.1 -970,192
[00138] Table 3 shows heat balance data for a typical SAGO
process for
comparison.
Table 3-Heat Balance Data for a Typical SAGD Process
Variable Bitumen in Typical SAGD Process
Volume (bpd) 1000
Volumetric Flow Rate (m3/s) 0.00184
Specific Heat Capacity @ 300 C (J/kg C) 1997.1
Average Density (kg/m3) 920
Temperature in ( C) 10
Temperature out ( C) 162.1
Rate of Heat Transfer (W) -514,274
[00139] Table 4 shows recoverable heat from a modeled catalytic
upgrading
process.
Table 4-Recoverable Heat from Upgraded Oil in Catalytic Upgrading Process
(Modeled)
Variable Upgraded Oil
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CA 02810022 2013-03-19
Volume (bpd) 1000
Volumetric Flow Rate (m3/s) 0.00184
Specific Heat Capacity @ 300 C (J/kg C) 1500
Average Density (kg/m3) 750
Temperature in ( C) 297
Temperature out ( C) 40
Rate of Heat Transfer (W) 532,027.8
Deasphalted Oil Assisted In situ Catalytic Upgrading (DAISCU)
[00140] A variation of the RAISCUP process is a deasphalted oil assisted in
situ
catalytic upgrading process (DAISCU). In this embodiment, and with reference
to Figure
6 bitumen 22 recovered from the well pair 13 is subjected to deasphalting
processes to
create deasphalted oil (DAO) that is used as an upgradable heat carrier for
injection and
pitch wherein a portion of the pitch is used as a fuel (the fuel portion) and
another portion
(the non-fuel portion) of the pitch is re-mixed with DA0 for injection.
Generally, the
relative proportion of the fuel portion to the non-fuel portion is dependent
on the degree
of upgrading being achieved wherein the proportion will change as the
reservoir is
approaching the target temperature in the upgrading zone.
[00141] In DAISCU, initially during the creation of the upgrading chamber,
bitumen is mobilized and produced by steam in order to create an incipient
upgrading
chamber in a manner similar to the start-up of RAISUP. During this stage,
water is
separated and the produced bitumen is stored in a large tank 82 until enough
oil is
assured to start a solvent deasphalting operation (SDO) that will produce
deasphalted oil
(DAD) and pitch as well as a sufficient increase in the temperature of the DAD
to the
upgrading reaction temperature of -320 C.
[00142] More specifically, recovered fluids 81 (containing bitumen and
upgraded
oil) are introduced into a submicronizer system 80 for creating very small
particles of the
recovered bitumen. The recovered fluids are then pumped to the storage tank 82
having
a sufficient volume to collect and store recovered fluids for subsequent
processing. Gas
85 from the storage tank may be subject to gas treatment 62. Upon a suitable
volume of
recovered fluids having been collected, upgraded oil products 34 (from
distillation
column, not shown) are collected and delivered to market.
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CA 02810022 2013-03-19
[00143] Heavier fractions 84a, containing substantially heavier fractions,
will be
introduced into a solvent deasphalting unit 86, which by solvent addition
forms a
deasphalted oil fraction (DAD) 87 and heavier asphalt/pitch fractions 88a
(fuel fraction)
and 88b (non-fuel fraction) will depend on the relative progress of the
upgrading
chamber and upgrading reactions. The fuel portion 88a is delivered to furnace
90
wherein the fuel portion is burned together with recovered gases 62a from gas
treatment
62 to heat DAD 87 for injection into well 16.
[00144] The non-fuel portion 88b may be returned to micronizer 80 and
storage
system 84.
[00145] The heated DAD may be combined with hydrogen 28 and catalyst 30 as
described above at injection.
[00146] With reference to Figure 7, the upgrading zone is described in
relation to
DAISCU processes. The recovery chamber is similar to that of Figures 1, 2, 3
and 4. As
shown, both the upper and lower wells enable hydrogen injection and DAD is
injected
into the upper injection well. The upgrading zone can be generally described
as having
three regions. In the first region (a), hydrogen, catalysts and DAD are
injected at
reaction temperature. Generally, the injector well volume will determine a
residence time
in the order of 0.5 to 3 hours, such that a relative minor degree
(approximately 10%) of
upgrading will occur.
[00147] The second region (b) extends immediately below the injector well
and
towards the production well. In a mature well, a significant amount of bitumen
has
already been produced, thus the zone can be described as having a higher
degree of
injectivity in comparison to other zones insomuch as flow is enabled between
the injector
and production wells. As such, injected DA0 will predominantly flow downwardly
and be
upgraded to a significant extent due to the reaction conditions in this zone.
[00148] Bitumen in the region above the injector well flows downwardly as a
result
of dissolution and convective heat being transferred by volatile hydrocarbon
vapors and
gases produced during upgrading, by the hydrogen injected but also by
overheated
steam formed from connate water. All these gases tend to concentrate and
reflux at the
top of the chamber carrying heat and solvent capabilities to assist in
mobilizing bitumen
downwards towards the production well. Thus, bitumen from above the injector
well is
also upgraded with zone (b).
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CA 02810022 2013-03-19
[00149] Bitumen conductively heated by the DA0 adjacent the lateral walls
of the
interwell region is also mobilized and is significantly upgraded as it mixes
with the DAO
carrying catalysts near the production well and in contact with the hydrogen
flow
emanating from hydrogen liner(s) externally attached to the upper hemisphere
of the
production well.
[00150] The third region, zone (c), is located around the production well
and
provides additional volume and, hence residence time for completing upgrading
before
the produced oil reaches the surface or the temperature drops below the
reaction
temperature.
