HORIZONTAL WELL LINE-DRIVE OIL RECOVERY PROCESS
FIELD OF THE INVENTION
The present invention relates to an oil extraction process, and more particularly to a
method of extracting oil from subterranean hydrocarbon deposits using horizontal wells.
BACKGROUND OF THE INVENTION
Steam-based oil recovery processes are commonly employed to recover heavy oil and
bitumen. 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, the steam drive process may also be used. A
serious drawback of steam 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.
4 15,41 6, 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.
There are many well patterns that can be 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 discloses a repetitive method, termed "toe-to-heel" air injection
(THAI™ ) , whereby a horizontal well is subsequently converted to an air injection we l 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 5,273,1 11 (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 the steam injectors. The horizontal sections of the injection wells are placed
in the reservoir above the horizontal sections of the production wells, with the horizontal
sections of the production wells being drilled into the reservoir at a point between the base of
the reservoir and the midpoint of the reservoir. Steam is injected on a continuous basis through
the upper injection wells, while oil is produced through the lower production wells. In situ
combustion processes are not mentioned.
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
THAI™ is a registered trademark of ARCHON Technologies Ltd. of Calgary, Alberta for "Oil recovery services,
namely, the recovery of oil from subterranean formations through in-situ combustion techniques
and methodologies and oil upgrading catalysts"
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 (Xiai and Mauduit, 2009) 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 a angement 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 i the reservoir, as in US Patent 5,803,171. Hot vapour is
injected in the upper wells (e.g. Steam).
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
An ideal oil recovery processes for recovering oil from an underground reservoir has a
high sweep efficiency, uses a free (no cost) and infinitely available injectant, requires no
purchased fuel, generates heat precisely where it is needed- at the oil face, and scavenges
heat from the reservoir where heating of a reservoir was used . Additionally, a high oil
production rate, especially in the initial stage of the exploitation, is critical to the viability and/or
profitability of an oil recovery process.
The present invention, a horizontal well line-drive process for recovery of oil from
hydrocarbon-containing underground reservoirs, has two advantages over a "Staggered Well"
pattern configuration of oil recovery, the latter being a non-public method of oil recovery
conceived by the inventor herein and more fully disclosed below, which "Staggered Well"
method in many respects is itself an improvement, in certain respects and to varying degrees,
over the above prior art methods and configurations.
Specifically, for a comparable volumetric sweep area and identical total cumulative oil
recovery in regard to a hydrocarbon-containing subterranean reservoir (formation), the
horizontal well line-drive (hereinafter "HWLD" ) process of the present invention has been
experimentally shown, as discussed herein, to provide a greater initial rate of recovery of oil
than the "Staggered Well" method discussed herein. Thus a greater and more rapid initial
return on investment for oil companies incurring large expenditures in developing subterranean
reservoirs may be achieved. This is a significant advantage , since investment in developing oil
reservoirs is very high, and 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 ever made in the first place.
In addition, the horizontal well line-drive process of the present invention, for a
comparable volumetric sweep area and near identical total oil recovery, has been
experimentally shown to require fewer wells than the "Staggered Well" configuration, thus
significantly reducing the capital costs to an oil company to develop and produce oil from an
underground hydrocarbon-containing formation.
Accordingly, by way of broad summary, in one broad embodiment of the HWLD oil
recovery process of the present invention, a first horizontal well is drilled high in a subterranean
hydrocarbon-containing reservoir, and a medium such as a gas is injected into the reservoir via
perforations in a well liner in such first horizontal well. Oil, water and gas are co-produced via a
second parallel laterally offset horizontal well, placed low in the reservoir. When the oil rate at
the second horizontal (production) well falls below an economical limit, a third parallel
horizontal well is drilled low in the reservoir laterally spaced apart from the second horizontal
well, and used to produce oil, while at the same time the second horizontal well (initially a
production well) is converted to an injection well, and such gas likewise injected into the
formation via such second horizontal well so as to allow the combustion front to be continually
supplied with oxidizing gas to permit continued progression of the combustion front and thus
continued heating of oil ahead of the advancing combustion front, which drains downwardly and
is collected by the horizontal wells drilled low in the formation ahead of (or at least below) the
advancing combustion front . The steps of drilling further horizontal, parallel, laterally spaced
apart wells low in the formation , and successively converting 'exhausted" production wells to
injection wells to further the recovery of oil from remaining production wells is continued in a
substantially linear direction along the reservoir in order to exploit the reservoir in a single
direction as a 'line-drive-process' that achieves high reservoir sweep efficiency. The injectant, if
a gas, may be a solvent gas such as C0 2 or light hydrocarbon or mixtures thereof, steam or an
oxidizing gas such as oxygen, air or mixtures thereof. Alternatively the injectant may be any
mixture of solvent, steam or oxidizing gas. A favoured embodiment utilizes steam injectant and
the most favoured embodiment utilizes oxidizing gas as the injected medium.
When the process utilizes oxidizing gas injectant and in situ combustion, it meets the
commercial needs of relatively low energy costs and low operating costs by providing a novel
and efficient method for recovering hydrocarbons from a subterranean formation containing
mobile oil.
The distance between the parallel and offset horizontal well producers, as well as the
well lengths, will depend upon specific reservoir properties and can be adequately optimized by
a competent reservoir engineer. The lateral spacing of 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.
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 each perforation in the
injection well liner and to compel equal fluid entry rates at each perforation at each perforation in
the production well liner. Considering that horizontal wells typically have a 'toe' at the end of
the horizontal segment , and a 'heel' where the horizontal segment joins the vertical segment, in
a refinement of the present invention it is preferred to place the horizontal wells so that the heel
of the injector (injection) well is opposite the toe of the adjacent laterally spaced apart producer
(production) well so that "short-circuiting" of gas between injector and producer wells is
minimized. Short circuiting otherwise occurs because the point of highest pressure in the
injector well is at the heel since a pressure drop is typically incurred as the injectant is pumped
under pressure and flows along the horizontal leg from heel to toe. Conversely, the point of
highest pressure in a producer (production) well is at the toe, as gas and oil is typically drawn
from the heel. Accordingly, it is preferred to have the heel of the injector well opposite the toe of
the adjacent production well, so that high pressure (typically heated) gas is forced to travel a
greater distance through the formation to the low pressure portion at the heel of the adjacent
production well.
