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
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heated zone oil 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withdrawn at the ignition well and the combustion front grows towards the offset well,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
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would enter the wellbore and burn 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 oilbearing
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 C0 2 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 1OOOmeter 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.
SUMMARY OF THE INVENTION
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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
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combustion front is formed proximate thereto, which advances in mutually opposite
directions along 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
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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
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.
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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
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 wellbore;
(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
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injection wells, oxidizing gas is injected into said reservoir at said succession further
vertical 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
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further one of said plurality of injection wells, oxidizing gas is injected into said
reservoir at said further one of said injection wells.
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;
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(iv) Co-production of combustion gas and hydrocarbon liquids also improves the
oil production rate because C0 2 present in the combustion gas permeates the
oil ahead of the drainage front and acts as a solvent to further reduce oil
viscosity and facilitate oil drainage into the horizontal well. Also, C0 2 in the
combustion gas has its highest solubility in cold oil, so that the drainage zone
is made wider as a consequence of C0 2 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 20 and preferable extending substantially across a length of an oil-bearing
reservoir 20 or 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 FacsRite™ 1
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.
1 FacsRite™ is a trademark of Shlumberger Inc. for producing well sand screens.
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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 8 (i.e. wherein distance "di" 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 20 to an area of lower pressure, namely the region of horizontal
well 8 which horizontal 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
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producer well 8, an oxygen-containing gas, for example air, oxygen-enriched air, C0 2-
enriched air or an oxygen-C0 2 mixture, is injected into the reservoir 20 via injector
well 6a as shown in Figure 1. At first, relatively moderate air 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 C0 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 THAI2™ (Toe-to-Heel Air Injection) process with regard to the burning
mechanism and drainage front. Petrobank Energy and Resources Ltd., operating the
THAI™ 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
2
THAI™ 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.
- 17 -
CAL_LAW\ 1655424M
upgrading. Consequently, the produced oil 3 from the present invention will be
substantially upgraded.
Advantageously, in the method of the present invention which provides for removing
hot combustion gases 5 via horizontal/vertical well pair 10, 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 5,456,3 15) placed in the upper reaches
of the reservoir to remove such combustion gases. Disadvantageous^, 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
disadvantageous^ such prior art methods remove produced hydrogen needed for
hydrocracking, as well as C0 2 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 unheated
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
- 18 -
CAL_LAW\ 1 55424
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 (cf Figure 1 and Figure 4 as
to increased volume of layer 24) .
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.
CAL_LAW\ 1655424X1
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 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 8 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 nonoxidizing
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 m Id 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 C0 2 , as suggested in co-pending US patent application 20090308606
-20 -
CAL_LAW\ 1655424M
(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
C0 2 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
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
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).
CAL LAW 1655424U
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,
(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 7 1 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 earliercompleted
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
-22 -
CAL LAW\ 1655424X1
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 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: STARS™ 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 m /d
-23 -
CAL_LAW\ L65 424
(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
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 m /d and increased to a maximum of 100,000 m d.
Table 1. Reservoir properties, oil properties and well control.
-24 -
CAL LAW\ 1655424M
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 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
"THA™" 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 m /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 m /d, while Run 6, with 5-injectors, received only 20,000 m /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 m /d total, providing 60,000 m /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
-25 -
CAL_LAW\ 1655424M
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 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
* 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 m /d versus 28 m /d for THAI, 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 THAI. 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)71291 ] using a single central injector compared with
CAL_LAW\ 1655424M
THAI. 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).
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
the air injection rates. By increasing the air rate from 20,000 m /d-well to 60,000
m /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
-27 -
CAL_ AW 1655424X1
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.

WHAT IS CLAIMED IS:
1. An improved in-situ combustion process for reducing the viscosity of oil
contained in an oil-containing 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;
(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 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 above said horizontal leg portion 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 the heel of said horizontal well or at surface said oil from said high
temperature combustion gases.
2. The process of claim 1, wherein said at least one injection well injects oxidizing gas
into said formation via said at least one injection well at less than fracturing pressure.
-29 -
CAL LAVA 1655424M
3. The process of claim 1 or 2, wherein 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.
4. The process of claim 1 , 2, or 3 wherein a plurality of vertical injection wells
are placed above and along a length of the horizontal well, and a combustion front is
initiated at each injection well which progresses outwardly from each injection well in
opposite directions, along a line of said horizontal well.
5. The process of claim 1 or 2, wherein said at least one injection well comprises a
horizontal injection 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.
