Note: Descriptions are shown in the official language in which they were submitted.
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HEAVY HYDROCARBON RECOVERY AND UPGRADING VIA MULTI-
COMPONENT FLUID INJECTION
FIELD OF THE INVENTION
[0001] The invention relates to systems, apparatus and methods for mobilizing
heavy
hydrocarbons within a reservoir, oil recovery and/or in-situ (in reservoir)
upgrading of
heavy oil and oil sand bitumens.
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,
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
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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 primarily from the cost of building
and
running a steam plant. In addition, as large amounts of water are required for
SAGD.
[0005] Thus, while SAGD processes are effective for heavy hydrocarbon
recovery, 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 improve the efficiency and particularly the environmental
impact of
heavy oil production from heavy oil reservoirs.
Vertical Injection/Recovery Wells
[0006] 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 more 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
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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 effective in promoting upgrading within the reservoir.
[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.
[0012] However, 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. As a result, catalytic upgrading
reactions generally
require higher temperatures and pressures to be effective.
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
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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
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
at temperatures
generally less than about 200 C. The hot fluids may include paraffins and
asphaltenes.
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[0019] US 2015/0114636 discloses using 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.
[0020] 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.
[0021] 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
[0022] In accordance with the invention, there is provided systems and methods
for
shaping a downhole mobilization chamber within a hydrocarbon formation.
[0023] In a first aspect, there is disclosed a method for recovery and in situ
upgrading of
hydrocarbons in a well having an injection well within a heavy hydrocarbon
reservoir, the
method comprising the steps of:
a. introducing a selected quantity of a hot injection fluid including a
heavy
hydrocarbon fraction and a steam fraction into the injection well to enable:
hydrocarbon recovery; and shaping of a downhole mobilization chamber; and
b. recovering hydrocarbons from the heavy hydrocarbon reservoir.
[0024] The mobilization chamber may be considered to be the downhole region
within
the reservoir which is mobile (e.g. by being in a liquid phase). For example,
a
mobilization chamber may be formed by melting solid heavy hydrocarbons. The
mobilization chamber may be a reaction chamber in which upgrading reactions
occur.
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[0025] The method of claim 1, wherein steam and heavy hydrocarbons are co-
injected
into the reservoir over a period of one or more of: less than 3 months;
between three
months and 6 months; between 6 months and 1 year; between 1 year and 2 years;
between 2 years and 5 years; between 5 years and 10 years; and over 10 years.
These
time periods may be continuous and/or cumulative (e.g. two separate 3-month
periods of
co-injection split by a period of pure steam injection may be considered to be
a
cumulative 6-month period of co-injection).
[0026] The ratio of steam to combined steam and heavy hydrocarbon may be
between
0.005 - 0.1 by mass.
[0027] The heavy hydrocarbon reservoir may include a recovery well. The
introduction
of the hot injection fluid in step a) may take place after connection between
the injector
well and the recovery well and formation of the downhole mobilization chamber.
[0028] The composition of the hot fluid injected may vary with time.
[0029] During step a) steam and hydrocarbons may be introduced sequentially.
[0030] Steam and hydrocarbons may be alternately introduced over multiple
cycles. A
cycle may be a time-dependent variation in the hot fluids injected which may
be
repeated to form multiple cycles. A cycle may comprise a period in which steam
is
injected without heavy hydrocarbons followed by a period in which heavy
hydrocarbons
are injected without steam. Another cycle may comprise a period in which steam
is
injected without heavy hydrocarbons followed by a period in which steam is
injected in
conjunction with heavy hydrocarbons.
[0031] Steam and hydrocarbons may be introduced simultaneously.
[0032] The injection fluid may include diluent. The injection fluid may
include hydrogen.
The injection fluid may include catalyst, the catalyst being configured to
promote
upgrading reactions.
[0033] The temperature and pressure of the injection fluid may be controlled
to promote
thermal cracking upgrading reactions.
[0034] The injection well and recovery well may be a horizontal well pair.
[0035] Prior to step a), steam may be injected into the horizontal well pair
to initiate
connection between the injector well and the recovery well and formation of a
downhole
mobilization chamber.
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[0036] The well may have an injection well and a recovery well forming a
horizontal well
pair.
