U.S. patent application number 13/314055 was filed with the patent office on 2013-06-13 for staggered horizontal well oil recovery process.
This patent application is currently assigned to Archon Technologies Ltd.. The applicant listed for this patent is Conrad AYASSE. Invention is credited to Conrad AYASSE.
Application Number | 20130146284 13/314055 |
Document ID | / |
Family ID | 48570930 |
Filed Date | 2013-06-13 |
United States Patent
Application |
20130146284 |
Kind Code |
A1 |
AYASSE; Conrad |
June 13, 2013 |
STAGGERED HORIZONTAL WELL OIL RECOVERY PROCESS
Abstract
An in situ combustion process entailing the simultaneous
production of oil and combustion gases that combines fluid drive,
gravity phase segregation and gravity drainage to produce
hydrocarbons from a subterranean oil-bearing formation, comprising
initially injecting a gas through a pair of horizontal wells placed
high in the formation and producing combustion gas and oil through
parallel and laterally offset horizontal wells that are placed low
in the formation intermediate the pair of horizontal wells placed
high in the formation.
Inventors: |
AYASSE; Conrad; (Calgary,
CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
AYASSE; Conrad |
Calgary |
|
CA |
|
|
Assignee: |
Archon Technologies Ltd.
Calgary
CA
|
Family ID: |
48570930 |
Appl. No.: |
13/314055 |
Filed: |
December 7, 2011 |
Current U.S.
Class: |
166/256 |
Current CPC
Class: |
E21B 43/243 20130101;
E21B 43/305 20130101 |
Class at
Publication: |
166/256 |
International
Class: |
E21B 43/24 20060101
E21B043/24 |
Claims
1. An in situ combustion method for recovering oil from a
hydrocarbon-containing subterranean reservoir, comprising the steps
of: (i) drilling a pair of parallel, spaced-apart, upper horizontal
wells within said hydrocarbon-containing reservoir and within a
horizontal plane therein; (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 within said formation and causing oil in said
formation intermediate said upper horizontal wells 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.
2. A method for recovering oil from a hydrocarbon-containing
subterranean reservoir as claimed in claim 1, comprising 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 upper horizontal wells, 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 upper horizontal wells so as to
thereby inject said oxidizing gas into said reservoir via a
plurality of apertures in 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 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.
3. A method for recovering oil from a hydrocarbon-containing
subterranean reservoir as claimed in claim 2, comprising the
further steps of: (f) successively repeating steps (a)-(e) 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.
4. A method for recovering oil from a hydrocarbon-containing
subterranean reservoir as claimed in claim 1, 2, or 3, wherein hot
combustion gases are further drawn into and recovered to surface
from said lower horizontal well along with said oil.
5. A method for recovering oil from a hydrocarbon-containing
subterranean reservoir as claimed in claim 1 wherein said 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 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.
6. A method for recovering oil from a hydrocarbon-containing
subterranean reservoir as claimed in claim 1 wherein said step of
injecting said oxidizing gas into said upper horizontal wells
comprises the step of injecting said oxidizing gas into proximal
ends of said upper horizontal wells 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 distal
ends of said lower horizontal well situated on another side of said
reservoir opposite said side at which said proximal ends of said
upper horizontal wells are situated.
7. A method for recovering oil from a hydrocarbon-containing
subterranean reservoir as claimed in claim 6, wherein production
tubing is positioned in said lower horizontal well and which tubing
has an open end proximate a distal end of said lower horizontal
well, said step of recovering oil from said lower horizontal well
comprising the step of recovering said oil via said open end of
said tubing.
8. A method for recovering oil from a hydrocarbon-containing
subterranean reservoir as claimed in claim 1 wherein production
tubing is positioned in each of said upper horizontal wells and
which tubing has an open end proximate a respective distal end of
each of said upper horizontal wells, said step of injecting
oxidizing gas into said formation comprising injecting said
oxidizing gas into said tubing situated in each of said upper
horizontal wells and thus into distal ends thereof, 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 a same side of said reservoir on which
proximal ends of said upper horizontal wells are situated.
9. A method for recovering oil from a hydrocarbon-containing
subterranean reservoir as claimed in claim 1, wherein each of said
upper horizontal 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.