Alternatively, both the injection and production wells may be placed with the respective
heel and toe portions in mutually juxtaposed position. In such case it is then preferred to use
internal tubing to inject the gas at the toe of the injection well , thereby moving the high pressure
source from the heel of the injection well to its toe. In such manner the high pressure source
will be at an end of the reservoir opposite the low pressure heel of the production well, thereby
forcing the gas to travel a longer distance through the formation and thereby more effectively
free oil trapped in the formation , so as to then travel and be collected by the low pressure area
at the heel of the production well. Such configuration has the benefit of requiring only a single
drilling pad located on the same side of the reservoir, since the vertical portion of the injector
wells and the producer wells will all be on the same side of the reservoir.
In addition 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 of oil along 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 of the injector well. This has the advantage of utilizing gas flow in the annular
space to further assist the homogeneous delivery of gas. Alternatively, or in addition, similar
methodologies may be applied to the production wells in order to more uniformly collect mobile
oil along substantially the entire length of the production well, and assist in preventing "fingering"
of injectant gas directly into production wells .
The outside diameter of the horizontal well liner segments can be 4 inches to 2 inches,
but preferably 5-1 0 inches and most preferably 7-9 inches. The perforations in the horizontal
segments can be slots, wire-wrapped screens, Facsrite "1 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.
Facsrite™ is an unregistered trademark of Absolute Completion Technologies for well liners having sand screens
therein
It is desirable to achieve equal gas injection rates along the injector well and equal fluid
production rates along the horizontal production well in order to obtain the greatest reservoir
sweep efficiency and uniform recovery. The maximum 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.
Accordingly, and more particularly, in a first broad aspect of the method of the present
invention, such method is directed to a method for recovering oil from a hydrocarboncontaining
subterranean reservoir, comprising the steps of:
(i) drilling a first horizontal well, situated relatively high in said reservoir;
(ii) drilling a second horizontal well, situated relatively low in said reservoir and
aligned substantially parallel to said first horizontal well;
(iii) injecting a medium comprising a gas, steam, or a liquid into said reservoir via
apertures in said first horizontal well ;
(iv) withdrawing oil which moves downwardly in said subterranean reservoir and flows
into said second horizontal well, from said second horizontal well;
(v) drilling a third horizontal well, relatively low in said reservoir and substantially parallel
to said first and second horizontal wells but laterally spaced apart therefrom, laterally
spaced farther from said first horizontal well than from said second horizontal well;
(vi) temporarily or permanently ceasing withdrawing hydrocarbons from said second
horizontal well and proceeding to inject a second medium comprising a gas, steam,
or a liquid into said second horizontal well; and
(vii) withdrawing oil which moves downwardly in said subterranean reservoir into said
third horizontal well, from said third horizontal well.
Each of said second , third, and further subsequently- drilled horizontal wells are all
preferably co-planar with each other , but not with said first well, and laterally spaced from one
another.
In order to make use of the "line drive" aspect of the invention and allow a sweeping of a
significant volume of oil from within a substantially-sized hydrocarbon- containing reservoir,
such method further comprises additional repeated steps to allow a progressive "sweep" in a
generally linear direction along said formation, including the further steps of :
successively drilling additional horizontal wells low in said reservoir substantially
parallel to and substantially co-planar with the third horizontal well but laterally spaced apart
therefrom and from each other; and
successively converting penultimate wells of said additional horizontal wells from a
production well to an injection well for injecting said gas, steam, or a liquid so as to cause oil
in said reservoir to move from within said reservoir downwardly into a last of said additional
horizontal wells.
In a preferred embodiment, the first medium and the second medium are one and the
same medium. In a further preferred embodiment, such medium is a gas which is soluable in
the oil. Alternatively, the medium is a gas, namely C02, light hydrocarbons, or mixtures
thereof.
In yet a further preferred embodiment such medium comprises oxygen gas, air, or
mixtures thereof for the purpose of conducting in situ combustion, and said method further
comprises the step , after step (iii) , of igniting hydrocarbons in the reservoir in a region
proximate the first horizontal well, and withdrawing oil and combustion by-products from the
subterranean formation via the second well and /or simultaneously or subsequently via the
third well. The step of igniting the hydrocarbons and withdrawing combustion by-products
and oil via said second horizontal well and/or said third horizontal well causes a combustion
front to move laterally from said first horizontal well in the direction of said second and third
horizontal wells, thereby heating oil in said reservoir and causing said oil to drain downwardly
for collection by said second and/or third horizontal wells.
Accordingly, in a most preferred embodiment of the HWLD method of the present
invention for recovering oil from a hydrocarbon-containing subterranean reservoir, such method
comprises:
(i) drilling a first horizontal well relatively high in said reservoir, having a plurality of
apertures along a length of said first well ;
(ii) drilling a second horizontal well relatively low in said reservoir and substantially
parallel to said first horizontal well;
(iii) injecting an oxidizing gas into said first horizontal well and into said reservoir via
said apertures , for purposes of conducting in situ combustion in said reservoir;
(iv) igniting hydrocarbons in said reservoir ;
(v) withdrawing oil which drains downwardly in said subterranean reservoir into said
second horizontal well from said second horizontal well;
(vi) drilling a third horizontal well, relatively low in said reservoir and substantially parallel
to said second horizontal well but laterally spaced apart therefrom and laterally spaced from
said first injection well farther than from said second injection well;
(vii) temporarily or permanently ceasing producing hydrocarbons from said second
horizontal well ;
(viii) injecting said oxidizing gas into said second horizontal well; and
(ix) withdrawing oil which drains downwardly in said subterranean reservoir into said
third horizontal well, from said third horizontal well.
Where oxidizing gas is used as the injected medium, for the purposes of conducting in
situ combustion, combustion ignition (ie step (iv) above) can be accomplished by various means
well known to those skilled in the art, such as pre-heating the near-wellbore oil with hot fluids
such as steam or the injection of spontaneously ignitable fluid such as linseed oil prior to
injection of oxidizing gas. In this case, hot nitrogen (400 °C.) was injected at the rate of 16,667
m3/d for one month prior to switching to air at 100 0 C. The air does not have to be heated at the
surface: it is heated by the act compression.
