Note: Descriptions are shown in the official language in which they were submitted.
HARVESTING RESOURCE FROM VARIABLE PAY INTERVALS
HELD
[0001] The present techniques relate to the use of well pairs to harvest
resources.
Specifically, techniques are disclosed for designing gravity drainage well
pairs to
increase the recovery of resource from a reservoir.
BACKGROUND
[0002] This section is intended to introduce various aspects of the art,
which may
be associated with exemplary embodiments of the present techniques. This
discussion is believed to assist in providing a framework to facilitate a
better
understanding of particular aspects of the present techniques. Accordingly, it
should
be understood that this section should be read in this light, and not
necessarily as
admissions of prior art.
[0003] Modern society is greatly dependant on the use of hydrocarbons for
fuels
and chemical feedstocks. Hydrocarbons are generally found in subsurface rock
formations that can be termed "reservoirs." Removing hydrocarbons from the
reservoirs depends on numerous physical properties of the rock formations,
such as
the permeability of the rock containing the hydrocarbons, the ability of the
hydrocarbons to flow through the rock formations, and the proportion of
hydrocarbons present, among others.
[0004] Easily harvested sources of hydrocarbon are dwindling, leaving
less
accessible sources to satisfy future energy needs. However, as the costs of
hydrocarbons increase, these less accessible sources become more economically
attractive. For example, the harvesting of oil sands to remove hydrocarbons
has
become more extensive as it has become more economical. The hydrocarbons
harvested from these reservoirs may have relatively high viscosities,. for
example,
ranging from 8 API, or lower, up to 20 API, or higher. Accordingly, the
hydrocarbons
may include heavy oils, bitumen, or other carbonaceous materials, collectively
referred to herein as "heavy oil," which are difficult to recover using
standard
techniques.
[0005] Several methods have been developed to remove hydrocarbons from
oil
sands. For example, strip or surface mining may be performed to access the oil
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sands, which can then be treated with hot water or steam to extract the oil.
However, deeper formations may not be accessible using a strip mining
approach.
For these formations, a well can be drilled to the reservoir and steam, hot
air,
solvents, or combinations thereof, can be injected to release the
hydrocarbons. The
released hydrocarbons may then be collected by the injection well or by other
wells
and brought to the surface.
[0006] A
number of techniques have been developed for harvesting heavy oil
from subsurface formations using thermal recovery techniques. Thermal recovery
operations are used around the world to recover liquid hydrocarbons from both
sandstone and carbonate reservoirs. These operations include a suite of steam
based in situ thermal recovery techniques, such as cyclic steam stimulation
(CSS),
steam flooding and steam assisted gravity drainage (SAGD) as well as surface
mining and their associated thermal based surface extraction techniques.
[0007] The CSS
process may raise the steam injection pressure above the
formation fracturing pressure to create fractures within the formation and
enhance
the surface area access of the steam to the heavy oil, although CSS may also
be
practiced at pressures that do not fracture the formation. The steam raises
the
temperature of the heavy oil during a heat soak phase, lowering the viscosity
of the
heavy oil. The injection well may then be used to produce heavy oil from the
formation. The cycle is repeated until the cost of injecting steam becomes
uneconomical, for instance if the cost is higher than the money made from
producing
the heavy oil. However, successive steam injection cycles reenter earlier
created
fractures and, thus, the process becomes less efficient over time. CSS is
generally
practiced in vertical wells, but systems are operational in horizontal wells.
[0008] Solvents
may also be used in combination with steam in CSS processes,
such as in mixtures with the steam or in alternate injections between steam
injections. Further, solvents can be used in cyclic recovery processes in the
absence of thermal sources. For example, a hydrocarbon solvent may be injected
into a reservoir to reduce the viscosity of a heavy oil. During a soak phase,
the
hydrocarbon solvent is allowed to mix with the heavy oil at an elevated
pressure.
The pressure in the reservoir can then be reduced to allow at least a portion
of the
hydrocarbon solvent to flash, providing a solvent gas drive to assist in
removing the
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heavy oil from the reservoir. The cycles may be repeated as long as economical
production is achieved.
[0009] Another group of techniques is based on a continuous injection of
steam
through a first well to lower the viscosity of heavy oils and a continuous
production of
the heavy oil from a lower-lying second well. Such techniques may be termed
"steam assisted gravity drainage" or SAGD.
[0010] In SAGD, two horizontal wells are completed into the reservoir.
The two
wells are first drilled vertically to different depths within the reservoir.
Thereafter,
using directional drilling technology, the two wells are extended in the
horizontal
direction that result in two horizontal wells, vertically spaced from, but
otherwise
vertically aligned with the other. Ideally, the production well is located
above the
base of the reservoir but as close as practical to the bottom of the
reservoir, and the
injection well is located vertically 10 to 30 feet (3 to 10 meters) above the
horizontal
well used for production.
[0011] The upper horizontal well is utilized as an injection well and is
supplied
with steam from the surface. The steam rises from the injection well,
permeating the
reservoir to form a vapor chamber that grows over time towards the top of the
reservoir, thereby increasing the temperature within the reservoir. The steam,
and
its condensate, raise the temperature of the reservoir and consequently reduce
the
viscosity of the heavy oil in the reservoir. The heavy oil and condensed steam
will
then drain downward through the reservoir under the action of gravity and may
flow
into the lower production well, whereby these liquids can be pumped to the
surface.
At the surface of the well, the condensed steam and heavy oil are separated,
and the
heavy oil may be diluted with appropriate light hydrocarbons for transport by
pipeline.
[0012] A number of variations of the SAGD process have been developed in an
attempt to increase the productivity of the process. Such processes may
include
new well placement techniques and tools used to enhance production of the
heavy
oil. In other variations, extensions similar to those used in CSS, such as
including
solvents in the process, have been made.
[0013] Similarly, Canadian Patent No. 2,591,498 and corresponding U.S.
Patent
No. 7,556,099 to Arthur, et al. discloses a recovery process that utilizes in-
fill wells.
