Note: Descriptions are shown in the official language in which they were submitted.
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IMPROVED IN-SITU COMBUSTION RECOVERY PROCESS USING SINGLE
HORIZONTAL WELL TO PRODUCE OIL AND COMBUSTION GASES TO
SURFACE
FIELD OF THE INVENTON
This invention relates to a process for recovering viscous hydrocarbons from a
subterranean reservoir using in-situ combustion, a vertical oxidizing gas
injection well,
and a separate horizontal well, and in particular to an improved process which
does not
employ separate additional gas venting wells.
BACKGROUND OF THE INVENTION
In situ combustion processes for producing oil from viscous underground
hydrocarbon
formations and various methods for separating hydrocarbons from subterranean
formations containing hydrocarbons are well known in the art.
By way of example, US Patent 3,502,372 (M. Prats) discloses a process wherein
shale oil
and soluble aluminum compounds are recovered from a rubbleized or fragmented
shale
oil formation by top-down burning of the shale oil. The removal of oil is
conducted to
clean the shale for subsequent solution mining of the aluminum in the shale
with alkaline
chemicals. The pyrolyzing agent can be a hot mixture of air and water but it
must be
injected at a temperature over 500 F and the temperature in the formation
must be
controlled to 600-950 F to prevent damage to the minerals. The present
invention, as
discussed in the Summary of the Invention and thereafter in the Detailed
Description
does not require rubbleization of the reservoir or utilize top-down burning.
Rather, an
established combustion front moves laterally along a horizontal well bore.
US Patent 3,515,212 (Allen et al) discloses an in situ combustion process
combining
forward and reverse in situ combustion between vertical wells. The region of
an injection
well is heated with steam to auto-ignition temperature and air is injected
from an offset
well and flows in the direction of the injection well. As the air enters the
heated zone oil
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zone near the injection well, ignition occurs. Combustion gas is withdrawn at
the ignition
well and the combustion front grows towards the offset well, in a reverse in
situ
combustion process. After the front approaches the offset well, air injection
is
undertaken at that well and the original injector is converted to an oil
producer, and a
forward in situ combustion process is initiated wherein the combustion front
moves
toward the original injection well, and is produced from the original
injection well.
US Patent 4,566,537 (Gussis) relates to the production of immobile oil, such
as the
Athabasca bitumen. The problem of communication between vertical wells is
overcome
by conducting a series of cyclic steam cycles to heat the oil near the
injector and create
voidage. In a second stage air is injected high in the reservoir at one of the
wells and
combustion gases are produced at the other well, establishing communication
between
the wells at the top of the reservoir. This now enables steam injection at the
base of one
well, with oil production at the other well. This process is different than
the process of the
present invention, which as discussed below, utilizes gravity drainage into a
horizontal
producer and does not requiring a steam drive stage. Further, continuous
removal of oil
and combustion gas occurs in the same well.
US Patent 4,410,042 (Shu) discloses a method of conducting the early stage of
in situ
combustion that utilizes pure oxygen. Until the combustion front reaches a
distance of 30
feet from the injector, the oxygen is diluted with carbon dioxide. Thereafter
pure oxygen
is injected. By way of contrast, as discussed in the Summary of the Invention
and the
detailed description, the process of the present invention does not employ
mixtures of
pure oxygen with carbon dioxide at any stage.
US Patent 4,418,751 (Emery) discloses an in situ combustion process wherein
water is
injected into the upper part of an oil reservoir separately from oxygen that
is injected near
the base. The water and combustion gases mix in the reservoir, vaporizing the
water and
scavenging heat. The present process does not require or employ the
simultaneous
injection of oxygen and water. In fact the injection of oxygen near the
horizontal well at
the base of the reservoir would be very dangerous since oxygen would enter the
wellbore
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and bum oil therein, causing high temperatures that would threaten the
integrity of the
wellbore and deposit coke that would partially plug the wellbore.
US Patent 4, 493,369 (Odeh et al) discloses essentially the same well and
fluid
arrangement as `751 with injection of oxidizing gas at the base of the
reservoir and water
at the top.
US Patent 5,456,315 discloses an in situ combustion process wherein an
oxidizing gas is
injected into vertical wells that are perforated in the upper part of an oil
reservoir. The
vertical wells are placed in a row directly above a horizontal well that is
situated at the
base of the reservoir. This orientation of wells is the same as the present
process.
However, `315 requires a row of horizontal/vertical gas vent wells that are
placed on
either side of and parallel to a horizontal producer, but each situated at the
top of the
reservoir. The purpose of the vent wells is to withdraw the combustion gasses
to the
surface separately from the liquids that drain by gravity into the horizontal
producer. The
present process, as more fully described below, does not utilize separate
combustion gas
vent wells, but produces the liquids and gases together through the same
horizontal well,
and so it needs only one horizontal producer well, and thus substantially
fewer expensive
horizontal wells. In addition, the withdrawal of combustion gas separately
from the
liquids as done in the process of `315 eliminates convective heat transfer in
the oil
drainage zone, making the process of `315 less energy efficient. Specifically,
by
inhibiting mixing of combustion gas with liquids, `315 removes produced
hydrogen from
contact with hot oil so that the degree of in situ hydrocracking and oil in
situ upgrading is
greatly reduced. The removal of carbon dioxide, which occurs at 16% in the
combustion
gas, inhibits the solvency benefit which occurs in the present invention as
described
below, which present invention is thereby better able to further reduce oil
viscosity and
broaden the oil drainage zone, thereby resulting in higher oil production
rates than the
method disclosed in `315.
A further major drawback of vent gas withdrawal as disclosed in the `315
patent is
process safety since the vent wells must be water-cooled on account of the
high
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temperature attained from the burnt (and sometimes burning) vent gas inside
the
reservoir. Furthermore, recalling that the air injection wells and the vent
wells are all at
the top of the reservoir and are in communication, there is likelihood of
oxygen mixing
with hydrocarbon liquids and gases in the vent wells so as to create an
explosive mixture
therein or at the surface.
US Patent 5,339,897 (Leaute) discloses a process similar to `315 for producing
hydrocarbons from tar sands wherein a vertical well is placed at the top of
the oil-bearing
reservoir over a horizontal producer and a second vertical well is emplaced
offset from
the first vertical well, also at the top of the reservoir, and laterally from
the horizontal
producer. Communication is accomplished between the vertical wells using hot
fluids,
then an oxidizing gas is injected in the well over the producer and combustion
gas is
withdrawn via the offset well. Heated oil drains downward to the producer.
