Note: Descriptions are shown in the official language in which they were submitted.
CA 2912301 2017-03-02
METHOD AND SYSTEM FOR ENHANCING THE RECOVERY OF HEAVY OIL
FROM A RESERVOIR
[0001]
BACKGROUND
Fields of Disclosure
[0002] The disclosure relates generally to the field of recovering heavy
oil and, more
particularly, to a method and system for enhancing the recovery of heavy oil
from a reservoir
within a subsurface formation.
Description of Related Art
[0003] This section is intended to introduce various aspects of the art,
which may be
associated with the present disclosure. This discussion is believed to assist
in providing a
framework to facilitate a better understanding of particular aspects of the
present disclosure.
Accordingly, it should be understood that this section should be read in this
light, and not
necessarily as admissions of prior art.
[0004] Modern society is greatly dependent on the use of hydrocarbon
resources for
fuels and chemical feedstocks. Hydrocarbons are generally found in subsurface
formations
that can be termed "reservoirs." Removing hydrocarbons from the reservoirs
depends on
numerous physical properties of the subsurface formations, such as the
permeability of the
rock containing the hydrocarbons, the ability of the hydrocarbons to flow
through the
subsurface formations, and the proportion of hydrocarbons present, among other
things.
Easily harvested sources of hydrocarbons are dwindling, leaving less
accessible sources to
satisfy future energy needs. As the costs of hydrocarbons increase, the less
accessible
sources become more economically attractive.
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[0005] Recently, the harvesting of oil sands to remove heavy oil has become
more
economical. Hydrocarbon removal from oil sands may be performed by several
techniques. For
example, a well can be drilled to an oil sand reservoir and steam, hot air,
solvents, or a
combination thereof, can be injected to release the hydrocarbons. The released
hydrocarbons
may be collected by wells and brought to the surface. In another technique,
strip or surface
mining may be performed to access the oil sands, which can be treated with hot
water, steam or
solvents to extract the heavy oil. Strip or surface mining when combined with
the hot water or
steam may produce a substantial amount of waste or tailings requiring
disposal.
[0006] Another process for harvesting oil sands, which may generate less
surface waste than
other processes, is the slurrified reservoir hydrocarbon recovery process. The
slurrified reservoir
hydrocarbon recovery process may also be referred to as a slurrified
hydrocarbon extraction
process.
[0007] In a slurrified reservoir hydrocarbon recovery process, such as that
described in U.S.
Patent No. 5,823,631, hydrocarbons trapped in solid media, such as bitumen in
oil sands, may be
recovered from subsurface formations by relieving an overburden stress by
injection of water to
raise the pore pressure and causing the subsurface formation to flow from an
injection well to a
production well, for example, by fluid injection, recovering an oil sand/water
mixture from the
production well, separating the bitumen and reinjecting the remaining sand in
a water slurry.
[0008] Another slurrified reservoir hydrocarbon recovery process, such as
that described in
U.S. Patent No. 8,360,157, may include a method for recovering heavy oil that
comprises
accessing, from two or more locations, a subsurface formation having an
overburden stress
disposed thereon. The subsurface formation comprises heavy oil and one or more
solids. The
subsurface formation is pressurized to a pressure sufficient to relieve the
overburden stress. A
differential pressure is created between the two or more locations to provide
one or more high
pressure locations and one or more low pressure locations. The differential
pressure is varied
within the subsurface formation between the one or more low pressure locations
to mobilize at
least a portion of the solids and a portion of heavy oil in the subsurface
formation. The
mobilized solids and heavy oil then flow toward one or more low pressure
locations to provide a
slurry comprising heavy oil and one or more solids. The slurry comprising the
heavy oil and the
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one or more solids is flowed to the surface where the heavy oil is recovered
from the one or more
solids. The one or more solids are recycled to the subsurface formation.
[0009] A process that relates to a slurrified reservoir hydrocarbon
recovery process may
include methods and systems for recompacting a hydrocarbon reservoir to
prevent override of a
fill material, such as that described in U.S. Published Application No.
2012/0325461. An
exemplary method may include detecting a slurry override condition and
reducing a pressure
within the reservoir so as to reapply overburden stress.
[0010] The slurrified reservoir hydrocarbon recovery processes discussed
above convert the
reservoir into a formation resembling a moving bed. When the reservoir moves
toward a
production well(s), void space is filled by a reinjected stream.
[0011] Although the slurrified reservoir hydrocarbon recovery processes can
recover a
substantial portion of the heavy oil present in a reservoir, the amount of
heavy oil produced from
the reservoir may be enhanced by increasing the flow rate in a given portion
of the reservoir.
But, the flow rate in the reservoir may be limited by achievable flow rates in
the production
wells. Problems may include but are not limited to ruptures in a well, a well
reaching an erosion
limit, and a well reaching a mechanical failure. The problems may make it more
difficult to
achieve optimal production because the problems may occur before achieving
optimal
production. Heterogeneities or differences in reservoir properties may lead to
non-uniform
displacement between injection wells and production wells if an entire well
pattern is run
simultaneously.
[0012] A need exists for improved technology. For example, a need exists
for enhancing the
recovery of heavy oil from a reservoir within a subsurface formation by, for
example, not
injecting components at such a fast rate that problems occur within a system
before achieving
optimal production and/or by increasing the rate of injection within a portion
of the reservoir
relative to the production rate in a production well by reducing the number of
injection wells
injecting into a portion of the reservoir associated with that production
well. By reducing the
number of injection wells associated with a production well or reducing the
number of
production wells associated with an injection well well, the overall
displacement may between
injection well(s) and production well(s) may be more uniform.
SUMMARY
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[0013] The present disclosure provides a method and system for enhancing
the recovery of
heavy oil.
[0014] A method for enhancing recovery of heavy oil from a reservoir within
a subsurface
formation may comprise (a) increasing a reservoir pore pressure of the
reservoir, wherein the
reservoir includes a first well pattern having at least one injection well and
at least one
production well and wherein the first well pattern has at least one first
portion injection well of
the at least one injection well and at least one first portion production well
of the at least one
production well and wherein the first well pattern has a second portion first
well pattern having
at least one second portion injection well of the at least one injection well
and at least one second
portion production well of the at least one production well, then (b) creating
a first portion first
differential pressure between the at least one first portion injection well
and the at least one first
portion production well, then; (c) producing primary sweep volume from the
first portion first
well pattern via one or more of the at least one first portion production
well; and (d) injecting an
injection media into the subsurface formation until the injection media is
produced by the one or
more of the at least one first portion production well.
[0015] A method for enhancing recovery of heavy oil from a reservoir within
a subsurface
formation may comprise (a) creating a first well pattern within a subsurface
formation, the first
well pattern having at least one injection well and at least one production
well, wherein the first
well pattern has a first portion first well pattern having at least one first
portion injection well of
the at least one injection well and at least one first portion production well
of the at least one
production well and wherein the first well pattern has a second portion first
well pattern having
at least one second portion injection well of the at least one injection well
and at least one second
portion production well of the at least one production well; (b) increasing a
reservoir pore
pressure of the reservoir, then; (c) creating a first portion first
differential pressure between the at
least one first portion injection well and the at least one first portion
production well, then; (d)
producing primary sweep volume from the first portion first well pattern via
one or more of the
at least one first portion production well; and (e) injecting an injection
media into the subsurface
formation until the injection media is produced by the one or more of the at
least one first portion
production well.
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[0016] The
foregoing has broadly outlined the features of the present disclosure so that
the
detailed description that follows may be better understood. Additional
features will also be
described.
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BRIEF DESCRIPTION OF THE DRAWINGS
[0017] These and other features, aspects and advantages of the present
disclosure will
become apparent from the following description and the accompanying drawings,
which are
described briefly below.
[0018] Figure 1 is a diagram showing the use of a slurrified reservoir
hydrocarbon recovery
process to recover hydrocarbons from a reservoir within a subsurface
formation.
[0019] Figure 2a is a diagram of the use of a slurrified reservoir
hydrocarbon process to
recover hydrocarbons from a reservoir within a first portion first well
pattern.
[0020] Figure 2b is a diagram of the use of a slurrified reservoir
hydrocarbon recovery
process to recover hydrocarbons from a reservoir within a second portion first
well pattern.
[0021] Figure 2c is a diagram of the use of a slurrified reservoir
hydrocarbon recovery
process to recover hydrocarbons from a reservoir within a first portion first
well pattern and a
second portion first well pattern.
[0022] Figure 3a is a diagram showing the use of a slurrified reservoir
hydrocarbon recovery
process to recover hydrocarbons from a reservoir within a first portion first
well pattern.
[0023] Figure 3b is a diagram showing the use of a slurrified reservoir
hydrocarbon recovery
process to recover hydrocarbons from a reservoir within a second portion first
well pattern.
[0024] Figure 3c is a diagram showing the use of a slurrified reservoir
hydrocarbon recovery
process to recover hydrocarbons from a reservoir within a first portion first
well pattern and a
second portion first well pattern.
[0025] Figure 4 is a diagram of the use of a slurrified reservoir
hydrocarbon process after a
recompletion process.
[0026] Figure 5 is a diagram of the use of a slurrified reservoir
hydrocarbon recovery process
after the recompletion process.
[0027] Figure 6 is a diagram showing a method of a slurrified reservoir
hydrocarbon
recovery process.
[0028] It should be noted that the figures are merely examples and that no
limitations on the
scope of the present disclosure are intended hereby. Further, the figures are
generally not drawn
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to scale but are drafted for the purpose of convenience and clarity in
illustrating various aspects
of the disclosure.
DETAILED DESCRIPTION
[0029] For the purpose of promoting an understanding of the principles of
the disclosure,
reference will now be made to the features illustrated in the drawings and
specific language will
be used to describe the same. It will nevertheless be understood that no
limitation of the scope of
the disclosure is thereby intended. Any alterations and further modifications,
and any further
applications of the principles of the disclosure as described herein are
contemplated as would
normally occur to one skilled in the art to which the disclosure relates. It
will be apparent to
those skilled in the relevant art that some features that are not relevant to
the present disclosure
may not be shown in the drawings for the sake of clarity.
[0030] At the outset, for ease of reference, certain terms used in this
application and their
meaning as used in this context are set forth below. 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
processes arc not limited by the usage of the terms shown below, as all
equivalents, synonyms,
new developments and terms or processes that serve the same or a similar
purpose are considered
to be within the scope of the present disclosure.
