Note: Descriptions are shown in the official language in which they were submitted.
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STAGGERED HORIZONTAL WELL OIL RECOVERY PROCESS
FIELD OF THE INVENTION
The present invention relates to an oil recovery process , and more
particularly to a
method of recovering oil from subterranean hydrocarbon deposits using
horizontal wells and in
situ combustion.
BACKGROUND OF THE INVENTION
There are many oil recovery processes of the prior art employed for the
production of oil
from subterranean reservoirs. Some of these use vertical wells or combine
vertical and
horizontal wells. Examples of pattern processes are the inverted 7-spot well
pattern that has
been employed for steam, solvent and combustion-based processes using vertical
wells, and
the staggered horizontal well pattern of US Patent 5,273,111 which has been
employed (but
limited to) a process using steam injection.
US Patent 5,626,191 to Toe-to-Heel Air Injection (THAI) discloses a repetitive
method
whereby the vertical segment of a vertical-horizontal producer well is
subsequently converted to
an air injection well, to assist in mobilizing oil for recovery by an adjacent
horizontal well, which
is subsequently likewise converted into an air injection well, and the process
repeated.
US Patent 6,167,966 employs a water-flooding process employing a combination
of
vertical and horizontal wells.
US Patent 4,598,770 (Shu et al, 1986) discloses a steam-drive pattern process
wherein
alternating horizontal injection wells and horizontal production wells are all
placed low in a
reservoir. In situ combustion processes are not contemplated.
Joshi in Joshi, S. D., "A Review of Thermal oil Recovery Using Horizontal
wells", In Situ,
11(2 &3), 211-259 (1987), discloses a steam-based oil recovery process using
staggered and
vertically-displaced horizontal injection and production wells pattern. A
major concern is the high
heat loss to the cap rock when steam is injected at the top of the reservoir.
US Patent 5,273,111 (Brannan et al, 1993) teaches a steam-based pattern
process for
the recovery of mobile oil in a petroleum reservoir. A pattern of parallel
offset horizontal wells
are employed with steam injectors. The horizontal sections of the injection
wells are placed in
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the reservoir above the horizontal sections of the production wells, with a
horizontal production
well drilled into the reservoir at a point below the injection wells, but
intermediate said injection
wells. Steam is injected on a continuous basis through the upper injection
wells, while oil is
produced through the lower production wells. Neither in situ combustion nor
line drive
processes are taught.
US Patent 5,803,171 (McCaffery et al, 1998) teaches an improvement of the
Brennan
patent wherein cyclic steam stimulation is used to achieve communication
between the injector
and producer prior to the application of continuous steam injection. In situ
combustion
processes are not mentioned.
US Patent 7,717,175 (Chung et al, 2010) discloses a solvent-based process
utilizing
horizontal well patterns where parallel wells are placed alternately higher
and lower in a
reservoir with the upper wells used for production of solvent-thinned oil and
the lower wells for
solvent injection. Gravity-induced oil-solvent mixing is induced by the
counter-current flow of oil
and solvent. The wells are provided with flow control devices to achieve
uniform injection and
production profiles along the wellbores. The devices compensate for pressure
drop along the
wellbores which can cause non-uniform distribution of fluids within the
wellbore and reduce
reservoir sweep efficiency. In situ combustion processes are not mentioned.
WO/2009/090477 (Xia et al) discloses an in situ combustion pattern process
wherein a
series of vertical wells that are completed at the top are placed between
horizontal producing
wells that are specifically above an aquifer. This arrangement of wells is
claimed to be utilizable
for oil production in the presence of an aquifer.
US Patent Application 2010/0326656 (Menard, 2010) discloses a steam pattern
process
entailing the use of alternating horizontal injection and production wells
wherein isolated zones
of fluid egress and ingress are created along the respective wellbores in
order to achieve
homogeneous reservoir sweep. The alternating wellbores may be in the same
vertical plane or
alternating between low and high in the reservoir, as in US Patent 5,803,171.
Hot vapour is
injected in the upper wells (e.g. steam).
As seen from the above patents, steam-based oil recovery processes are
commonly
employed to recover heavy oil and bitumen from underground formations. For
example, steam-
assisted-gravity-drainage (SAGD) and cyclic steam injection are used for the
recovery of heavy
oil and cold bitumen. When the oil is mobile as native oil or is rendered
mobile by some in situ
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pre-treatment, such as a steam drive process, the thus-mobilized oil can then
drain
downwardly by gravity and be collected by a horizontal collector well.
A serious drawback of steam drive processes is the inefficiency of generating
steam at
the surface because a considerable amount of the heat generated by the fuel is
lost without
providing useful heat in the reservoir. Roger Butler, in his book "Thermal
Recovery of oil and
Bitumen', p. 415,416, estimates the thermal efficiency at each stage of the
steam-injection
process as follows: steam generator, 75-85%; transmission to the well, 75-95%'
flow down the
well to the reservoir, 80-95%; flow in the reservoir to the condensation
front, 25-75%. It is
necessary to keep the reservoir between the injector and the advancing
condensation front at
steam temperature so that the major energy transfer can occur from steam
condensing at the oil
face. In conclusion, 50% or more of the fuel energy can be lost before heat
arrives at the oil
face. The energy costs based on BTU in the reservoir are 2.6-4.4 times lower
for air injection
compared with steam injection. Several other drawbacks occur with steam-based
oil recovery
processes: natural gas may not be available to fire the steam boilers, fresh
water may be scarce
and clean-up of produced water for recycling to the boilers is expensive. In
summary, steam-
based oil recovery processes are thermally inefficient, expensive and
environmentally
unfriendly.