Additionally,
`897 process of injecting a cracking fluid such as superheated steam into the
accumulated
oil above the horizontal producer induce cracking reactions.
US Patent 5,626,191 (Greaves et al) discloses an in situ process wherein an
oxidizing gas
injector is placed near the top of an oil reservoir in the vicinity of the toe
of a horizontal
producer that is emplaced at the base of the reservoir. A combustion front is
developed
that is quasi-vertical, extends laterally and moves from the toe of the
producer towards
the heel of the producer. Oil and gas drain together into the same horizontal
producer.
The present invention, as described below, is a valuable improvement over '191
because
by placing the injector midway along the horizontal producer or placing
multiple
injectors above the producer as in the present invention greatly enhances the
oil
production rate and degree of oil upgrading at moderate cost. In this
configuration, each
injector sustains two combustion/drainage fronts instead on only one using
`191.
Surprisingly, the combustion/drainage fronts advance at equal rates toward the
toe and
the heel of the producer. US Patent 5.626,191 is incorporated herein in its
entirety.
US Patent 6,412,557 (Ayasse et al) is an improvement on `191 wherein a
catalyst is
emplaced in, on or around the horizontal producer well to enhance oil
upgrading. US
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Patent 6,412,557 is incorporated herein in its entirety.
US Patent 7,493,952 (Ayasse) discloses an improvement on `191 and `557 wherein
a
non-oxidizing gas is injected within the horizontal producer at the toe to
prevent oxygen
entry and enhance process safety by controlling temperature and pressure
within the
wellbore. US Patent 7,493,952 is incorporated herein in its entirety.
US Patent Publ. 20090308606 (US Pat. Appl. 12/280,832) (Ayasse) discloses an
improvement to `191 and `952 wherein a diluent such as naphtha or other
hydrocarbon
solvent, or CO2 is injected in a long tubing extending to the toe of the
horizontal producer
well in order to control wellbore pressure and temperature and to facilitate
flow of
wellbore oil by density and viscosity reduction.
US Patent Pat. Pub. 20090200024 (US Appl. No. 12/068,881) (Ayasse et al)
discloses a
new process, similar to `191, wherein oxidizing gas is injected near the heel
of a
horizontal well, having a tubing extending to the toe. A combustion front
develops with
movement from the heel to the toe. The advantage of the process of the present
invention,
as more fully described below, over US ' 191 is that unlike US `191 the
drilling of a
distant vertical injector near the toe is not required. Rather, in the present
invention, the
injector could be drilled away from the toe, such as midway along the
horizontal leg The
advantage of the present process over US Application `881 is that a single
injector well
may be placed midway between the toe and heel of the horizontal producer well
and dual
combustion fronts will move towards the toe and heel without concern about
burning up
the vertical segment of the horizontal producer as could happen with '881
wherein the air
injection point is nearby or at the vertical segment. The present invention,
as with "881,
also has the advantage of placing a vertical air injector well back from the
toe of the
horizontal well (for example at 500 meters from the toe for a 1000meter
horizontal
producer leg) so that surface inaccessibility, such as caused by a bog or lake
at the toe
region, will not prohibit the drilling of a vertical injector there and
inhibit reservoir
exploitation.
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SUMMARY OF THE INVENTION
This invention is directed to an improved process for recovering viscous
hydrocarbons
from a subterranean reservoir using in-situ combustion, utilizing at least one
oxidizing
gas injection well and a separate horizontal well, and in particular to an
improved
process which does not employ separate additional vent gas wells and instead
uses a
horizontal well bore situated low in a formation to collect not only heated
oil but also hot
combustion gases, and to thereafter produce both to surface, where the oil is
thereafter
separated from the high temperature combustion gases.
In the embodiment of the invention where only one vertical injection well is
utilized, the
vertical injection well is disposed and completed in the upper part of the
reservoir, for
injecting oxygen-containing gas into the reservoir to support in-situ
combustion therein.
Such vertical injection well is situated above the horizontal well and
approximately at a
midpoint along said horizontal well, and upon injection of an oxidizing gas
into the
reservoir via the injection well and upon ignition of hydrocarbons in such
reservoir
proximate such vertical injection well a combustion front is generated
proximate the
vertical injection well which combustion front propagates outwardly from the
injection
well in mutually opposite directions each mutually opposite direction being
along the
horizontal well, as well as laterally to the horizontal well. Both high
temperature
combustion gases and heated oil are drawn downwardly from the hydrocarbon
formation and collected within the horizontal well, and thereafter are
together produced
to surface via such horizontal well, where at surface the hot combustion gases
are
separated from the oil using a multi-phase separator, vortex separating
techniques or
other techniques well known to persons of skill in the art, and further where
desired the
hot combustion gases are used to heat water so as to produce steam, preferably
for use in
powering steam turbines for the production of electrical power. Alternatively,
the
combustion gases, which contain flammable components such as methane, ethane,
propane, carbon monoxide, hydrogen and hydrogen sulfide, may be combusted at
the
surface to produce electricity with a steam turbine or gas turbine. In
processes with gas
vent wells, these gases are combusted in the upper reaches of the reservoir
and must be
cooled to protect the vent wells from thermal damage, so that the energy is
wasted.
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Similarly, in a preferred embodiment of the process of the present invention
employing
multiple vertical oxidizing gas injection wells aligned and extending in a
direction of the
horizontal well, each vertical oxidizing gas injection well is completed above
and
appropriately spaced along the horizontal well bore, and dual combustion
fronts of hot
combustion gases and draining oil are created at each injector, which
combustion fronts
propagate along the horizontal wellbore substantially orthogonal to the
horizontal well
bore and through the hydrocarbon formation, in mutually opposite directions
from the
vertical injection well bore as well as towards the toe and the heel of the
horizontal well.
For example, for 5-oxidizing gas injectors there will be generated ten (10)
fluid drainage
fronts, which provides high oil production rates an low extra cost.
Notably, if the inner diameter of the horizontal leg of the producer well is
too small, then
wellbore hydraulics interfere with the symmetry of combustion front
advancement-the
front advancement in the direction of the heel of the horizontal producer will
be faster
than toward the toe, thereby reducing efficiency of the process, and the
symmetry of
simultaneously proceeding equally in mutually opposite directions along the
horizontal
producer will be lost, and more importantly slowed in the direction
progressing towards
the toe.