[0031] "Bitumen" is a naturally occurring heavy oil material. Generally, it
is the
hydrocarbon component found in oil sands. Bitumen can vary in composition
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 weight (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. %).
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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 percentage of the hydrocarbon found in
bitumen can vary.
The term "heavy oil" includes bitumen as well as lighter materials that may be
found in a sand or
carbonate reservoir.
[0032] "Breakthrough" refers to a description of reservoir conditions under
which an
injection material, previously isolated or separated from production as
observed at the production
well(s), gains access to one or more production wells. For breakthrough to
occur, anywhere
from greater than 0 to less than or equal to 100 percent of the material being
produced at the
production well(s) is injection media. The percentage of injection material
may include any
number within or bounded by the preceding material. For example, the
percentage of injection
material may be, but is not limited to, at least 50% or no more than 90%. In
other words,
breakthrough refers to a description of reservoir conditions when a material
injected into the
reservoir reaches one or more production wells after being reinjected into the
reservoir.
Breakthrough may occur at the end of primary production. Breakthrough may
occur at the end
of secondary production. When breakthrough occurs at the end of secondary
production, the
percentage of media being produced at the production well(s) is reinjection
media and/or
injection media. Breakthrough may occur at the end of any production (e.g.,
primary production,
secondary production, tertiary production).
[0033] "Conditioning fluid" is fluid injected into a reservoir prior to
primary production to
increase the pore pressure of the reservoir. The conditioning fluid may be any
suitable fluid. For
example, the conditioning fluid may comprise at least one of water, fines,
caustic, flocculants,
coagulants, sodium silicate, polymeric compounds, salts, solvents, brine,
hydrocarbons,
polymers, and hydrocarbons.
[0034] "Facility" 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, sand
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processing plants, and delivery outlets. In some instances, the term "surface
facility" is used to
distinguish from those facilities other than wells.
[0035] "Heavy oil" includes oils which are classified by the American
Petroleum Institute
("API"), as heavy oils, extra heavy oils, or bitumens. The term "heavy oil"
includes bitumen.
Heavy oil may have a viscosity of about 1,000 centipoise (cP) or more, 10,000
cP or more,
100,000 cP or more, or 1,000,000 cP or more. In general, a heavy oil has an
API gravity
between 22.3 API (density of 920 kilograms per meter cubed (kg/m3) or 0.920
grams per
centimeter cubed (g/cm3)) and 10.00 API (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 API (density greater
than 1,000 kg/m3 or 1
g/cm3). For example, a source of heavy oil includes oil sand or bituminous
sand, which is a
combination of clay, silt, sand, water and bitumen.
[0036] A "hydrocarbon" is an organic compound that primarily includes the
elements of
hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any number
of other elements
may be present in small amounts. Hydrocarbons generally refer to components
found in heavy
oil or in oil sands. Hydrocarbon compounds may be aliphatic or aromatic, and
may be straight
chained, branched, or partially or fully cyclic.
[0037] "Injection media" is media injected into the reservoir during
primary production. The
injection media may comprise, for example, at least one of water, clay, silt,
sand, brine, salts,
hydrocarbons, polymers, coagulants, flocculants, solvents and conditioning
fluid. The injection
media may comprise a portion of the conditioning fluid. The injection media
may include
reinjected sand.
[0038] An "injection well" refers to a well or wellbore that receives a
material, such as but
not limited to the conditioning fluid or the injection media.
[0039] A "line drive well pattern" refers to an injection pattern in which
injection wells are
located in a first straight line and production wells are located in a second
straight line that is
parallel to the first straight line.
[0040] "Overburden" refers to the material overlying a reservoir. The
overburden may
contain rock, soil, sand, clay, pore fluids, and ecosystem above the
reservoir. The pore fluids
may include, but are not limited to, water and/or hydrocarbons.
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[0041] "Overburden stress" is the stress, or force exerted by unit area,
that the overburden
applies to the sands within the reservoir due to its weight. Overburden stress
may be considered
to be the effective stress applied by the overburden, e.g., the total stress
of the overburden minus
the fluid pressure within the reservoir. As such, overburden stress is a
measure of the vertical
component of the stress the solids in the reservoir exert on each other due to
the weight of the
overburden. "Overburden stress" may interchangeably be referred to as
"overburden load." The
solids in the reservoir may comprise sand grain, silt and/or clay particles,
etc.
[0042] "Permeability" is the capacity of a rock to transmit fluids through
the interconnected
pore spaces of the structure. The customary unit of measurement for
permeability is the
milliDarcy (mD). The term "relatively permeable" is defined, with respect to
formations or
portions thereof (for example, 10 or 100 mD). The term "relatively low
permeability" is defined,
with respect to subsurface formations or portions thereof, as an average
permeability of less than
about 10 mD.
[0043] "Pressure" is a force exerted per unit area which is defined as
being equal in all
directions and is typically used here in reference to the pore fluids in the
reservoir or to describe,
in part, the fluid or material in the injection wells and production wells.
Pressure can be shown
as pounds per square inch (psi), kilopascals (kPa), or megapascals (MPa).
"Atmospheric
pressure" refers to the local pressure of the air. "Absolute pressure" (psia)
refers to the sum of
the atmospheric pressure (14.7 psia at standard conditions) plus the gauge
pressure. "Gauge
pressure" (psig) refers to the pressure measured by a gauge, which indicates
only the pressure
exceeding the local atmospheric pressure (i.e., a gauge pressure of 0 psig
corresponds to an
absolute pressure of 14.7 psia). The term "vapor pressure" has the usual
thermodynamic
meaning. For a pure component in an enclosed system at a given pressure, the
component vapor
pressure is essentially equal to the total pressure in the system.
[0044] "Pressure gradient" represents the pressure differences divided by
the distance
between the locations where those pressure differences are measured (e.g., the
change in pore
pressure per unit of depth). Depth may refer to length or width. Pressure
gradient is a measure
of driving force moving the sand through the subterranean reservoir or the
pressure moving
slurries through a pipe. The "pressure gradient" may interchangeably be
referred to as a "pore
pressure gradient" or, when the distance over which the pressure varies, a
"differential pressure."
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[0045] "Primary production," primary recovery or primary sweep is the first
stage of
hydrocarbon production by which the formation is displaced by an injection
media injected at an
injection well and produced via a production well. Primary production may
terminate at or after
breakthrough.
[0046] "Primary sweep volume" is material produced from the reservoir
during primary
recovery. Primary sweep volume may refer to the volume of the reservoir
produced during
primary production. For example, primary sweep volume may refer to anywhere
between 20 to
70% inclusive volume of a reservoir total volume within a subsurface formation
path of the total
volume of reservoir produced during primary production within the subsurface
formation path.
The aforementioned ranges may include any number bounded by and/or within the
preceding
ranges. The primary sweep volume may comprise at least one of heavy oil, sand,
silt, clay,
connate or in situ water, and conditioning fluid. The primary sweep volume may
comprise a
portion of the conditioning fluid.
[0047] "Production well" refers to a well or wellbore that produces a
material.
[0048] A "recompleted injection well" is a well that initially served as a
production well but
has been completed to serve as an injection well. In other words, such a well
is a well that
initially produced materials, such as but not limited to primary sweep volume
and/or secondary
sweep volume, and later receives materials, such as but not limited to
injection media.
[0049] A "recompleted production well" is a well that initially served as
an injection well but
has been completed to serve as a production well. In other words, such a well
is a well that
initially received materials to be injected, such as but not limited to
injection media, and later
produces materials, such as but not limited to primary sweep volume and/or
secondary sweep
volume.
[0050] "Reconditioning fluid" is fluid injected into a reservoir prior to
secondary production
and/or tertiary production, etc. to increase the pore pressure of the
reservoir. The reconditioning
fluid may be any suitable fluid. For example, the reconditioning fluid may
comprise at least one
of water, fines, caustic, flocculants, coagulants, sodium silicate, polymeric
compounds, salts,
solvents, brine, hydrocarbons, polymers, and hydrocarbons. Reconditioning
fluid may include
conditioning fluid such as, for example, a portion of the conditioning fluid.
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[0051] "Reinjected sand" may comprise sand, clay, and silt that was
previously within the
reservoir, was produced from the reservoir and is now being reinjected into
the reservoir.
Reinjected sand may comprise any part of the reservoir. For example, the
reinjected sand may
comprise clay, fluid, etc., in a proportion that may be the same or different
than the makeup of
clay, fluid, etc. in the reservoir.
[0052] "Reinjection media" is media injected into the reservoir during
secondary production
and/or tertiary production, etc. The reinjection media may comprise, for
example, at least one of
water, clay, silt, sand, brine, salts, hydrocarbons, polymers, coagulants,
flocculants, solvents,
conditioning fluid, reconditioning fluid and injection media. The reinjection
media may
comprise a portion of the conditioning fluid, reconditioning fluid and/or
injection media. The
reinjection media may include the reinjected sand.
[0053] A "reservoir" or "subterranean reservoir" is a subsurface rock or
sand formation from
which a production fluid or resource can be harvested. The subsurface rock or
sand formation
may include sand, granite, silica, carbonates, clays, and organic matter, such
as bitumen, heavy
oil (e.g., bitumen), gas, or coal, among others. Reservoirs can vary in
thickness from less than
one foot (0.3048 meter (m)) to hundreds of feet (hundreds of meters).
[0054] "Reservoir pore pressure" is the pressure of fluids within pores of
a reservoir at a
given time. "Reservoir pore pressure" may be interchangeably referred to as
"pore pressure."