Nano-Catalytic In situ Upgrading (n-CISU)
[00151] In a further embodiment, and with reference to Figure 8, a nano-
catalytic
in situ upgrading (n-CISU) technology is described. The n-CISU process can be
applied
to a simple well configuration using huff and puff extraction. In this
embodiment, a
vertical well 13c can be utilized in which hot fluids (i.e. including produced
oil) together
with other additives including hydrogen 28 and catalyst 30 are pumped into the
well.
After injection, the well is sealed and pressurized for a soak time to allow
in-situ
upgrading to occur. After a sufficient soak time, the pressure is released and
fluids
including upgraded oil 80 is pumped from the well. The cycle can be repeated
as long as
the well is productive.
[00152] In greater detail, the start-up and production phases may be
achieved in
the following representative description. Initially, steam 60 is used to
preheat the
reservoir zone around a vertical well 13 in accordance with normal huff and
puff
procedures. During this phase, preliminary quantities of oil/bitumen 80 will
be produced
from the well and stored in a heated tank 62 (1-80-140 C) for later use. Once
enough
injectivity has been created (if initially non-existent), the stored oil 62a
would be used for
two purposes, first to disperse nano-catalysts 30 (at an approximate
concentration of
600 ppm) in that oil and second to convey heat to the reservoir at a typical
injection
temperature 270-290 C. Catalyst is injected once in the first injection cycle
and in a
small quantity. Any additional catalyst can be introduced during successive
cycles to
maintain catalyst concentration at a desired level. Hydrogen 28 is co-injected
with the
down-going oil (H2/bitumen ratio 90 sma/bitumen or oil ma).
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CA 02810022 2013-03-19
[00153] The injected material is introduced at a pressure slightly above
the
reservoir pressure. Once sufficient hot oil has been injected (typically about
90% of the
oil initially produced and stored during 10-15 days of initial production), a
closed well
period (soaking time) between 10 to 15 days is maintained. During the soak
time, both
the injected oil and the oil being recovered is upgraded.
[00154] During soaking, the pressure and gas composition of the well is
monitored to ensure that favorable upgrading conditions are being maintained.
Additional hydrogen may be added during the soak time as may be required to
maintain
reservoir pressure and to promote favorable reaction kinetics.
[00155] Hydrogen is typically consumed at a ratio of 15 sm3 per barrel of
oil
injected and produced. 45 sm3 of hydrogen per barrel of heated oil/bitumen
injected may
be consumed as a maximum, assuming oil productivity is doubled with respect to
a
standard huff and puff dry operation (highest expectation). Thus approximately
25 to
50% of the hydrogen injected would be consumed.
[00156] After the soak period, recovered fluids will be subjected to
distillation in
distillation column 20 to effect separation of upgraded oil for market 34 and
recovery of
gas components 85. As in previous embodiments, high viscosity components,
including
residue, may be re-injected into the well as the cycles are repeated.
[00157] The same general methodology can be applied to each of the well
configurations as shown in Figure 2B.
Other
Comparison to SAGD
[00158] The methods and apparatus in accordance with the invention can
provide
significant advantages over SAGD in terms of overall energy balance. As known,
in a
SAGD operation, heat is injected into the formation in the form of steam and
Is generally
recovered as warm water. As such, at surface, water is heated utilizing
significant
amounts of fossil fuel energy to create the necessary volumes, pressures and
temperature of steam for dovmhole injection. Specifically, the amount of
energy required
to heat water to steam requires the energy of the heat of vaporization of
water to create
steam. While the energy of the heat of vaporization of water is input into the
reservoir as
the steam condenses to water, the water returns to surface as a contaminated
water/mineral/hydrocarbon stream that requires significant treatment prior to
being
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CA 02810022 2013-03-19
reheated to steam. Specifically, the mineral contaminants must be removed to
prevent
scaling in the steam generation equipment, and the hydrocarbon must be
separated
from the water.
[00159] As is understood, the energy cost of removing mineral/hydrocarbon
contaminants from water has an associated energy requirement that is
significantly
reduced with the subject technology as the volume of water recovered from the
formation will be significantly less as generally the only water present in
the system will
be connate water. After hydrocarbon separation, no additional water treatment
may be
required.
[00160] As such, the environmental impact of the subject technology is
significantly lower as significantly lower volumes of water are required for
the process.
The elimination of settling ponds could be achieved.
[00161] Furthermore, as the in situ upgrading reactions are exothermic
reactions,
the requirement for heat input at surface is reduced.
Carbonate Formations and Enhanced Oil Recovery in Conventional Reservoirs
[00162] The technology may also be applied to other formations beyond heavy
oil
reservoirs including conventional reservoirs that may be declining in
production, deeper
reservoirs than oil sands which are relatively shallow, and carbonate
formations. In
particular, as compared to SAGD which can generally only be applied to
relatively
shallow type reservoirs, the subject methodologies can be applied to other
formations as
an enhanced oil recovery technique.
[00163] The additional oil recoverable with the hot fluid injection method
may be
to 30% higher than the one recovered via steam stimulation, which are
significantly
higher recovery rates than from steam injection technologies. Moreover, the
oil produced
with the subject technologies can reach transportable level (.1. <280 cPoises
@ 25 C) for
bitumen embedded sands, with minimal to no reduction in permeability of the
reservoir
and with at least similar recovery of oil.
[00164] As a result, the technologies can lead to the elimination of
upgrading
facilities to enable transportation and/or diluent needs.
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CA 02810022 2013-03-19
[00165] Although the
present invention has been described and illustrated with
respect to preferred embodiments and preferred uses thereof, it is not to be
so limited
since modifications and changes can be made therein which are within the full,
intended
scope of the invention as understood by those skilled in the art.
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