As mentioned above, to ensure high pressure ends of an injector well are not situated
immediately adjacent the lowest pressure point (ie the heel portion) of an adjacent producer well
thus giving rise to "short circuiting" or "fingering" of high pressure gas directly to the heel portion
of the production well, in a preferred embodiment said step (iii) of injecting a gas, steam, or
liquid into said first horizontal well comprises the step of injecting said gas, steam, or liquid
into one end of said first horizontal well, and said step of withdrawing oil from said second
horizontal well comprises the step of withdrawing said oil from one end of said second well ,
said one end of said second well situated on a side of said reservoir opposite a side thereof at
which said one end of said first horizontal well is situated. Such configuration allows more
uniform injection of such gas into the formation and reduces (and preferably avoids) "fingering"
("short-circuiting") of high pressure gas directly from the injector well to the production well.
Such approach may likewise be adopted not only with regard to the first and second
wells, but also with regard to the second well relative to the third, and so on. For example, with
regard to the arrangement of the second well relative to the third well, said step of injecting
said gas, steam, or liquid into said second horizontal well may comprise the step of injecting ·
said gas, steam, or liquid into an end of said second horizontal well situated on a side of said
reservoir opposite an end of said third horizontal well from which said oil is collected from. In
other words, proximal ends of mutually adjacent wells may be situated on mutually opposite
sides of said reservoir .
Alternatively , the first end of each of the second well and third well may be situated on
the same side of the reservoir. In such case, to reduce or avoid the "fingering" problem, said
step of injecting said gas, steam, or liquid into said second horizontal well comprises injecting
said gas, steam, or liquid into a second end of said second well via tubing, which tubing
extends internally within said second well substantially from said first end to said second end of
said second well.
Alternatively, where a first end of each of said second and third horizontal wells are
located on a same side of said reservoir, said step of injecting said gas, steam, or liquid into
said second horizontal well may comprise injecting said gas, steam, or liquid into said first end
of said second well, and said step of withdrawing oil from said third well comprises withdrawing
such oil from a second end of said third well via tubing , said tubing extending internally
within said third well from said first end to substantially said second end of said third well.
Alternatively, or in addition, to avoid or reduce "fingering" of high pressure gas from an
injection well to a production well, such as from the first horizontal injector well to the second
well when such second well acts as a producer well, in one embodiment the first horizontal
well has a well liner in which said plurality of apertures are situated, and a size of said
apertures or a number of said apertures within said liner within said first horizontal well
progressively increase from a first end to a second end of said first horizontal well.
Likewise, progressive increase in aperture size or number of apertures along the length
of well liners in each of second, third, or subsequent wells may likewise be utilized. In such
manner , by having larger or more numerous apertures at one end of a well than at another ,
pressure (and thus flow) can be more uniform over the length of the well, or even made higher
at one end than another, and provided an adjacent well similarly employs progressive variation
in an opposite direction, direct "short-circuiting " of gas from an injector well to an adjacent
production well can be reduced or avoided. Instead, cross-flow of gas through the formation is
thereby inducted to better expose the (typically high temperature) gas to more oil in the
formation, thus increasing recovery rate of oil from the formation.
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:
Fig. 1 shows a perspective schematic view of a subterranean hydrocarbon- containing
reservoir of the "staggered well " configuration, having a plurality of horizontal injection wells
located high in the reservoir and a plurality of alternatingly-spaced horizontal production wells
situated low in the reservoir;
Fig. 1a shows a similar perspective schematic view of a subterranean hydrocarboncontaining
reservoir of the "staggered well configuration, to show the model used in Example
1 of the computer simulation , and which produced the experimental test results (line "B") of
Fig. 5 ;
Fig. 2 (i)-(iii) are views on section A-A of Fig. 1, at various time intervals, showing a
variation of the Staggered Well method of producing oil, which may optionally use a line drive
of oil recovery in the direction of arrow "Q;
Fig. 3 shows a perspective schematic view of a subterranean hydrocarbon-containing
reservoir of the horizontal well line drive ("HWLD") configuration of the present invention,
having a first horizontal well located high in the reservoir, and a plurality of spaced horizontal
production wells situated low in the reservoir;
Fig. 4a (i) - iii) are views on section B-B of Fig. 3, at successive time intervals,
showing a method of producing oil using such "horizontal well line drive" configuration, showing
the method for causing a line drive of oil recovery in the direction "Q;
Fig. 4b (i) -(iii) are views on section B-B of Fig. 3, at successive time intervals,
showing a modified method of producing oil using such "horizontal well line drive"
configuration, showing the method for causing a line drive of oil recovery in the direction "Q;
Fig. 4c (i) -(iv) are views on section B-B of Fig. 3, at successive time intervals,
showing a further variation of the method of producing oil using such "horizontal well line drive"
configuration, showing the steps for causing a line drive of oil recovery in the direction "Q;
Fig. 5 is a graph of cumulative oil recovery versus time (years), comparing cumulative
oil recovery of the "staggered well" method of recovery shown in Fig.'s 1 & 2 (line "B" of Fig.
5), to the cumulative oil recovery obtained using the "horizontal well line drive " method of the
present invention shown in Fig. 4b (i)-(iii), for a reservoir having the horizontal well locations
and configuration shown in Fig. (line "A" of Fig. 5);
Fig. 6 is a perspective schematic view of a subterranean hydrocarbon- containing
reservoir of the "horizontal well line drive " configuration of the present invention similar to Fig.