[0055] A "Sand breakthrough indicator" refers to a way of detecting
breakthrough. For
example, a sand breakthrough indicator may refer to a way of detecting the end
of primary
production and/or secondary production at a given production well along a
subsurface formation
path that material travels from one or more injection wells to the given
production well. More
specifically, if there is one production well and four injection wells, the
sand breakthrough
indicator may detect when breakthrough occurs along the subsurface formation
path from each
of the four injection wells to the production well such that if breakthrough
occurs first along the
subsurface formation path from a first one of the four injection wells to the
production well, the
one of the four injection wells can be shut in while material continues to
travel from the other of
the three injection wells to the production well. This process may continue
until breakthrough
has occurred for all of the injection wells. The sand breakthrough indicator
may comprise any
suitable mechanism. For example, the sand breakthrough indicator may comprise
periodically
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conducting a well test (e.g. once a week), taking a sample (e.g., of the well)
every well test to
detect the bitumen flow rate, or using a tracer in the injection media to
indicate when injected
media is produced into the production well. If the sand breakthrough indicator
comprises taking
the sample, the sand breakthrough indicator may also comprise one or more well
tests and using
the tracer media in the injection media. If the sand breakthrough indicator
comprises one of
these additional steps, the sand breakthrough indicator may determine where
breakthrough
occurs. Merely taking the sample may indicate that breakthrough has occurred
but may not
indicate where breakthrough has occurred; performing one of these additional
steps may
determine where the breakthrough has occurred. The bitumen concentration
variation at the
production well may also be used. The tracer may be radioactive, ferrous, or
otherwise labeled.
[0056] "Secondary production," secondary recovery or secondary sweep is the
second stage
of hydrocarbon recovery. Secondary production occurs after primary production.
[0057] "Secondary sweep volume" is material produced from the reservoir
during secondary
recovery. Secondary sweep volume may refer to the volume of the reservoir
produced during
secondary production. For example, secondary sweep volume may refer to
anywhere between
20 to 70% inclusive volume of the reservoir total volume within a subsurface
formation path of
the total volume of reservoir produced during secondary production within the
subsurface
formation path. The aforementioned range may include any number bounded by or
within the
preceding range. The secondary sweep volume may include some of the volume
produced
during primary production as this volume may be reinjected into the reservoir
and produced
during secondary production The secondary sweep volume may comprise at least
one of heavy
oil, sand, silt, clay, conditioning fluid, reconditioning fluid, and injection
media. The secondary
sweep volume may comprise a portion of the conditioning fluid. The secondary
sweep volume
may comprise a portion of the reconditioning fluid. The secondary sweep volume
may comprise
a portion of the injection media.
[0058] "Shut in" refers to a shut in injection well or a shut in production
well. A well that is
shut in no longer injects or produces material, but may still be utilized for
reservoir monitoring.
For example, the well may be used to monitor a pore pressure in a reservoir or
for sampling
material in the reservoir. "Shutting in" may interchangeably be used to refer
to a well that is shut
in.
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[0059] "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. For example, the exact degree of
deviation
allowable may range anywhere from less than or equal to a 10% exact degree in
deviation.
[0060] A "subsurface formation" refers to the material existing below the
Earth's surface.
The subsurface formation may interchangeably be referred to as a formation,
subsurface or a
subterranean formation. The subsurface formation may comprise a range of
components, e.g.
minerals such as quartz, siliceous materials such as sand and clays, as well
as the oil and/or gas
that is extracted.
100611 A "subsurface formation path" refers to the path within a subsurface
formation that
portions of the reservoir within the subsurface formation could travel when
the portions of the
reservoir are, for example but not limited to, produced from the subsurface
formation. For
example, the subsurface formation path may refer to a path between one or more
injection wells
and production wells that portions of the reservoir may travel by injecting
into the one or more
injection well and producing from the one or more production well.
[0062] A "wellbore" is a hole or access path in the subsurface made by
drilling or inserting a
conduit into the subsurface. A wellbore may have a substantially circular
cross section or any
other cross-section shape, such as an oval, a square, a rectangle, a triangle,
or other regular or
irregular shapes. The term "well," when referring to an opening in the
formation, may be used
interchangeably with the term "wellbore." Further, multiple pipes may be
inserted into a single
wellbore, for example, as a liner configured to allow flow from an outer
chamber to an inner
chamber.
[0063] "Well pattern" refers to a configuration of wells within a single
pattern. Examples of
well patterns include, but are not limited to, a line drive well pattern, a 4-
spot well pattern, an
inverted 4-spot well pattern, a 5-spot well pattern, an inverted 5-spot well
pattern, a 7-spot well
pattern, an inverted 7-spot well pattern, a 9-spot well pattern and an
inverted 9-spot well pattern.
[0064] A "4-spot well pattern" refers to a standard 4-spot well pattern. A
standard 4-spot
well pattern includes 3 injection wells at corners of a triangle and a
production well at the center
of the triangle.
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CA 02912301 2015-11-18
[0065] An "inverted 4-spot well pattern" refers to a standard inverted 4-
spot well pattern.
An inverted 4-spot well pattern includes 3 production wells at corners of a
triangle and an
injection well at the center of the triangle.
[0066] A "5-spot well pattern" refers to a standard 5-spot well pattern. A
standard 5-spot
well pattern includes 4 injection wells at corners of a square and a
production well at the center
of the square.
[0067] An "inverted 5-spot well pattern" refers to a standard inverted 5-
spot well pattern.
An inverted 5-spot well pattern includes 5 production wells at corners of a
square and an
injection well at the center of the square.
[0068] A "7-spot well pattern" refers to a standard 7-spot well pattern. A
standard 7-spot
well pattern includes 6 injection wells at corners of a hexagon and a
production well at the center
of the hexagon.
[0069] An "inverted 7-spot well pattern" refers to a standard inverted 7-
spot well pattern.
An inverted 7-spot well pattern includes 6 production wells at corners of a
hexagon and an
injection well at the center of the hexagon.
[0070] A "9-spot well pattern" refers to a standard 9-spot well pattern. A
standard 9-spot
well pattern includes 8 injection wells at corners and midpoints of the sides
of a square and a
production well at the center of the square.
[0071] An "inverted 9-spot well pattern" refers to a standard inverted 9-
spot well pattern.
An inverted 9-spot well pattern includes 9 production wells at corners and
side midpoints of a
square and an injection well at the center of the square.
[0072] "At least one," in reference to a list of one or more entities
should be understood to
mean at least one entity selected from any one or more of the entity in the
list of entities, but not
necessarily including at least one of each and every entity specifically
listed within the list of
entities and not excluding any combinations of entities in the list of
entities. This definition also
allows that entities may optionally be present other than the entities
specifically identified within
the list of entities to which the phrase "at least one" refers, whether
related or unrelated to those
entities specifically identified. Thus, as a non-limiting example, "at least
one of A and B" (or,
equivalently, "at least one of A or B," or, equivalently "at least one of A
and/or B") may refer, to
- 15 -
CA 02912301 2015-11-18
at least one, optionally including more than one, A, with no B present (and
optionally including
entities other than B); to at least one, optionally including more than one,
B, with no A present
(and optionally including entities other than A); to at least one, optionally
including more than
one, A, and at least one, optionally including more than one, B (and
optionally including other
entities). In other words, the phrases "at least one," "one or more," and
"and/or" are open-ended
expressions that are both conjunctive and disjunctive in operation. For
example, each of the
expressions "at least one of A, B and C," "at least one of A, B, or C," "one
or more of A, B, and
C," "one or more of A, B, or C" and "A, B, and/or C" may mean A alone, B
alone, C alone, A
and B together, A and C together, B and C together, A, B and C together, and
optionally any of
the above in combination with at least one other entity.
[0073] Where two or more ranges are used, such as but not limited to 1 to 5
or 2 to 4, any
number between or inclusive of these ranges is implied.
[0074] The articles "the", "a" and "an" are not necessarily limited to mean
only one, but
rather are inclusive and open ended so as to include, optionally, multiple
such elements.
[0075] As depicted in Figures 1-6 and set forth above and below, the
present disclosure
relates to a system and method for recovering heavy oil, and more particularly
to a system and
method for enhancing the recovery of heavy oil from a reservoir within a
subsurface formation.
The system and method make it possible to increase production from a reservoir
when compared
to a system and/or method where an entire well pattern is run simultaneously.
The system and
method make it possible to run a portion, such as but not limited to a first
portion or a second
portion, of a well pattern at a time, thereby increasing production from that
of a system and/or
method where the entire well pattern is run simultaneously. In other words,
the system and
method make it possible to produce portions of a reservoir that remain after
primary production
within an entire well pattern or a portion of a well pattern, thereby
enhancing the recovery of
heavy oil. The system and method may produce portions of a reservoir that
remain after primary
production within an entire well pattern or a portion of a well pattern by
modifying the flow
direction by which material is produced from the reservoir, thereby allowing
for the production
of not previously produced subsurface formation paths within the reservoir.
The system and
method allow for the modification by modifying the pattern of injection wells
and/or production
wells. The portion of the well pattern, such as but not limited to the first
portion of the well
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CA 02912301 2015-11-18
pattern (i.e., the first portion well pattern) or the second portion of the
well pattern (i.e., the
second portion well pattern) is some portion that is smaller than the entirety
of the well pattern.
The system and method may lead to a more uniform recovery as there may be
conditions within
the reservoir that challenge uniform recovery between injection wells and
production wells if an
entire well pattern is run simultaneously. Operating a first portion of a well
pattern and then a
second portion of the well pattern may mitigate against uniform recovery being
negatively
impacted due to variations in reservoir properties and stress conditions that
may lead to
nonuniform sweep between injection wells and production wells had the entirety
of the well
pattern been run simultaneously.
[0076] The system 100 and method may include at least one injection well
104 and at least
one production well 106 (Figure 1). The at least one injection well 104 may
just be referred to as
an injection well for simplicity. The at least one production well 106 may
just be referred to as a
production well for simplicity. The at least one injection well 104 and the at
least one production
well 106 may access a reservoir 102 within a subsurface formation 124. The at
least one
injection well 104 and the at least one production well 106 may extend through
an overburden
108 of the subsurface formation 124 to access the reservoir 102. The
overburden 108 may be
above the reservoir 102. The overburden 108 may be closer to the Earth's
surface 112 than the
reservoir 102. The reservoir 102 may be at depths greater than or equal to
about 50 meters from
the Earth's surface 112. The depths may include any number within or inclusive
of the
preceeding range.
[0077] The at least one injection well 104 may extend through the reservoir
102. The at least
one injection well 104 may include one or more injection wells 104. For
example, the at least
one injection well may include one injection well, two injection wells, three
injection wells, etc.
The at least one injection well 104 may include any number of injection wells
that is greater than
or equal to one. The number of injection wells may include any number within
and/or inclusive
of the preceding range.
[0078] The at least one production well 106 may extend through the
reservoir 102. The at
least one production well 106 may include one or more production wells 106.