In the method, a first injector-producer well pair is operated under a
substantially
gravity-controlled recovery process, forming a first mobilized zone. A second
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injector-producer well pair is also operated under a substantially gravity-
controlled
recovery process, forming a second mobilized zone. An in-fill well is provided
in a
bypassed region, formed between the adjacent well pairs. When the first
mobilized
zone and the second mobilized zone merge to form a common mobilized zone, the
in-fill well can be operated to establish fluid communication between the in-
fill well
and the common mobilized zone. Accordingly, the in-fill well and the adjacent
well
pairs may be operated under a substantially gravity-controlled recovery
process to
recover heavy oil from the in-fill well.
[0014] In another example of the use of in-fill wells, U.S. Patent
Application
Publication No. 2009/0288827 by Coskuner, filed November 26, 2009, discloses a
process for recovering heavy oil from oil sands. In the process, CSS is first
used in a
series of horizontal wells in the reservoir. SAGD is then used with a
vertically-
spaced horizontal well pair in which one well in each well pair is part of the
series of
wells to which CSS was applied, and oil is produced from at least one single
well in
the series of wells. In this case, each single well is adjacent to and offset
from at
least one of the well pairs. The method can then include applying a SAGD
injection
to an injection well of each well pair and producing oil from a production
well of each
well pair and from the single well.
[0015] SAGD designs often stress the need to minimize the pressure drop
that
occurs along the length of the liners of the injection and production wells.
Current
industry practice is to use as a target a pressure drop in the liners,
irrespective of the
length of the liners, for example, of 50 kPa. This corresponds to a liquid
head of
about five meters, which corresponds to the typical separation between SAGD
injection and production wells. To achieve this target, current injector
designs
include splitting steam injection between the two ends of the liner by
including a
tubing string that extends to the toe of the liner. Other designs increase the
liner
diameter as the liner length and, thus, the steam demand increase. Increasing
the
liner diameter as the operating pressure decreases and the physical volume of
the
steam travelling through the liner increases. In some designs, the steam
injection
and production locations in each liner are offset, so that portions of the
pressure
drops occurring in the injection and production wells cancel. In yet other
designs,
the toe tubing string can be repositioned and the steam injection rebalanced
between the two injection strings to account for the changes in the hydraulic
diameters along the liner length that result. Further, in some designs, once
sufficient
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steam injectivity into the reservoir exists, a tubing string with a series of
limited entry
perforations is used to distribute the steam at multiple locations along the
annulus.
Further, in other designs, the open area between the liner and reservoir can
be
constrained such that the pressure drop within the liner is not transferred to
the
reservoir.
[0016] It is
current industry practice that when gravity drainage is the dominant
recovery mechanism the production liner should be drilled as flat as possible
and the
injection and production wells should have matched lengths. This
arrangement
decreases the potential for the steam to be coned into the production well at
high
points along the liner trajectory. Reproduction of the steam vapor represents
a
needless increase in operating costs. However, in situations where the base of
pay
is not flat, a flat production liner trajectory can result in significant
quantities of
otherwise recoverable resource being located beneath the depth of the
producer. As
a result, recovering this bypassed resource will require a future investment
in new
wells or sidetrack completions from the existing wells.
SUMMARY
[0017] An
embodiment described herein provides a method for improving
recovery from a subsurface hydrocarbon reservoir, the method comprising:
creating
a geological model of the reservoir; constructing a structural map of a
position of a
base of a pay interval of the reservoir which includes a region that comprises
hydrocarbons; based on the structural map, designing a serpentine well pair
comprised of a production well and an injection well wherein a trajectory of
the
production well and the injection well use both vertical displacements and
lateral
displacements, and wherein the trajectory of the serpentine well pair follows
the base
of the pay interval of the reservoir; and accessing the region by the
serpentine well
pair, wherein the serpentine well pair comprises the production well at a
first
elevation and the injection well at a higher elevation, and wherein the
serpentine well
pair is drilled with a serpentine trajectory comprising both vertical
displacements and
lateral displacements to follow the base of the pay interval of the reservoir
as
determined by the structural map to maximize the recovery of the unswept
hydrocarbons and wherein at least a portion of the production well comprises a
liner
with no perforations.
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[0018] Another embodiment provides a system for harvesting resources from
a
reservoir, comprising: a geological model of the reservoir; a structural map
of a
position of a base of a pay interval of the reservoir; the reservoir
comprising
hydrocarbons; and a serpentine well pair, wherein the serpentine well pair
comprises
a production well at a first elevation and an injection well at a higher
elevation,
wherein the serpentine well pair has a serpentine trajectory comprising both
vertical
displacements and lateral displacements to follow the base of the pay interval
of the
reservoir as determined by the structural map, and wherein at least a portion
of the
production well is completed using a liner that has no perforations.
DESCRIPTION OF THE DRAWINGS
[0019] The advantages of the present techniques are better understood by
referring to the following detailed description and the attached drawings, in
which:
[0020] Fig. 1 is a drawing of a steam assisted gravity drainage (SAGD)
process
100 used for accessing hydrocarbon resources in a reservoir 102;
[0021] Fig. 2 is a cross section of a well interval showing the presence of
separate production intervals in a reservoir;
[0022] Fig. 3 is a schematic illustrating an injection liner having a
tapered section
to improve the movement through a wellbore;
[0023] Figs. 4(A), (B), and (C) are North - South cross-sectional views
of different
production intervals in a reservoir;
[0024] Figs. 5(A), (B), and (C) are cross-sectional views illustrating
the placement
of standard well-pairs in the cross-sectional views of Figs. 4(A), (B), and
(C),
respectively;
[0025] Fig. 6 is a cross-sectional view illustrating the placement of a
curving
SAGD well-pair in the cross-sectional view of Fig. 4(A);
[0026] Figs. 7(A), (B), and (C) are cross-sectional views illustrating
various
configurations that may be used for the placement of serpentine well-pairs in
the
cross-sectional view of Fig. 4(A);
[0027] Figs. 8(A) and (B) are cross-sectional views illustrating various
configurations that may be used for the placement of serpentine well-pairs in
the
cross-sectional views of Figs. 4(B) and (C), respectively; and
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[0028] Fig. 9
is a process flow diagram of a method for completing serpentine
well-pairs that access resources that may be bypassed by SAGD well pairs
having a
flat trajectory.
DETAILED DESCRIPTION
[0029] In the following detailed description section, specific embodiments
of the
present techniques are described.