[0037] The method may include the step of subjecting the hydrocarbons
recovered from
the recovery well to a separation process wherein heavy and light fractions
are
separated and wherein the heavy fraction includes a residue fraction.
[0038] The heavy hydrocarbon fraction may be selected from any one of or a
combination of shale oil, bitumen, atmospheric residue, vacuum residue, or
deasphalted
oil.
[0039] The hydrocarbons recovered from the recovery well may be subjected to a
separation process wherein heavy and light fractions are separated and wherein
the
heavy fraction includes a residue fraction.
[0040] The residue fraction from the separation process may be mixed with the
injection
fluid prior to introduction into the injection well.
[0041] The method may comprise 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.
[0042] The injection fluid may include diluent.
[0043] The temperature and pressure of the injection fluids may be controlled
to
promote thermal cracking upgrading reactions.
[0044] The temperature of the injection fluid may be controlled to provide a
downhole
sump temperature of 320 20 C and/or the downhole residence time of injected
fluids is
24-2400 hours.
[0045] The temperature and/or pressure of the injection fluids may be
controlled such
that greater than 30% of residual heavy hydrocarbon of the recovered bitumen
is
upgraded into lighter fractions.
[0046] The temperature and pressure of the injection fluids may be controlled
such the
recovered hydrocarbons have a viscosity less than 500 cP at 25 C.
[0047] The recovered hydrocarbons may have a viscosity less than 250 cP at 25
C.
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[0048] Prior to step a), steam may be injected into the horizontal well pair
to initiate
connection between the injector well and the recovery well and formation of a
downhole
mobilization chamber.
[0049] Prior to step a) the steam may be progressively partially 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.
[0050] The method may include the step of mixing a catalyst into the injection
fluid prior
to introducing the injection fluid into the injection well.
[0051] The method may comprise the step of mixing hydrogen into the injection
fluid
prior to introducing the injection fluid into the injection well.
[0052] The temperatures and pressures of the injection fluid may be controlled
to
promote any one of or a combination of hydrotreating, hydrocracking or steam-
cracking
reactions.
[0053] The hydrogen may be mixed with the injection fluid to provide excess
hydrogen
for the upgrading, hydrotreating and/or hydrocracking reactions.
[0054] The hydrogen may be injected along the length of the injection well.
[0055] Approximately 1/3 of the hydrogen may be mixed with the injection fluid
at
surface and approximately 2/3 may be injected to the reservoir along the
horizontal
length of the recovery well.
[0066] Hydrogen may be injected from the recovery well via at least one liner
operatively
configured to the recovery well.
[0057] The catalyst may be any one of or a combination of nano-catalysts or
ultradispersed catalyst. The catalyst may comprise micronic particles (e.g.
particles with
one dimension around 1 micron). The catalyst may have particles with
dimensions less
than 1 micron and/or less than 120 nm. A nano-catalyst may be considered to
comprise
catalyst particles which have one dimension less than or equal to 100nm. A
nano-
catalyst may be considered to comprise solid catalyst particles of which at
least 50% by
number have one dimension which is less than or equal to 100nm. This can be
determined by looking at 050 or median values for the particle size
distribution.
[0058] A plurality of adjacent interconnecting well pairs may be configured to
a single
well pad wherein one of the interconnecting well pairs is an upgrading well
pair and
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wherein heavy hydrocarbon fluids recovered from each well is mixed with the
injection
fluid of the upgrading well pair.
[0069] The heavy hydrocarbon fluids may include any one of or a combination of
heavy
oil, shale oil, bitumen, atmospheric residue, vacuum residue, or deasphalted
oil
[0060] The injection well and recovery well may have vertically overlapping
horizontal
sections and the injection well is the lower of the injection well and the
recovery well.
[0061] The injection well and recovery well may have vertically overlapping
horizontal
sections and the injection well is the upper of the injection well and the
recovery well.
[0062] 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. The hot fluid may comprise heavy
hydrocarbons
and water/steam.
[0063] A portion of the heavy residual fraction from the separation may be
used as a
fuel to produce heat to heat the injection fluids for upgrading reactions.
[0064] The method may comprise the step of using a portion of the lighter
hydrocarbons
to additional separation processes for commercialization.