For example, the
at least one production well may include one production well, two production
wells, three
injection wells, etc. The at least one production well 106 may include any
number of production
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CA 02912301 2015-11-18
wells that is greater than or equal to one. The number of production wells may
include any
number within and/or inclusive of the preceding range.
[0079] The system and method may include creating a first well pattern
1110, 801 (Figures
2a-3c and 6). The first well pattern 1110 may have the at least one injection
well 104 and the at
least one production well 106. The first well pattern 1110 may have a first
portion first well
pattern 1111 (Figures 2a and 3a). The first portion first well pattern 1111
may include at least
one first portion injection well 104a of the at least one injection well 104.
The first portion first
well pattern 1111 may include at least one first portion production well 106a
of the at least one
production well 106. The first well pattern 1110 may have a second portion
first well pattern
1112 (Figures 2b and 3b). The second portion first well pattern 1112 may
include at least one
second portion injection well 104b of the at least one injection well 104 and
at least one second
portion production well 106b of the at least one production well 106.
[0080] Figures 2a-3a show multiple first portion first well patterns 1111
where one first
portion first well pattern 1111 is inside one first well pattern 1110. Figures
2a-3a show the first
portion first subsurface formation path 1300 that hydrocarbons travel within
the first portion first
well pattern 1111. The first portion first subsurface formation path is
depicted by the shaded
areas within the first portion first well pattern 1111. Figures 2b-3b show
multiple second portion
first well patterns 1112 where one second portion first well pattern 1112 is
inside one first well
pattern 1110. Figures 2b-3b show the second portion first subsurface formation
1301 path that
hydrocarbons travel within the second portion first well pattern 1112. The
second portion first
subsurface formation path is depicted by the shaded areas within the second
portion first well
pattern 1112. Figures 2c-3c shows multiple first portion first well patterns
1111 and multiple
second portion first well patterns 1112 where one first portion first well
pattern 1111 and one
second portion first well pattern 1112 is inside one first well pattern 1110.
Figures 2c-3c show
the first portion first subsurface formation path 1300 and the second portion
first subsurface path
1301 that hydrocarbons travelled for the first portion first well pattern and
the first portion
second well pattern, respectively. The first portion first subsurface
formation path is depicted by
the shaded areas within the first portion first well pattern 1111; the second
portion first
subsurface formation path is depicted by the shaded areas within the second
portion first well
pattern 1112.
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CA 02912301 2015-11-18
[0081] The first well pattern 1110 may consist of the first portion first
well pattern 1111 and
the second portion first well pattern 1112. If the first well pattern 1110
consists of the first
portion first well pattern 1111 and the second portion first well pattern
1112, the first well
pattern 1110 only contains the first portion first well pattern 1111 and the
second portion first
well pattern 1112.
[0082] The first well pattern 1110 may comprise the first portion first
well pattern 1111 and
the second portion first well pattern 1112. If the first well pattern 1110
comprises the first
portion first well pattern 1111 and the second portion first well pattern
1112, the first well
pattern 1110 may include more than the first portion first well pattern 1111
and the second
portion first well pattern 1112. For example but not limited to, the first
well pattern 1110 may
include the first portion first well pattern 1111, the second portion first
well pattern 1112 and a
third portion first well pattern 1113.
[0083] The first well pattern may comprise any suitable well pattern that
is able to be
separated into at least two portions, such as the first portion first well
pattern 1111 and the
second portion first well pattern 1112. For example, the first well pattern
may comprise one of a
five-spot well pattern, an inverted five-spot well pattern, a seven-spot well
pattern and a nine-
spot well pattern.
[0084] While the above section and preceding sections discuss a first well
pattern, the system
and method may comprise more than one well pattern. For example, the system
and method may
comprise a first well pattern, a second well pattern, etc. Each of the well
patterns may have
similar structures and/or operate similarly to the present disclosure's
description of the first well
pattern.
[0085] The at least one first portion injection well 104a may be the at
least one second
portion injection well 104b. In other words, the at least one first portion
injection well 104a may
be the same well and therefore not separate from the at least one second
portion injection well
104b. The at least one first portion injection well 104a may be the at least
one second portion
injection well 104b when the well pattern is inverted. Examples of a well
pattern that is inverted
include an inverted five-spot well pattern. When the at least one first
portion injection well 104a
is the at least one second portion injection well 104b, the at least one first
portion production
well 106a may be separate from the at least one second portion production well
106b. In other
- 19 -
CA 02912301 2015-11-18
words, the at least one first portion production well 106a may be a different
well from the at least
one second portion production well 106b.
[0086] The at least one first portion production well 106a may be the at
least one second
portion production well 106b. In other words, the at least one first portion
production well 106a
may be the same well and therefore not separate from the at least one second
portion production
well 106b. Examples of a well pattern that is not inverted include a five-spot
well pattern, a
seven-spot well pattern and a nine-spot well pattern. When the at least one
first portion
production well 106a is the at least one second portion production well 106b,
the at least one first
portion injection well 104a may be separate from the at least one second
portion injection well
104b. In other words, the at least one first portion injection well 104a may
be a different well
from the at least one second portion injection well 104b.
[0087] One or more of the at least one first portion injection well 104a
may be separate from
one or more of the at least one second portion injection well 104b. In other
words, none or only
some of the one or more of the at least one first portion injection well 104a
may be the same
injection well as none or only some of the one or more of the second portion
injection well 104b.
[0088] One or more of the at least one first portion production well 106a
may be separate
from one or more of the at least one second portion production well 106b. In
other words, none
or only some of the one or more of the at least one first portion production
well 106a may be the
same injection well as none or only some of the one or more of the second
portion production
well 106b.
[0089] The system and method may include increasing a reservoir pore
pressure of the
reservoir 102, 802 (Figure 6). Increasing the reservoir pore pressure may
comprise injecting a
conditioning fluid into the reservoir 102. The conditioning fluid may be
injected at one or more
locations within the subsurface formation 124. The conditioning fluid may be
injected into any
suitable location within the reservoir 102. The pressure caused by the
injection of the
conditioning fluid may allow the conditioning fluid to permeate through the
portion of the
reservoir 102 that contains hydrocarbons. As the conditioning fluid is
injected, the reservoir pore
pressure increases and may thereby alleviate or mostly balance the stresses on
the reservoir 102
that are caused by an overburden stress. Accordingly, the pressure of the
conditioning fluid
injected may be sufficient to alleviate and/or substantially balance
overburden stress. The
- 20 -
CA 02912301 2015-11-18
pressure of the conditioning fluid may be sufficient to develop a
substantially constant pressure
within the reservoir 102.
[0090] Injecting the conditioning fluid into the reservoir 102 may comprise
injecting the
conditioning fluid via one or more of the at least one first portion injection
well 104a and the at
least one first portion production well 106a within the first well pattern
1111. The at least one
first portion injection well 104a and the at least one first portion
production well 106a may each
have a structure that enable them to receive the conditioning fluid. Examples
of the structure
may include, but are not limited to, an uncased wellbore or a cased wellbore.
The conditioning
fluid travels in the at least one first portion injection well 104a and the at
least one first portion
production well 106a in a direction 122 toward the reservoir 102. The
conditioning fluid may be
fed to the reservoir 102.
[0091] When the conditioning fluid is injected into one or more of the at
least one first
portion injection well 104a and the at least one first portion production well
106a, the porosity of
the subsurface formation 124 may increase. The porosity of the subsurface
formation 124 may
increase because the reservoir 102 may comprise a sand particle network. The
sand particle
network may dilate or expand in volume as the effective stress due to the
overburden stress is
alleviated and/or substantially balanced by the increase in reservoir pore
pressure. The increase
in porosity may be accompanied by a decrease in the mechanical strength of the
material within
the reservoir 102 to a state where the material within the reservoir 102 may
slide in a direction of
the at least one first portion production well 106a when a pressure gradient
is imposed due to the
flow of a fluid from the at least one first portion injection well 104a to the
at least one first
portion production well 106a. Increasing the initial porosity of the
subsurface formation 124
may increase the permeability of the subsurface formation 124.
[0092] The injection of the conditioning fluid into one or more of the at
least one first portion
injection well 104a and the at least one first portion production well 106a
may be referred to as
the conditioning process. In other words, the conditoning fluid may be
injected into one or more
of the at least one first portion injection well 104a and the at least one
first portion production
well 106a during the conditioning process. When the conditioning fluid is
injected into the at
least one first portion production well 106a, the at least one first portion
production well 106a
acts like an injection well in that it receives a fluid that is fed to the
reservoir 102. When the
-21-
CA 02912301 2015-11-18
conditioning fluid is injected into at least one first portion injection well
104a and at least one
first portion production well 106a, the stresses on the reservoir 102 may be
balanced more
quickly than if the conditioning fluid is only injected into at least one one
first portion injection
well 104a.
[0093] The conditioning process may end once the effective stresses on the
reservoir 102 in
the first portion first well pattern 1111 due to the overburden stress are
alleviated and/or
substantially balanced by the increased reservoir pore pressure. Whether or
not the effective
stresses on the reservoir 102 in the first portion first well pattern 1111 due
to overburden stress
have been alleviated and/or substantially balanced may be determined, but is
not limited to being
determined, by comparing the bottom hole pressures in the at least one first
portion injection well
104a, the at least one first portion production well 106a, and/or at least one
observation well to
an estimated applied overburden stress due to its weight. The observation well
may be a well
that allows for the observation of parameters, such as but not limited to
fluid levels and pressure
changes, of one or more of the at least one first portion injection well 104a
and the at least one
first portion production well 106a. The magnitude of the effective stress
applied by the
overburden to the reservoir (e.g., overburden stress minus the reservoir pore
pressure) at the end
of the conditioning process is generally small (generally in the range of 10
to 500 kilopascals
(kPa) out of the 1 megapascal (MPa) to lOMPa effective overburden stress that
would have
existed before the conditioning process, where the aforementioned ranges may
include any
number bounded by and/or within the preceding ranges depending on a depth of
the reservoir, an
initial pore pressure of the reservoir, and/or in situ stresses of the
reservoir, of which the
overburden stress may be one component).