However, to the extent that the following
description is specific to a particular embodiment or a particular use of the
present
techniques, this is intended to be for exemplary purposes only and simply
provides a
description of the exemplary embodiments. Accordingly, the techniques are not
limited to the specific embodiments described below, but rather, include all
alternatives, modifications, and equivalents falling within the true spirit
and scope of
the appended claims.
[0030] At the
outset, for ease of reference, certain terms used in this application
and their meanings as used in this context are set forth. To the extent a term
used
herein is not defined below, it should be given the broadest definition
persons in the
pertinent art have given that term as reflected in at least one printed
publication or
issued patent. Further, the present techniques are not limited by the usage of
the
terms shown below, as all equivalents, synonyms, new developments, and terms
or
techniques that serve the same or a similar purpose are considered to be
within the
scope of the present claims.
[0031] As used
herein, the term "base" indicates a lower boundary of the
resources in a reservoir that are practically recoverable, by a gravity-
assisted
drainage technique, for example, using an injected mobilizing fluid, such as
steam,
solvents, hot water, gas, and the like. The base may be considered a lower
boundary of the pay interval. The lower boundary may be an impermeable rock
layer, including, for example, granite, limestone, sandstone, shale, and the
like. The
lower boundary may also include layers that, while not impermeable, impede the
formation of fluid communication between a well on one side and a well on the
other
side. Such layers may include broken shale, mud, silt, and the like. The
resources
within the reservoir may extend below the base, but the resources below the
base
may not be recoverable with gravity-assisted techniques.
[0032]
"Bitumen" is a naturally occurring heavy oil material. Generally, it is the
hydrocarbon component found in oil sands. Bitumen can vary in composition
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depending upon the degree of loss of more volatile components. It can vary
from a
very viscous, tar-like, semi-solid material to solid forms. The hydrocarbon
types
found in bitumen can include aliphatics, aromatics, resins, and asphaltenes. A
typical bitumen might be composed of:
19 wt. % aliphatics (which can range from 5 wt. %-30 wt. %, or higher);
19 wt. % asphaltenes (which can range from 5 wt. %-30 wt. %, or higher);
30 wt. % aromatics (which can range from 15 wt. %-50 wt. %, or higher);
32 wt. % resins (which can range from 15 wt. %-50 wt. %, or higher); and
some amount of sulfur (which can range in excess of 7 wt. %).
In addition bitumen can contain some water and nitrogen compounds ranging from
less than 0.4 wt. % to in excess of 0.7 wt. %. The metals content, while
small, must
be removed to avoid contamination of the product synthetic crude oil (SCO).
Nickel
can vary from less than 75 ppm (part per million) to more than 200 ppm.
Vanadium
can range from less than 200 ppm to more than 500 ppm. The percentage of the
hydrocarbon types found in bitumen can vary. As used herein, the term "heavy
oil"
includes bitumen, as well as lighter materials that may be found in a sand or
carbonate reservoir.
[0033] As used herein, two locations in a reservoir are in "fluid
communication"
when a path for fluid flow exists between the locations. For example, the
establish of
fluid communication between a lower-lying production well and a higher
injection well
may allow material mobilized from a steam chamber above the injection well to
flow
down to the production well from collection and production. As used herein, a
fluid
includes a gas or a liquid and may include, for example, a produced
hydrocarbon, an
injected mobilizing fluid, or water, among other materials.
[0034] As used herein, a "cyclic recovery process" uses an intermittent
injection
of a mobilizing fluid selected to lower the viscosity of heavy oil in a
hydrocarbon
reservoir. The injected mobilizing fluid may include steam, solvents, gas,
water, or
any combinations thereof. After a soak period, intended to allow the injected
material to interact with the heavy oil in the reservoir, the material in the
reservoir,
including the mobilized heavy oil and some portion of the mobilizing agent may
be
harvested from the reservoir. Cyclic recovery processes use multiple recovery
mechanisms, in addition to gravity drainage, early in the life of the process.
The
significance of these additional recovery mechanisms, for example dilation and
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compaction, solution gas drive, water flashing, and the like, declines as the
recovery
process matures. Practically speaking, gravity drainage is the dominant
recovery
mechanism in all mature thermal, thermal-solvent and solvent based recovery
processes used to develop heavy oil and bitumen deposits. For this reason the
approaches disclosed here are equally applicable to all recovery processes in
which,
at the current stage of depletion, gravity drainage is the dominant recovery
mechanism.
[0035]
"Facility" as used in this description is a tangible piece of physical
equipment through which hydrocarbon fluids are either produced from a
reservoir or
injected into a reservoir, or equipment which can be used to control
production or
completion operations. In its broadest sense, the term facility is applied to
any
equipment that may be present along the flow path between a reservoir and its
delivery outlets.
Facilities may comprise production wells, injection wells, well
tubulars, wellhead equipment, gathering lines, manifolds, pumps, compressors,
separators, surface flow lines, steam generation plants, processing plants,
and
delivery outlets. In some instances, the term "surface facility" is used to
distinguish
those facilities other than wells.
[0036] "Heavy
oil' includes oils which are classified by the American Petroleum
Institute (API), as heavy oils or extra heavy oils. In general, a heavy oil
has an API
gravity between 22.3 (density of 920 kg/m3 or 0.920 g/cm3) and 10.00 (density
of
1,000 kg/m3 or 1 g/cm3). An extra heavy oil, in general, has an API gravity of
less
than 10.0 (density greater than 1,000 kg/m3 or greater than 1 g/cm3). For
example,
a source of heavy oil includes oil sand or bituminous sand, which is a
combination of
clay, sand, water, and bitumen. The thermal recovery of heavy oils is based on
the
viscosity decrease of fluids with increasing temperature or solvent
concentration.
Once the viscosity is reduced, the mobilization of fluids by steam, hot water
flooding,
or gravity is possible. The reduced viscosity makes the drainage quicker and
therefore directly contributes to the recovery rate
[0037] A
"hydrocarbon" is an organic compound that primarily includes the
elements hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or
any
number of other elements may be present in small amounts. As used herein,
hydrocarbons generally refer to components found in heavy oil, or other oil
sands.