3;
Fig. 7 is a view on a modification to the parallel, mutually adjacent but spaced-apart
horizontal injection (production) wells of Fig. 6 , showing two of such horizontal mutuallyadjacent
wells, wherein in a further embodiment tubing is used to deliver a medium such as an
oxidizing gas to a "toe" (ie distal) end of the horizontal injection well;
Fig. 8 is a view on a modification to the parallel, mutually adjacent but spaced-apart
horizontal injection (production) wells of Fig. 6, showing two of such horizontal mutuallyadjacent
wells, wherein in a further embodiment tubing is used to recover oil from a "toe" (ie
distal) end of the horizontal production well;
Fig. 9 is a view of an alternative modification to the parallel, mutually adjacent but
spaced-apart horizontal injection (production) wells of Fig. 6, showing two of such horizontal
mutually-adjacent wells, wherein apertures therein are more closely spaced and more
numerous towards the "toe" (ie distal) end of each of such horizontal wells;
Fig. 10 is a view of a further alternative modification to the parallel, mutually adjacent
but spaced-apart horizontal injection (production) wells of Fig. 6, showing two of such
horizontal mutually-adjacent wells, wherein apertures therein are larger towards the "toe" (ie
distal) end of each of such horizontal wells;
Fig. 11 is a perspective schematic view of a subterranean hydrocarbon- containing
reservoir similar to Fig. 6, showing a modified "horizontal well line drive " configuration of the
present invention , and which configuration produced the experimental test results (line "A") of
Fig. 5 ;
Fig. 12 is a view of a modification to the parallel, mutually adjacent but spaced-apart
horizontal injection (production) wells of Fig. 11, showing two of such horizontal mutuallyadjacent
wells , wherein apertures therein are larger towards the "toe" (ie distal) end of each of
such horizontal wells; and
Fig. 13 is a view of a modification to the parallel, mutually adjacent but spaced-apart
horizontal injection (production) wells of Fig. 11, showing two of such horizontal mutuallyadjacent
wells , wherein apertures therein are more numerous and more closely spaced
towards the "toe" (ie distal) end of each of such horizontal wells.
DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS
Fig.'s 1 & 1a show a developed hydrocarbon-containing subterranean
formation/reservoir 22 of the "staggered well" (hereinafter "Staggered Well" configuration) ,
which does not form part of the invention claimed herein but forms subject matter of another
application of the undersigned inventor, such other application being commonly assigned with
the present invention.
In such "Staggered Well" configuration, parallel horizontal injection wells 1, 1' , & 1" of
each of length 6 are placed parallel to each other in mutually spaced relation, all situated high
in a hydrocarbon-containing portion 20 of subterranean formation/reservoir 22 of thickness 4 ,
situated below ground-level surface 24. Parallel horizontal , spaced apart production wells 2, 2'
& 2" of similar length 6 are respectively placed low in the reservoir 22, midway between
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 fluid production
wells 2, 2' & 2", as shown in Fig. 1 and 1a..
The hydrocarbon-containing reservoir 22 shown in Fig. 1 possesses two and one-half
injection wells 1, V , & 1" (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. a.
The lateral spacing 5 of the injection wells 1, ' , & 1" and production wells 2, 2' & 2" is
preferably uniform.
In a preferred embodiment shown in Fig.'s 1, 1a, the vertical segments 8 of the
horizontal injection wells 1, 1' & 1" are at opposite ends compared with the vertical segments 9
of the horizontal production wells 2, 2' & 2". The vertical segments 8 of the injection wells 1, 1' ,
& 1" are offset by the well width 6 from the vertical segments 9 of the production wells. This is
to minimize short-circuiting of injection gas into the production wells 1, 1', & 1" as explained
above. The pattern shown 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. For example, for a channel deposit the
pattern could extend across the width of the channel. In additional phases of reservoir 22
development, additional arrays are placed adjacent to the first array, and so on, eventually
exploiting the entire reservoir 22.
Referring to Fig. 1, a preferred embodiment of the invention horizontal injector wells 1,
1' & 1" and production wells 2, 2' & 2" which are simultaneously drilled, each possess well
liner segments 30 situated in each of horizontal wells 1, 1' , & 1" and 2, 2' & 2" which
contain apertures 24, from which a medium such as an oxidizing gas, air, oxygen alone or in
combination with carbon dioxide or steam, steam alone, or a diluent such as a hydrocarbon
diluent , or combinations thereof, may be injected into the hydrocarbon-containing portion 20
via an injector well 1, 1' , & 1" , and through which oil may be allowed to flow through to collect
in a horizontal production well 2, 2' & 2" . In the case of horizontal production wells 2, 2' & 2" ,
such well liners 30 and the apertures 24 therein may take the form of slotted liners, wirewrapped
screens, Facsrite 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 the
production wells 2, 2' & 2" .
In the "Staggered Well" configuration of Fig. 1, 1a, & 2, a medium such as an oxidizing
gas, air, oxygen alone or in combination with carbon dioxide or steam, steam alone, or a
diluent such as a hydrocarbon diluent , or combinations thereof, is injected into formation 22
via apertures in horizontal injector wells 1, V , & 1", to cause mobility of oil in the oil-containing
portion 20 of formation 22. Such oil flows downwardly within formation 22, and is collected in
horizontal collector wells 2, 2' & 2".
The Staggered Well method, in one embodiment, may alternatively utilize a line drive
configuration, such method shown in Fig. 2 (i)-(iii), in which three phases are implemented. In
this regard, Fig. 2 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" using such "Staggered Well" configuration. Specifically, as seen from the first phase [Fig.
2 (i) ] , the injector well 1 , and producer well 2 and 2' are first drilled, and production from wells
2 and 2' commenced. Thereafter in a second phase [Fig. 2(ii)] , a third injector 1" and a third
producer 2" are drilled, and injection and production commenced respectively in regard to such
wells. In a third phase, 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. 1a , until reaching an end of reservoir 22
Alternatively, as mentioned above, such "Staggered Well" 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. Such
pattern may be repeated as necessary, as shown in Fig. 1a. This method was used in the
Examples (discussed below), for comparing the HWLD configuration and method to the
Staggered Well configuration, using simultaneous drilling of five wells as discussed above.
Fig's. 3, 6 & Figs. 4a-4c shows an alternative well arrangement / configuration (Fig.
3,6) and method (Figs. 4a-4c) for recovery of oil from a reservoir 22, namely the horizontal
well line drive ("HWLD") configuration and method respectively of the present invention, to
develop an oil bearing portion 20 of a reservoir 22 of a thickness 4, a width 6, and which
comprises a plurality of segments 50a-50o each of length 5 consecutively positioned
commencing from plane 7 and progressing to the right of the page, as shown in Fig's 3 and 6.
In such HWLD configuration and method, a first horizontal injection well 1 is drilled high
within oil-containing portion 20 of reservoir 22, along edge 7, and a second parallel horizontal
well 2 is drilled low in oil-containing portion 20 of reservoir 22, laterally spaced apart from first
injector well 1.
Horizontal wells 2 & 2' have vertical portions 3 at each of their respective heel portions
42 which extend to surface 24. The distance separating planes 7 and 8 represent the edges of
the oil-swept volume of oil containing portion 20 of reservoir 22 in a first phase of the method of
the present invention.