[0065] Step e) may include introducing a catalyst into the injection well to
promote
catalytic upgrading within the injection well and the hydrocarbon mobilization
chamber
and/or step e) may include introducing hydrogen into the injection well to
promote
upgrading reactions within the hydrocarbon mobilization chamber.
[0066] 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
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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 (e.g.
steam) for injection into the injection well.
[0067] The system further may comprise 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.
[0068] In yet a further 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 comprising heavy hydrocarbons
and
steam 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
and/or pitch 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. Pitch
is the
most viscous and heaviest fraction and so may require more upgrading than the
deasphalted portion. However, the deasphalted portion may be more reactive in
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upgrading reactions. Pitch may comprise 10-20% of raw hydrocarbon or 30% of
the
vacuum residue portion.
[0069] Asphaltic pitch may be used as a fuel to produce heat to heat the
injection fluids
for upgrading reactions.
[0070] The method may comprise the step of using a portion of the lighter
hydrocarbons
to additional separation processes for commercialization.
[0071] The invention may provide 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 (e.g. including steam) for injection into the
injection well.
[0072] 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 and steam 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.
[0073] Catalyst and/or hydrogen may be introduced into the well.
[0074] 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 steam and 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
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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
[0076] 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;
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;
Figure 8 is a schematic diagram of another embodiment of the invention using a
huff and puff methodology;
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Figure 9 is a graph showing simulations results of cumulative oil recovery
over
time for different regimes; and,
Figures 10a-d are simulation results showing the simulated downhole
temperature distribution for different regimes.
DETAILED DESCRIPTION OF THE INVENTION
Overview
[0076] The systems, apparatus and methods relate to the recovery of heavy oil
in a
production well by introducing a hot multi-component fluid into the production
well to
control the shape of the mobilization chamber. The multi-component fluid
includes a
heavy hydrocarbon component (e.g. a vacuum or atmospheric residue fraction or
deasphalted oil) and a steam component.
[0077] It will be appreciated that, gaseous steam will tend to carry heat
towards the top
of the mobile reservoir whilst the liquid heavy hydrocarbon component will
carry heat
laterally from the bottom of the mobile reservoir. The combination of steam
and heavy
hydrocarbons may therefore grow the mobile reservoir more evenly at the top
and
bottom of the mobile reservoir thereby expanding the mobile reservoir in all
dimensions.
[0078] 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.
[0079] 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
comprising heavy oil and steam. 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
steam and hot
residue or deasphalted oil to promote in situ upgrading and recovery of the
heavy oils
and bitumen. Pitch is the most viscous and heaviest fraction and so may
require more
upgrading than the deasphalted portion. However, the deasphalted portion may
be more
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reactive in upgrading reactions. Pitch may comprise 10-20% of raw hydrocarbon
or 30%
of the vacuum residue portion.
[0080] 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.
[0081] A residue fraction is the fraction that distills at temperatures higher
than 540 C. A
deasphalted oil (DAO) fraction is a crude fraction produced in a deasphalting
unit (DAU)
that separates asphalt from bitumen.
Residue Assisted In situ Upgrading (RAISUP)
[0082] 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 and/or steam are 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
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).
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[0083] 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, steam and/or other hot fluids. The ratio of
steam to
combined steam and heavy hydrocarbon in this case is approximately 0.05 (5%)
by
mass. The hot fluids comprising heavy hydrocarbons and steam may be
continuously
injected for several years following formation of the mobile chamber between
the
injection and recovery wells.
[0084] As noted above, the steam component (e.g. 5% by mass of the hot fluid)
causes
heat to be transferred to the top of the mobile chamber. This encourages the
chamber to
grow upwards and outwards from the top. In contrast, the more viscous heavy
hydrocarbon component causes the mobile chamber to grow downwards and
laterally
outwards from the bottom. The combination of these effects means that the
mobile
reservoir grows more evenly top to bottom. It will be appreciated that the
water and
hydrocarbon components of the hot fluid may be injected sequentially (e.g. in
repeated
cycles of steam and hydrocarbon) or concurrently.
[0085] In addition, 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.
[0086] 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.