Consequently, in a further preferred embodiment of the process of the present
invention,
where the horizontal well may have in the neighborhood of approximately 400
meters of
reservoir above it, with corresponding wellbore hydraulics at such depth, the
inner
diameter of the horizontal leg of the producer well should be greater than 3-
inches so as
to maintain frontal advancement symmetry, preferably greater than 5-inches and
most
preferably greater than 7-inches to permit sufficient diameter in the producer
well.
Also contemplated within this invention is a process whereby a plurality of
vertical
oxidizing gas wells may be initially completed above the horizontal well bore
along a line
thereof, and an oxidizing gas is injected initially into the formation at one
of said vertical
injection wells located approximately midsection of the horizontal well and a
combustion
front is formed proximate thereto, which advances in mutually opposite
directions along
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the horizontal well. After the combustion front has advanced a given distance
in
mutually opposite directions past additional vertical oxidizing gas injection
wells, on
respective opposite sides of such initial injection well, further oxidizing
gas may then be
injected into one or each of said additional injection wells so as to sustain
combustion
and permit the combustion front(s) to continue to advance along the horizontal
well bore.
Advantageously, by using a horizontal well bore to draw down both heated oil
and hot
combustion gases and then producing both oil and hot combustion gases
(depleted of
oxygen) to surface, the following advantages are cumulatively realized,
namely:
(i) the hot combustion gases which are drawn into the horizontal production
well
along with the heated oil serve to keep the oil continuously heated and thus
improve not only collection rates of such oil from the hydrocarbon formation
but also ensures the viscosity of the heated oil remains low and thus such oil
may be lifted to surface using gas "lift", eliminating the use and necessity
of
pumps;
(ii) fewer wells need be drilled, and in particular no gas vent wells need be
drilled
to separately collect and vent hot combustion gases, as was necessary with
certain prior art processes; and
(iii) hot combustion gases may be thereafter be used at surface to heat water
so as
to produce steam, which may be used for heating and/or to power steam
turbines so as to generate electrical power, and thus energy which otherwise
which would have been lost is thereby able to have been made use of in this
process.
(iv) oil upgrading will be achieved because of higher oil temperatures and the
comingling of oil in the reservoir with hydrogen generated in this process
Specifically, with regard to advantage (ii) above, by situating a vertical
injection well
proximate the midsection of a horizontal well and by propagating the
combustion front
in two mutually opposite directions along such well bore, such allows more
rapid
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collection of oil than by the method disclosed in either US 5,626,191 ("toe to
heel"
propagation of combustion front) or US 7,493,952 ("heel to toe" propagation of
combustion front) which merely causes the combustion front to advance in a
single
direction along the horizontal well bore.
Moreover, by injecting an oxygen-containing gas at less than fracturing
pressure through
the injection well and establishing a zone of oxygen-containing gas around the
injection
well that extends upwards to the reservoir cap rock and downward (but not
reaching) the
horizontal production well, and establishing a water, oil and combustion gas
drainage
front that grows along the horizontal well in directions both towards the toe
and towards
the heel of the horizontal well and also grows perpendicularly to the strike
of the
horizontal well, the heated oil and water and the heated combustion gas may
all drain
under the influence of gravity and pressure forces and further be collected in
the
horizontal well free of oxygen or oxidizing gas, which greatly reduces the
chance of
explosion.. Compared with the process of vent gas withdrawal by separate vent
wells, the
present process preserves the valuable flammable components for production to
the
surface rather than burning them in the reservoir where the heat is wasted,
and it utilizes
some of the generated hydrogen to hydrocrack the hot oil, thus producing a
stable
partially upgraded oil.
Accordingly, in one broad aspect of the process of the present invention such
process
comprises an improved in situ combustion process for reducing the viscosity of
oil
contained in an oil-bearing reservoir and recovering said oil along with
combustion gases
from the reservoir, which process does not employ one or more separate
combustion gas
venting wells, comprising:
(a) providing at least one production well having a substantially vertical
portion
extending downwardly into said reservoir and having a horizontal leg portion
in fluid
communication with said vertical portion and extending horizontally outwardly
therefrom, said horizontal leg portion completed relatively low in the
reservoir;
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(b) providing at least one injection well in a region intermediate opposite
ends of said
horizontal leg portion and in spaced relation to said horizontal leg portion
and positioned
substantially directly above said horizontal leg portion for injecting an
oxidizing gas into
said reservoir above said horizontal leg portion and in a region intermediate
mutually
opposite ends of said horizontal leg portion;
(c) injecting an oxidizing gas at less than fracturing pressure through said
at least one
injection well and initiating combustion of hydrocarbons in said reservoir
proximate
said injection well so as to establish at least one or more combustion fronts
above said
horizontal leg portion, said one or more combustion fronts causing oil in said
reservoir to
become reduced in viscosity and to drain downwardly into said horizontal leg
portion;
(d) allowing high temperature combustion gases along with said oil of reduced
viscosity to be together collected in said horizontal leg portion; and
(e) producing said high temperature gases and said oil to surface; and
(f) separating at surface or at the heel of said horizontal well said oil from
said high
temperature combustion gases.
In a first refinement of the above method, said at least one injection well
comprises at
least one vertical injection well situated along a length of the horizontal
well and
intermediate mutually opposite ends thereof extending downwardly from surface
towards
said horizontal leg portion, and upon injection of oxidizing gas and ignition
thereof said
injection well supplies said oxidizing gas to at least two combustion fronts
which each
move in opposite directions outwardly from said vertical injection well and in
a direction
along said horizontal leg portion of said production well.
In a second alternative refinement, said at least one injection well comprises
a horizontal
well extending both above and along said horizontal leg portion of said
production well,
for injecting said oxidizing gas above said horizontal leg portion of said
production well.
Alternatively, in another broad aspect of the method of the present invention,
such
method comprises an improved in-situ combustion process for reducing the
viscosity of
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oil contained in an oil-bearing reservoir and recovering said oil of reduced
viscosity from
the formation, which process does not employ one or more separate combustion
gas
venting wells, further comprising:
(a) drilling at least one production well having a substantially vertical
portion extending
downwardly into said reservoir and having a horizontal leg portion in fluid
communication with said vertical portion and extending horizontally outwardly
therefrom, said horizontal leg portion completed relatively low in the
reservoir;
(b) drilling at least one injection well located directly above said
horizontal leg portion
and in substantial alignment therewith, positioned or extending intermediate
opposite
ends of said horizontal leg portion;
(c) injecting an oxidizing gas into said reservoir via each of said vertical
wells located
along said horizontal welibore;
(d) initiating in situ combustion in said reservoir proximate said injection
well so as to
form at least a pair of vertically-extending combustion fronts advancing
laterally in
opposite directions along said horizontal leg portion, said combustion fronts
causing oil
in said formation to become reduced in viscosity and to drain downwardly into
said
horizontal leg portion;
(e) collecting high temperature combustion gases along with said oil of
reduced
viscosity in said horizontal leg; and
(f) simultaneously producing such high temperature gases and oil to surface;
and
(g) separating at surface or at the heel of said horizontal well said oil from
said high
temperature gases.