10. A method for recovering oil from a hydrocarbon-containing
subterranean reservoir as claimed in claim 1, wherein said lower
horizontal well has 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, and
said oil is recovered from said proximal end of said lower
horizontal well.
11. A method for recovering oil from a hydrocarbon-containing
subterranean reservoir as claimed in claims 9 and 10.
12. A method for recovering oil from a hydrocarbon-containing
subterranean reservoir as claimed in claim 11, wherein proximal
ends of said upper wells and proximal ends of said lower horizontal
wells are situated on a same side of said reservoir.
13. A method for recovering oil from a hydrocarbon-containing
subterranean reservoir as claimed in claim 1, wherein a volume of
said oxidizing gas injected into said subterranean reservoir is
equal or less than a volume of oil recovered from said horizontal
wells located low in the reservoir.
14. A method of recovering oil from a hydrocarbon-containing
subterranean reservoir as claimed in claim 1, wherein said
oxidizing gas comprises oxygen or air.
15. A method of recovering oil from a hydrocarbon-containing
subterranean reservoir as claimed in claim 1, wherein said
oxidizing gas further comprises water, steam, or carbon
dioxide.
16. A line-drive method for recovering oil from a
hydrocarbon-containing subterranean reservoir, comprising the steps
of: (i) drilling a pair of parallel, spaced-apart, upper horizontal
wells within an upper region of 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 within said formation and causing oil
in said formation intermediate said upper horizontal wells 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 recovering said oil from said lower
horizontal well to surface. (vi) 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; (vii)
drilling a further lower horizontal well intermediate said further
upper horizontal well and a nearest of said upper horizontal wells,
positioned below said upper horizontal wells and positioned
substantially parallel therewith; (viii) injecting said oxidizing
gas into said further upper horizontal well and into said nearest
of said upper horizontal wells so as to thereby inject said
oxidizing gas into said reservoir via a plurality of apertures in
said further upper horizontal well and said nearest of said upper
horizontal wells; (ix) 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 has migrated
downwardly in said subterranean reservoir, in said further lower
horizontal well; (x) recovering said oil from said further lower
horizontal well to surface; and (xi) successively repeating steps
(vi)-(x) 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.
17. A method of recovering oil from a hydrocarbon-containing
subterranean reservoir as claimed in claim 16, wherein said
oxidizing gas comprises a mixture of (i) air and steam; (ii) air
and suspended water droplets; or (iii) air and water vapour.
Description
FIELD OF THE INVENTION
[0001] 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
[0002] 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 U.S. Pat. No. 5,273,111 which has been
employed (but limited to) a process using steam injection.
[0003] U.S. Pat. No. 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.
[0004] U.S. Pat. No. 6,167,966 employs a water-flooding process
employing a combination of vertical and horizontal wells.
[0005] U.S. Pat. No. 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.
[0006] 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.
[0007] U.S. Pat. No. 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 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.
[0008] U.S. Pat. No. 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.
[0009] U.S. Pat. No. 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.
[0010] WO/2009/090477 (Xai 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.
[0011] 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 U.S. Pat. No. 5,803,171. Hot
vapour is injected in the upper wells (e.g. steam).
[0012] 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
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.
[0013] 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.
[0014] Improved efficiency, shortened time on initial return on
investment (i.e. 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
[0015] The present invention overcomes problems with the prior art
steam-injection method of inter alfa U.S. Pat. No. 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.
[0016] 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
acquiring, shipping, and assembling the necessary steam generating
equipment in the form of boilers, burners, and associated
piping.
[0017] Moreover, although in situ combustion oil recovery
techniques such as that disclosed in U.S. Pat. No. 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.
[0018] 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 U.S. Pat. No. 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 U.S. Pat. No. 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.
[0019] 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 U.S. Pat. No. 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.
[0020] 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.
[0021] 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 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.
[0022] 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 (i.e. alternately `staggered`) parallel
horizontal injection and production wells.
[0023] More particularly, in one broad embodiment of the oil
recovery method of the present invention such method comprises the
steps of:
[0024] (i) drilling a pair of parallel, spaced-apart, upper
horizontal wells within said hydrocarbon-containing reservoir,
substantially coplanar with each other;
[0025] (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;
[0026] (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;
[0027] (iv) igniting said oxidizing gas and hydrocarbons then
contained within said formation and causing oil in said formation
to become heated;
[0028] (v) recovering oil which has become heated and which has
migrated downwardly in said subterranean reservoir, in said lower
horizontal well; and
[0029] (vi) recovering said oil from said lower horizontal well to
surface.