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[0038] "Permeability" is the capacity of a rock to transmit fluids
through the
interconnected pore spaces of the rock. The customary unit of measurement for
permeability is the millidarcy.
[0039] As used herein, a "reservoir" is a subsurface rock or sand
formation from
which a production fluid, or resource, can be harvested. The rock formation
may
include sand, granite, silica, carbonates, clays, and organic matter, such as
oil, gas,
or coal, among others. Reservoirs can vary in thickness from less than one
foot
(0.3048 m) to hundreds of feet (hundreds of m). The resource is generally a
hydrocarbon, such as a heavy oil impregnated into a sand bed.
[0040] As used herein, "serpentine well pair" indicates that at least one
of the
wells in the well pair uses lateral displacements, vertical displacements, or
both to
follow a base of the pay interval in a reservoir. Further, serpentine well
pairs include
well pairs in which one of the paired wells extends past the other well.
[0041] As discussed in detail above, "Steam Assisted Gravity Drainage"
(SAGD),
is a thermal recovery process in which steam, or combinations of steam and
solvents, is injected into a first well to lower a viscosity of a heavy oil,
and fluids are
recovered from a second well. Both wells are generally horizontal in the
formation
and the first well lies above the second well. Accordingly, the reduced
viscosity
heavy oil flows down to the second well under the force of gravity, although
pressure
differential may provide some driving force in various applications.
[0042] "Substantial" when used in reference to a quantity or amount of a
material,
or a specific characteristic thereof, refers to an amount that is sufficient
to provide an
effect that the material or characteristic was intended to provide. The exact
degree
of deviation allowable may in some cases depend on the specific context.
[0043] As used herein, "thermal recovery processes" include any type of
hydrocarbon recovery process that uses a heat source to enhance the recovery,
for
example, by lowering the viscosity of a hydrocarbon. These processes may use
injected mobilizing fluids, such as hot water, wet steam, dry steam, or
solvents
alone, or in any combinations, to lower the viscosity of the hydrocarbon. Such
processes may include subsurface processes, such as cyclic steam stimulation
(CSS), cyclic solvent stimulation, steam flooding, solvent injection, and
SAGD,
among others, and processes that use surface processing for the recovery, such
as
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sub-surface mining and surface mining. Any of the processes referred to
herein,
such as SAGD may be used in concert with solvents.
[0044] A
"well" is a hole in the subsurface made by drilling or inserting a conduit
into the subsurface. A well may have a substantially circular cross section or
any
other cross-sectional shape, such as an oval, a square, a rectangle, a
triangle, or
other regular or irregular shapes. As used herein, the term "wellbore", when
referring to an opening in the formation, may be used interchangeably with the
term
"well".
Overview
[0045] Current techniques for harvesting heavy oils may bypass a
substantial
amount of hydrocarbon resources in the reservoir. The location and quantity of
resources, or unswept hydrocarbons, bypassed by the current recovery processes
is
a function of several factors. These include geologic variability, well
placement
decisions, operational decisions, and well failures, among others. For
example, the
current industry practice for well pairs used for steam assisted gravity
drainage
(SAGD) is to keep the well trajectories as flat as possible, in order to
minimize the
risk of steam, or other mobilizing fluids, from crossing over to the
production well at a
high point along a trajectory. Thus, the SAGD wells may bridge low points in a
reservoir without accessing the hydrocarbons present.
Similarly, the current
approaches to using in-fill wells to recover bypassed hydrocarbons use
horizontal
wells placed between SAGD well pairs, wherein the horizontal wells are kept to
flat
trajectories for essentially the same reasons.
[0046]
Embodiments described herein relate to a method for improving recovery
from a subsurface hydrocarbon reservoir. Regions are identified within the
reservoir
that may contain significant accumulations of unswept hydrocarbons after a
normal
SAGD process. Serpentine well pairs can then be designed to pass through the
regions. The placement and completion of the serpentine well pairs can be
optimized to maximize the recovery of the unswept hydrocarbons. For example,
the
serpentine wells may be completed to follow a base of the reservoir. Further,
a
production well may travel through a non-pay interval to connect two pay
intervals.
In areas where the production well has an increasing trajectory, the
production well
liner may not have perforations, e.g., being completed with blank pipe. In
addition,
an injection well may extend beyond a production wells into raised areas
containing
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resources, helping the resources to drain to the production wells. A tapered
liner
may be used in embodiments to assist in following the curving wells. As noted
herein, the base of the reservoir represents a practical lower limit of the
hydrocarbons that may be recoverable by a gravity-assisted process.
[0047] In embodiments, various techniques are used to prevent excess
reproduction of injected mobilizing fluids used in the hydrocarbon recovery
process.
These techniques may include process design and control or the selective
obstruction of portions of the liner in the serpentine well pairs. In some
embodiments, a geometric pattern may be used for placing the in-fill wells.
[0048] Although, for
simplicity of explanation, SAGD is used to describe the
techniques herein, the techniques are equally applicable to all recovery
processes in
which gravity drainage is the dominant recovery mechanism. For example, in an
embodiment, a serpentine well pair may be completed into a reservoir to
enhance
recovery of hydrocarbons. Further, the techniques may be used in recovery
processes that use solvent, or steam and solvent mixtures, to mobilize
hydrocarbons. Thus, the injected mobilizing fluid used to harvest the
hydrocarbons
may include steam, solvents, gas, steam and solvent mixtures, and any
combinations thereof, including different mobilizing fluids at different
points in the life
of a reservoir.
[0049] Fig. 1 is a
drawing of a steam assisted gravity drainage (SAGD) process
100 used for accessing hydrocarbon resources in a reservoir 102. In the SAGD
process 100, steam 104 can be injected through injection wells 106 to the
reservoir
102. As previously noted, the injection wells 106 may be horizontally drilled
through
the reservoir 102. Production wells 108 may be drilled horizontally through
the
reservoir 102, with a production well 108 underlying each injection well 106.
Generally, the injection wells 106 and production wells 108 will be drilled
from the
same pad 110 at the surface 112. This may make it easier for the production
well
108 to track the injection well 106. However, in some embodiments the wells
106
and 108 may be drilled from different pads 110.