Improved efficiency, shortened time on initial return on investment (ie
quicker initial oil
recovery rates to allow more immediate return on capital invested), and
decreased initial capital
cost, in various degrees, are each areas in the above methods which may be
improved.
SUMMARY OF THE INVENTION
The present invention overcomes problems with the prior art steam¨injection
method of
inter alia US Patent 5,273,111 (Brannan) wherein reservoir heating is
accomplished by the
injection of large quantities of steam, typically under high pressure. Such
prior art method has
the drawbacks of needing to provide large and costly steam-generating
equipment at surface,
and as noted below is thermally inefficient in transferring heat to oil within
the reservoir in order
to achieve the necessary reduction in viscosity to be able to produce oil from
a viscous oil
reservoir.
Thus substantial costs are further incurred in steam recovery methods which
use steam
to heat oil in heating the large quantities of steam needed, over and above
the captical costs of
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acquiring , shipping, and assembling the necessary steam generating equipment
in the form of
boilers, burners, and accociated piping.
Moreover, although in situ combustion oil recovery techniques such as that
disclosed in
US Patent 5,626,191 are known, such typically involve a progression of a
combustion front
perpendicular to and along a horizontal collector well, which combustion front
at any instant is
travelling from a point along the horizontal production well. Accordingly,
such prior art in situ
combustion recovery method does not allow production of oil from within the
underground
formation simultaneously along an entire horizontal length of a production
well.
Advantageously, the applicant has created a method of recovering oil from
within an
underground formation, which is able to incorporate in a particular manner in
situ combustion for
generating heat (and thus unlike US 5,273,111 does not require costly steam-
generating
equipment at surface and injection of steam), and which further, unlike prior
art in situ recovery
methods such as US 5,626,191, is able to simultaneously utilize in situ
heating and importantly
attain production of oil from within a formation along an entire length of a
horizontal collector
well (or wells), and is able to have relatively high initial oil recovery
rates.
Specifically, the method of the present invention has been experimentally
proven, in
certain conditions as discussed later herein, to achieve a higher initial oil
recovery rate than
either the staggered well method of oil recovery using steam injection as
taught in US 5,273,111
[hereinafter the "staggered steam" method] and which disadvantageously need
have costly
steam generating equipment at surface], or a "crossed well" method of oil
recovery which
similarly uses in-situ combustion, the latter being a non-public method of oil
recovery
conceived by the inventor herein and in many respects itself an improvement ,
in certain
respects and to varying degrees, over prior art methods and configurations.
Specifically, for a comparable volumetric sweep area and identical total
cumulative oil
recovery in regard to a subterranean underground reservoir (formation), the
staggered well (air
injection) method of the present invention has been experimentally shown,
under certain
conditions as discussed herein, to provide a greater initial rate of recovery
of oil than the
"staggered steam" method or the "crossed well" method . Thus using the method
of the present
invention a greater and more rapid initial return on investment may be
achieved .
For oil companies incurring large expenditures in developing subterranean
reservoirs,
the ability to utilize a method which will generate revenue quickly and
thereby permit quicker
"pay- down" of initial expenses incurred with regard to search, locating, and
acquiring, and
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initially drilling wells in a hydrocarbon-bearing formation is a significant
advantage . The time
in which a return on investment may be realized is frequently a very real and
substantial
consideration as to whether the investment in such a capital project is or can
ever be made in
the first place.
Accordingly, in one broad embodiment of the oil recovery process of the
present
invention, such method comprises a continuous in situ combustion process using
solely
horizontal wells for injection of an oxidizing gas and for the simultaneous
production of oil, using
a symmetrical array of laterally and vertically offset (ie alternately
'staggered') parallel horizontal
injection and production wells.
More particularly, in one broad embodiment of the oil recovery method of the
present
invention such method comprises the steps of:
(i) drilling a pair of parallel , spaced-apart, upper horizontal wells within
said
hydrocarbon-containing reservoir, substantially coplanar with each other;
(ii) drilling , relatively low in said reservoir, a lower horizontal well
situated below said
upper horizontal wells and positioned substantially parallel to and
intermediate said pair of
upper horizontal wells;
(iii) injecting an oxidizing gas into each of said upper horizontal wells and
injecting said
oxidizing gas into said reservoir via apertures in each of said pair of upper
horizontal wells;
(iv) igniting said oxidizing gas and hydrocarbons then contained within said
formation
and causing oil in said formation to become heated;
(v) recovering oil which has become heated and which has migrated downwardly
in
said subterranean reservoir, in said lower horizontal well ; and
(vi) recovering said oil from said lower horizontal well to surface.
Such method meets the commercial need of having relatively low energy costs
(in that
a separate supply of fuel for boilers to generate steam is not needed), and
has lower initial
capital start-up costs due to lack of need to acquire steam-generating
equipment. Moreover, as
set out below, such novel method for recovering hydrocarbons from a
subterranean formation
has a high initial oil recovery rate which is a significant advantage in
allowing income generated
from the produced oil to be more quickly applied against the significant
expenses of locating,
acquiring, and developing a suitable hydrocarbon containing deposit.