[0094] Once the conditioning process ends, a first portion first
differential pressure between
the at least one first portion injection well 104a and the at least one first
portion production well
106a may be created, 803 (Figure 6). Creating the first portion first
differential pressure between
the at least one first portion injection well 104a and the at least one first
portion production well
106a may impose a pressure gradient. The creation of the first portion first
differential pressure
between the at least one first portion injection well 104a and the at least
one first portion
production well 106a may cause water or brine to flow in the subsurface
formation 124. The
water or brine may create fluid drag forces on solids in the subsurface
formation 124. Once the
first portion first differential pressure increases to a point where it
overcomes the friction holding
- 22 -
CA 02912301 2015-11-18
the reservoir 102 in place, some of the first portion first well pattern
primary sweep volume may
move toward the at least one first portion production well 106a. In other
words, the first portion
first differential pressure may move or flow the subsurface formation 124
toward the at least one
first portion production well 106a.
[0095] The first portion first differential pressure may be created by
continuing to inject the
conditioning fluid into the at least one first portion injection well 104a and
by starting to produce
the first portion first well pattern primary sweep volume from the at least
one first portion
production well 106a. The first portion first differential pressure may be
created after the
conditioning process ends. The flow of the conditioning fluid, fluid within
the subterranean
formation, and/or a portion of the first portion first well pattern primary
sweep volume into the at
least one first portion production well 106a may create the first portion
first differential pressure
near the at least one first portion production well 106a.
[0096] The first portion first differential pressure may be created by
increasing a rate or
pressure at the least one first portion injection well 104a. The rate or
pressure may be increased
such that it is higher than the rate or pressure used during the conditioning
process.
[0097] Once the first portion first differential pressure alleviates and/or
substantially
balances the frictional stress opposing the motion or sliding of the material
within the first
portion first well pattern 1111, which has been reduced from the initial in
situ values due to
raising the pore pressure by injecting the conditioning fluid, the first
portion first well pattern
primary sweep volume may be produced via one or more of the at least one first
portion
production well 106a. The first portion first well pattern primary sweep
volume produced may
be the rest of the first portion first well pattern primary sweep volume that
was not produced
while creating the first portion first differential pressure. Producing the
first portion first well
pattern primary sweep volume may comprise mobilizing the first portion first
well pattern
primary sweep volume along a first subsurface formation path within the first
portion first well
pattern 1111 (i.e., first portion first subsurface formation path). The first
portion first well
pattern primary sweep volume moves along the first portion first subsurface
formation path away
from one or more of the at least one first portion injection well 104a to the
one or more of the at
least one first portion production well 106a. The first portion first well
pattern primary sweep
volume may be only a portion of the reservoir.
- 23 -
CA 02912301 2015-11-18
[0098] The first portion first well pattern primary sweep volume may be
produced via one or
more of the at least one first portion production well 106a, 804 (Figure 6).
The one or more of
the at least one first portion production well 106a may be configured to
produce the first portion
first well pattern primary sweep volume from the subsurface formation 124. The
one or more of
the at least one first portion production well 106a has a structure that
enables it to produce the
first portion first well pattern primary sweep volume. Examples of the
structure may include, but
are not limited to, an uncased wellbore or a cased wellbore with an opening or
perforations that
allow the first portion first well pattern primary sweep volume to flow into a
well. The first
portion first well pattern primary sweep volume travels in a direction 114
away from the
reservoir 102 and toward the surface 112.
[0099] After being produced via the one or more of the at least one first
portion production
well 106a, the first portion first well pattern primary sweep volume may be
fed to a pumping
station 116. From the pumping station 116, the first portion first well
pattern primary sweep
volume may be processed in a facility 118 to remove at least a portion of the
hydrocarbons 120
within the first portion first well pattern primary sweep volume that may then
be sold. The
hydrocarbons 120 can be sent to other facilities for refining or further
processing such as but not
limited to upgrading to produce upgraded hydrocarbons. The upgraded
hydrocarbons may be
sold. The hydrocarbons 120 may be combined with a diluent stream and then sent
to other
facilities and/or or sold. The portion of the first portion first well pattern
primary sweep volume
not sent to the other facilities for refining or further processing may enter
a pumping station 110.
[0100] After creating the first portion first differential pressure between
the at least one first
portion injection well 104a and the at least one first portion production well
106a and to produce
the first portion first well pattern primary sweep volume not produced while
creating the first
portion first differential pressure between the at least one first portion
injection well 104a and the
at least one first portion production well 106a, injection media may be
injected into the at least
one first portion injection well 104a. The at least one first portion
injection well 104a may be
configured to receive the injection media. The at least one first portion
injection well 104a has a
structure that enables it to receive the injection media and inject that media
through an opening
or perforations into the reservoir. Examples of structure may include, but are
not limited to, an
uncased wellbore or a cased wellbore. The injection media received by the at
least one first
- 24 -
CA 02912301 2015-11-18
portion injection well 104a travels in the at least first portion injection
well 104a in the direction
122. The injection media may be fed to the reservoir 102.
[0101] The injection media may be injected while producing the first
portion first well
pattern primary sweep volume and after creating the first portion first
differential pressure. As
the injection media is injected into the first portion first well pattern 1111
via the at least one first
portion injection well 104a, the first portion first well pattern primary
sweep volume is swept
toward one or more of the at least one first portion production well 106a via
the first portion first
subsurface formation path to be produced from the one or more of the at least
one first portion
production well 106a. The injection media may fill the void that the produced
first portion first
well pattern primary sweep volume left in the reservoir 102.
[0102] The injection media may be injected into the first portion first
well pattern 1111 via
the at least one first portion injection well 104a until the injection media
is produced by the at
least one first portion production well 106a, 805 (Figure 6). Specifically,
the injection media
may be injected into the first portion first well pattern until breakthrough
occurs at the at least
one first portion production well 106a. The injection media being produced by
the at least one
first portion production well 106a marks the end of primary production within
the first portion
first well pattern 1111 when the injection media being produced comprises the
reinjected sand.
The reinjected sand may start to be produced from the at least one first
portion production well
106a when a portion of the reinjected sand reaches the at least one first
portion production well
106a, when the reinjected sand is travelling through the at least one first
portion production well
106a, when the reinjected sand is exiting the at least one first portion
production well 106a, or
when the reinjected sand is moving through the surface processing facility
118.
[0103] The actual determination of when to stop injecting injection media
via any of the one
or more first portion injection well 104a into the first portion first well
pattern 1111, because the
injection media is being produced by the one or more of the at least one first
portion production
well 106a, may be determined by the sand breakthrough indicator.
101041 After injecting the injection media into the first portion first
well pattern 1111 and
producing the first portion first well pattern primary sweep volume, the
system and method may
include increasing the reservoir pore pressure of the reservoir 102.
Increasing the reservoir pore
pressure may comprise injecting a conditioning fluid into the reservoir 102.
The conditioning
fluid may be injected into the reservoir 102 at one or more locations within
the subsurface
- 25 -
CA 02912301 2015-11-18
formation 124. The conditioning fluid may be injected into any suitable
location within the
reservoir 102. The pressure of the conditioning fluid may allow the
conditioning fluid to
permeate through the portion of the reservoir 102 that contains hydrocarbons.
As the
conditioning fluid is injected, the reservoir pore pressure increases and may
thereby alleviate
and/or substantially balance the stresses on the reservoir 102 that are caused
by the overburden
stress. The pressure of the conditioning fluid may be sufficient to develop a
substantially steady-
state pressure profile within the reservoir 102.
[0105] Injecting the conditioning fluid into the reservoir 102 may comprise
injecting the
conditioning fluid via one or more of the at least one first portion injection
well 104a, the at least
one second portion injection well 104b, the at least one first portion
production well 106a and the
at least one second portion production well 106b. The at least one first
portion injection well
104a, the at least one second portion injection well 104b, the at least one
first portion production
well 106a and the at least one second portion production well 106b may each
have a structure
that enable them to receive the conditioning fluid. Examples of the structure
may include, but
are not limited to, an uncased wellbore or a cased wellbore. The conditioning
fluid travels in the
at least one first portion injection well 104a, the at least one second
portion injection well 104b,
the at least one first portion production well 106a and/or the at least one
second portion
production well 106b in a direction 122 toward the reservoir 102.
[0106] When the conditioning fluid is injected into one or more of the at
least one first
portion injection well 104a, the at least one second portion injection well
104b, the at least one
first portion production well 106a and the at least one second portion
production well 106b, a
porosity of the subsurface formation 124 may increase. The porosity of the
subsurface formation
124 may increase because the reservoir 102 may comprise a sand particle
network. The sand
particle network may dilate or expand in volume as the effective stress due to
the overburden
stress is alleviated and/or substantially balanced by by the increase in
reservoir pore pressure.
The increase in porosity may be accompanied by a decrease in the mechanical
strength of the
material within the reservoir 102 to a state where the material within the
reservoir 102 may slide
in a direction of one or more of the at least one first portion production
well 106a and the at least
one second portion production well 106b when a pressure gradient is imposed
due to the flow of
a fluid from one or more of the at least one first portion injection well 104a
to the at least one
first portion production well 106a and the at least one second portion
injection well 104b to the
- 26 -
CA 02912301 2015-11-18
at least one second portion production well 106b. Increasing the initial
porosity of the
subsurface formation 124 may increase the permeability of the subsurface
formation 124.
[0107] The injection of the conditioning fluid into one or more of the at
least one first portion
injection well 104a, the at least one second portion injection well 104b, the
at least one first
portion production well 106a and the at least one second portion production
well 106b may be
referred to as the conditioning process. In other words, the conditioning
fluid may be injected
into one or more of the at least one first portion injection well 104a, the at
least one second
portion injection well 104b, the at least one first portion production well
106a and the at least one
second portion production well 106b during the conditioning process. When the
conditioning
fluid is injected into the at least one first portion production well 106a
and/or the at least one
second portion production well 106b, the at least one first portion production
well 106a and/or
the at least one second portion production well 106b act like an injection
well in that they receive
a fluid that is fed to the reservoir 102. When the conditioning fluid is
injected into the at least
one first portion injection well 104a, the at least one second portion
injection well 104b, the at
least one first portion production well 106a and at least one second portion
production well 106b,
the stresses on the reservoir 102 may be alleviated and/or substantially
balanced more quickly
than if the conditioning fluid is only injected into less than all of these.