In the embodiment of the HWLD method shown in Fig. 11, the position of vertical
segment 3 of first injection well 1 is offset by the well length 6 from the vertical segments 3 of
the production wells 2 & 2'. This is to minimize short-circuiting of injection gas into the
production wells as explained above. The pattern shown can be extended indefinitely away from
the face 7 and/or the face 8 as desired to cover a specific volume of oil reservoir 22. For
example, for a channel deposit it could extend across the width of the channel. In additional
phases of development of reservoir 22 as shown for example in Fig. 6, additional wells 2", 2"',
2 are drilled, laterally offset from the earlier drilled horizontal well 2', so as to eventually exploit
the entire reservoir 22 along a length thereof.
Figs. 4a-c, namely in various alternative sub-phases (i),(ii), ( i), and (iv) thereof, each
show the residual oil in oil containing portion 20 which is remaining after each sub-phase of the
method of the present invention, in shaded portion.
In a first phase of the method of the present invention [identical in each of various
methods shown in Fig. 4a (i), Fig. 4b(i), and Fig. 4c(i)] , gas is injected into horizontal well 1
and oil is produced via second horizontal well 2 . In a second phase of the method of the
present invention [ shown in . Fig. 4a , Fig. 4b, and Fig. 4c as step (ii)] , a third horizontal
well 2' is drilled low in the oil-containing portion 20 of reservoir 22, parallel to horizontal well 2
but laterally spaced apart therefrom, and spaced laterally further from first well 1 than from well
2 , and production of oil carried out via well 2'. Upon the oil rate being produced from second
horizontal well 2 diminishing to below an economical limit , production from such well 2 is
ceased, and well 2 is then employed for gas injection, as shown in Figs. Fig. 4a (ii), Fig. 4b(ii),
and Fig. 4c(ii) . Gaseous injection via well 1 may continue during this phase, or may cease as
shown in step (ii) of Fig.'s 4 a-c.
In a preferred embodiment, where vertical ends 3 of production well 2, 2' are on the
same side of reservoir 22 as shown in Fig.3, gas injection in second horizontal well 2 during
this second phase is preferably via an internal tubing 40 extending from a proximal end (heel)
42 of third well 2' to the distal end (toe) 44 of well 2', with an open end thereof being at distal
end 44 as shown in Fig. 7. Alternatively, if injection of gas into second well 2 is simply into a
proximal end 42 of injection well 71 (ie no tubing 40 in injection well 2 during injection) , then
internal tubing 40 may instead be provided in adjacent third well 2' when such well 2' is acting
as a production well, and oil is thereby drawn from toe portion 44 of such third well 2' via such
tubing 40, as shown in Fig. 8. As explained above, each of the alternative configurations of Fig.
7 and Fig. 8 assist in avoiding "fingering" or "short circuiting of pressurized gas from injection
well 2 directly to production well 2', when a configuration such as shown in Fig. 3 is used
wherein each of the vertical portions 3 of production wells 2, 2', and 2"' are each on the same
side of reservoir 22. As noted above, in this second phase a new parallel third well 2' is drilled
low in the reservoir and placed on fluid production [see Fig. 4a(ii), Fig. 4b(ii) and Fig. 4c(ii)].
During this second phase a fourth horizontal well 2" may be drilled, as shown in Fig. 4a(ii) and
production initiated from such well 2" as well as from well 2'. Alternatively only the drilling of
well 2" may be conducted during this phase, with production from well 2" occurring during the
third phase (discussed below) and as shown in Fig. 4c(iii) and (iv).
Figs. 4a(iii), 4b(iii), and 4c(iii) each show slightly different third phases of the method of
the present invention.
As regards the embodiment of the method disclosed in Fig. 4(b) (iii), when the rate of
oil production from third well 2' being produced in step (ii) drops below a pre-determined limit,
a drawdown phase is undertaken where gas is again injected in well 1. Well 2 is switched back
to operating as a production well, and wells 2 and 2' are employed as production wells for a
time to withdraw all remaining oil .
Thereafter the fourth well 2" may be drilled, and a similar process repeated wherein a
former production well (well 2') is converted into an injection well 2', and production commenced
from fourth well 2", while gas continues to be injected via well .
Alternatively, as regards the third phase shown in step (iii) of Fig. 4a, injection of gas
from well 1 is ceased, with gas being injected into the reservoir 22 solely via such well 2' which
as noted above is converted from a production well to an injection well. Fourth well 2" operates
as a production well.
Alternatively, as shown in Fig. 4c(iii), injection of gas into well 1 may be re-instituted to
completely drain all oil above wells 2 and 2', and a new fourth well 2" drilled. Only thereafter,
when production from wells 2 and 2" is exhausted or substantially exhausted, is well 2
converted to an injector well and gas subsequently supplied to the formation via well 2' and
production commenced from well 2" as shown in Fig. 4c(iii .
As noted above, where the vertical portions 3 of wells 2, 2', 2", 2"', and 2 are all
situated on the same side of reservoir 22 (see Fig. 6) and not on alternating sides of reservoir
22, in order to reduce "fingering" between a mutually adjacent collector/production well and a
mutually-adjacent injector well, tubing may be employed in the manner described above and as
shown in Fig's 7 or 8.
As an alternative configuration to reducing or avoiding the "fingering" or short-circuiting
problem between an injector and mutually-adjacent production wells 2, 2', 2" , 2"', 2, having
respective vertical portions 3 of such wells on the same side of reservoir 22 as shown in Fig. 6
and to more uniformly inject gaseous medium such as oxidizing gas, steam, carbon dioxide,
hydrocarbon diluents (in either gaseous or liquid form) in one embodiment shown in Fig. 9, the
number of apertures 24 may be progressively made more numerous over the length of
horizontal well 2, and similarly over the length of a mutually adjacent well 2', progressing from
the proximal end 42 toward the distal end 44 of each of said wells 2, 2', 2" , 2'", 2i , and so
forth.