6. The process of claim 5, wherein said at least one injection well injects
oxidizing gas into the formation at a plurality of locations above said horizontal leg
portion, so as to establish at least a pair of combustion fronts at each location which
advance laterally outwardly from each location in opposite directions along said
horizontal leg portion of said production well in a direction along said horizontal leg
portion of said production well.
7. The process of claim 1, wherein said hot combustion gases are subsequently
used to heat water.
8. The process of claim 7, wherein said heated water is subsequently used to
produce steam for use in producing electrical power using turbines.
9. The process of claim 1, wherein said high temperature combustion gases are
used or further burned to produce electricity using gas turbines or steam turbines.
-30 -
CAL LAW\ 1655424M
10. The process of any one of claims 1-9 wherein a tubing is placed within the
horizontal leg portion of said production well, and a medium selected from the group
of mediums comprising water, steam, non-oxidizing gas including C0 , hydrocarbon
diluent, and mixtures thereof, is injected therein.
11. The process of claim 1 wherein the inner diameter of the horizontal leg
portion of the production well is greater than 3 inches.
12. The process of claim 11 wherein the inner diameter of the horizontal leg
portion of the production well is greater than 5 inches.
13. The process of claim 12 wherein the inner diameter of the horizontal leg
portion of the production well is greater than 7 inches.
14. The process of any one of claims 1 -6 and 10 wherein the oxidizing gas
contains oxygen and C0 2.
15. The process of any one of claims 1-6 wherein the oxidizing gas injection
pressure is limited to a maximum of less than 50% over the reservoir pressure by
adjusting the oxidizing gas injection rate.
16. An improved in-situ combustion process for reducing the viscosity of oil
contained in an oil-containing 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) 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 alignment therewith, positioned or extending intermediate opposite ends
of said horizontal leg portion;
-3 1 -
CAL LAW\ 1655424U
(c) injecting an oxidizing gas into said reservoir via said at least one injection well at
a location above said horizontal leg portion and intermediate opposite ends of said
horizontal leg portion ;
(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) producing such high temperature gases and oil to surface; and
(g) separating at the heel of said horizontal well or at surface said oil from said high
temperature gases.
17. The method as claimed in claim 16, wherein said step of drilling at least one
injection well comprises drilling at least one vertical injection well intermediate
opposite ends of said horizontal leg portion, and said step of initiating in situ
combustion comprises initiating combustion proximate said at least one vertical
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
18 The method as claimed in claim 17, wherein said step of drilling at least one
vertical injection well comprises drilling a plurality of vertical injections wells, and
said step of initiating in situ combustion comprises initiating combustion proximate
one of said plurality of vertical injection wells situated along said horizontal leg
portion and intermediate opposite ends thereof, so as to thereby form a pair of
vertically-extending combustion fronts advancing laterally in opposite directions along
said horizontal leg portion, and upon said pair of vertically-extending combustion
fronts advancing respectively and laterally along said horizontal well bore past a
-32 -
CAL_LAW\ 1655424 1
further one of said plurality of injection wells, oxidizing gas is injected into said
reservoir at said further one of said injection wells.
19. The method as claimed in claim 17, wherein said step of drilling at least one
injection well comprises drilling a plurality of vertical injection wells directly above
said horizontal leg portion and in alignment therewith and positioned intermediate
opposite ends of said horizontal leg portion, said step of initiating in situ combustion
comprising initiating combustion proximate each of said plurality of vertical injection
wells so as to thereby form pairs of vertically-extending combustion fronts advancing
laterally in opposite directions along said horizontal leg portion and outwardly from
each of said plurality of vertical injection wells.
20. The method as claimed in claim 16, wherein said step of drilling at least one
injection well comprises drilling an injection well directly above said horizontal leg
portion and in alignment therewith and extending intermediate opposite ends of said
horizontal leg portion, said step of injecting an oxidizing gas into said reservoir
comprising injecting said oxidizing gas into said injection well and into the formation
at locations above said horizontal leg portions and along said horizontal leg portion
intermediate opposite ends of said horizontal leg portion; said step of initiating in-situ
combustion comprising initiating combustion proximate each of said locations
situated above and along said horizontal leg portion so as to at each location form
pairs of combustion fronts advancing laterally in opposite directions along said
horizontal leg portion and outwardly from each of said locations.
21. An improved in-situ combustion process for reducing the viscosity of oil
contained in an oil-containing 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;
-33 -
CAL LAW\ 1655424U
(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.