In a further refinement, where combustion is only initiated at a vertical
injection well
located midpoint along the horizontal well, upon the substantially vertical
combustion
front advancing laterally along said horizontal well bore and past further
vertical injection
wells, oxidizing gas is injected into said reservoir at said succession
further vertical
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injection wells to accelerate movement of the vertical combustion fronts in
both
directions along said horizontal well.
In a still further embodiment, such improved in-situ combustion process (which
process
does not employ one or more separate combustion gas venting wells) comprises:
(a) providing at least one production well having a substantially vertical
portion
extending downwardly into said reservoir and having a horizontal leg portion
in fluid
communication with said vertical portion and extending horizontally outwardly
therefrom, said horizontal leg portion completed relatively low in the
reservoir;
(b) providing a plurality of vertical injection wells positioned directly
above said
horizontal leg portion and in substantial alignment therewith, extending
downwardly
towards said horizontal leg portion;
(c) injecting an oxidizing gas into said reservoir via at least two of said
vertical wells;
(d) initiating in situ combustion in said reservoir proximate said at least
two vertical
injection wells so as to form at each injection well a pair of vertically-
extending
combustion fronts which advance laterally in opposite directions along said
horizontal leg
portion and outwardly from each of said at least two vertical injection wells,
said
combustion fronts causing oil in said formation to become reduced in viscosity
and to
drain downwardly into said horizontal leg portion;
(e) collecting high temperature combustion gases along with said oil of
reduced viscosity
in said horizontal leg; and
(f) thereafter producing such high temperature gases and oil to surface; and
(g) separating at surface said oil from said high temperature gases.
In a further refinement of such immediately-preceding process, said
substantially vertical
combustion front advancing laterally along said horizontal well bore past a
further one of
said plurality of injection wells, oxidizing gas is injected into said
reservoir at said further
one of said injection wells.
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Optionally, cyclically or directly stimulating the reservoir with steam
through the
injection well and the production well may be initially conducted prior to
initiating in situ
combustion, in order to establish fluid communication between the injection
well and the
horizontal oil production well, to better ensure the flow of heated combustion
gases and
heated oil once in-situ combustion is initiated. Optionally, oil ignition may
be enabled or
assisted by the known technique of injecting linseed oil or other fluid which
is easily
ignited into the reservoir through the air perforations.
It will be noted that the process of the present invention advantageously
comprises and is
characterized by the following features:
(i) There is no split production of the liquid and gas phases since they both
enter the
same production well (i.e. the horizontal well) completed low in the reservoir
near the base thereof;
(ii) The high gas/liquid ratio in the horizontal well, when using air as an
oxidizing
gas, due to depth of the well and ingress of high temperature gases into the
production well, assures that natural gas lift will be effective in a
reservoir that
is not pressure-depleted so that the use of pumps is unnecessary, reducing
process complexity and cost;
(iii) As a direct consequence of the oil and combustion gas (and sometimes
water
and/or steam) flowing together into the horizontal well bore, high energy
efficiency is achieved because all the combustion heat energy is transferred
convectively to the oil inside of and ahead of the drainage zone in the
reservoir,
which thereby due to the energy transfer from combustion gases to the oil
provides the greatest viscosity decrease of the fluids and maximizes the oil
production rate. The air-oil ratio is also decreased, reflecting increased
energy
efficiency compared with the case of split gas and liquid production with
different wells;
(iv) Co-production of combustion gas and hydrocarbon liquids also improves the
oil
production rate because CO2 present in the combustion gas permeates the oil
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ahead of the drainage front and acts as a solvent to further reduce oil
viscosity
and facilitate oil drainage into the horizontal well. Also, CO2 in the
combustion
gas has its highest solubility in cold oil, so that the drainage zone is made
wider
as a consequence of CO2 dissolving in cold oil;
(iv) Hydrogen entrained with the flowing hot oil in the drainage zone and in
the
wellbore enables hydrocracking and partial upgrading of the oil
(v) Low air injection pressure is required in the present process because the
combustion gas is in direct communication with the nearby horizontal
production well, being distant at most by the thickness of the oil zone.
BRIEF DESCRIPTION OF THE DRAWINGS
In the accompanying drawings which illustrate exemplary embodiments of the
present
invention:
Figure 1 is a cross section through an oil-bearing reservoir, showing the
arrangement of
wells used to carry out the method of the invention, such cross section
cutting through
both the vertical injection well and horizontal/vertical production well pair.
A layer of
overburden lies over the oil-bearing reservoir, into which are placed a
vertical oxidizing
gas injection well and a vertical/horizontal well pair for producing the oil;
Figure 2 is a cross-sectional through the oil-bearing reservoir shown in
Figure 1, taken
along plane B-B, with the horizontal production well shown in cross-section;
Figure 3 is a partially-transparent top view of the oil-bearing reservoir
shown in Figure 1
from numerical simulation;
Figure 4 is a cross-section through an oil-bearing reservoir similar to Figure
1, showing
a variation of the method of the present invention, where a plurality of
oxidizing gas
injection wells are used to advance a combustion front in two mutually
opposite
directions; and
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Figure 5 is similar to Figure 1, but employing 5- oxidizing gas injection
wells as
simultaneous injectors.
DETAILED DESCRIPTION OF A PREFERRED EMBODIMENT
Referring to Figure 1, an oil-bearing reservoir 20 shown in Figure 1 is
typically covered
by an overburden 1, preferably constituted of shale or cap rock sufficiently
thick to be
substantially impermeable to gas flow so that the injected oxygen-containing
gas 22 will
be contained within the oil-bearing reservoir 20.
In accordance with the method of the present invention, at least one vertical
oxidizing
gas injection well 6a is drilled from the surface 30 downwardly into an upper
portion of
the reservoir 20, and is perforated so as to permit injection of oxidizing gas
22 into
reservoir 20 proximate the top of the oil-bearing reservoir 20, such oxidizing
gas being
compressed and forced within well 6a via compressor 71.