[0050] The injection
of steam 104 into the injection wells 106 may result in the
mobilization of hydrocarbons 114, which may drain to the production wells 108
and
be removed to the surface 112 in a mixed stream 116 that can contain
hydrocarbons, condensate and other materials, such as water, gases, and the
like.
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As described herein, screen assemblies may be used on the injection wells 106,
for
example, to throttle the inflow of injectant vapor to the reservoir 102.
Similarly,
screen assemblies may be used on the production wells 108, for example, to
decrease sand entrainment
[0051] The hydrocarbons 114 may form a triangular shaped drainage chamber
118 that has the production well 108 located at a lower apex. The mixed stream
116
from a number of production wells 108 may be combined and sent to a processing
facility 120. At the processing facility 120, the water and hydrocarbons 122
can be
separated, and the hydrocarbons 122 sent on for further refining. Water from
the
separation may be recycled to a steam generation unit within the facility 120,
with or
without further treatment, and used to generate the steam 104 used for the
SAGD
process 100.
[0052] In prior SAGD processes, the production wells 108 often had a
segment
that was relatively flat and, in some circumstances, had a slight upward slope
from
the heel 126, at which the pipe branches to the surface, to the toe 128, at
which the
pipe ends. However, the previous configuration of the production well 108
could
result in bridging over some sections 132 of the reservoir 102, leaving
hydrocarbons
behind. These sections 132 can be caused by natural variations, or rugosity,
in the
base 134 of the reservoir, for example, caused by karsting, depositional
facies, and
erosional incisements.
[0053] In embodiments described herein, the unswept resources in these
sections 132 may be accessed by making the trajectories of the production
wells
108, or both the production 108 and injection wells 106 follow the base 134 in
a
serpentine fashion. Any number of other configurations may be used as
discussed
with respect to Figs. 6-8. As used herein, any of these variations, including
systems
in which only the production well 108 follows the base 134 of the reservoir
and in
which one well or the other extends out beyond the other well, is termed a
serpentine
well pair 136. The serpentine well pairs 136 can be directionally drilled to
follow the
base 134 of the reservoir 102, for example, moving laterally and vertically
towards
and through the sections 132, permitting hydrocarbons to be harvested from
areas
that would otherwise be bypassed. High points in the production wells 108 may
be
left uncompleted, for example, by being left as blank pipe segments.
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[0054] Fig. 2 is a cross section of a well interval showing the presence
of
separate production intervals 202 and 204 in a reservoir 102. The production
intervals 202 and 204 are formed by a limestone layer 206 that has a high spot
208
blocking flow of hydrocarbon between the production intervals 202 and 204. In
the
low points of the production intervals 202 and 204, the production well 108
can be
completed, for example, with screens, perforations, mesh, or other openings,
to
harvest hydrocarbons from the production intervals 202 and 204. As used
herein,
the production intervals 202 and 204 containing the completed well
trajectories may
be termed subsurface drainage boxes.
[0055] Other portions 210 of the trajectory of the production well 108 can
be
formed using blank pipe, e.g., without perforations. In contrast, all of the
injection
well 106 may be completed, allowing injection of the mobilizing agent 212,
such as
steam, throughout the reservoir 102. Mobilized hydrocarbons 214 can then flow
down to the production intervals 202 and 204. The liners of the wells 106 and
108
may have difficulty following the complex trajectory or passing over sand
bridges that
have formed in the well. In some embodiments, this is resolved by tapering the
liners, as discussed with respect to Fig. 3.
[0056] Fig. 3 is a schematic illustrating an injection liner 300 having a
tapered
section 302 to improve the movement through a wellbore. The tapered section
302
may include a single section of pipe having a smaller diameter than the liner,
or may
be a series of smaller diameter pipe segments at the end of the liner. For
example,
the tapered segment may be a 14 cm in diameter pipe segment attached to an 18
cm in diameter liner section using a 14 cm x 18 cm crossover. In this example,
a
toe-tubing string 304, which carries steam 306 to the end of the liner 300, is
placed
within the full sized-section 308 of the liner 300. The tapered section 302
can be
used to follow a rising trajectory 310, for example, of about 0.5 degrees,
allowing
steam 306 to flow up into the tapered section 302 and water 312 to flow down
from
the tapered section 302. Similar tapering may be used for liners in production
wells,
allowing complex trajectories to be drilled for the wells. The tapered section
302
does not have to be long to make following a trajectory easier, for example,
50 m to
100 m may be sufficient.
[0057] Figs. 4(A), (B), and (C) are North - South cross-sectional views
of different
production intervals 402, 404, and 406 in a reservoir 102. In these cross-
sections
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=
the base 408 and top 410 of the pay interval 412 deemed to be acceptable for
exploitation with SAGD are noted. As previously noted, the rugosity of the
base 408
can be due to a combination of factors, for example, karsting, changes in
depositional fades, or erosional incisements, among others.
[0058] Figs. 5(A),
(B), and (C) are cross-sectional views illustrating the placement
of standard well-pairs in the cross-sectional views of Figs. 4(A), (B), and
(C),
respectively. In each of these cross-sections a SAGD well pair 502, drilled
with a flat
trajectory, has been added. In all
three cases, a significant quantity 504 of
exploitable resource has been stranded beneath the trajectory of the SAGD well
pair
502.
[0059] Fig. 6
is a cross-sectional view illustrating the placement of a curving
SAGD well-pair 602 in the cross-sectional view of Fig. 4(A), in accordance
with
previous studies. In this case the SAGD well-pair 602 has been drilled such
that it
tracks the base 408 of the pay interval 412. The expected benefit with this
profile is
lost by restricting production from the production well 108 to prevent the
steam
chamber from coning into the high point of the trajectory of the production
well 108.
This will result in fluid accumulating above the remainder of the well
trajectory,
effectively decreasing the effective height of the steam chamber. If, as drawn
here,
the height of the liquid sump 604 exceeds the depth of the injection well 106,
the
accumulated fluids can impair steam injection at these locations, further
impeding
the SAGD operation.
[0060] Figs.
7(A), (B), and (C) are cross-sectional views illustrating various
configurations that may be used for the placement of serpentine well-pairs in
the
cross-sectional view of Fig. 4(A). In these embodiments, the injection well
106 can
be used as a "hot finger" that results in the accelerated depletion of a
reservoir 102.