[0108] The conditioning process may end once the effective stresses on the
reservoir 102 due
to the overburden stress are alleviated and/or substantially balanced by the
increased reservoir
pore pressure. Whether or not the effective stresses on the reservoir 102 due
to overburden stress
have been alleviated and/or substantially balanced may be determined, but is
not limited to being
determined, by comparing the bottom hole pressures in the at least one first
portion injection well
104a, the at least one second portion injection well 104b, the at least one
first portion production
well 106a, the at least one second portion production well 106b, and/or at
least one observation
well to an estimated applied overburden stress due to its weight. The
observation well may be a
well that allows for the observation of parameters, such as but not limited to
fluid levels and
pressure changes, of one or more of the at least one first portion injection
well 104a, the at least
one second portion injection well 104b, the at least one first portion
production well 106a and the
at least one second portion production well 106b. The magnitude of the
effective stress applied
by the overburden to the reservoir (e.g., overburden stress minus the
reservoir pore pressure) at
the end of the conditioning process is generally small (generally in the range
of 10 to 500
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CA 02912301 2015-11-18
kilopascals (kPa) out of the 1 Megapascal (MPa) to IOMPa effective overburden
stress that
would have existed before the conditioning process, where the aforementioned
ranges may
include any number bounded by and/or within the preceding ranges depending on
a depth of the
reservoir, an initial pore pressure of the reservoir, and/or in situ stresses
of the reservoir, of
which the overburden stress may be one component).
[0109] Once the conditioning process ends, a second portion first
differential pressure
between the at least one second portion injection well 104b and the at least
one second portion
production well 106b may be created. Creating the second portion first
differential pressure
between the at least one second portion injection well 104b and the at least
one second portion
production well 106b may impose a pressure gradient. The creation of the
second portion first
differential pressure between the at least one second portion injection well
104b and the at least
one second portion production well 106b may cause water or brine to flow in
the subsurface
formation 124. The water or brine may create fluid drag forces on solids in
the subsurface
formation 124. Once the second portion first differential pressure in the
second portion first well
pattern 1112 increases to a point where it overcomes the friction holding the
reservoir 102 in
place, some of a primary sweep volume within the second portion first well
pattern (i.e., the
second portion first well pattern primary sweep volume) may move toward the at
least one
second portion production well 106b. In other words, the second portion first
differential
pressure may move or flow the subsurface formation 124 toward the at least one
second portion
production well 106b.
[0110] The second portion first differential pressure may be created by
continuing to inject
the conditioning fluid into the at least one second portion injection well
104b and by starting to
produce the second portion first well pattern primary sweep volume from the at
least one second
portion production well 106b. The second portion first differential pressure
may be created after
the conditioning process ends. The flow of the conditioning fluid, fluid
within the subterranean
formation and/or a portion of the second portion first well pattern primary
sweep volume into the
at least one second portion production well 106b may create the second portion
first differential
pressure near the at least one second portion production well 106b.
[0111] The second portion first differential pressure may be created by
increasing a rate or
pressure at the least one second portion injection well 104b. The rate or
pressure may be
increased such that it is higher than the rate or pressure used during the
conditioning process.
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CA 02912301 2015-11-18
[0112] Once the second portion first differential pressure alleviates or
substantially balances
the overburden stress opposing the motion or sliding of the material within
the second portion
first well pattern 1112, which have been reduced from the initial in situ
values due to raising the
pore pressure by injecting the conditioning fluid, the second portion first
well pattern primary
sweep volume may be produced via one or more of the at least one second
portion production
well 106b. The second portion first well pattern primary sweep volume produced
may be the
rest of the second portion first well pattern primary sweep volume that was
not produced while
creating the second portion first differential pressure. Producing the second
portion first well
pattern primary sweep volume may comprise mobilizing the second portion first
well pattern
primary sweep volume along a second portion first subsurface formation path
within the second
portion first well pattern 1112 (i.e., second portion first subsurface
formation path). The second
portion first well pattern primary sweep volume moves along the second portion
first subsurface
formation path away from one or more of the at least one second portion
injection well 104b to
the one or more of the at least one second portion production well 106b. The
second portion first
well pattern primary sweep volume may be only a portion of the reservoir.
[0113] The second portion first well pattern primary sweep volume may be
produced via one
or more of the at least one second portion production well 106b. The one or
more of the at least
one second portion production well 106b may be configured to produce the
second portion first
well pattern primary sweep volume from the subsurface formation 124. The one
or more of the
at least one second portion production well 106b has a structure that enables
it to produce the
second portion first well pattern primary sweep volume. Examples of the
structure may include,
but are not limited to, an uncased wellbore or a cased wellbore with an
opening or perforations
that allow the second portion first well pattern primary sweep volume to flow
into a well. The
second portion first well pattern primary sweep volume travels in a direction
114 away from the
reservoir 102 and toward the surface 112.
[0114] After being produced via the one or more of the at least one second
portion
production well 106b, the second portion first well pattern primary sweep
volume may be fed to
a pumping station 116. From the pumping station 116, the second portion first
well pattern
primary sweep volume may be processed in a facility 118 to remove at least a
portion of the
hydrocarbons 120 within the second portion first well pattern primary sweep
volume that may
then be sold. The hydrocarbons 120 can be sent to other facilities for
refining or further
- 29 -
CA 02912301 2015-11-18
processing such as but not limited to for upgrading to produce upgraded
hydrocarbons. The
upgraded hydrocarbons may be sold. The hydrocarbons 120 may be combined with a
diluent
stream and then sent to other facilities and/or or sold. The portion of the
second portion first
well pattern primary sweep volume not sent to the other facilities for
refining or further
processing may enter a pumping station 110.
[0115] After creating the second portion first differential pressure
between the at least one
second portion injection well 104b and the at least one second portion
production well 106b and
to produce the second portion first well pattern primary sweep volume not
produced while
creating the second portion first differential pressure between the at least
one second portion
injection well and the at least one second portion production well, injection
media may be
injected into the at least one second portion injection well 104b. The at
least one second portion
injection well 104b may be configured to receive the injection media. The at
least one second
portion injection well 104b has a structure that enables it to receive the
injection media and inject
that media through an opening or perforations into the reservoir. Examples of
structure may
include, but are not limited to, an uncased wellbore or a cased wellbore. The
injection media
received by the at least one second portion injection well 104b travels in the
at least one second
portion injection well 104b in the direction 122. The injection media may be
fed to the reservoir
102.
[0116] The injection media may be injected while producing the second
portion first well
pattern primary sweep volume and after creating the second portion first
differential pressure.
As the injection media is injected into the second portion first well pattern
1112 via the at least
one second portion injection well 104b, the second portion first well pattern
primary sweep
volume is swept toward one or more of the at least one second portion
production well 106b via
the second portion first subsurface formation path to be produced from the one
or more of the at
least one second portion production well 106b. The injection media may fill
the void that the
produced second portion first well pattern primary sweep volume left in the
reservoir 102.
[0117] The injection media may be injected into the second portion first
well pattern 1112
via the at least one second portion injection well 104b until the injection
media is produced by
the at least one second portion production well 106b. Specifically, the
injection media may be
injected into the second portion first well pattern until breakthrough occurs
at the at least one
second portion production well 106b. The reinjected sand may start to be
produced from the at
- 30 -
CA 02912301 2015-11-18
least one second portion production well 106b when a portion of the reinjected
sand reaches the
at least one second portion production well 106b, when the reinjected sand is
travelling through
the at least one second portion production well 106b, when the reinjected sand
is exiting the at
least one second portion production well 106b, or when the reinjected sand is
moving through
the surface processing facility 118. The injection media being produced by the
at least one
second portion production well 106b marks the end of primary production within
the second
portion first well pattern 1112 when the injection media being produced
comprises the reinjected
sand.
[0118] The actual determination of when to stop injecting injection media
via any of the one
or more second portion injection well 104b into the second portion first well
pattern 1112,
because the injection media is being produced by the one or more of the at
least one second
portion production well 106b, may be determined by the sand breakthrough
indicator.
[0119] After injecting the injection media into the first portion first
well pattern 1111 and
producing the first portion first well pattern primary sweep volume and before
increasing the
reservoir pore pressure, creating the second portion first differential
pressure, producing the
second portion first well pattern primary sweep volume and injecting the
injection media into the
second portion first well pattern, or after injecting the injection media into
the first portion first
well pattern 1111 and producing the first portion first well pattern primary
sweep volume and
after increasing the reservoir pore pressure, creating the second portion
first differential pressure,
producing the second portion first well pattern primary sweep volume and
injecting the injection
media into the second portion first well pattern, the system and method may
comprise reducing
the reservoir pore pressure. Reducing the reservoir pore pressure may allow
the overburden
stress to be at least partially reapplied to the first portion first well
pattern 1111 and/or the second
portion first well pattern 1112, respectively, thereby recompacting at least a
portion of the
reservoir 102, reducing the porosity and or increasing the mechanical
stiffness of a portion of the
sand matrix comprising the reservoir 102. One or more of the at least one
first portion injection
well 104a and the at least one first portion production well 106a and one or
more of the at least
one second portion injection well 104b and the at least one second portion
production well 106b
may allow for this recompaction of the first portion first well pattern 1111
and/or the second
portion first well pattern 1112, respectively, by being wells for withdrawing
fluids from the
reservoir in order to lower the reservoir pore pressure. The reservoir pore
pressure may be
-31 -
CA 02912301 2015-11-18
reduced by ceasing the injection of the injection media into the at least one
first portion injection
well 104a and the at least one second portion injection well 104b. The
reservoir pore pressure
may be reduced by ceasing production of all but fluid (e.g., preferentially
only producing the
fluid) through the one or more of the at least one first portion production
well 106a and the at
least one second portion production well 106b. The reservoir pore pressure may
be reduced by
ceasing injection of injection media into the at least one first portion
injection well 104a and
allowing the reservoir pore pressure to drop due to leak off or equilibration
of the reservoir pore
pressure and/or ceasing injection of injection media into the at least one
second portion injection
well 104b and allowing the reservoir pore pressure to drop due to leak off or
equilibration of the
reservoir pore pressure. The reservoir pore pressure may be reduced by ceasing
injection of
injection media into the at least one first portion injection well 104a and by
ceasing production of
the primary sweep volume by the at least one first portion production well
106a and allowing the
reservoir pore pressure to drop due to leak off or requilibration of the
reservoir pore pressure
and/or by ceasing injection of injection media into the at least one second
portion injection well
104b and by ceasing production of the primary sweep volume by the at least one
second portion
production well 106b and allowing the reservoir pore pressure to drop due to
leak off or
requilibration of the reservoir pore pressure. The reservoir pore pressure
leaks off into one or
more portions of the reservoir that are not being targeted for production.