[0087] 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. Under injection conditions, the
heat capacity
of the injected hot residue is comparable with that of steam (e.g. under
certain
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conditions, the heat capacity of hot residue may be 90% that of steam under
equivalent
conditions).
[0088] 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.
[0089] In embodiments described herein, the combination of low-density gaseous
steam
and higher-density liquid oil may help to shape the mobile chamber by more
evenly
expanding the chamber laterally away from the injection point. This may
improve rates of
oil recovery.
[0090] 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
(e.g. thermal cracking), as well as decreasing the viscosity of the bitumen to
improve the
overall mobility of the bitumen in the reservoir.
[0091] 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.
[0092] 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
purely steam injection. Accordingly, injecting hot residue can reduce the
injection of
water into the reservoir, such that the main source of water in the reservoir
will be
connate water. As a result, water treatment and/or water disposal costs may be
reduced.
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[0093] During start-up, steam (e.g. with no heavy oil portion) 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 and partially 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 or supplemented by
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 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.
[0094] 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.
Residue Assisted In-situ Catalytic Upgrading (RAISCUP) Process
[0096] 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.
[0096] 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.
[0097] 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
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well pairs (50 b, c, d) may be upgraded in well pair 50a in which all the
bitumen
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.
[0098] 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.
[0099] 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.
[0100] During steady-state operation, incoming bitumen 20e and diluent 20f
will be
blended with hot residue 20a along with steam and 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.
[0101] 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.
[0102] 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
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separation. Lighter fraction oil products 20b are removed and residual
catalyst, residue
fraction separated from the vacuum/atmospheric residue to recover and recycle
the
catalyst particles, resulting in upgraded oil 32 with more than 200 API. The
recovered
fluids 44 are composed of excess hydrogen, upgraded 14-16 API oil,
unconverted
bitumen and atmospheric/vacuum residue, water (e.g. in the form of steam),
other
produced gases (CH4, H2S and H20 from connate water), and catalyst not
retained in the
upgrading zone.
[0103] 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.
[0104] 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 may come up to the
surface if
catalyst is not immobilized within the reservoir within a reactor zone
adjacent the
injection well. That is, it has been observed that in the case of
nanocatalysts that such
catalysts are immobilized adjacent the injection well within the reservoir
pores and,
hence, are not transported to the recovery well. If catalyst is returned to
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
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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.
[0105] 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 if
catalysts are recovered. As a 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.
[0106] 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:
CIO '1 0 0 + H2
equation 1
Upgrading and Recovery Chamber
[0107] 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.
[0108] 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. Steam and 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,
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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. Hence, bitumen is recovered through
vapor
extraction, gravity drainage and gas displacement along with a much lower
contribution
to recovery (with respect to SAGD) of steam from connate water.
Start Up
[0109] 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) of heavy hydrocarbon per day per 100 m of well length may be
injected. In addition, a steam component (e.g. around 1-10% of total injected
mass) may
be injected with the heavy hydrocarbon portion. The heavy hydrocarbon portion
may
comprise 50% bitumen and 50% residue. 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.
[0110] 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 reduce the use of
steam and
water treatment needs compared to SAGD operations, 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.
[0111] After the preheat phase, low viscosity oil at approximately 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
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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 approximately 350 C.
[0112] 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,
increasing the fractional volume occupied by gas in the well pair and in the
interwell pore
space.
[0113] 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
[0114] Once an interwell temperature of approximately 350 C is reached,
injection of
bitumen and vacuum residue with steam, hydrogen and hydrocracking catalysts
commences.
[0115] 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.
[0116] Ideally, hydrogen partial pressure is maintained higher than 2,500 kPa
(360 psi)
for effective reaction kinetics. The excess hydrogen conditions described
above will
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ensure sufficient hydrogen partial pressure in the injection well, the
upgrading zone and
the production fluids.
[0117] 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
oil. Therefore, the fractional volume occupied by gas in the injection well
will be 50% or
lower.
[0118] 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%.
[0119] The gas to liquids ratio in the production well is also expected to be
similar to the
conditions in the injection well.
[0120] 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.
[0121] 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
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d. Flow rate of injected bitumen and atmospheric residue.
[0122] 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.