Alternatively, to likewise more uniformly inject gaseous medium such as oxidizing gas,
steam, carbon dioxide, hydrocarbon diluents (in either gaseous or liquid form) along the length
of an injector well (e.g. 2') and also to more uniformly collect oil along a length of a mutually
adjacent collector well (e.g. 2"), in an embodiment shown in Fig. 10 the size of apertures 24
may be progressively be made larger over the length of each well 2, 2', 2" , 2"', 2, and so
forth and similarly over the length of a mutually adjacent well 2', progressively increasing in
area from the proximal end 42 toward the distal end 44 of each of said wells 2, 2', 2" , 2"', 2 .
Conversely , vertical portions 3 of mutually-adjacent wells 2, 2', 2" , 2"', 2 and so forth
may be situated on respective opposite sides of the reservoir 22 as shown in Fig. to more
uniformly inject gaseous medium such as oxidizing gas, steam, carbon dioxide, hydrocarbon
diluents (in either gaseous or liquid form), and to collect oil via an adjacent well. To further and
even better accomplish uniform injection of air and/or collection of oil, where adjacent wells are
used respectively to inject air from one, and to collect oil from the other, in a further
embodiment shown in Fig. 12 the number of apertures 24 in each of such wells may be
progressively made more numerous over the length of each horizontal well (e.g. well 2), and
similarly over the length of a mutually adjacent well (e.g. well 2') , progressing from the proximal
end 42 toward the distal end 44 of each of said wells 2, 2', 2" , 2'", 2i , and so forth.
Alternatively, in an embodiment shown in Fig. 3 the size of apertures 24 may be
progressively be made larger over the length of each well 2, 2', 2" , 2"', 2 and so forth and
similarly over the length of a mutually adjacent well 2', progressively increasing in area from the
proximal end 42 toward the distal end 44 of each of said wells 2, 2', 2" , 2"', 2 , to achieve the
same result of more even pressure distribution over the length of each of the respective wells 2,
2', 2" , 2"', 2i
EXAMPLES
For the purpose of making a direct performance comparison of the "Staggered Well"
configuration shown in Fig. 1, 1a, and Fig. 2 and the HWLD process of the present invention
shown in Fig.'s 3 , Fig. 4b, & Fig. 6, and Fig. 11 computer modelling and simulation
techniques as more fully described herein were used.
Specifically, extensive computer numerical simulation of each of the Staggered Well
Pattern and HWLD, using an in situ combustion process for the recovery of mobile oil in a
homogeneous reservoir, were undertaken using the STARS™ Thermal Simulator 201 0.12
provided by the Computer Modelling Group, Calgary, Alberta, Canada. The modelling reservoir
used in the Examples contained bitumen at elevated temperature (54.4 °C) with high rock
permeability.
In each of the modelled Staggered Well well (Figs. 1, 1a, and Fig. 2), and HWLD well
configuration (Figs. 11, Fig. 4b ) , the oil-containing portion 20 of reservoir 22 is developed in
three phases .
Specifically, for each of the Staggered Well Pattern shown in Fig. 1, the entire volume
of Fig. 1 was exploited three times, once for each of the three phases. This requires a total of
fifteen horizontal wells, as shown in Fig. 1A.
For the HWLD process , a first phase of which is shown in Fig. 3 and Fig. 4b, only part
of the total reservoir volume is exploited, but after conducting two additional phases, in the end
the same volume of reservoir 22 is exploited (namely 20m x 100m x (50mx 15
blocks)=1 ,500,000m3) as with the Staggered Well Pattern process, but requiring a total of only
7.5 horizontal wells as opposed to fifteen wells for the Staggered Well well configuration as
shown in Fig. 1a.
For combustion simulations with air the reactions used:
1. .0 Oil - 0.42 Upgrade + .3375 CH + 29.6992 Coke
2 . 1.0 Oil + 13.24896 0 2 5.949792 H 0 + 6.0 CH4 + 9.5 C0 + 0.5 CO/N2 + 27.3423
Coke
3. .0 Coke + 1.2575 0 -» 0.565 H20 + 0.95 C0 2 + 0.05 CO/N2
Table 1 below sets out the modelled reservoir properties, oil properties and well control for
each of the Staggered Well Offset configuration and HWLD configuration :
Table 1.
Reservoir Properties
Parameter Units Value
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 °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 -C 2.35E+6
Oi Properties
Density Kg/m 1009
Viscosity, dead oil @ 20 C. cP 77,000
Viscosity, in situ cP 1139
Average molecular weight oil AMU 598
Average molecular weight Upgrade AMU 224
Oil mole fraction Fraction 0.737
Compressibility /kPa 1.06E+3
The wells were controlled using
the following parameters:
Maximum air injection pressure kPa 7000
Horizontal well length m 100
Producer BHP minimum kPa 2600
Total air injection rate Sn d 50,000
The transmissibility of the oil production wells was varied monotonically along the well from 1.0
at the toe to 0.943 at the heel, in order to improve sweep efficiency.
Example i-Staggered Well configuration
For the Staggered Well configuration, the oil containing portion 20 of reservoir 22
comprising grid blocks 50a-50o shown in Fig. A was is divided into three equal parts, each
consisting of five grid blocks 50a-e , 50 f-j, and 50k-o, as shown in Fig. 1. Each equal part
was successively exploited in three separate but successive phases, each phase taking 5
years, using the wells in Fig. 1 over a 15-year period. The total reservoir volume exploited over
the 15-years process life is 1,500,000 m3.
For the Staggered Well Pattern shown in Fig. 1, a first part of the three part modelling
used 2.5 injection wells 1, 1' , and 1", and 2.5 production wells 2, 2', and 2", all simultaneously
drilled, for a total of five wells . The reservoir thickness 4 was 20m and the well offset was 50m
for each grid block 50a-50o. Air injection rates were 10,000 m3/d for well 1 and 20,000 m3/d for
each of injectors V and 1" , for a total of 50,000 m3/d for the pattern.
For the computer modelling of the Staggered Well pattern the first phase comprised
grid blocks 50a-50e. A second pattern comprised an identical pattern (grid blocks 50f-50j),
modelled as exploited over a further 5-years and in a third phase (grid blocks 50k-50o)
comprised another identical pattern which was modelled as being exploited over a final 5-years.
The reservoir volume of each part was 500,000m3 for a total field exploitation volume of
1,500,000 m3 (i.e. 3x1 00mx250mx20m) over 15-years. The final oil recovery factor was 79 % of
original oil in place. A summary of results is shown in Table 2 and Fig. 5.