[0120] Reducing the reservoir pore pressure to recompact at least the
portion of the first
portion first well pattern 1111 and/or the second portion first well pattern
1112 may seal the first
portion first subsurface formation path 1300 and/or the second portion first
subsurface formation
path 1301, respectivelyõ which is beneficial. Sealing the first portion first
subsurface formation
path and/or the second portion first subsurface formation path after the
hydrocarbons are
produced during for example, primary production, will promote production from
the reservoir
along other subsurface formation paths (e.g. where production has not yet
occured). Sealing the
first portion first subsurface formation path and/or the second portion first
subsurface formation
path helps make it possible to produce a portion of the reservoir 102 that was
not previously
produced, thereby helping make it possible to enhance heavy oil recovery. The
process of
reducing the reservoir pore pressure may be referred to as a recompaction
process.
[0121] While producing the primary sweep volume of and/or injecting the
injection media
into the first portion first well pattern and/or the second portion first well
pattern, the reservoir
- 32 -
CA 02912301 2015-11-18
pore pressure may be reduced. This reduction may occur as a mitigation during
a process upset.
One example of a process upset includes, but is not limited to, when the
injection media includes
too much water. When the injection media includes too much water, the primary
sweep volume
may not be able to be mobilized or only a portion of the primary sweep volume
may be
mobilized with a portion of the injection media bypassing the primary sweep
volume. When the
primary sweep volume is not able to be mobilized or only a portion of the
primary sweep volume
is mobilized, the reservoir pore pressure may be reduced in a manner similar
to how the reservoir
pore pressure is reduced during the previously described recompaction process.
After
recompacting the subsurface formation, injection media may again be injected
so that primary
sweep volume may be produced.
[0122] While producing the primary sweep volume of and/or injecting the
injection media
into the first portion first well pattern and/or the second portion first well
pattern, the reservoir
pore pressure may be increased. This increase may occur as a mitigation during
a process upset.
One example of a process upset includes, but is not limited to, when the
reservoir pore pressure
has not been increased enough to mobilize the primary sweep volume when the
injection media
is injected. The reservoir pore pressure may not be increased enough if the
conditioning process
ends before the effective stresses on the reservoir 102, due to the overburden
stress, are
alleviated and/or substantially balanced by the increased reservoir pore
pressure. The reservoir
pore pressure may be increased in a similar manner to how the reservoir pore
pressure is
increased during the previously described conditioning process. Increasing the
reservoir pore
pressure may be stopped when it appears that the effective stresses on the
reservoir 102, due to
the overburden stress, have been alleviated and/or substantially reduced by
the increased
reservoir pore pressure. After increasing the reservoir pore pressure has
stopped, injection media
may again be injected so that primary sweep volume may be produced.
[0123] While producing the primary sweep volume of and/or injecting the
injection media
into the first portion first well pattern and/or the second portion first well
pattern, the reservoir
pore pressure may be reduced and then increased. This reduction and increase
may occur as a
mitigation during a process upset. One example of a process upset includes,
but is not limited to,
when the injection media includes too much water, so the reservoir pore
pressure is reduced in a
manner similar to how the reservoir pore pressure is reduced during the
previously described
recompaction process, and then the reservoir pore pressure is not high enough
for the primary
- 33 -
CA 02912301 2015-11-18
sweep volume to be mobilized, so the reservoir pore pressure is increased in a
similar manner to
how the reservoir pore pressure is increased during the previously described
conditioning
process. After the reduction and increase stops, injection media may again be
injected so that
primary sweep volume may be produced.
[0124] While producing the primary sweep volume of and/or injecting the
injection media
into the first portion first well pattern and/or the second portion first well
pattern, the reservoir
pore pressure may be increased and then reduced. This increase and reduction
may occur as a
mitigation during a process upset. One example of a process upset includes,
but is not limited to,
when the reservoir pore pressure is not high enough for the primary sweep
volume to be
mobilized, so the reservoir pore pressure is increased in a similar manner to
how the reservoir
pore pressure is increased during the previously described conditioning
process, and then the
injection media includes too much water, so the reservoir pore pressure is
reduced in a manner
similar to how the reservoir pore pressure is reduced during the previously
described
recompaction process. After the increase and reduction stops, injection media
may again be
injected so that primary sweep volume may be produced.
[0125] After the injection media ceases being injected into the at least
one first portion
injection well 104a and the first portion first well pattern primary sweep
volume ceases being
produced and/or the injection media ceases being injected into the at least
one second portion
injection well 104b and the second portion first well pattern primary sweep
volume ceases being
produced, the method and system may comprise recompleting at least one of (1)
recompleting
one or more of the at least one production well 106 as a recompleted injection
well 105 and (2)
shutting in one or more of the at least one injection well 104 and/or at least
one or
(1)recompleting one or more of the at least one injection well 104 as a
recompleted production
well 107 and (2) shutting in one or more of the at least one production well
106a, 106bb (Figures
4-5). A recompleted first portion injection well and a recompleted second
portion injection well
may interchangeably be referred to as a recompleted production well. A
recompleted first
portion production well and a recompleted second portion production well may
interchangeably
be referred to as a recompleted production well.
[0126] Recompleting and shutting in may be referred to as a recompletion
process. The
recompleted production well 107 may comprise an injection well 104 that was
recompleted to act
as a production well such that the recompleted production well 107 produces a
fluid or a second
- 34 -
CA 02912301 2015-11-18
portion of the reservoir material. In other words, the recompleted production
well 107 may have
previously acted as an injection well 104. The recompleted production well 107
may have
previously acted as an injection well 104 during primary production. The
recompleted
production well 107 may comprise one or more recompleted production wells 107.
The
recompleted production well 107 may comprise any amount of wells bounded by
and including
the aforementioned range. The recompleted injection well 105 may comprise a
production well
106 that was recompleted to act as an injection well such that the recompleted
injection well 105
receives a fluid or injection media to inject into the reservoir. In other
words, the recompleted
injection well 105 may have previously acted as a production well 106. The
recompleted
injection well 105 may have previously acted as a production well 106 during
primary
production. The recompleted injection well 105 may comprise one or more
recompleted
injection wells 105. The recompleted injection well 105 may comprise any
amount of wells
bounded by and including the aforementioned range.
[0127] Reducing the reservoir pore pressure, after the injection media
ceases being injected
and the primary sweep volume ceases being produced, may occur before at least
one of
recompleting and shutting in.
[0128] After recompleting and/or shutting in, the method and system may
comprise
increasing the reservoir pore pressure by injecting a reconditioning fluid
into the subsurface
formation. The reconditioning fluid may be injected via one or more of the at
least one first
portion injection well 104a, the at least one second portion injection well
104b, the at least one
first portion production well 106a, the at least one second portion production
well 106b, the
recompleted production well 105 and the recompleted injection well 107. As the
reconditioning
fluid is injected, the reservoir pore pressure may increase to alleviate
and/or substantially balance
the stresses on the reservoir 102 that are caused by an overburden stress of
the overburden 108
on the reservoir 102. The pressure of the reconditoning fluid injected may
help make it possible
to increase the reservoir pore pressure.
[0129] When the reconditioning fluid is injected, a porosity of the
subsurface formation 124
may increase. Increasing the porosity of the subsurface formation 124 may
increase a
permeability of the subsurface formation 124 and partially or totally break up
or dissagregate
(through shear dilation) a portion of the shale and/or mudstone layers that
may be embedded
within the reservoir. Increasing the porosity and permeability may remove the
shale and/or
- 35 -
CA 02912301 2015-11-18
mudstone layers from acting as baffles and/or barriers to the flow within the
subsurface
formation 124. The pressure of the reconditioning fluid injected may help make
it possible to
increase the initial porosity and the permeability.
[0130] The injection of the reconditioning fluid into the subsurface
formation 124 may be
referred to as the reconditioning process. The reconditioning process may end
once the stresses
on the reservoir 102 that are caused by the overburden stress are alleviated
and/or substantially
balanced by the reconditioning process. The magnitude of the effective stress
applied by the
overburden to the reservoir (e.g., overburden stress minus pore pressure) at
the end of the
reconditioning process is generally small (generally in the range of 10 to 500
kilopascals (kPa)
out of the 1 Megapascal (MPa) to 1 OMPa overburden stress that would have
existed before the
reconditioning process, where the aforementioned ranges may include any number
bounded or
within the preceding ranges).
[0131] After the reconditioning process ends, a second differential
pressure may be created
between (a) the recompleted production well 107 and the at least one injection
well 104a, 104b
or (b) the recompleted injection well 105 and the at least one production well
106a, 106b
(Figures 4-5). Creating the second differential pressure may impose a pressure
gradient. The
creation of the second differential pressure may occur after recompleting and
shutting in The
creation of the second differential pressure may cause water or brine to flow
into the subsurface
formation 124. The water or brine may create fluid drag forces on solids in
the subsurface
formation 124. Once the second differential pressure in a given portion of the
subsurface
formation 124 near the recompleted production well 107 or the at least one
production well 106a,
106b increases to a point where it overcomes the friction holding the
reservoir 102 in place,
some of a secondary sweep volume 131 may move toward the recompleted
production well 107
or the at least one production well 106a, 106b. In other words, the second
differential pressure
may move or flow the subsurface formation 124 toward the recompleted
production well 107 or
the at least one production well 106a, 106b.
[0132] The second differential pressure may be created by continuing to
inject the
reconditioning fluid into the recompleted injection well 105 or the at least
one injection well
104a, 104b and by starting to produce secondary sweep volume from the
recompleted production
well 107 or the at least one production well 106a, 106b. The flow of the
reconditioning fluid,
fluid within the subterranean formation, a portion of the primary sweep
volume, and/or a portion
- 36 -
CA 02912301 2015-11-18
of the secondary sweep volume, into the recompleted production well 107 or the
at least one
production well 106a, 106b may create the second differential pressure near
the recompleted
production well 107 or the at least one production well 106a.
[0133] The second differential pressure may be created by increasing a rate
or pressure at the
recompleted injection well 105 or the least one injection well 104a, 104b. The
rate or pressure
may be increased such that it is higher than the rate or pressure used during
the reconditioning
process.