[0123] The injection rate is a constant volumetric rate but production is
generally set to
maintain constant pressure in the mobilization chamber. Normally, the liquids
production
rate will be higher than the injection rate because of oil volume expansion
from hydrogen
addition and incremental recovery from the upgrading formation.
[0124] 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
consumed hydrogen and is also exothermic.
[0125] 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.
[0126] 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.
[0127] 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.
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[0128] 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.
[0129] Heat losses will be significantly less than typical SAGD heat losses
because:
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 (e.g.
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.
[0130] Furthermore, gas in the production fluid will provide gas lift, 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).
[0131] 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
[0132] 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.
[0133] 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.
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Excess hydrogen conditions and production of other gases offset hydrogen
consumption
and maintain fractional gas volume at approximately 90%.
[0134] 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.
[0135] 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.
[0136] 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
[0137] 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.
[0138] The thermal energy supply includes bitumen and atmospheric residue at
approximately 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
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the reaction zone generate thermal energy that offset heat losses and maintain
the
reaction zone at the desired temperature of 280-320 C.
[0139] 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
bitumen for
mobilization; heating of recovered bitumen to the upgrading temperature; and
vaporization of connate water.
Temperature Distribution Considerations
[0140] 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. Exothermic 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.
[0141] 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
[0142] 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.
[0143] 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.
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[0144] Liquids are sent to the distillation column 20. Upgraded oil 34, with
higher than
200 API is sent to the market 34a. Diluent 34b, 64 may be added to the
upgraded oil.
[0145] 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.
[0146] 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.
[0147] Bitumen 22, from adjacent SAGD well pairs 13a is mixed with water,
residue 26,
hydrogen 28 and catalyst 30 as appropriate. The combined stream is added to
recycled
gas 32, and injected into the upgrading well pair 13b.
[0148] 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.
[0149] 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
[0150] 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 mobilization chamber.
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[0151] 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 mobilization chamber;
b. catalyst distribution;
c. shape of the mobilization chamber; and
d. the rate of incremental recovery.
Top Injection Well and Bottom Production Well
[0152] 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
[0163] In other embodiments, 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
[0154] 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 tubing
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string inserted in the bottom producer, thereby replenishing hydrogen supply
in the
wellbore surrounding the bottom producer and inside the production well.
Electrical Heating
[0155] 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
[0156] 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 (no steam)
[0157] Modeling results of the RAISUP and RAISCUP 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 with no steam
(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, pC (w%) 11 9
Total Acid Number (mg KOH/g) 5 <1
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[0158] Table 2 shows modeled heat balance data for a catalytic upgrading
process.
Table 2- Heat Balance Data for Catalytic Upgrading Process with no steam
(Modeled)
Variable Vacuum Residue at Start Recovered Bitumen
Volume (bpd) 2500 1000
Volumetric Flow Rate (m3/s) 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
[0159] Table 3 shows heat balance data for a typical SAGD 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
[0160] Table 4 shows recoverable heat from a modeled catalytic upgrading
process.
Table 4-Recoverable Heat from Upgraded Oil in Catalytic Upgrading Process with
no
steam (Modeled)
Variable Upgraded Oil
Volume (bpd) 1000
Volumetric Flow Rate (m3/s) 0.00184
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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
Modeling Results (present disclosure with steam)
[0161] In general, simulations indicate that combining steam with heavy
hydrocarbon
. injection can increase the productivity of a well compared with purely SAGD
or recovery
using purely heavy oil injection. This may apply even to wells which have been
operating
for some time using purely SAGD or recovery using purely heavy oil injection.
That is,
converting to a multi-component injection strategy as described herein may
lead to an
increase in productivity.
[0162] Regarding the simulation results, the well was modelled as follows:
= Model size: 40x10x30 grid cells (1x50x1m)
= Top depth: 200 m
= Porosity: 0.33
= Horizontal Permeability: 3600 mD
= Vertical Permeability: 1800 mD
= PermK=0.5PermX (That is, the vertical Permeability is half that of the
horizontal
permeability)
= Reservoir pressure: 2000 kPa
= Reservoir temperature: 11 C
= Oil Saturation, So: 0.81, Water Saturation, Sw=0.19
[0163] Within the well, the well was modelled as having the following
composition:
Oil components Mole fraction
Gases 1.00098E-7
Naphtha 0.041644
Distillate 0.13114
Vacuum gas oil 0.32281
(VGO)
Vacuum Residue 0.5044
(VR)
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[0164] To account for the reactions which may take place within the well, the
following
kinetic model was used which comprises 14 reactions. Some of the reactions
related to
reactions of the hydrocarbons found within the well, and others related to
reactions of
the hydrocarbons introduced into the well.