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In a further preferred method of the present invention, such method may
comprise the
further steps of:
(a) drilling a further upper horizontal well within an upper region of said
hydrocarbon-
containing reservoir substantially parallel to and laterally spaced apart from
said upper
horizontal wells;
(b) drilling a further lower horizontal well intermediate said further upper
horizontal well
and a nearest of said previously-drilled upper horizontal wells, said lower
horizontal well
positioned below said upper horizontal wells and positioned substantially
parallel therewith;
(c) injecting said oxidizing gas into said further upper horizontal well and
into said
nearest of said previously-drilled upper horizontal wells so as to thereby
inject said oxidizing gas
into said reservoir via a plurality of apertures in both said further upper
horizontal well and
said nearest of said upper horizontal wells;
(d) collecting oil which has become heated as a result of heat being produced
during
combustion of said oxidizing gas and hydrocarbons in said reservoir
and which oil has
migrated downwardly in said subterranean reservoir, in said further lower
horizontal well;
(e) recovering said oil from said further lower horizontal well to surface.
In a further preferred embodiment, such above method may be used to
progressively
recover oil from an underground formation in a "line drive" manner.
Accordingly, in such "line
drive" embodiment, above steps (a)-(e) are successively repeated to thereby
progress in a
linear direction with drilled horizontal wells so as to progressively recover
oil in said linear
direction from said underground hydrocarbon reservoir.
The distance between the parallel lower horizontal wells, the upper horizontal
wells, as
well as the respective upper and lower well lengths, will all depend upon
specific reservoir
properties . Such distances can, however, be adequately optimized by a
competent reservoir
engineer. The lateral spacing between the horizontal wells can be 25-200
meters, preferably
50-150 meters and most preferably 75-125 meters. The length of the horizontal
well segments
can be 50-2000 meters, preferably 200-1000 meters and most preferably 400-800
meters. The
vertical distance between the upper horizontal injection wells and the lower
horizontal producer
wells is typically dictated by the depth of the oil bearing seam within an
underground formation,
with such depths typically varying between 2 m to 50m , but sometimes greater,
with the
upper horizontal injection wells being located in an upper region of the
hydrocarbon-containing
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seam within the underground formation, and the lower horizontal production
wells located along
a lower base of the oil-containing seam within the underground formation.
In each of the above methods it is further contemplated that hot combustion
gases
which are produced upon ignition of the hydrocarbons and oxidizing gas will
travel from a high
pressure area within the formation (ie typically proximate the upper
horizontal injector wells) to
a low pressure area (ie typically proximate the lower producer wells), and be
further drawn into
and recovered from said lower horizontal well along with said oil to surface.
In a homogeneous reservoir using the method of the present invention it is
beneficial
for high reservoir sweep efficiency to deliver the injectant equally to
perforations in a well liner
within the upper horizontal wells, and to utilize as best as possible equal
oil entry rates at each
perforation along well liner(s) contained within the lower horizontal
(production) well.
Considering that all horizontal wells typically have a `toe' at a distal end
thereof, and a 'heel'
at a proximal end thereof where the horizontal well joins the downwardly-
drilled vertical
segment of a horizontal-vertical well pair, in a refinement of the present
invention the upper
horizontal wells are drilled so that the respective "heels" of the parallel
upper horizontal
(injection) wells are all on a same side of the reservoir, such side being
opposite a side of the
reservoir at which the respective heel (proximal end) of the adjacent
laterally spaced apart
lower horizontal production wells is situated. In other words, the vertical
wells which are
connected to each of the respective upper horizontal wells are on opposite
sides of the reservoir
that the vertical wells for the corresponding lower horizontal wells (and
their associated
respective heel portions) are located. In such manner oxidizing gas which is
injected in the
upper horizontal well (the pressure thereof being highest at the teelqie
proximal] end of such
upper horizontal wells) has less of a tendency to "short-circuit" directly to
the low pressure
portion of the lower horizontal well which is at the heel (proximal) end of
such lower horizontal
well, then located on the opposite side of the reservoir.
Accordingly, in a further preferred embodiment of the present invention the
step of
injecting said oxidizing gas into said upper injection wells comprises the
step of injecting
said oxidizing gas into proximal ends of said upper horizontal wells, such
proximal ends
situated on a side of said underground formation, and said step of withdrawing
oil from said
lower horizontal well comprises withdrawing said oil from a proximal end of
said lower
horizontal well which is situated on another side of said reservoir opposite
said side at which
said proximal ends of said upper horizontal wells are situated.
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In an alternative embodiment which accomplishes the same purpose of reducing
the
tendency of "short circuiting" and advantageously allows both the injection
and production
wells to be drilled with their respective vertical portions (ie proximal ends)
situated on the same
side of the reservoir (ie a drilling pad for drilling each of the upper and
lower wells can thereby
remain on the same side of the reservoir and need not be moved back and forth
to opposite
sides of the reservoir when drilling lower wells and then upper wells),
internal tubing may be
used in the upper injection wells and/ or the lower production well(s).
Specifically, in an alternative embodiment where tubing is employed in the
upper
horizontal wells, such tubing is provided with an open end proximate the
distal end of the upper
horizontal wells. Such allows transfer of the point of injection of the
oxidizing gas (and thus the
high pressure point in such upper horizontal well ) to the distal end thereof.
In such manner the
high pressure source in the upper horizontal injection wells will be at an end
of the reservoir
opposite the low pressure toe of the producing wells, thereby forcing heated
gas to travel a
longer distance through the formation and thereby more effectively heat and
free oil trapped in
the formation, and further avoid "short-circuiting" of combustion gases.
Heated gases are thus
caused to travel through the formation and be collected by the low pressure
area at the toe of
the production well. Such configuration has the benefit of permitting drilling
pads to all be
located on the same side of the reservoir.