[0030] 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.
[0031] In a further preferred method of the present invention, such
method may comprise the further steps of:
[0032] (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;
[0033] (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;
[0034] (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;
[0035] (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;
[0036] (e) recovering said oil from said further lower horizontal
well to surface.
[0037] 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.
[0038] 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 50 m, but sometimes greater, with the upper
horizontal injection wells being located in an upper region of the
hydrocarbon-containing 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.
[0039] 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 (i.e. typically proximate the upper
horizontal injector wells) to a low pressure area (i.e. typically
proximate the lower producer wells), and be further drawn into and
recovered from said lower horizontal well along with said oil to
surface.
[0040] 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 "heel" [i.e. 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.
[0041] 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.
[0042] 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 (i.e. proximal
ends) situated on the same side of the reservoir (i.e. 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).
[0043] 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.
[0044] 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.
[0045] 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 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.
[0046] 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.
[0047] 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.
[0048] 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.
[0049] 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
[0050] (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
[0051] (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.
[0052] 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, Facsrite.TM. screen plugs or
other technologies that provide the desired degree of sand
retention.
[0053] 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.
[0054] 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.
[0055] 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.
[0056] 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
[0057] 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:
[0058] 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 ;
[0059] FIG. 2 shows a cross-sectional view of FIG. 1 taken along
plane "A-A" in the direction of arrows "A-A;
[0060] FIG. 3 is a perspective view of the staggered well method of
the present invention, after a "line drive" method is employed;
[0061] 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;
[0062] FIG. 6 shows a perspective schematic view of an alternative
"staggered well" method of the present invention, wherein the
proximal ends of each of the upper and lower horizontal wells are
located on the same side of the underground hydrocarbon
reservoir;
[0063] 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;
[0064] 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;
[0065] 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;
[0066] 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;
[0067] 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
[0068] 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
[0069] FIGS. 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 FIGS. 1-3 & 5.
[0070] 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.
[0071] 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.
[0072] 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 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''.
[0073] 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 8a 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.
[0074] 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.
[0075] 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'.
[0076] 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.
[0077] 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, FacsRite.TM. 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''.
[0078] 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), & (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 20 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
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 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.
[0079] Alternatively, as mentioned above, such "Staggered Well (Air
Injection)" method may simply consist of simultaneously drilling a
set number of injector wells (e.g. such as three wells 1, 1', &
1'') and a corresponding number of producer wells (e.g. 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-50o, in order to
exploit an entire reservoir 22.
[0080] FIG. 5 shows an alternate embodiment of the Staggered Well
(Air Injection) method of unregistered trademark of Absolute
Completion Technologies for well liners having sand screens therein
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.
[0081] 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.
[0082] 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 20 of
formation 22 via apertures 24 in well liner segments 30 as shown in
FIG. 6. Heated oil "O" flows into apertures 24 in well liners 30 of
producer well 2', and is thereafter produced to surface 24 (see
FIG. 1)
[0083] 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 "O" is withdrawn from
toe 44 of production well 2' via tubing 40, such oil "O" entering
apertures 24 in well liners 30 in production well 2', and is
thereafter produced to surface 24 (see FIG. 1).
[0084] Alternatively, 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 "O" 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.
[0085] Specifically, FIG. 8 shows one such embodiment being
utilized in respect of a single 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.
[0086] 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
[0087] Extensive computer simulation of processes for the recovery
of mobile oil were undertaken using the STARS.TM. Thermal Simulator
2010.12 provided by the Computer Modelling Group, Calgary, Alberta,
Canada.
[0088] The model dimensions used in comparative Examples 1-3 below
in number of grid blocks were 20.times.50.times.20 and the grid
block sizes were respectively 5.0 m, 5.0 m and 1.0 m, resulting in
the same total reservoir volume in each case of 500,000 m.sup.3
(i.e. 100 m.times.250 m.times.20 m).
[0089] The modelling reservoir used in each of comparative Examples
1-3 below contained bitumen at elevated temperature (54.4.degree.)
with high rock permeability.