[0165] Reactions modelled for the hydrocarbons already in the well consisted
of:
= VR + H2 4 VG0
= VR + H2 4 DISTILLATE
= VR + H2 4 NAPHTHA
= VR + H2 4 GASES
= VGO + H2 4 DISTILLATE
= VG0 + H2 4 NAPHTHA
= DISTILLATE + H2 4 NAPHTHA
[0166] Reactions modelled for injected oil consisted of:
= VR_INJ + H2 4 VGO_INJ
= VR_INJ + H2 4 DISTILLATE _INJ
= VRINJ + H2 4 NAPHTHA _INJ
= VR_INJ + H2 4 GASES_INJ
= VGO_INJ + H2 4 DISTILLATE _INJ
= VGO_INJ + H2 4 NAPHTHA _INJ
= DISTILLATE _INJ + H2 4 NAPHTHA _INJ
[0167] In addition, the simulation takes into account the nature of the
injection and
recovery wells by placing constraints on the performance and tolerances of the
wells.
[0168] The recovery well's constraints are as follows:
= Min BHP (Bottom Hole Pressure): 2200 kPa
= Max surface liquid rate: 400 m3/d
= Min steamtrap: 10 C
[0169] The steam trap (temperature) is the difference in temperature around
the
producer which is maintained in order to have a negligible loss of live steam.
That is, a
steam-trap control relates to making a steam process (e.g. SAGD, or other two-
well
steam arrangements) more thermally efficient by maintaining a liquid pool that
surrounds
the bottom production well and prevents escape of steam from the steam
chamber. In
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practice, the continued existence of the liquid pool is monitored by examining
the
temperature difference (also known as the interwell subcool) between the
injected steam
and produced fluids. Typically, the subcool is maintained between 20 and 40 C.
In this
model, the minimum steam trap is set at 10 C. It will be appreciated that
there may be a
critical steam trap subcool temperature below which the steam trap fails and
steam is
allowed to exit the producing well.
[0170] The injector's constraints are as follows:
= Max BHP: 2300 kPa
= Max water rate: 80 m3/d
= Injection temperature: 220 C
= Steam quality: 0.9 (In thermodynamics, vapor quality is the mass fraction
in a
saturated mixture that is vapor. Therefore, Steam quality: 0.9 means that 90 %
of the
water is gas.)
[0171] Using this model, a variety of hot-fluid injection regimes were
simulated. The
regimes are differentiated as follows:
= Case 1: SAGD ¨ injecting of steam. This simulation simulated the period
starting
on January 1, 2008 until the end of simulation (January 1, 2020).
= Case 2: Co-intection steam-catalyst. In particular, this simulation
involved:
o injecting steam (SAGD) for 15 months (starting on January 1, 2008) to
expand steam chamber until it reached the top of the formation;
o then injecting steam, heavy hydrocarbon and catalyst (volume fraction:
0.0495 steam + 0.00793 vacuum residue + 0.94257 H2) at 350 C until the
end of simulation (2020/1/1).
= Case 3: ISUP-only inject catalyst. In particular, this simulation
involved:
o injecting steam (SAGD) for 15 months (starting on January 1, 2008) to
expand steam chamber until it reached the top of the formation;
o then inject heavy hydrocarbon and catalyst (vol. fraction: 0.00793VR +
0.99207H2) until the end of simulation (January 1, 2020).
= Case 4: Alternate Co-Iniection steam-catalyst. In particular, this
simulation
involved:
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o injecting steam (SAGD) for 15 months (starting on January 1, 2008) to
expand steam chamber until it reached the top of the formation;
o then alternating 6 months of SAGD and 6 months of Co-injection steam
and heavy hydrocarbon and catalyst (using same heavy hydrocarbon fluid
as case 2) until the end of simulation (January 1, 2020).