Similarly, where tubing is employed in the lower horizontal wells, such tubing
is provided
with an open end proximate the distal end of the lower horizontal wells, with
the proximal ends
of each of the upper production wells, and the lower production well(s)
situated on the same
side of the reservoir. Such tubing allows transfer of the point of recovery of
the produced oil
(and thus transfer of the lowest pressure point in such lower horizontal well
) to the distal end
of the lower production well. In such manner the high pressure source in the
upper horizontal
injection wells will again be at a proximal end thereof, namely at an end of
the reservoir opposite
the low pressure distal (toe) portion of the producing wells, thereby forcing
heated gas to travel
a longer distance through the formation and thereby more effectively heat and
thus free oil
trapped in the formation, and avoid "short-circuiting" of heated gas. Such
configuration, wherein
each of the proximal ends of the upper injector wells and lower production
wells are on the
same side of the reservoir, again has the benefit of permitting all drilling
pads to be located
on the same side of the reservoir.
As an alternative to the employment of configurations which transpose
(reverse) the
respective heel and toe portions of adjacent horizontal wells or alternatively
use internal
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tubing in the injector well, the uniform delivery of gas along the length of
the injection well and
uniform collection in the production well may be obtained, or further
enhanced, by varying the
number and size of perforations along the well liner in an injector well, to
balance the pressure
drop along the well. A pressure-drop-correcting perforated tubing can be
placed inside the
primary liner. This has the advantage of utilizing gas flow in the annular
space to further assist
the homogeneous delivery of gas.
Specifically, the number and size of perforations of the well liner in a
injector producer
well may progressively increase from the heel portion to the toe portion
thereof, in order to
more uniformly distribute such oxidizing gas to the reservoir along the entire
length of the upper
injector wells, and assist in preventing "fingering" of injectant gas directly
into production wells.
Accordingly, in one such embodiment each of said upper horizontal injector
wells has a
well liner in which said plurality of apertures are situated, and wherein a
size of said apertures
or a number of said apertures within said well liner progressively increases
from a proximal
end to a distal end of said upper horizontal wells, and said oxidizing gas is
injected into said
proximal end of each of said upper horizontal wells.
Alternatively, or in addition, said lower horizontal well may be provided with
a well liner
in which a plurality of apertures are situated, and wherein a size of said
apertures or a number
of said apertures within said well liner progressively increases from a
proximal end to a distal
end of said lower horizontal well, in order to more uniformly collect mobile
oil along substantially
the entire length of the production well, and to assist in preventing
"fingering" of injectant gas
directly into production wells.
Accordingly, in a further preferred refinement to better allow the upper
production wells
to more uniformly distribute the oxidizing gas to the formation to avoid
"fingering" or "short
circuiting" of high pressure oxidizing gas directly to production wells, and
to further allow more
uniform and efficient collection of oil from the formation by the lower
production wells, each of
said proximal ends of the upper horizontal injection wells are situated on the
same side of the
reservoir as the proximal ends of each of the lower horizontal producer wells,
and
(i) each of said upper horizontal injector wells has a well liner in which
said plurality of
apertures are situated, and wherein a size of said apertures or a number of
said apertures
within said well liner progressively increases from a proximal end to a distal
end of said upper
horizontal wells, and said oxidizing gas is injected into said proximal end of
each of said upper
horizontal wells; and
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(ii) said lower horizontal well(s) may be provided with a well liner in which
a plurality of
apertures are situated, and wherein a size of said apertures or a number of
said apertures
within said well liner progressively increases from a proximal end to a distal
end of said lower
horizontal well.
The outside diameter of the horizontal well liner segments can be 4 inches to
12 inches,
but preferably 5-10 inches and most preferably 7-9 inches. The perforations in
the horizontal
segments can be slots, wire-wrapped screens, Facsritetm screen plugs or other
technologies
that provide the desired degree of sand retention.
The injected gas may be any oxidizing gas, including but not limited to, air,
oxygen or
mixtures thereof. In a preferred embodiment the oxidizing gas is air but is
further diluted with a
varying quantity a non-oxidizing gas such as carbon dioxide or steam, to
thereby reduce (per
injected volume) the relative concentration of oxygen in such quantity of
injected gas, thereby
allowing control over the temperature produced during combustion by decreasing
the amount of
oxygen allowed to combust with hydrocarbon within the formation.
Alternatively, or in addition, such oxidizing gas contains water vapour, or
water droplets,
or water which turns to steam, which condenses when moving downwardly in the
formation and
which releases heat in the latent heat of condensation thereby assisting in
transferring heat to
oil in the lower portion of the formation and allowing such oil to become
mobile and drain
downwardly into the lower horizontal collector well.
The maximum oxidizing gas injection rate will be limited by the maximum gas
injection
pressure which must be kept below the rock fracture pressure, and will be
affected by the length
of the horizontal wells, the reservoir rock permeability, fluid saturations
and other factors.
The use of a numerical simulator such as that used in the examples below is
beneficial
for confirming the operability and viability of the design of the present
invention for a specific
reservoir, and can be readily conducted by reservoir engineers skilled in the
art.