A horizontal/vertical production well pair 9 is provided, having a vertical
well portion 10
and a horizontal portion 8. The horizontal well portion 8 is completed low in
the reservoir
and preferable extending substantially across a length of an oil-bearing
reservoir 20 or
20 a portion thereof from which oil is desired to be recovered by the process
of the present
invention. The casing of the horizontal well, is perforated as shown in
Figures 1 and 4,
or may consist of porous screens, as shown and taught in PCT/CA to the
assignee herein,
Archon Technologies Ltd., narrow slots or FacsRiteTM1 screen plugs and the
such to
permit ingress of hot oil 3 and hot combustion gases 5 from the reservoir 20
into the
horizontal well 8, for subsequent production to surface 30. The inner diameter
of the
horizontal producer well is preferably greater than 3-inches so as to maintain
frontal
advancement symmetry, and preferably greater than 5-inches and most preferably
greater
than 7-inches (ie an inner diameter of approximately 9 5/8 inches in typical
current
standard wellbore size) to permit sufficient diameter in the producer well.
The at least one oxidizing gas injector well 6a, in accordance with the method
of the
present invention, is located above and approximately midway along horizontal
well bore
FacsRiteTM is a trademark of Shlumberger Inc. for producing well sand screens.
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8 (i.e. wherein distance "d1" is approximately equal to distance "d2" as shown
in Figure
1), although the precise position may be altered based on known reservoir
heterogeneity
or other factors.
The first step in starting and conducting the oil recovery process of the
present invention,
in a preferred embodiment, is to establish fluid communication between the
vertical
injection well 6a and the horizontal production well 8 so that oxidizing gas
22 can more
easily be injected into the reservoir 20 and heated oil 3 and combustion gas 5
can be
removed from the reservoir 20 via horizontal/vertical well pair 9. Initially,
steam (not
shown) may be injected cyclically or continuously in the vertical well 6a, and
also
injected from surface into horizontal well 8 and circulated therein to heat
the horizontal
well 8 and increase mobility of heated oil 3 therein. The pressure of the
initially-injected
steam is not to be so great so as to force large volumes of steam directly
through
reservoir 20 and into horizontal well 8, but merely sufficient to assist
viscous liquids in
reservoir 20 to be assisted under such assisting pressure to drain downwards
in reservoir
to an area of lower pressure, namely the region of horizontal well 8 which
horizontal
20 well 8 removes fluids from such region and thereby creates an area of
relatively lower
pressure, and thus establishes fluid flow in such direction). For oil 3 that
is immobile at
reservoir conditions, steam may also be injected via the injection well 6a in
a continuous
manner, relying on reservoir dilation to achieve steam injectivity. When the
oil 3 is so
viscous that it is immobile in the reservoir 20 , pre-heating the horizontal
production well
8 prevents oil 3 from solidifying in the horizontal well 8 and inhibiting
production,
especially when the production well 8 must be shut-in, as may happen should
difficulties
occur with the surface oil-treating facilities. Such pre-heating may be
conducted by
circulating steam in the horizontal leg 8 from the toe 40 to the heel 42 of
the horizontal
well 8. The circulation is achieved by placing a long tubing (not shown)
within the
horizontal well 8 for injecting steam that flows via the tubing to the toe 40
and returns
back the heel 42 via the annular space between the tubing and horizontal well
casing 8
and thereafter to surface 30. Once fluid communication is established between
the
injector well 6a and horizontal producer well 8, an oxygen-containing gas, for
example
air, oxygen-enriched air, C02-enriched air or an oxygen-CO2 mixture, is
injected into the
reservoir 20 via injector well 6a as shown in Figure 1. At first, relatively
moderate air
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rates are used, but these rates are ramped up to the target maximum while
keeping the
wellbore temperature below about 350 C as measured by a string of
thermocouples
placed in the wellbore. After initiating injection of oxidizing gas,
combustion by-products
such as CO2 will appear at the surface in the produced gas, indicating that
combustion has
been achieved in the reservoir.
Pre-heating the reservoir 20 near the vertical injector well 6a serves a
second important
purpose because oil at steam temperatures is usually able to auto ignite and
start the
burning and oil production processes. It also reduces the oil saturation in
the sand near
the vertical injector, which serves to reduce the strength of the combustion
exotherm and
prevent over-heating the injector well.
At the beginning of the in-situ combustion process, when oxidizing gas 22
contacts oil 3
in formation 20, burning reactions occur and coke is created in region 4
immediately
following the combustion fronts 50, as shown in Figures 1-4. Thereafter, coke
is the only
fuel consumed, which after consumption leaves a burned-out zone 2, as shown in
Figures
1-4. Coke, in region 4 (see Figures 1-4), is constituted of small carbonaceous
particles
dispersed on the sand grains. The hydrogen/carbon ratio is typically 1.13 as
measured in
laboratory reactors and refinery cokers involving Athabasca bitumen. The sands
containing coke particles remain substantially permeable to gas, so that the
oxidizing gas
22 and the produced combustion gas 4 can readily flow through, contacting cold
oil and
transferring heat. The convective oil heating is so extensive that oil
hydrocracking occurs
on account of high temperatures produced during coke combustion and the
presence of
generated hydrogen. The present process will operate similarly to the THAI2TM
(Toe-to-
Heel Air Injection) process with regard to the burning mechanism and drainage
front.
Petrobank Energy and Resources Ltd., operating the THAITM process at Conklin,
Alberta
has reported reservoir temperatures over 600 C, up to 8 volume percent
hydrogen in the
produced gas and 3-4 points of bitumen upgrading. Consequently, the produced
oil 3
from the present invention will be substantially upgraded.
2 THAITM is a registered trademark of Archon Technologies Ltd, of Calgary,
Alberta, for the services of licensing of a
particular patented method/technology for enhanced oil recovery from petroleum
formations.