In all three cases shown in Fig. 7, the completed portion of the trajectory of
the
production well 108 remains confined to the deepest pay, while the trajectory
of the
injection well 106 has been extended beyond the toe of the production liner
into an
area of thinner pay interval.
[0061] In Fig. 7(A), the profile of the injection well 106 continues to
slowly raise
though the pay interval 412. This "toe up" configuration enables steam to be
present
throughout the entire length of the injector liner extension 702, without
requiring an
injection tubing string to be present in the toe up section. As the steam
condenses,
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the condensate can travel back along liner string under the influence of
gravity. The
heated oil surrounding the injector extension can also drain under the
influence of
gravity along the heated pathway back to the toe of the production well. Steam
present in the injector liner will leave the injector to occupy the space
vacated by the
oil thereby causing the steam chamber to rapidly grow into the area
surrounding the
toe up injector liner. This configuration may cause a rapid drainage of the
resource
from the thinner area of the pay interval 412.
[0062] In Fig. 7(B) the slow rise of the injector liner extension 702 has
been
interrupted by a series of flat or dipping sections 704 that will result in a
slower rate
of heating in the extension area. For example, in a dipping section 704 of the
injector liner extension 702, the condensed steam cannot drain out of the
dipping
section 704 until the steam chamber has had the opportunity to extend as far
as the
first liner access point beyond the location of the dipping section 704. Once
this
occurs, the condensate that has accumulated in the dipping section 704 can
drain
from the liner and steam to access the next increment of toe up liner that
ends at the
next dip in the injector profile. This may result in a slower drainage of
resource from
the thinner section of the pay interval 412.
[0063] In Fig. 7(C) the profile of the injector liner extension 702
initially rises to
stay within the pay interval 412 and then remains flat. This configuration
allows
some steam to be present throughout the entire length of the injector liner
extension,
without requiring an injection tubing string to be present. The flat well
profile will
slow the drainage of the condensate from the injector liner extension 702 and
the
drainage of oil from the heated reservoir surrounding the injector liner
extension 702.
As a result, the long term rate of heat penetration and resource depletion
should be
between that expected with the configurations shown in Figures 7(A) and 7(B).
In
all three cases, as shown in 7(A), 7(B), and 7(0), the liquid sump 604 is
slightly above the production well 108. If the production well 108 rises
above a target depth for the liquid sump 604, higher sections may be
completed with blank pipe to prevent the liquid sump 604 from getting
deeper than the target depth.
[0064] Figs. 8(A) and (B) are cross-sectional views illustrating various
configurations that may be used for the placement of serpentine well-pairs in
the
cross-sectional views of Figs. 4(B) and (C), respectively. The configurations
in Fig. 8
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show that the injection well 106 can be used as a "hot finger" that results in
the
accelerated depletion of reservoirs similar to those shown in Fig. 7.
[0065] In
Figure 8(A), the completions in the liner, e.g., perforations in the
production well 108, stops at the end of the structural low 802. The injector
profile
on either side of the structural low has been modified to allow steam to
accumulate,
condense and drain from these non-horizontal sections, thereby accelerating
recovery.
[0066] In
Figure 8(B) the production well 108 is drilled through an interval 804 of
poor reservoir quality, while the injection well 106 passes above the interval
804.
The profile of the injection well 106 is modified to ensure that steam is able
to
accumulate, condense and drain in the section above the interval 804, thereby
accelerating recovery from the thinner good quality reservoir present above
the
interval 804 of poor quality. The two open portions of the production well
liner that
allow inflow are confined to the two structural low areas 806.
[0067] Fig. 9 is a
process flow diagram of a method for completing serpentine
well-pairs that access resources that may be bypassed by SAGD well pairs
having a
flat trajectory. The method 900 starts at block 902 with the delineation of
the one or
more pay intervals expected to be developed over the life of the project.
Reservoir
delineation typically occurs through the combined use of delineation wells,
remote
sensing technologies such as 2-dimensional and 3-dimensional seismic analyses,
studies of modern analogs, and outcrop studies of the target reservoir, if
parts of the
reservoir outcrop on surface. Other reservoirs with comparable depositional
settings
may be used to provide insight into the delineation.
[0068]
Delineation wells are used to collect core samples of the target reservoir
and open hole and cased hole log data. The core samples are further used to
gain
an understanding of the depositional settings present in the reservoir,
porosity and
oil content distributions, horizontal and vertical permeability distributions,
oil density
and viscosity distributions, sand grain size analyses and reservoir rock
samples that
can be used to understand how the reservoir material will respond to heating
with
steam and/or water or extended exposure to a solvent. Remote
sensing
technologies, modern reservoir analogs, and outcrop studies allow the
prediction of
the spatial distribution of the geologic attributes and fluid properties in
the reservoir.
As used herein, modern reservoir analogs include modern regions that have the
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same depositional environment as the older buried reservoir, such as river
systems,
coastal areas, and the like.
[0069] Additional data can be collected to understand various other
properties of
the reservoir for the modeling. Such properties include the ability of the
reservoir
caprock to withstand changes in pressure associated with an injection of
injectant
when an in-situ recovery process is applied. Other properties include the
initial
pressure distribution in the reservoir and surrounding strata. Pressure
properties in
the reservoir collected may include the presence and areal extend of any
pressure
sinks, such as top gas, top water, or bottom water. Further, information can
be
collected on any interstitial intervals within the reservoir. Such
interstitial intervals
may have initial enhanced water mobility and may be present within, or
directly
adjacent, to the oil-bearing sections. A determination may be made of the
locations,
and capacities, of water make-up sources and water disposal intervals.
[0070] These data are used to create a geologic model for each reservoir
that is
expected to be included as part of the overall development. The geologic
models
are usually constructed using a geologic modeling software program, such as
the
Petrel program available from the Schlumberger corporation, among others. The
available open hole and cased hole log, core, 2-D and 3-D seismic data, and
knowledge of the depositional environment setting are used in the construction
the
geologic model which can include many millions of individual cells of sizes
specified
by the user.