BRIEF DESCRIPTION OF THE DRAWINGS
In the accompanying drawings, which illustrate one or more exemplary
embodiments
and are not to be construed as limiting the invention to these depicted
embodiments:
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FIG.1 shows a perspective schematic view of a subterranean hydrocarbon-
containing,
showing the 'staggered well " method of the present invention, having a
plurality of upper
horizontal injection wells and a plurality of alternatingly-spaced lower
horizontal production
wells situated low in the reservoir, which uses air injection and in-situ
combustion to provide
heat to mobilize oil in the formation ;
FIG.2 shows a cross-sectional view of FIG.1 taken along plane "A-A" in the
direction of
arrows "A-A;
FIG.3 is a perspective view of the staggered well method of the present
invention, after a
"line drive" method is employed;
FIG.4 (i)-(iii) is a series of three cross-sectional view of FIG.1 taken along
plane "A-A" in
the direction of arrows 'A-A', showing a progression of oil recovery steps
during successive time
intervals during the carrying out of the staggered well "line drive"
embodiment of the present
invention;
FIG.5 shows a perspective schematic view of an alternative "staggered well"
method of
the present inventon, wherein the proximal ends of each of the upper and lower
horizontal wells
are located on the same side of the underground hydrocarbon reservoir;
FIG.6 is an enlarged perspective view of various upper and lower horizontal
wells,
showing a manner of employing tubing in each of the upper horizontal wells in
accordance with
an embodiment of the method of the present invention;
FIG.7 is an enlarged perspective view of various upper and lower horizontal
wells,
showing a manner of employing tubing in the lower horizontal well(s) in
accordance with an
embodiment of the method of the present invention;
FIG.8 is an enlarged perspective view of various upper and lower horizontal
wells,
showing a manner of employing progressively increasing number of apertures in
each of the
well liners of the upper and lower horizontal wells, in accordance with a
further alternative
embodiment of the method of the present invention;
FIG.9 is an enlarged perspective view of various upper and lower horizontal
wells,
showing a manner of employing progressively increasing sizes of apertures in
each of the well
liners of the upper and lower horizontal wells, in accordance with a further
alternative
embodiment of the method of the present invention;
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FIG.10 is an alternative oil recovery method, not part of the present
invention herein, and
is the configuration of the alternative method used for comparison purposes in
comparing
relative oil recovery factor of such method to that of the present invention,
as shown in FIG.11;
and
FIG.11 is a graph showing the percentage of oil recovered from a formation,
using the
method of the present invention (graph "X"); the method of FIG.10 (graph `Y");
and a method
using staggered wells not forming part of the invention which utilizes steam
injection for heating
instead of oxidizing gas injection and in situ combustion for heating (graph
"Z").
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
FIG.'s 1-3 & 5 show a developed subterranean formation/reservoir 22 using an
embodiment of the "staggered well" method of oil recovery of the present
invention (hereinafter
the "Staggered Well" method). In such "Staggered Well" method parallel upper
horizontal
injection wells 1, 1', & 1" of each of length "b" are placed parallel to each
other in mutually
spaced relation, all situated high in a hydrocarbon-containing portion 20 of
thickness "a" which
forms part of subterranean formation/reservoir 22 situated below ground-level
surface 24.
Parallel horizontal , spaced apart lower horizontal production wells 2, 2' &
2" of similar length
"b" are respectively placed low in the reservoir 22, both below and
approximately intermediate
respective injection wells 1, 1', and 1", to make a well pattern array of
staggered and laterally
separated parallel and alternating horizontal gas injection wells 1, 1', & 1"
and oil production
wells 2, 2' & 2" as shown in FIG.'s 1-3 & 5.
The hydrocarbon-containing reservoir 22 shown in FIG.1 possesses two and one-
half
injection wells 1, 1', & 1" and two and one-half production wells 2, 2', & 2"
(edge injection well
1 and edge production well 2" each respectively constituting one-half well)
for a total of five
horizontal wells in the pattern. Conducting three repetitions of the method of
FIG.1 requires
fifteen horizontal wells, as shown in FIG. 3.
The lateral spacing "c" of the upper horizontal injection wells 1, 1', & 1"
and the lower
horizontal injection wells 2, 2' & 2" is preferably uniform.
In the embodiment of the Staggered Well method shown in FIG. 1, the vertical
segments 8 of the horizontal injection wells 1, 1' & 1" are at opposite sides
of reservoir 22
compared with the vertical segments 9 of the horizontal production wells 2, 2'
& 2", each
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vertical segment 8 of associated respective horizontal well 1, 1' & 1"
extending upwardly to
surface 24, and likewise each vertical segment 9 of associated respective
horizontal production
well 2, 2' & 2" extending upwardly to surface 24. ( For purposes of clarity,
only vertical
segments portions 8, 9 of the respective vertical wells extending to surface
24 are depicted in
FIG. 1). Accordingly, the vertical segments 8 of the each of injection wells
1, 1', & 1" in the
embodiment of the method shown in FIG. 1 are thus longitudinally offset by the
well length 'b'
from the respective vertical segments 9 (and corresponding associated
horizontal production
wells 2, 2' & 2".
Vertical segments 9 and associated horizontal production wells 2, 2', & 2"
which are
situated intermediate horizontal injection wells 1, 1' &1", are laterally
offset from horizontal
injection wells 1, 1' &1" and associated vertical segments 8 a distance "c" .
The reason for
such lateral offset "c" is to eliminate or at least minimize "short-
circuiting" of injected oxidizing
gas directly from injection wells 1, 1', & 1" into production wells 2, 2' & 2"
as explained above.