Example 2-HWLD well configuration
For the HWLD process which was modelled using computer simulation, and as shown
in Fig. 4b, in a first phase (Fig. 4b(i)] a horizontal injector well 1 is located high in the
formation, and a horizontal well 2 located low in the reservoir 22 is provided, both being placed
along one side of the oil containing portion 20 of reservoir 22.
In Fig. 4b and Fig. 11, representing the HWLD process and configuration of the method
of the present invention , the well lengths 6 were each 100m, the reservoir thickness, 4, was
20m and the well offset was 100m. The total volume of reservoir produced over the 15-year
exploitation period was thus also 1,500,000 m .
The air injection rate was 16,667 m /d for each of the injectors for a total of 50,000 m /d
throughout Phase .
In a second phase [Fig. 4b(ii)], after 5-years, the oil production rate per producer fell to
3 m3/d, which was considered uneconomical, and a second phase [Fig. 4b(ii)] conducted,
namely the original producer well 2 was converted as shown in Fig. 4b(ii) to an air injector by
injecting steam at 270 °C for 2-weeks to flush out weilbore oil and then air was injected through
the weilbore tubing at 26,000 m /d. At the same time, a second producer well 2' was drilled as
shown in Fig. 4b.
After 5-years, a final drawdown phase (Fig. 4b(iii)] was begun, with air injection at
7,333 m /d into the original injector well 1, while both the producers 2 and 2' were put on
production. The total field exploited volume was 1,500,000 m3 (i.e. 3x100mx250mx20m) over
5 years. The final oil recovery factor was 79 % of original oil in place.
COMPARISON AND PROVEN ADVANTAGES
A summary of comparative results of each of Examples 1 & 2 is shown in Table 2 below.
Table 2.
*Not part of the invention claimed herein
The significant and important differences in the two methods are shown in grey.
Specifically, Fig. 5 shows the Cumulative Oil Recovery over time for each of the
Staggered Well configuration (triangles-line 'B") and the HWLD well configuration (squares-line
TV).
Referring to Table 2 and Fig. 5, the HWLD for production of mobile oil is advantageous
over the Staggered Well process even in a homogeneous reservoir for at least the following
two reasons.
Firstly, only half the number of horizontal wells (7.5 wells, as compared to 15 wells) are
needed for the same compressed air volume and cumulative oil rates are substantially higher
over most of the life of the process.
Secondly, the cumulative oil recovery for the HWLD process as compared to the
Staggered Well process is initially higher, resulting in a higher initial return on investment.
Specifically in this regard, as may be seen from Fig. 5 herein, at the end of Phase 1 (5-years),
the cumulative oil (133, 278m3) is 40% higher than that initially covered in the Staggered Well
method (95,126 m3). At the end of Phase 2 (10-years) cumulative oil recovered using the HWLD
process is 30 % higher (125,646m3 as compared to quantum recovered using the Staggered
Well method described above (95,126m3). As the HWLD process is a line-drive process, the
reservoir fluids flow in a single direction, which improves reservoir sweep in reservoirs with
lateral heterogeneity.
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.
CLAIMS
. A method for recovering oil from a hydrocarbon-containing subterranean reservoir,
comprising the steps of:
(i) drilling a first horizontal well, situated relatively high in said reservoir;
(ii) drilling a second horizontal well, situated relatively low in said reservoir and
aligned substantially parallel to said first horizontal well;
(iii) injecting a medium comprising a gas, steam, or a liquid into said reservoir via
apertures in said first horizontal well ;
(iv) withdrawing oil which moves downwardly in said subterranean reservoir and flows
into said second horizontal well, from said second horizontal well;
(v) drilling a third horizontal well, relatively low in said reservoir and substantially parallel
to said first and second horizontal wells but laterally spaced apart therefrom, laterally spaced
farther from said first horizontal well than from said second horizontal well;
(vi) temporarily or permanently ceasing withdrawing hydrocarbons from said second
horizontal well ;
(vii) proceeding to inject a second medium comprising a gas, steam, or a liquid into
said second horizontal well; and
(ix) withdrawing oil which moves downwardly in said subterranean reservoir into said
third horizontal well, from said third horizontal well.
2. A method for recovering oil from a hydrocarbon-containing subterranean reservoir as
claimed in claim 1 for sweeping a substantial volume of oil from within a hydrocarboncontaining
reservoir by progressing in a generally linear direction along said formation,
comprising additional repeated steps including:
successively drilling additional horizontal wells low in said reservoir substantially
parallel to and substantially co-planar with said third horizontal well but laterally spaced apart
therefrom and from each other; and
successively converting penultimate wells of said additional horizontal wells from a
production well to an injection well for injecting said gas, steam, or a liquid so as to cause oil
in said reservoir to move from within said reservoir downwardly into a last of said additional
horizontal wells.
3. A method for recovering oil from a hydrocarbon-containing subterranean reservoir as
claimed in claim 1, wherein said first medium and said second medium are the same medium.
4. A method for recovering oil from a hydrocarbon-containing subterranean reservoir as
claimed in claim 3, wherein said first medium comprises oxygen gas, air, or mixtures thereof
for the purpose of conducting in situ combustion, said method further comprising the step ,
after step (iii) , of igniting said hydrocarbons in said reservoir in a region proximate said first
horizontal well, and withdrawing combustion by-products and said oil from said subterranean
formation via said second well and /or via said third well.
5. A method as claimed in claim , wherein said first medium and said second medium is a
gas which is soluble in the oil.
6. A method as claimed in claim 4, wherein the gas is C02, light hydrocarbons, or mixtures
thereof.
7. A method for recovering oil from a hydrocarbon-containing subterranean reservoir as
claimed in claim 4, wherein said step of igniting said hydrocarbons and withdrawing
combustion by-products via said second horizontal well and/or said third horizontal well causes
a combustion front to move laterally from said first horizontal well in the direction of said second
and third horizontal wells, thereby heating oil in said reservoir and causing said oil to drain
downwardly for collection by said second and/or third horizontal wells.
8. A method for recovering oil from a hydrocarbon-containing subterranean reservoir as
claimed in claim 1 wherein said step (iii) of injecting a gas, steam, or liquid into said first
horizontal well comprises the step of injecting said gas, steam, or liquid into one end of said
first horizontal well, and said step of withdrawing oil from said second horizontal well comprises
the step of withdrawing said oil from one end of said second well , said one end of said
second well situated on a side of said reservoir opposite a side thereof at which said one end
of said first horizontal well is situated.