[0071] The geologic model can then be used to identify the region of the
resource
to be included in the initial phase of the development. Criteria for this
decision
include pay thickness, pay cleanliness (e.g., the absence of shale lenses),
the
number and size of pressure sinks, if any, and the like. The model also allows
the
construction of a structural map of the position of the base of the pay
interval. This
map may use sea level as a reference point, as the ground level above the
reservoir
will not be flat.
[0072] Thus, at block 904, serpentine well pairs can be designed using
the
available geologic model. The depth and lateral offset of the trajectories of
the
serpentine wells vary such that a portion of each serpentine well can
intercept one or
more of the low-lying hydrocarbon intervals near the base. To perform this
function,
surface constraints are identified that may limit the position of surface
drilling
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locations and, thus, the specific layout of the completed production liners in
low
regions of the reservoir, i.e., the subsurface drainage boxes.
[0073] For each subsurface drainage box, the model is used to identify
the
portions of the well trajectory that are the deepest. These will become the
desired
locations for the production completion intervals. The model is also used to
identify
the portions of the well trajectory that are the shallowest. These will become
the
desired locations for the inclusion of non-completion intervals, as well as
for
modifications to the trajectory of the production well, injection well, or
both.
[0074] As will be recognized, for a reservoir of uniform quality, the
rate at which it
is depleted is predicted to be inversely proportional to the square root of
the
thickness of the pay above the depth of the producer wellbore. Thus, regions
along
a well pair trajectory that are thinner can negatively affect ultimate
recovery by
depleting faster. Once depleted, the thinner portion of the reservoir will
contribute to
continued heat losses, but will not contribute additional oil production.
[0075] Further, the thinner portions of the reservoir may become locations
for
steam coning into the production well. As less fluid is flowing into the
production well
at this location than at other areas along the production well, the chamber
can
expand downwards to the depth of the production well. When this occurs, either
steam will enter the production well or production rates for the entire well
will be
need to be constrained, resulting in mobilized fluids accumulating above the
producer in the more productive regions along the production well trajectory.
This
accumulation of fluid will reduce the effective steam chamber height and
reduce
recovery at these portions of the liner. Additionally, as steam injection is
provided by
a substantially constant pressure line source, the reduced steam demand in the
areas of the reservoir with reduced pay thickness will result in a localized
increase in
chamber pressure near the wells which will further aggravate the coning
tendency at
these thinner pay locations.
[0076] As described herein, when a region that is expected to be depleted
faster
than the remainder of the well trajectory is located along a planned
trajectory of a
well pair, a number of strategies can be implemented to lower the chances that
it will
detrimentally affect overall performance. For example, there may be no open
completions, in the production well, the injection well, or both, along that
portion of
the reservoir, as discussed with respect to Fig. 8.
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[0077] By
including no completions in a region, the recovery of the oil in the
region will occur as the depleted zone spreads laterally along the well pair,
and flows
to other regions where the production well has completions. In situations
where
steam, or another heated fluid, is an injectant, growth of depletion into the
uncompleted regions will benefit from the heat losses from the existing
injection wells
and production wells, which can create "hot fingers" in this direction,
thereby
accelerating the mobilization and drainage of oil.
[0078] When a
region that is expected to be depleted faster than the remainder of
the well spacing is located at the end of the planned trajectory of the well
pair, as
.. discussed with respect to Fig. 7, an additional opportunity is available to
improve the
cost effectiveness of the recovery process. Specifically, the injection well
of the well
pair can be drilled longer than the production well, creating a mismatch in
their
lengths.
[0079] When
steam, or another heated fluid, is an injectant, having the injection
well extend past the toe of the production well creates a "hot finger in this
direction.
The hot finger accelerates the mobilization of the oil.
Depending on the
circumstances, the access to this additional resource may occur at different
speeds.
A change in speed of production can be accomplished by manipulating the
injector
well profile and/or the placement of the tubing string within the injector
liner. For
.. example, the fastest heating will occur when steam can access the entire
length of
the injection liner from the start of injection. This can be accomplished by
installing
an injection string to the end of the liner, or drilling the injection well
extension with a
shallow upward angle, as discussed with respect to Fig. 7(A). The shallow
upward
angle allows steam to rise in the extension and the condensed steam, or
condensate, to drain freely out of the extension. Without this upward angle
the
removal of the heated oil will progress much slower as the gravity head is
reduced.
[0080]
Accordingly, by placing downward dips in the otherwise shallow upwards
angle profile of the injector extension, as discussed with respect to Fig.
7(6), the
distance of heating in the extension can be regulated. Specifically, the
portion of the
injection well that lies beyond the dips will not drain of condensate until
after the
depletion zone has extended beyond the first screen location on the other side
of the
dip. When the injectant is a non-heated solvent, having the injection well
extend
past the toe of the production well creates a pathway to accelerate the mixing
of the
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solvent and oil in this direction. Thus, similar strategies for the injector
extension
discussed above can be applied with the non-heated solvent.
[0081] In some embodiments, the production well may extend past the
injection
well. In this the hydrocarbons entering the production liner may be redirected
to the
toe before being produced. Further, this can provide the ability to inject the
injectant
near the toe of the production well, for example, using a coiled tubing
string. Once
the well trajectories are designed, the liners may be designed and completions
may
be located.
[0082] At block 906, the production liners of the serpentine well pairs
are
designed. The designs are based in part on a number of considerations,
including the expected well completions, the start-up techniques to be used,
and
the production strategies to be used, including artificial lift design and the
desired
number and location of the production points. Other considerations include
strategies planned for transitioning to a follow-up recovery technology and
preparing
for the final shutdown of the pattern of wells. The design of the serpentine
well pairs
and patterns of wells can be modified in light of the liner design, resulting
in an
iterative process.
[0083] The design of the liners is based on the subsurface drainage
boxes. Once
the locations of the subsurface drainage boxes are known, an assessment is
completed on the wellbore trajectories to ensure that the path can be
successfully
drilled and the liner installed.
[0084] To improve the ease at which the liners can be placed in the
drilled hole,
the diameter of the liner can be reduced one or more times towards the toe, as
discussed with respect to Fig. 3. The size reduction makes the liner lighter
and more
flexible, allowing it to more easily conform to changes in direction of the
drilled hole.