The pattern shown in FIG. 1 can be extended indefinitely away from the face 3
and/or
the face 6 as desired to cover a specific volume of oil reservoir 22. In
further phases of the
reservoir development, as shown in FIG. 3, an additional array of injections
wells 1, 1', & 1"
and production wells 2, 2' & 2" are drilled adjacent to the first array of
FIG. 1, and such process
repeated , eventually exploiting the entire reservoir 22.
Referring to FIG.1 showing one embodiment of the invention, horizontal
injector wells 1
& 1' and production well 2 are drilled, in a preferred embodiment each being
provided with
well liner segments 30 situated in each of horizontal wells 1, 1', & 1" and 2,
2' & 2" . Well
liner segments 30 each contain apertures or slots 24 from which an oxidizing
gas , which may
further include carbon dioxide and/or steam, is injected into formation 22 via
an injector wells
1, 1'.
Upon ignition of the so-formed oxidizing gas and hydrocarbon mixture in the
reservoir
22, and in particular in the oil-bearing seam 20 thereof, heated oil and
combustion gas (not
shown) contained with reservoir partition segments 50a, 50b flow and are drawn
downwardly
due to lower pressures toward production well 2 , and are drawn into and enter
production well
2 via apertures 24 therein. Thereafter such collected oil and combustion gases
(not shown) are
drawn to surface 24 via gas lift or pump means.
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In the case of horizontal production wells 2, 2' & 2", well liners 30 and the
apertures 24
therein may take the form of slotted liners, wire-wrapped screens, FacsRitel
well liners having
sand screen plugs , or combinations thereof, to reduce the flow of sand and
other undesirable
substances such as drill cuttings from within the formation 22 into production
wells 2, 2' & 2".
The Staggered Well (Air Injection) method may utilize a "line drive"
configuration, by
drilling another injection well 1" and a corresponding production well 2', as
shown in FIG. 1.
Such method is better illustrated in Fig. 4 (i)-(iii), in which three
successive phases are
implemented and depicted. In this regard, FIG. 4 shows views on section A-A of
FIG.1, at
successive respective time intervals (i), (ii), & (iii), showing a method of
causing a" line drive"
of oil recovery in the direction "Q", and in particular the remaining portions
of oil bearing seam
which continue to possess oil and thus illustrates the progressive recovery of
oil from oil
bearing seam 20. Specifically, as seen from the first phase [FIG. 4 (i) ], the
injector wells 1, 1',
and 1", and producer well 2 and 2' are first drilled, and after injection of
oxidizing gas into
formation 22 via injection wells 1, 1' & 1" and ignition of the so-formed
mixture of oxidizing gas
15
and hydrocarbons in reservoir 22, production of oil from well 2 and 2' is
commenced, causing
depletion of oil from oil bearing seam 20, as shown in FIG. 4(i). Thereafter
in a second phase
[FIG.4(ii)] , a further producer well 2" is drilled, and injection and
production commenced
respectively in regard to injector wells 1, 1', and production well 2' . In a
third phase [FIG. 4(iii)],
a fourth injector 1" and a fourth producer 2" are drilled, with production
ceasing from
20
production well 2, and injection and production commenced in injection well 1"
and production
well 2" respectively. The process may be continued indefinitely as shown in
FIG. 3 , until
reaching an end of reservoir 22.
Alternatively, as mentioned above, such "Staggered Well (Air Injection) "
method may
simply consist of simultaneously drilling a set number of injector wells (eg
such as three wells
1, 1', & 1") and a corresponding number of producer wells (eg such as three
wells 2, 2' & 2"),
so as to produce the "pattern" of staggered wells of wells 1, 1', & 1" and 2,
2' & 2" shown in
FIG.1, and produce oil from reservoir partition segments 50a, b,
50c, d, and 50e. Such
pattern may be repeated as necessary, as shown in FIG. 3 through well
partition segments 50f-
500, in order to exploit an entire reservoir 22.
FIG. 5 shows an alternate embodiment of the Staggered Well (Air Injection)
method of
1
unregistered trademark of Absolute Completion Technologies for well liners
having sand screens therein
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the present invention, where each of vertical segments 8, 9 of corresponding
horizontal wells 1,
1', & 1" and 2, 2', & 2" respectively, are drilled on the same side 4 of
reservoir 22.
Advantageously, as discussed above, such configuration allows a drilling pad
for drilling wells 1,
1', & 1" and 2, 2', & 2" to remain on the same side 4 of reservoir 22, thus
increasing the speed
and ease by which the wells 1, 1', & 1" and 2, 2', & 2" may be drilled.
When vertical segments 8,9 of corresponding horizontal wells 1, 1', & 1" and
2, 2', &
2" respectively are drilled on the same side 4 of reservoir 22 as shown in
FIG. 5, to better and
more uniformly inject oxidizing gas into formation 22 via horizontal wells 1,
1', & 1" , and/or to
more uniformly collect oil in horizontal wells 2, 2', & 2" , it is preferred
to use tubing 40 in the
manner described below.
Specifically, in a first embodiment employing tubing 40, tubing 40 is inserted
in upper
horizontal injection wells 1', 1", 1" of FIG. 1 and in all injection wells, if
desired. FIG. 6
shows an exemplification of such concept using tubing 40 in two adjacent
injection wells 1', 1".
Such tubing 40 preferentially extends from the heel 43 at the vertical portion
8 of each of wells
1', 1" to the toe portion 44 of each of such wells 1', 1". Gaseous air "G" is
injected into tubing
40, which air "G" thereafter flows into injection wells 1', 1" and thereafter
into oil bearing seam
of formation 22 via apertures 24 in well liner segments 30 as shown in FIG. 6.