= Case 5: Alternate Co-Injection steam-catalyst. In particular, this
simulation
involved:
o injecting steam (SAGD) for 15 months (starting on January 1, 2008) to
expand steam chamber until it reached the top of the formation;
o then alternating 12 months of SAGD and 12 months of Co-injection steam
and heavy hydrocarbon and catalyst (using same heavy
hydrocarbon/steam injection fluid as case 2) until the end of simulation
(January 1, 2020).
= Case 6: Alternate Co-Iniection steam-catalyst. In particular, this
simulation
involved:
o injecting steam (SAGD) for 15 months (starting on January 1, 2008) to
expand steam chamber until it reached the top of the formation;
o then alternating 24 months of SAGD and 24 months of Co-injection steam
and heavy hydrocarbon and catalyst (using same heavy
hydrocarbon/steam injection fluid as case 2) until the end of simulation
(January 1, 2020).
[0172] It will be appreciated that the first 15 months of each simulation is
the same: 15
months of SAGD injection.
[0173] The cumulative oil recovery over time for this well is shown in figure
9 for each of
the simulated regimes. As shown in this graph, the SAGD recovery (case 1, 901)
is the
lowest of the 6 regimes. The next lowest is SAGD initiation followed by pure
hydrocarbon injection (case 3, 903). The highest recovery is when the common
SAGD
initiation is followed by combined steam and heavy hydrocarbon injection (case
2, 902).
[0174] Intermediate between the pure hydrocarbon injection (case 3, 903) and
the multi-
component steam-hydrocarbon injection (case 2, 902) are the cycled regimes
(cases 4-
6, 904-906) in which periods of multi-component steam-hydrocarbon injection
are
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alternated with periods of conventional SAGD injection. As indicated in figure
9, the
periods of multi-component steam-hydrocarbon injection correspond to higher
production rates, whereas the periods of conventional SAGD injection
correspond to
slower production (mirroring that of conventional SAGD of case 1, 901).
[0175] To give an indication of the well shaped produced by these regimes, the
temperature profile of the reservoir is shown for four of the regimes in
figures 10a-d. In
each case, the recovery well is located adjacent to left of the profile, one
square up from
the bottom; and the injection well is located 5 squares directly above the
recovery well.
In this case, the model is for a horizontal well. In each case, the
temperature profile is
shown corresponding to June 1, 2012.
[0176] As shown in the profiles, the temperature in the purely SAGD case
(figure 10a)
rises vertically from the injection well and then is transmitted horizontally
when it
interacts with the overburden. This causes the cross section to have an upside-
down
pear shape (the full three-dimensional profile will be this profile reflected
in the vertical y-
axis and extended along the axis of the horizontal wells which is normal to
the plane of
the graphs).
[0177] In the other extreme, when only hydrocarbon is injected (after the
initial 15 month
SAGD phase), the temperature is more concentrated around the injection and
recovery
wells (as shown in figure 10c). This may be because of the higher density of
the heavy
hydrocarbon injection fluid with respect to the gaseous steam.
[0178] When both hydrocarbons and steam are injected, there is a much more
even
vertical distribution of temperature, and the high temperature region extends
further in
the horizontal direction. In this simulation, in case 4 as shown in figure
10d, the steam
appears to be still preferentially heating the top of the reservoir. In
contrast, in case 2 as
shown in figure 10b, there appears to be a smooth transition between reservoir-
top
heating and reservoir-bottom heating.
[0179] By allowing a more even vertical distribution of temperature and by
allowing the
temperature to extend farther horizontally, a larger proportion of the viscous
heavy
hydrocarbons may be mobilized and extracted from the recovery well.
[0180] Results of this study indicates that:
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= Multi-component, steam-hydrocarbon injection is a promising method for
improving oil recovery compared to conventional injection methods.
= The incremental oil production may arise from the superior effectiveness
in
decreasing the viscosity and mass density of heavy-oil.
= The co-steam injection plays an important role to achieve the better
performance.
= Multi-component, steam-hydrocarbon may increase oil recovery by 35.81%
and reduces the Steam-Oil Ratio (SOR) up to 50% in comparison with the
conventional steam injection.
= Simulation results also indicate that a combination of catalysts,
hydrogen, and
vacuum residue may help to improve the quality of the produced oil.