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Advantageously, in the method of the present invention which provides for
removing hot
combustion gases 5 via horizontal/vertical well pair 9, such allows
significant advantages
to be achieved over the prior art such as the process of US patent 5,456,315,
which relied
on extra wells 4 (see Fig. 2 of US 5,456,315) placed in the upper reaches of
the reservoir
to remove such combustion gases. Disadvantageously, such prior art methods as
shown
in U.S Patent 5,456,315 greatly reduce the ability to provide convective heat
transfer
from the hot combustion gases to the oil, and further disadvantageously such
prior art
methods remove produced hydrogen needed for hydrocracking, as well as CO2
solvent
which further serves to advantageously reduce the viscosity of the oil. Such
prior art
processes, by relying mainly on conductive heat transfer, are less energy
efficient and
have lower oil rates than the present process. In the present process, a fluid
drainage zone
15 is established and the hot upgraded oil 3, (as well as water/steam (not
shown) and
combustion gases 5 flow downward and into the horizontal well 8 for conveyance
together to the surface 30. As the process proceeds, the outer part of the
coke layer 4
nearest the injected oxygen-containing gas 22 burns away and fresh coke is
laid down
where the hot combustion gas first contacts oil. In this operation, reservoir
oil 3 never
meets oxygen, so that oxygenated organics are not made and the produced oil
emulsions
are easy to break in oil treating facilities at the surface. The oil 3 beyond
the fluid
drainage zone 15 remains substantially un- heated until the drainage zone 15
and
combustion front 50 advances. For reservoirs 20 containing mobile oil, un-
heated native
oil 3 away from the combustion drainage front 15 mixes with hydrocracked oil 3
in the
horizontal well 8 to reduce the overall degree of upgrading. However, for
mobile-oil
reservoirs the oil production rate is increased because the entire horizontal
wellbore is
productive throughout the life of the well. In all reservoirs 20, the zone of
injected
oxidizing gas remains isolated from the horizontal well by a layer 24 of oil
3, preventing
entry of oxidizing gas (e.g. oxygen) into the horizontal well 8. This layer 24
is fed by hot
upgraded oil 3 that drains from the laterally expanding combustion front 50
and flows at
the base of the reservoir 20 into the horizontal well 8. As the process of the
present
invention proceeds, the volume of oil 3 entering the horizontal well 8 from
the protective
layer 24 increases relative to the volume of oil 3 draining along with
combustion gases 5
(ef Figure 1 and Figure 4 as to increased volume of layer 24) .
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Figure 2 is a cross-sectional view along plane B-B of the oil-bearing
reservoir 20 and
present method shown in Figure 1, with identical components identically
itemized to
those of Figure 1. This figure shows how the protective oil layer over the
horizontal well
is formed.
Figure 3 is a top-down view of the present process showing the oil-bearing
reservoir 20,
the burned zone 2, the coke fuel deposit zone 4 and the fluid drainage zone
15. The
oxygen-containing gas injector well 6a is located in the upper part of the oil-
bearing
reservoir 20 and the horizontal segment 8 of the production well pair 9 is at
the base of
the reservoir 20. The vertical segment 10 of the horizontal/vertical well pair
9 is
connected to the horizontal segment 8 at the heel 42 of the production well 9
and
connects to the surface oil treating facilities (not shown). While the fluid
drainage zone
15 intersects the horizontal well 8 at two points, 17 and 18, nevertheless all
produced oil
3 moves inside the horizontal well 8 towards the heel 42 of the horizontal
well 8.
Surprisingly, the distance between the projection of the injector well 6a and
the drainage
entry points 17, 18 into the horizontal well 8 remains substantially equal
throughout the
operation of the process. One would have expected that portion (entry point)
18 of the
drainage zone 15 moving towards the heel 42 of the horizontal producer well 8
would
advance much faster than that portion (entry point) 17 of drainage zone 15
that moves
towards the toe 40, since portion (entry point) 18 is nearer the low pressure
heel 42-
however that is not the case.
Referring to Figure 1, the cap rock overburden 1 prevents fluids, including
oxidizing gas
22, from escaping the oil-bearing reservoir 20. Figure 1 also shows the burned
zone 2,
the coke fuel deposit zone 4, the fluid drainage zone 15, the oxygen-
containing gas
injector 6a, the horizontal leg 8 of the production well pair 9, and the
vertical segment of
the horizontal producer 9.
As the process of the present invention shown in Figure 1 proceeds, each of
the coke
zones 4 and fluid drainage zones 15 move laterally outwardly from the
injection well 6a,
in two mutually opposite directions, firstly towards the toe 40 and secondly
towards the
heel 42 of the production well pair 9, as do the fluid entry points 17, 18,
and the burned
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zone 2 expands. (cf Figure 1, and Figure 4) This process continues until the
fluid
drainage zones 15 reach the toe 40 and the heel 42, which will occur at
approximately the
same time if the injector well 6a is placed midpoint along the horizontal well
8 of the
production well pair 9. Importantly, the oil bank 24, protecting the
horizontal well 8
from exposure to oxygen, thickens with oil 3, as shown in Figure 4 that drains
from the
drainage regions 15 into the horizontal well at points 17, 18. Once the toe 40
and heel 42
endpoints are reached by the drainage points 17, 18, the oxidizing gas
injection rate must
be reduced or halted to prevent over-pressuring the reservoir which would
either cause
fracturing of the reservoir, or force oxygen entry into the horizontal well 8.
Specifically, ingress of oxygen or oxygen-containing gas into the horizontal
well 8 or
vertical well 10 is to be prevented because otherwise oil 3 therein will be
capable of
burning or exploding thus causing very high temperatures that could damage the
production well pair 9 and cause extensive coke formation that could plug the
production
well pair 9. One way of controlling temperature and pressure in horizontal
well 8 (and
thus also vertical well 10) is to continue the circulation of steam or non-
oxidizing gas
through wellbore tubing (not shown, but described above) that was used for pre-
heating
the horizontal well 8. Very low steam rates, typically 1-10 m3/d are adequate.
A
thermocouple string (not shown) placed alongside the tubing (not shown) in the
horizontal well 8 will alert operators that the steam rate needs to be
increased to reduce
temperature of horizontal well 8.
Provision of tubing in horizontal well 8 , in addition to allowing provision
of steam to
pre-heat horizontal well bore 8 and surrounding areas of horizontal well bore
8 and to
initiate fluid communication between reservoir 20 and horizontal well 8, may
also
advantageously be used to supply a diluent to oil 3 in horizontal wellbore 8,
and in
particular a hydrocarbon diluent such as VAPEX, hydrocarbon solvents or
naphtha, or
alternatively CO2 , as suggested in co-pending US patent application
20090308606 (US
Pat. Appl. 12/280,832), hereby incorporated herein by reference in its
entirety, and
commonly assigned to the assignee of the within invention. Advantageously,
injecting
CO2 into tubing within horizontal well 8 has the advantages of not only acting
as a
diluent to the oil 3 being collected within the horizontal well 8 and in pool
24
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surrounding horizontal well 8, but further serves to slightly pressurize the
horizontal well
8 and thereby assist in preventing any ingress of oxidizing gas 22, which if
permitted to
enter the horizontal well 8 after drawdown of oil layer 24, could create a
potentially
explosive mixture with the oil 3 therein.