Heated oil "0"
flows into apertures 24 in well liners 30 of producer well 2', and is
thereafter produced to surface
24 (see FIG 1) .
20
Alternatively, in a second alternative embodiment employing tubing 40, tubing
40 is
inserted in lower production wells 2, 2", 2", and 2" of FIG. 1 and in all
injection wells, if
desired. FIG. 7 shows an exemplification of such concept using tubing 40 in
one production well
2'.
Such tubing 40 preferentially extends from the heel 43 at the vertical
portion 9 of
production 2' to the toe portion 44 thereof, as shown in FIG. 7. Oil "0" is
withdrawn from toe 44
of production well 2' via tubing 40, such oil "0" entering apertures 24 in
well liners 30 in
production well 2', and is thereafter produced to surface 24 (see FIG 1) .
Alternativelyõ instead of using tubing 40 within the method of the present
invention to
more uniformly heat the oil in the formation, prevent short-circuiting between
injector wells 1, 1',
1", and producer wells 2, 2', 2", and 2-, and thereby better collect oil "0"
in horizontal wells 2,
2', & 2" , it is contemplated that either the number or size of apertures 24
in well liners 30 in
production wells 2, 2', 2", be progressively increased from heel 42 to toe 44.
Specifically, FIG. 8 shows one such embodiment being utilized in respect of a
single
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production well 2' , where the number of apertures 24 in well liners 30 in
production wells 2,
2', 2", is progressively increased from heel 42 to toe 44.
FIG. 9 shows another alternative embodiment of such concept being utilized in
respect
of a single production well 2' , where the size of apertures 24 in well liners
30 in production
wells 2, 2', 2", is progressively increased from heel 42 to toe 44.
EXAMPLES
Extensive computer simulation of processes for the recovery of mobile oil were
undertaken using the STARSTm Thermal Simulator 2010.12 provided by the
Computer
Modelling Group, Calgary, Alberta, Canada.
The model dimensions used in comparative Examples 1-3 below in number of grid
blocks were 20x50x20 and the grid block sizes were respectively 5.0m, 5.0m and
1.0m,
resulting in the same total reservoir volume in each case of 500,000 m3 (ie
100m x 250m x
20m).
The modelling reservoir used in each of comparative Examples 1-3 below
contained
bitumen at elevated temperature (54.4 C) with high rock permeability.
In each of comparative Examples 1-3 below, the total number of wells used for
comparative purposes was the same.
Specifically, for the Staggered Well (Air Injection) method, namely a method
of the
present invention (Example 1 below), a total of five wells were employed,
namely 2.5 injection
wells 1, 1', and 1", and 2.5 production wells 2, 2', and 2", keeping in mind
that injection well 1
and production well 2" which appear at the end of grid block 50a and 50e,
respectively, are
counted as half-wells.
For the Staggered Steam configuration and method (eg as per FIG. 1, but not
using air
injection or in situ combustion-see Example 2 below), a total of five wells
consisting of 2.5
injection wells 1, 1', and 1", and 2.5 production wells 2, 2', and 2", again
keeping in mind that
injection well 1 and production well 2" which appear at the end of grid block
50a and 50e,
respectively, are counted as half-wells.
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With regard to the "crossed-wells" configuration/method as shown in FIG. 10
(see
Example 3, below) , a similar total of five wells were used, namely two (2)
injection wells 1', 1",
and three (3) production wells 2, 2', 2", and 2", again keeping in mind that
production well 2
and production well 2" which each appear at the end of the grid block shown in
FIG. 10 are
counted as half-wells.
With regard to each comparative model described in Examples 1-3 below, each
model
received an identical amount of gaseous injection, namely a total of 50,000 m3
/day, with
Examples 1 and 3 receiving air injection, and Example 2 receiving gaseous
steam injection.
For combustion simulations with air the reactions used:
1. 1.0 Oil - 0.42 Upgrade (C161-134) + 1.3375 CH4 + 29.6992 Coke
2. 1.0 Oil + 13.24896 02 ---> 5.949792 H20 + 6.0 CH4 + 9.5 CO2 + 0.5 CO/N2 +
27.3423
Coke
3. 1.0 Coke + 1.2575 02 ---> 0.565 H20 + 0.95 CO2 + 0.05 CO/N2
In order to improve sweep efficiency, the transmissibility of the oil
production wells 2, 2',
2", and 2" was varied monotonically from 1.0 at the toe to 0.943 at the heel.
Practically
speaking, as described herein, such diminished transmissibility of the oil
along the length of a
production well 2, 2', 2", and/or 2" can be accomplished by progressively
decreasing either
the aperture 24 size , or number of apertures 24 of sequential slotted liner
segments 30 from
toe 44 to heel 42 of production wells 2, 2', 2", or 2" (see for example FIG.
8, FIG. 9,
respectively).
Additional reservoir properties for each of the reservoirs 22 and comparative
methods of
oil extraction modelled in Examples 1-3 below were set out in TABLE 1, below:
Table 1. Reservoir properties, oil properties and well control.