Deasphalted Oil Assisted In situ Catalytic Upgrading (DAISCU)
[0181] 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 DAO and steam 29 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.
[0182] 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 62 until enough oil is assured to
start a
solvent deasphalting operation (SDO) that will produce deasphalted oil (DAO)
and pitch
as well as a sufficient increase in the temperature of the DAO to the
upgrading reaction
temperature of ¨320 C.
[0183] 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
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recovered fluids having been collected, upgraded oil products 34 (from
distillation
column, not shown) are collected and delivered to market.
[0184] 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 (DAO) 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 DA0 87 for injection into well 16.
[0185] The non-fuel portion 88b may be returned to micronizer 80 and storage
system
84.
[0186] The heated DAC) may be combined with hydrogen 28 and catalyst 30 as
described above at injection.
[0187] 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 DA0 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, steam and DAC)
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.
[0188] The second region (b) extends 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. The steam component of the
injection fluid
may cause region (b) to extend upwards above the upper well due to the lower
density
of the steam component.
[0189] 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
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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).
[0190] 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 DA0
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.
[0191] 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)
[0192] 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 and
steam)
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.
[0193] 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 will be delivered to
micronizer 80
will be produced from the well and stored in a heated tank 62 (T-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
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successive cycles to maintain catalyst concentration at a desired level.
Hydrogen 28 is
co-injected with the down-going oil (H2/bitumen ratio 90 sm3/bitumen or oil
m3).
[0194] 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.
[0195] 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.
[0196] 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.
[0197] 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.
[0198] The same general methodology can be applied to each of the well
configurations
as shown in Figure 2B.
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Other
Typical Injection Regimes
[0199] Typical injection regimes are shown in the table below:
Parameters/SOR 0.53 0.88 1.13 1.65
H2NR Ratio 100 100 100 160
Water Fraction 0.00500 0.01797 0.03397 0.05509
Injection rate, Q (m3/d) 5,549 5,451 4,997 6,500
Water rate, Q,õ, (m3/d) 28 98 170 358
H2 rate, QH2 (1113/C) 5,466 5,300 4,779 6,103
VR rate, QvR (M3/C1) 55 53 48 39
Injection Temp, C 311 300 302 360
Production BHP, kPa 2,000 2,000 2,055 2,397
Production rate, (m3/d) 335 300 322 534
Steam quality 0.95 0.87 0.87 0.94
RF, % 34.38 46.28 81.17 92.11
Chamber Volume, m3 6,265 23,539 73,851 106,486
[0200] SOR is the Steam Oil Ratio (m3/m3).
[0201] In particular, these regimes were modelled optimize the steam oil ratio
(to
minimize steam use) whilst maximizing the oil recovery factor (RF%) in the
well
described above in the Modeling Results section.
[0202] The left-most data column provides the steam oil ratio but does not
maximize
recovery factor. The right-most data column gives the highest oil recovery
factor but
uses a higher Steam Oil Ratio. The intermediate data columns show intermediate
regimes. It will be appreciated that the user will optimize the regime based
on the
relative importance of water use and recovery factor.
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[0203] The table below shows corresponding values for SAGD optimization in the
same
well:
Parameters/SOR 2.70 3.04 3.12 3.20
Injection rate, Qw (m3/d) 160 359 442 467
Injection BHP, kPa 2,000 3,383 4,000 4,000
Injection Temp, C 170 210 240 240
Production BHP, kPa 2,000 2,265 2,332 2,249
Production rate, (m3/d) 335 300 302 333
Steam quality 0.95 0.95 0.95 0.95
RF, % 51.22 57.69 58.79 59.24
Chamber Volume, m3 80,852 93,736 96,709 97,214
Comparison to SAGD
[0204] 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.
[0205] As such, the environmental impact of the subject technology is
significantly lower
as significantly lower volumes of water are required for the process.
[0206] 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
[0207] 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.
[0208] The additional oil recoverable with the hot fluid injection method may
be 10 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
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WO 2018/161173
PCT/CA2018/050283
the subject technologies can reach transportable level (j2 < 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.
[0209] As a result, the technologies can lead to the elimination of upgrading
facilities to
enable transportation and/or diluent needs.
[0210] 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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