Further, the size reduction may allow the toe of the liner to ride over top of
small
accumulations of materials in the drilled hole as it is pushed into the hole,
lowering
the chances of materials piling up in front of the liner. The reduction in
liner cross-
section will generally not interfere with the recovery performance due to the
reduced
total fluid rates expected in both the injection and production liners at
these points.
[0085] The portions of the trajectories of the serpentine well pairs that
have no
openings can either be completed with blank pipe or have the completions
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obstructed to prevent in-flow. For example, one such obstruction that can be
used is
a scab liner that is set inside a production liner.
[0086] At block 908, the serpentine well pairs are drilled using the
paths and well
patterns selected. Where sufficient geologic contrast is present, for example,
between an oil sand layer and a lower impermeable rock layer, the serpentine
well
pairs can be geosteered. The geosteering may be done by gamma ray detectors,
seismic detectors, or any other suitable techniques. The geosteering may help
to
ensure that the actual well paths remains close to the base of the reservoir
and in a
region that has adequate vertical permeability. This may allow the development
of
acceptable production rates with the gravity drainage mechanism at the new
well.
As a result, the trajectory of the serpentine wells may undulate vertically
and laterally
as they pass through the reservoir interval.
[0087] At block 910, the liners are installed in the production wells and
injection
wells. During installation, liner completions, e.g., perforations, may be
blocked so
that the apparent weight of the liner can be manipulated by the amount of
liquid and
gas fill inside the liner, thereby making it easier to install. For example,
the liner
completions can be blocked using wax plugs. After installation, the wax is
removed
by melting, such as by using steam circulation during start-up.
[0088] At block 912, hydrocarbons are produced from the subsurface
drainage
boxes. During the production, process design and control combined with the
selective obstruction of portions of the liner of the production wells can be
used to
prevent excess reproduction of an injected mobilizing fluid. Further,
production rates
may be controlled to help minimize the co-production of the injectant used to
mobilize the hydrocarbon.
[0089] Depending on whether the injectant is steam, a steam-gas mixture, a
steam-solvent mixture, solvent or gas, such procedures for controlling the
amount of
injectant co-production can include monitoring the bottom hole temperature or
pressure, as well as the production rates of injectant observed at surface. In
addition, the injectant amount and type may also be modified to keep the
measurements within control ranges. The control measures can be modified to
reflect changes in the injectant type and composition that may occur over the
life of
the project. In addition, the production liner or a production tubing string
present
within the liner could be completed with inflow control devices to restrict
the
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, .
production of injectant vapor. In some embodiments, each subsurface production
box can be depleted in sequence, with the perforations, screens, or slots
along the
remaining portions of the trajectory of the production liner obstructed to
prevent flow.
[0090]
While the present techniques may be susceptible to various modifications
and alternative forms, the embodiments discussed above have been shown only by
way of example. However, it should again be understood that the techniques is
not
intended to be limited to the particular embodiments disclosed herein. Indeed,
the
present techniques include all alternatives, modifications, and equivalents
falling
within the true spirit and scope of the appended claims.
Embodiments
[0091]
An embodiment described herein provides a method for improving
recovery from a subsurface hydrocarbon reservoir. The method includes mapping
a
base of a reservoir to determine a region that holds hydrocarbons and
accessing the
region by a serpentine well pair. The serpentine well pair includes a
production well
at a first elevation and an injection well at a higher elevation, and the
production well
is drilled with a variable trajectory to follow at least a portion of the base
of the
reservoir.
At least a portion of the production well includes a liner with no
perforations.
[0092]
The method includes designing the serpentine well pair with a vertical
placement, lateral placement, or both, that changes to allow the production
well to
intercept the region near a base within the reservoir. The production well may
be
drilled through intervals of non-pay to couple two or more pay intervals of
pay.
Portions of the production well may be completed in pay intervals with slotted
pipe,
wirewrap screen assemblies, or mesh rite screen assemblies.
[0093] A portion of
the injection well may be drilled beyond the production well
and an injector liner extension can be installed in the portion of the
injection well that
extends beyond the production well. The injector liner extension can be
completed
with slotted pipe, wirewrap screen assemblies, or mesh rite screen assemblies.
At
least a portion of the injection well that extends beyond the production well
can be
drilled at an angle to horizontal.
[0094]
A portion of the production well may be drilled beyond the injection well
and a production liner extension can be installed in the portion of the
production well
that extends beyond the injection well. The portion of the production well
that
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extends beyond the injection well can be drilled at an angle to horizontal.
The
production liner extension can be completed with slotted pipe, wirewrap screen
assemblies, or mesh rite screen assemblies.
[0095] Another embodiment provides a system for harvesting resources from
a
reservoir. The system includes a reservoir that holds hydrocarbons. A
serpentine
well pair is included in the system, wherein the serpentine well pair
comprises a
production well at a first elevation and an injection well at a higher
elevation. The
production well has a variable trajectory to follow at least a portion of the
base of the
reservoir and at least a portion of the production well includes a liner with
no
perforations.
[0096] The production well can extend through intervals of non-pay to
couple two
or more pay intervals in the reservoir. Portions of the production well can be
completed with slotted pipe, wirewrap screen assemblies, or mesh rite screen
assemblies. Portions of the production well can be completed with blank pipe.
[0097] A portion of the injection well can extend beyond the production
well to
form an injector liner extension. At least a portion of the injector liner
extension can
be completed with slotted pipe, wirewrap screen assemblies, or mesh rite
screen
assemblies. The injector liner extension can include blank pipe.
[0098] A portion of the production well can extend beyond the injection
well to
form a production liner extension. Any portion of the production liner that
extends
above a target depth for a liquid sump can be completed with blank pipe.
[0100] Another embodiment provides a method for drilling a well in a
reservoir.
The method includes planning a well trajectory for a serpentine well pair. The
production well is drilled using lateral displacements and vertical
displacements to
follow a base of a pay interval in the reservoir. The production well is
completed with
a liner that includes perforations in regions comprising a hydrocarbon,
wherein at
least a portion of the production well has no perforations.
[0101] The method can include identifying well trajectories of the
production well
that need to be blocked to lower a production of an injected mobilizing fluid.
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