Reservoir Properties
Parameter Units Value
Pay thickness m 20
Porosity 30
Oil saturation 80
Water saturation 20
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Gas mole fraction fraction 0.263
H. Permeability mD 5000
V. Permeability mD 3400
Reservoir temperature C 54.4
Reservoir pressure kPa 3000
Rock compressibility /kPa 3.5E-5
Conductivity J/m.d.0 1.5E+5
Rock Heat capacity J/m3-C 2.35E+6
Oil Properties
Density Kg/m3 1009
Viscosity, dead oil @ 20 C. cP 77,000
Viscosity, in situ cP 1139
Average molecular weight oil AMU 598
Average molecular weight AMU 224
Upgrade
Oil mole fraction Fraction 0.737
Compressibility /kPa 1.06E+3
The wells were controlled
using the following
parameters:
Maximum air injection pressure kPa 7,000
Horizontal well length m 500
Producer BHP minimum kPa 2600
Total air or steam injection rate m3/d 50,000
Example 1- [Staggered Well (Air Injection) Method]
FIG.'s 1 and 4 (i)-(iii) depict a method of oil recovery (using air injection
and in situ
combustion heating) of the present invention, and in particular depict the
method used in
Example 1 [Staggered Well (Air Injection) ], utilizing a total air injection
volume of 50,000 m3/d.
For the Staggered Well ( Air Injection) Method as shown in FIG.1, 2.5
injection wells
1, 1', and 1", and 2.5 production wells 2, 2', and 2' as part of grid blocks
50a-50e, were all
simultaneously drilled, for a total of five wells . The reservoir thickness
'a' was 20m and the
well offset 'c' was 50m for each grid block 50a-500. Air injection rates were
10,000 m3/d for
well 1 and 20,000 m3/d for each of injectors 1' and 1", for a total of 50,000
m3/d for the grid
block pattern 50a-50e.
A summary of results, namely the Oil Recovery Factor over time (1,825days=5
years)
for Example 1, is shown in FIG. 11 as line 'X'.
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Example 2- [Crossed- Wells Method]
FIG. 10 shows an alternative method of oil recovery from a subterranean
reservoir 22,
which is not the subject matter of this application but of another patent
application of the within
inventor and commonly assigned (hereinafter the "crossed wells" method).
In the crossed-well method depicted in FIG. 10, injector wells 1, 1' are
perpendicularly
disposed to the horizontal collection wells 2, 2', 2", and 2". Specifically in
this crossed-well
method, parallel horizontal well injection wells 1, 1' are placed high in
reservoir 22, and parallel
horizontal production wells 2, 2', 2", & 2" are placed low in reservoir 22
perpendicular to
injection wells 1, 1'. Horizontal Injection well 1' is located distance 'q'
(25m) from the front
edge of the model and injection well 1 is placed distance 'q' from the back
side of reservoir 22,
namely with injectors 1, 1' separated by a distance '2q' . The well length is
"b". The spacing of
the horizontal production wells is "c", for a total grid block volume of
500,000m3.
The air injection rate into the upper injection wells 1, 1' was 50,000 m3/d,
divided
equally between injector wells 1, 1'. Air was injected continuously and oil,
water and gas were
produced continuously from the lower wells 2, 2', 2" & 2".
A summary of results, namely the Oil Recovery Factor over time (1,825days=5
years)
for Example 2, is shown in FIG. 11 as line 'Y'.
Example 3- [Staggered Steam Method]
Example 3 (method of FIG. 1, but with hot steam injection instead of air
injection and
not employing in situ combustion) is not part of the present invention, and is
only provided to
illustrate the comparative efficiency with other oil recovery methods (eg
Example 1 and
Example 2).
Saturated steam was injected continuously at the rate of 150, 300 and 300 m3/d
(water
equivalent- for a total of 50,000 m3/d gaseous equivalent) into injection
wells 1, 1' and 1"
respectively, while production wells 2, 2' and 2" were open to production.
A summary of results of the Staggered Steam method, showing the Oil Recovery
Factor
over time (1,825days=5 years) for Example 3, is shown in FIG. 11 as line
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COMPARISON AND PROVEN ADVANTAGES
Comparing lines 'Y" (Crossed-wells) and line "X" [the present invention,
Staggered Wells
(Air Injection) ] it is clear that at any selected time the oil recovery is
higher with the present
invention.
Comparing line "Z" (Staggered Steam injection ) with line "X" of the present
invention
[Staggered Wells (Air Injection) ] the benefit of higher early oil rate with
the present invention is
even greater.
The higher Oil Recovery Factors at 2.4 years and 5.0 years of the present
invention
(Line "X") show the significant financial advantage of the present invention
considering the
earlier return on investment in the form of earlier and greater oil recovery.
Also, with a lower
Air/Oil ratio than the steam injection method (Example 3) , the present
invention (Example 1) will
carry lower air compression costs. Because of the thermal inefficiency of
steam processes, the
Staggered Steam process is not competitive.
Table 2. Oil recovery Factors and energy requirements.
Well Line Oil recovery Cumulative Oil recovery
CumulativeAir/Oil Relative
Arrangement factor, % Oil factor at 5- Ratio
energy
2.4-years 5-year, km3 years, %
cost
(874 days) (1827 days)
Crossed Wells*
(Example 2 and FIG. "Y" 49.9 93.3 80.0 980
1.0
10)*
Staggered Steam
Injection* (Example 3 "Z" 40.7 98.2 82.7
N/A 2.2-4.4
and FIG. 1)
Staggered Wells (Air
Injection) (Example 1 "X" 56.5 98.2 81.2
866 1.0
and FIG. 1)
* Does not form part of the invention claimed herein
The scope of the claims should not be limited by the preferred embodiments set
forth in
the foregoing examples, but should be given the broadest interpretation
consistent with the
description as a whole, and the claims are not to be limited to the preferred
or exemplified
embodiments of the invention.
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