[0134] Once the second differential pressure is large enough to overcome
the friction holding
the portion of the reservoir 102 near the recompleted production well 107 or
the at least one
production well 106a, 106b, secondary sweep volume may be produced via one or
more of the
recompleted production well 107 and the at least one production well 106a,
106b. The
secondary sweep volume produced may be the rest of the secondary sweep volume
that was not
produced while creating the second differential pressure.
[0135] Producing the secondary sweep volume may comprise mobilizing the
secondary
sweep volume along a second subsurface formation path 302 within the
subsurface formation
124. The second subsurface formation path may be different from the first and
second portion
first subsurface formation path. When the second subsurface formation path is
different from the
first and second portion first subsurface formation path, the recovery of
heavy oil may be
enhanced because a different portion of the first well pattern may be swept.
The swept portion of
the second subsurface formation path is the secondary sweep volume 131 that
may be produced.
The second subsurface formation path may be different from the first and
second portion first
subsurface formation path because the subsurface formation 124 undergoes the
recompleting and
reconditioning processes after the primary sweep volume 130 is produced. The
reconditioning
process helps to seal the first and second portion first subsurface formation
path 1301 so that a
new portion of the well pattern can be produced. The recompletion process
helps provide an
alternative path for reinjection media to enter the subsurface formation 124
and for secondary
sweep volume to be produced from the subsurface formation 124 so that a new
portion of the
reservoir 102 can be swept and produced.
[0136] During production, the secondary sweep volume moves along the second
subsurface
formation path away from the one or more of the at least one recompleted
injection well 105 and
the at least one injection well 104a, 104b to the one or more of the at least
one recompleted
- 37-
CA 02912301 2015-11-18
production well 107 or the one more more of the at least one production well
106a, 106b,
respectively. The secondary sweep volume may only be a portion of the
reservoir.
[0137] The secondary sweep volume may be produced via one or more of the
recompleted
production well 107 and the at least one production well 106a, 106b. The one
or more of the
recompleted production well 107 and the at least one production well 106a,
106b may be
configured to produce the secondary sweep volume from the first well pattern.
The one or more
of the recompleted production well 107 and the at least one production well
106a, 106b each
have a structure that enable them to produce the secondary sweep volume.
Examples of structure
may include, but are not limited to, a caseless wellbore or a cased wellbore.
The secondary
sweep volume travels in a direction 114 away from the reservoir 102 and toward
the surface 112
such that a secondary sweep volume may be swept in a second subsurface
formation path.
Similar to primary production, secondary production may end when breakthrough
occurs.
[0138] After being produced via the one or more of the recompleted
production well 107 and
the at least one production well 106a, 106b the secondary sweep volume may be
fed to a
pumping station 116. From the pumping station 116, the secondary sweep volume
may be
processed in a facility 118 to remove at least a portion of the hydrocarbons
120 within the
secondary sweep volume, which may then be sold. The hydrocarbons 120 can be
sent to other
facilities for refining or further processing, such as but not limited to for
upgrading to produce
upgraded hydrocarbons. The upgraded hydrocarbons may be sold. The hydrocarbons
120 may
be combined with a diluent stream and then sent to other facilities and/or
sold. The portion of
the secondary sweep volume not sent to the other facilities for refining or
further processing may
enter a pumping station 110.
[0139] While producing the secondary sweep volume and/or injecting the
reinjection media,
the reservoir pore pressure may be reduced, increased, reduced and then
increased, or increased
and then reduced. The reduction, increase, reduction and then increase, or
increase and then
decrease of the reservoir pore pressure may occur during a process upset in a
similar and/or
identical way to that described above for when the reservoir pore pressure is
reduced, increases,
reduced and then increased or increased and then decreased while producing the
primary sweep
volume and/or injecting the injection media into the first portion first well
pattern and/or the
second portion first well pattern.
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[0140] All of the above steps may be performed at a first elevation or
depth first and then,
after all the steps are completed, the above steps may be performed at a
second elevation. The
second elevation or depth may be above the first elevation. In other words,
the second elevation
may be closer to the Earth's surface than the first elevation. The second
elevation may be farther
from the Earth's surface than the first elevation; the first elevation may be
closer to the Earth's
surface than the second elevation. It may be advantageous to perform at a
first elevation first and
then a second elevation to increase the total production for a given set of
wells. After performing
the above steps at a second elevation, the steps could be performed at a third
elevation and so on.
[0141] It is important to note that the steps depicted in Figure 6 are
provided for illustrative
purposes only and a particular step may not be required to perform the
inventive methodology.
The claims, and only the claims, define the inventive system and methodology.
[0142] Disclosed aspects may be used in hydrocarbon management activities.
As used
herein, "hydrocarbon management" or "managing hydrocarbons" includes
hydrocarbon
extraction, hydrocarbon production, hydrocarbon exploration, identifying
potential hydrocarbon
resources, identifying well locations, determining well injection and/or
extraction rates,
identifying reservoir connectivity, acquiring, disposing of and/ or abandoning
hydrocarbon
resources, reviewing prior hydrocarbon management decisions, and any other
hydrocarbon-
related acts or activities. The term "hydrocarbon management" is also used for
the injection or
storage of hydrocarbons or CO2, for example the sequestration of CO2, such as
reservoir
evaluation, development planning, and reservoir management. The disclosed
methodologies and
techniques may be used to extract hydrocarbons from a subsurface region.
Hydrocarbon
extraction may be conducted to remove hydrocarbons from the subsurface region,
which may be
accomplished by drilling a well using oil drilling equipment. The equipment
and techniques
used to drill a well and/or extract the hydrocarbons are well known by those
skilled in the
relevant art. Other hydrocarbon extraction activities and, more generally,
other hydrocarbon
management activities, may be performed according to known principles.
[0143] The system and method discussed above are different from waste
injection. In the
system and method discussed above, the goal is to displace the reservoir
itself. In other words, in
the system and method discussed above, the goal is to produce the reservoir
itself, which
includes producing hydrocarbons within the reservoir as well as other
components, such as but
not limited to sand, within a reservoir. The reservoir is produced by
displacing the reservoir with
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CA 02912301 2015-11-18
injection media and/or reinjection media. In waste injection, the injection
media does not
displace the reservoir, but is rather injected into the reservoir with no
accompanied production.
[0144] The system and method discussed above are different from
hydrocarbons
waterflooding. In waterflooding, water may be injected into the subsurface to
cause a pressure
differential between sets of injection wells and production wells to aid in
the production of
hydrocarbons from the production wells. Waterflooding is generally a
"secondary" or
"enhanced" hydrocarbons recovery concept as it increases the pressure in the
reservoir locally to
drive more hydrocarbons out of the reservoir through creation of a pressure
differential between
sets of injection wells or production wells.
[0145] The basic physics that govern waterflooding are the flow of fluids
through a porous
and/or permeable media. The physics of flow through porous and/or permeable
media show that
the pressures between injection wells and production wells is governed by the
rate at which
fluids are injected and produced and the mobility of those fluids through the
porous and/or
permeable media. That mobility is controlled by the permeability of the media
divided by the
viscosity of the fluid flowing in the media. Thus for the single media (i.e.
single permeability),
water with it viscosity of 1 (centipoise) cP will have a higher mobility than
hydrocarbons which
generally have a higher to much higher viscosity than water (generally 5-500
cP). It is this
physics that dictates that when the injected fluid (most often water) "breaks
through" to a
production well during a waterflood, the production rate of hydrocarbons drops
dramatically due
both to the higher mobility of the water versus the hydrocarbons and to the
drop in pressure
differential between injection wells and production wells due to the ease for
water now to flow
between the injection wells and production wells. This break through of water
may substantially
decrease the effectiveness of an injection well to aid in the production of
hydrocarbons from
production wells in the area as for the same injection rate, as its injection
pressure now is much
lower and thus its pressure differential even with non-break through
production wells is much
less.
[0146] The system and method described above involve the flow of the porous
and/or
permeable media itself as opposed to the flow of fluids through a porous
and/or permeable
media. The flow of fluid relative to the porous and/or permeable media exerts
a drag. When the
drag balances or overcomes the frictional stresses holding the porous and/or
permeable media in
the reservoir in place, the reservoir will begin to flow. When the reservoir
flows, the pressure
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CA 02912301 2015-11-18
differential is proportional to the frictional stresses rather than being
proportional to the flow rate
of fluid as it is in waterflood. This completely changes the physics of the
process from that of
waterflooding. As the pressure differential is proportional to the frictional
stresses opposing the
flow of the reservoir, it is also proportional to those stresses normal to the
direction of flow.
Those normal stresses are the effective overburden stresses applied to that
porous and/or
permeable media. The effective overburden stresses applied to the porous
and/or permeable
media are inversely proportional to the pore pressure. During reservoir flow,
the effective
overburden stresses applied to both the flowing and nonflowing porous and/or
permeable media
evolve and vary. This is different from waterflooding where production is
fairly independent of
stresses and stress evolution. The effective overburden stress in the system
and method
described above may impact the pressure gradient needed to flow the porous
and/or permeable
media between the wells. Specifically, for a given portion of porous and/or
permeable media,
the higher the effective overburden stress ¨ the higher the required pressure
differential for
reservoir flow. If the overall pressure differential is dominated by the flow
of porous and/or
permeable media via a low stress path, the higher stressed porous and/or
permeable media will
not flow.
[0147] The different physics of fluid flow with porous and/or permeable
media flow
envisioned for the system and method described above relative to waterflooding
makes it
extremely unlikely that one of ordinary skill in the art of flow through
porous and/or permeable
media would extrapolate waterflooding to the flow of porous and/or permeable
media as
described for the above system and method.
[0148] It should be noted that the orientation of various elements may
differ, and that such
variations are intended to be encompassed by the present disclosure. It is
recognized that
features of the disclosure may be incorporated into other examples.
[0149] It should be understood that the preceding is merely a detailed
description of this
disclosure and that numerous changes, modifications, and alternatives can be
made in accordance
with the disclosure here without departing from the scope of the disclosure.
The preceding
description, therefore, is not meant to limit the scope of the disclosure.
Rather, the scope of the
disclosure is to be determined only by the appended claims and their
equivalents. It is also
contemplated that structures and features embodied in the present examples can
be altered,
rearranged, substituted, deleted, duplicated, combined, or added to each
other.
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