9. A method for recovering oil from a hydrocarbon-containing subterranean reservoir as
claimed in claim 1 , wherein said step (vi) of injecting said gas, steam, or liquid into said
second horizontal well comprises injecting said gas, steam, or liquid into an end of said second
horizontal well situated on a side of said reservoir opposite an end of said third horizontal well
from which said oil is collected from.
10. A method for recovering oil from a hydrocarbon-containing subterranean reservoir as
claimed in claim 1 , wherein said step (vi) of injecting said gas, steam, or liquid into said
second horizontal well comprises injecting said gas, steam, or liquid into a first end of said
second horizontal well , said first end of said second well situated on a same side of said
reservoir at which a first end of said third horizontal well from which said oil is collected from is
situated.
11. A method for recovering oil from a hydrocarbon-containing subterranean reservoir as
claimed in claim , wherein said oil is collected from a first end of each of said second and
third horizontal wells, said first end of each of said second and third horizontal wells located on
a same side of said reservoir, and said step (vi) of injecting said gas, steam, or liquid into said
second horizontal well comprises injecting said gas, steam, or liquid into a second end of said
second well via tubing , which tubing extends substantially from said first end to said second
end of said second well.
12. A method for recovering oil from a hydrocarbon-containing subterranean reservoir as
claimed in claim , a first end of each of said second and third horizontal wells located on a
same side of said reservoir, and said step (vi) of injecting said gas, steam, or liquid into said
second horizontal well comprises injecting said gas, steam, or liquid into said first end of said
second well, and said step of withdrawing oil from said third well comprises withdrawing such oil
from a second end of said third well via tubing , said tubing extending from said first end to
substantially said second end of said third well.
13. A method for recovering oil from a hydrocarbon-containing subterranean reservoir as
claimed in claim 1, each of said second horizontal well and said third horizontal well having a
distal end and a proximal end, said proximal end of said second horizontal well and said
proximal end of said third horizontal well being situated on mutually opposite sides of said
reservoir .
14. A method for recovering oil from a hydrocarbon-containing subterranean reservoir as
claimed in claim 1, wherein said first horizontal well possesses a plurality of apertures along
substantially its length, and said step of injecting a gas, steam or liquid into said horizontal well
comprises the step of injecting said gas, steam, or liquid into said reservoir via said apertures in
said first well.
15. A method for recovering oil from a hydrocarbon-containing subterranean reservoir as
claimed in claim 14 , wherein said first horizontal well 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 liner within said first horizontal well progressively increases from a first end to a
second end of said first horizontal well, and said gas, steam or liquid is injected into said first
end of said first well.
16. A method for recovering oil from a hydrocarbon-containing subterranean reservoir as
claimed in claim , wherein each of said second horizontal well and said third horizontal well
have a plurality of apertures therein, wherein a size of said apertures or a number of said
apertures progressively increases from a first end to a second end of each of said second and
third horizontal wells.
17. A method for recovering oil from a hydrocarbon-containing subterranean reservoir as
claimed in claim 10, wherein said second horizontal well has a plurality of apertures therein,
wherein a size of said apertures or a number of said apertures progressively increases from a
first end to a second end of each of said second and third horizontal wells.
18. A method for recovering oil from a hydrocarbon-containing subterranean reservoir as
claimed in claim 10, wherein said third horizontal well has a plurality of apertures therein,
wherein a size of said apertures or a number of said apertures progressively increases from
said first end to a second end thereof.
9. A method for recovering oil from a hydrocarbon-containing subterranean reservoir as
claimed in claim 0, wherein each of said second well and said third well have a plurality of
apertures therein, wherein a size of said apertures or a number of said apertures progressively
increases from said first end thereof to a second thereof.
20. A method as claimed in claim , further including the step, after step (v) or (vi), of
ceasing injecting said gas, steam, or liquid into said first horizontal well when recovery of oil
from said second horizontal well has fallen to a pre-determined fraction of a maximum recovery
rate.
21. A method for recovering oil from a hydrocarbon-containing subterranean reservoir as
claimed in claim 1 wherein said first horizontal well possesses a plurality of apertures along
substantially its length, and said step of injecting a gas, steam or liquid into said horizontal well
thereby comprises the step of injecting said gas, steam, or liquid into said reservoir via said
apertures in said first injection well.
22. A line-drive method for recovering oil from a hydrocarbon-containing subterranean
reservoir, comprising the steps of:
(i) drilling a first horizontal well relatively high in said reservoir, having a plurality of
apertures therein;
(ii) drilling a second horizontal well relatively low in said reservoir and substantially
parallel to said first horizontal well;
(iii) injecting an oxidizing gas into said first injection well and into said reservoir via said
apertures therein, for purposes of conducting in situ combustion in said reservoir;
(iv) igniting hydrocarbons in said reservoir ;
(v) withdrawing oil which drains downwardly in said subterranean reservoir into said
second horizontal well from said second horizontal well;
(vi) drilling a third horizontal well, relatively low in said reservoir and substantially parallel
to said second horizontal well but laterally spaced apart therefrom and laterally spaced from
said first injection well farther than from said second injection well;
(vii) temporarily or permanently ceasing producing hydrocarbons from said second
horizontal well , and converting said second well into an injection well;
(viii) injecting said oxidizing gas into said second horizontal well; and
(ix) withdrawing oil which drains downwardly in said subterranean reservoir into said
third horizontal well, from said third horizontal well;
(x) successively drilling additional horizontal wells low in said reservoir substantially
parallel to and substantially co-planar with said third horizontal well but laterally spaced apart
therefrom and from each other; and
(xi) successively converting penultimate wells of said additional horizontal wells from a
production well to an injection well for injecting said gas, steam, or a liquid so as to cause oil
in said reservoir to move from within said reservoir downwardly into a last of said additional
horizontal wells.
23. A method for recovering oil from a hydrocarbon-containing subterranean reservoir as
claimed in claim 22, wherein a volume of gas, steam, or liquid injected into said subterranean
reservoir is approximately equal to volume of oil recovered from said horizontal wells located
low in the reservoir.