[0090] In each of comparative Examples 1-3 below, the total number
of wells used for comparative purposes was the same.
[0091] 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.
[0092] For the Staggered Steam configuration and method (e.g. 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.
[0093] 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.
[0094] 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 m.sup.3/day, with Examples 1
and 3 receiving air injection, and Example 2 receiving gaseous
steam injection.
[0095] For combustion simulations with air the reactions used:
[0096] 1. 1.0 Oil.fwdarw.0.42 Upgrade (C.sub.16H.sub.34)+1.3375
CH.sub.4+29.6992 Coke [0097] 2. 1.0 Oil+13.24896
O.sub.2.fwdarw.5.949792 H.sub.2O+6.0 CH.sub.4+9.5 CO.sub.2+0.5
CO/N2+27.3423 Coke [0098] 3. 1.0 Coke+1.2575 O.sub.2.fwdarw.0.565
H.sub.2O+0.95 CO.sub.2+0.05 CO/N2
[0099] 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).
[0100] 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-US-00001 TABLE 1 Reservoir properties, oil properties and
well control. Parameter Units Value Reservoir Properties Pay
thickness m 20 Porosity % 30 Oil saturation % 80 Water saturation %
20 Gas mole fraction fraction 0.263 H. Permeability mD 5000 V.
Permeability mD 3400 Reservoir temperature .degree. C. 54.4
Reservoir pressure kPa 3000 Rock compressibility /kPa 3.5E-5
Conductivity J/m.d.C 1.5E+5 Rock Heat capacity J/m.sup.3-C 2.35E+6
Oil Properties Density Kg/m.sup.3 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 m.sup.3/d
50,000
Example 1
Staggered Well (Air Injection) Method
[0101] FIGS. 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 m.sup.3/d.
[0102] For the Staggered Well (Air Injection) Method as shown in
FIGS. 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 20 m and the well offset `c` was 50 m for each
grid block 50a-50o. Air injection rates were 10,000 m.sup.3/d for
well 1 and 20,000 m.sup.3/d for each of injectors 1' and 1'', for a
total of 50,000 m.sup.3/d for the grid block pattern 50a-50e.
[0103] A summary of results, namely the Oil Recovery Factor over
time (1,825 days=5 years) for Example 1, is shown in FIG. 11 as
line `X`.
Example 2
Crossed-Wells Method
[0104] 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).
[0105] 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` (25 m) 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
`2 q`. The well length is "b". The spacing of the horizontal
production wells is "c", for a total grid block volume of 500,000
m.sup.3.
[0106] The air injection rate into the upper injection wells 1, 1'
was 50,000 m31/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''.
[0107] A summary of results, namely the Oil Recovery Factor over
time (1,825 days=5 years) for Example 2, is shown in FIG. 11 as
line `Y`.
Example 3
Staggered Steam Method
[0108] 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 (e.g. Example 1 and Example 2).
[0109] Saturated steam was injected continuously at the rate of
150, 300 and 300 m.sup.3/d (water equivalent--for a total of 50,000
m.sup.3/d gaseous equivalent) into injection wells 1, 1' and 1''
respectively, while production wells 2, 2' and 2'' were open to
production.
[0110] A summary of results of the Staggered Steam method, showing
the Oil Recovery Factor over time (1,825 days=5 years) for Example
3, is shown in FIG. 11 as line `Y`.
COMPARISON AND PROVEN ADVANTAGES
[0111] 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.
[0112] 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.
[0113] 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-US-00002 TABLE 2 Oil recovery Factors and energy
requirements. Oil recovery Cumulative factor, % Oil Oil recovery
Cumulative Relative Well 2.4-years 5-year, km.sup.3 factor at
Air/Oil energy Arrangement Line (874 days) (1827 days) 5-years, %
Ratio cost Crossed Wells* "Y" 49.9 93.3 80.0 980 1.0 (Example 2 and
FIG. 10)* Staggered Steam "Z" 40.7 98.2 82.7 N/A 2.2-4.4 Injection*
(Example 3 and FIG. 1) Staggered Wells "X" 56.5 98.2 81.2 866 1.0
(Air Injection) (Example 1 and FIG. 1) *Does not form part of the
invention claimed herein
[0114] 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.
* * * * *