After the toe 40 and heel 42 of horizontal well 8 are simultaneously reached
by the
to drainage fronts 17, 18, a new stage of operation begins- the drawdown
stage.
Specifically, at this point in time there will no longer be sufficient
quantities of high
temperature gases 5 produced to provide natural gas lift of oil 3 to surface
30 because
the entire length of the horizontal well 8 will be covered by layer 24 and
sealed with oil
3. Therefore, liquid pumping or artificial gas lift is required to recover the
large pool of
hot upgraded oil 3 remaining at the base of the reservoir 20. The oxidizing
gas 22
injection rate into the injector well 6a is then adjusted to maintain an
injection pressure
substantially below reservoir fracture pressure. A maximum oxidizing gas
injection
pressure of less than 70% over the reservoir pressure is preferred, and less
than 50% over
reservoir pressure is most preferred during the drawdown stage. The drawdown
stage is
advantageous because compressed gas requirements are low and output of the
compressor 71 providing compressed air as the oxidizing gas 22 can be
substantially re-
directed to new operations that initially require large volumes of oxidizing
gas 22. The
gas/oil ratio is much lower during the drawdown stage which boosts the overall
energy
efficiency of this process. For Athabasca tar sands, the cumulative air oil
ratio can be as
low as 715:1 (m3 air/m3 Oil).
The process is characterized by smooth and consistent operation with oil
recovery factors
up to 80 %, and it minimizes thermal cycling of the producers which leads to
frequent
wellbore failures in steam processes such as steam-assisted gravity drainage
(SAGD).
In situations where poor reservoir permeability exists, it may be necessary to
use a
plurality of oxidizing gas injector wells 6a, 6b, as shown in Figure 4 and
adapt the
method of the present invention accordingly. Accordingly, in a further
refinement of the
present invention, upon combustion fronts 50 proceeding a specified distance
from
original oxidizing gas injector well 6a, additional oxidizing gas injector
wells 6b,
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(completed on mutually opposite sides of injector well 6a) may further be,
after
combustion fronts have progressed outwardly past them as shown in Figure 4,
each
provided with oxidizing gas (air) 22 via compressor 71 for injection into the
reservoir 20
to ensure combustion fronts 50 continue to advance outwardly in the direction
of toe 40
and heel 42 of horizontal well and do not fail to advance and/or become
extinguished.
Additional injector wells 6b, as shown in Figure 4, may be completed on
opposite sides
of initial injector well 6a prior to initial commencement of the process of
the present
invention, or alternatively may be drilled and completed upon the process
being initiated
for a period of time and it becoming apparent that the combustion fronts 50
have
advanced to a point where they are too remote from original injector well 6a
and require
more immediate and proximate supply of oxidizing gas 22 in order for the
combustion
fronts 50 to progress outwardly along horizontal well 8 and the process
thereby continue .
The further step of utilizing or completing additional gas injection wells 6b
may be
repeated, as necessary, each on respective outward sides of earlier-completed
injection
wells 6b, until such time as points of intersection 17, 18 of drainage zone 15
respectively reach toe portion 40 and heel portion 42 of horizontal well 8.
In the most favored embodiment of the present process, multiple oxidizing gas
injectors
are employed from the outset.
Referring to Figure 5, there are 5-oxidizing gas injectors, 6a-6e, in a
bitumen reservoir 20
and spaced as indicated in positions as indicated where x = well length
divided by the
number of injectors. This arrangement assures that the burning fronts, whose
direction of
movement is indicated by arrows, all join or reach the toe and heel all at the
same time. If
the injectors are misplaced the process will operate the same way with all the
benefits,
but the energy efficiency will be somewhat compromised. The oil 3 covering
over the
horizontal well isolates it from the oxygen. At approximately the time that
the
combustion fronts reach the toe and heel the drainage points 17a-17e and 18a-
18e will
merge and the horizontal well will be covered entirely with oil. If the air
injection rate is
kept high, the reservoir will over-pressure: Therefore, operational control is
switched
from gas flow control to gas pressure control. Consequently, from then onwards
the gas
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injection rate becomes much diminished while the drained oil spread over the
lower
section of the reservoir flows into the horizontal producing well. Because of
the low gas-
oil-ratio during this drawdown stage the oil must be produced by pumping or
artificial
lift.
As compared with the use of a single oxidizing gas injection well, the use of
multiple
wells reduces the amount of air that can be safely injected into a single
injector, but
increases total injectable over all the injectors, which greatly increases the
oil production
rate.
EXAMPLE 1
Table 1 below gives a list of list of Numerical Model Parameters used in this
Example.
Numerical simulator: STARSTM 2009.1, Computer Modelling Group Limited
Model dimensions:
Length: 540 meters, 216 grid blocks at 2.5 meters each
Width: 50 m, 20 grid blocks of 2.5 meters each with an element of symmetry,
giving a
wellbore spacing of 100 m
Height: 20m, 20 grid blocks of 1-meter each
Horizontal production well
A discrete horizontal wellbore of 500 m extended from grid blocks 9 to 208,
leaving a
20-meter buffer zone on either end of the horizontal well. The inner diameter
of the
horizontal leg was 9 5/8 inches. A steam rate in the horizontal well tubing of
10 m3/d
(water equivalent) was maintained throughout all the tests, although this
procedure is
optional.
Steam and oxidizing gas injector(s)
A number of models were run having from 1- 5-vertical injectors placed over
the
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horizontal producer and perforated in grid blocks 6-9 for steam pre-heating
(for 3-
months) and at the top 4-grid blocks for air injection. Air rates per injector
started at
10,000 m3/d and increased to a maximum of 100,000 m3/d.
Table 1. Reservoir properties, oil properties and well control.
Reservoir Properties
Reservoir
Units Rock
Pay thickness m 20
Porosity % IV
Oil saturation % 80
Water saturation % 20
Gas mole fraction % 0
H. permeability mD 6700
V. permeability mD 5O
Reservoir temperature C 12
Reservoir pressure kPa 2600
Rock compressibility /Kpa 3.5
Conductivity J/m.d.C 1.5E+5
Heat capacity J/m'.c 2.35E+6
Oil Properties
(Athabasca bitumen) 30
Density Kg/m-' 995.7
Viscosity cP 200,000
Molecular weight AMU 508
Mole fraction 0.886
Heat capacity
Combustion enthalpy J/gmole 6.29
The wells were controlled using
the following parameters:
Air injection pressure max. kPa 6075
Producer BHP Minimum kPa 2600
Air rate max. per injector In '/d 20k-1Y6k
Test Runs
Seven numerical simulation runs were conducted: The results are provided in
Table 2.
Run 1 was for the THAI process of US Patent' 191 and is for comparative
purposes only.
Runs 2-7 are with oxidizing gas injectors placed over the horizontal producer
well along
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its length so that the distance between the midpoints between adjacent
injectors or the
ends of the producer are equal. The grid block numbers for the air injector
locations were
as follows:
Run 1- 9
Run 2 -109
Run 3- 59, 158
Run 4 -42,109, 175
Run 5 -29, 69, 109, 149, 188
Run 6- 29, 69, 109, 149, 188
It was found that the oil drainage over the horizontal well 8 from each
injector well was
complete at the same time with this configuration. However, such a
configuration of
injectors is not imperative. The combustion also worked well with highly
asymmetric
injector orientations. Compared with the well configuration of US Patent '191
(the
"THATM" process), where a single injector is placed near the toe of the
horizontal
producer and has a single drainage front, Runs 2-7 had two drainage fronts for
each air
injector.
Runs 1-6 all had the same total maximum air injection rate, 100,000 m3/day, so
that the
efficiency of each Run could be compared with the same air compressor
capacity. For the
Runs with multiple air injectors, the total air was divided evenly between the
injectors.
For example, Run 2 the single injector 6a received all of the available air,
100,000 m3/d,
while Run 6, with 5-injectors, received only 20,000 m3/d of air per injector.
In order to
quantify the benefit of increasing total air compressor capacity, in Run 7 it
was increased
from 100,000 to 300,000 m3/d total, providing 60,000 m3/d of air in each of
the 5-
injectors. The air rate per injector well was ramped-up with the following
monthly
schedule until the targeted maximum air rate was achieved: 10,000 m3/d;
20,000; 33,333;
50,000; 70,000 and 100,000. After all of the desired maximum air rate was the
reached
this rate was continued until the burning front simultaneously reached the toe
and heel of
the horizontal producer. At that point, the exit points for the combustion gas
into the
horizontal well became sealed by the oil layer covering the horizontal well
and it was
necessary to control the air rate by injection pressure, otherwise, fracture
pressure would
have been exceeded. An injection pressure of 4000 kPa was selected, and this
was
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sufficient to fill the voidage from producing oil. The air requirements after
the front
reached the toe and heel of the producer were greatly reduced from the
targeted
maximum and so the air/oil ratio became reduced.
`Peak oil rate' refers to the highest oil rate achieved in a Run. For Runs
with 1 or 2-air
injectors.
Table 2. Numerical simulation results
Run number 1 2 3 4 5 6 7
#Air 1* 1 2 3 4 5 5
Injectors THAI
Max. Air per
injector, 100k 100k 50k 33.3k 25k 20k 60k
m3/da .well
Max. Total Air
injected, m3/day 100 100 100 100 100 100 300
Oil rate after first 28 47 57 68 81 90 156
year, m3/d
Peak oil rate, 183 141 141 134 130 121 176
m3/d
Days to 60%
Oil Recovery 2948 2067 2045 2019 1992 1990 1923
Factor
Recovery factor
at 30m3d oil rate, % 72 77 78 77 77 78 78
Minimum
Cumulative 1291 1023 1021 923 819 764 924
Air/Oil ratio
* Results for the THAI process- not part of the present invention.
Comparing Runs 1 and 2, there were two major benefits. Firstly, Run 2 gave a
much
higher oil rate after the first year of operation: 47 m3/d versus 28 m3/d for
THAT, for the
same injector capital cost and the same rate of air compression cost. This is
very
important to the economics of oil production and was achieved by simply moving
the air
injector to a different location relative to THAT. Secondly, the air/oil ratio
was
substantially lower in Run 2, 1023 instead of 1291. A major operating cost of
combustion
processes is the air compression energy cost and this was accordingly lower by
20% [i.e.
(1291-1023)/1291 ] using a single central injector compared with THAT.
Additionally to
the benefits of high early oil rates and low energy cost, the use of a central
injector
provided a higher oil recovery factor (percent of original- oil- in -place
that is recovered).
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The use of multiple air injectors placed over the producer horizontal well is
represented
in Runs 3-6. As the number if injectors are increased, further benefits of
high early oil
production rates are achieved, reaching 90 m3/d with 5-injectors. Also the
energy
efficiency of the process is substantially improved with multiple injectors,
reaching 764
m3 air/m3 oil for a 25% improvement compared with a single central air
injector.
Comparing Run 6 and Run 7, both Runs have 5-injector wells and the only
difference is
in the air injection rates. By increasing the air rate from 20,000 m3/d-well
to 60,000 m3/d-
well, a large benefit in early oil rate and peak oil rate is achieved,
although at a slight
reduction in energy efficiency. Comparing Run 7 with Run 1 (prior art),
employing 5-air
injectors and 3-times the peak air rate increased the first-year oil rate 5.57-
fold.
Those skilled in the art will be able to select the optimum combination of air
rate and the
optimum number of air injectors for a specific reservoir and business
environment,
factoring in parameters such as electricity rates (for air compression) and
vertical well
drilling costs. It should be noted that a so-called "SMART" well horizontal
could be
drilled from the same drilling pad as the horizontal well in the present
process for air
injection at various points in the upper portion of the reservoir. In SMART
wells there are
individual perforated sections and each is isolated with packers and has its
own separate
tubing string from the surface that enables specific air volumes to be
delivered to each
perforated section. A SMART well could be advantageous for instances where
there is a
lake or other impediment on the land surface over the reservoir that would
impede
drilling vertical air injector wells.
While a number of particular embodiments of the present invention have been
described
above, it is to be understood that other embodiments are possible within the
scope of the
invention and are intended to be included herein. It will now be clear to any
person
skilled in the art that various modifications to this invention, not shown,
are possible
without departing from the scope of the invention as exemplified by the
examples herein.
For a complete definition of the scope of the invention, reference is to be
had to the
appended claims.
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