Note: Descriptions are shown in the official language in which they were submitted.
=A=
METHOD AND SYSTEM FOR ENHANCING THE RECOVERY OF HEAVY OIL
FROM A RESERVOIR
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 slurrified reservoir hydrocarbon recovery processes can
recover a
significant portion of the heavy oil present in a reservoir during primary
production, an
additional significant portion of heavy oil may remain unswept at the
conclusion of primary
production. Primary production may terminate when the heavy oil recovered from
the
production streams are economically insufficient to continue. To recover the
significant portion
of heavy oil that may remain unswept at the conclusion of primary production,
secondary
production may be undertaken. When secondary production is commenced after
breakthrough
occurs during primary production, injected sand or reinjected sand may be
produced along with
in situ oil sand. The production of injected or reinjected sand may lead to a
reduced recovery
efficiency of the heavy oil. The surface processing facilities may have been
designed with a
target heavy oil, sand, water, and fines content in mind. Since the injected
or reinjected sand will
have a lower portion of heavy oil content than the heavy oil, it is possible
that the production of
the injected or reinjected sand may lead to inefficiencies for processing the
produced material.
[0012] A need exists for addressing the aforementioned disadvantages
associated with
commencing production after breakthrough occurs.
SUMMARY
[0013] The present disclosure provides a method and system for enhancing
the recovery of
heavy oil from a reservoir within a subsurface formation.
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[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, then; (b)
creating a first differential pressure between at least one injection well and
at least one
production well within the subsurface formation, then; (c) producing primary
sweep volume
from the subsurface formation via one or more of the at least one production
well; (d) injecting
an injection media into the subsurface formation via one or more of the at
least one injection
well, then; (e) ceasing injecting the injection media before the injection
media is produced by the
at least one production well and ceasing producing primary sweep volume from
the subsurface
formation before the injection media is produced, then; (f) shutting in one or
more of the at least
one injection well and the at least one production well and (g) one of
recompleting one or more
of the at least one production well as a recompletcd injection well and
recompleting one or more
of the at least one injection well as a recompleted production well.
[0015] 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.
BRIEF DESCRIPTION OF THE DRAWINGS
[0016] 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.
[0017] 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.
[0018] Figure 2a is a diagram of the use of a slurrified reservoir
hydrocarbon recovery
process.
[0019] Figure 2b is a diagram of the use of a slurrified reservoir
hydrocarbon recovery
process.
[0020] Figure 3a is a diagram of the use of a slurrified reservoir
hydrocarbon recovery
process.
[0021] Figure 3b is a diagram of the use of a slurrified reservoir
hydrocarbon recovery
process.
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[0022] Figure 4a is a diagram of the use of a slurrified reservoir
hydrocarbon process.
[0023] Figure 4b is a diagram of the use of a slurrified reservoir
hydrocarbon recovery
process.
[0024] Figure 5 is a diagram showing a method of a slurrified reservoir
hydrocarbon
recovery process.
[0025] 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
to scale but are drafted for the purpose of convenience and clarity in
illustrating various aspects
of the disclosure.
DETAILED DESCRIPTION
[0026] 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.
[0027] 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 are 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.
[0028] "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-
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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. %).
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.
[0029] "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).
[0030] "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,
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coagulants, sodium silicate, polymeric compounds, salts, solvents, brine,
hydrocarbons,
polymers, and hydrocarbons.
[0031] "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
processing plants, and delivery outlets. In some instances, the term "surface
facility" is used to
distinguish from those facilities other than wells.
[0032] "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 10.0 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.
[0033] 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.
[0034] "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.
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[0035] 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.
[0036] 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.
[0037] "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.
[0038] "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.
[0039] "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 1 0 mD.
[0040] "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
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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.
[0041] "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."
[0042] "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.
[0043] "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.
[0044] "Production well" refers to a well or wellbore that produces a
material.
[0045] 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.
[0046] 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
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produces materials, such as but not limited to primary sweep volume and/or
secondary sweep
volume.
[0047] "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.
[0048] "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.
[0049] "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.
[0050] 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).
[0051] "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."
[0052] 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
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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
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.
[0053] "Secondary production," secondary recovery or secondary sweep is the
second stage
of hydrocarbon recovery. Secondary production occurs after primary production.
[0054] "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
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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.
[0055] "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.
[0056] "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.
[0057] 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.
[0058] 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.
[0059] 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
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wellbore, for example, as a liner configured to allow flow from an outer
chamber to an inner
chamber.
[0060] "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.
[0061] 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.
[0062] 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.
[0063] 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.
[0064] 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.
[0065] 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.
[0066] 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.
[0067] 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.
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[0068] 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.
[0069] "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
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.
[0070] 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.
[0071] 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.
[0072] As depicted in Figures 1-5 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. The sytem and method make it
possible to
reduce the amount of sand injected and/or reinjected into the subterranean
formation that would
be produced from a subterranean formation during secondary production if the
primary
- 14 -
CA 02912275 2015-11-18
production is run to breakthrough. The system and method make it possible to
increase sweep
efficiency. The system and method, therefore, enhance the recovery of heavy
oil. The system
and method enhance the recovery of heavy oil by ceasing production before
breakthrough,
shutting in one or more of at least one injection well and at least one
production well after
ceasing production before breakthrough, and recompleting one of one or more of
the at least one
production well as a recompleted injection well and recompleting one or more
of the at least one
injection well as a recompleted production well after ceasing production
before breakthrough.
[0073] The system 100 and method 1000 may include at least one injection
well 104 and at
least one production well 106 (Figures 1 and 5). 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.
[0074] 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.
[0075] 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
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.
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CA 02912275 2015-11-18
[0076] The at least one injection well 104 may be configured to receive a
conditioning fluid
from the surface to be injected into the reservoir 102. The at least one
injection well 104 has a
structure that enables it 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 injection well 104 in a direction 122 toward the reservoir
102. The conditioning
fluid may be fed to the reservoir 102.
[0077] When the conditioning fluid is injected into the at least one
injection well 104, a
reservoir pore pressure of the reservoir 102 may increase, 501 (Figure 5). In
other words,
increasing the reservoir pore pressure may include injecting the conditioning
fluid into the
reservoir 102. The conditioning fluid is injected at one or more locations
within the subsurface
formation. The conditioning fluid may be injected into any suitable location
within the
subsurface formation. 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 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 portion of
the reservoir 102 that
contains hydrocarbons at the end of injecting the conditioning fluid.
[0078] When the conditioning fluid is injected into the at least one
injection well 104, 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 one or more production well when a pressure gradient is
imposed due to the
flow of a fluid from the one or more injection well to the one or more
production well.
Increasing the initial porosity of the subsurface formation 124 may increase
the permeability of
the subsurface formation 124.
- 16-
CA 02912275 2015-11-18
[00791 The injection of the conditioning fluid into the at least one
injection well 104 or the at
least one production well 106 may be referred to as the conditioning process.
In other words, the
conditoning fluid may be injected into the at least one production well 106
during the
conditioning process. When the conditioning fluid is injected into the at
least one production
well 106, the at least one production well 106 acts like an injection well in
that it receives a fluid
that is fed to the reservoir 102.
[0080] Injecting the conditioning fluid may comprise injecting the
conditioning fluid via one
or more of the at least one injection well 104 and the at least one production
well 106. When the
conditioning fluid is injected into the at least one injection well 104 and
the at least one
production well 106, the stresses on the reservoir 102 may be balanced more
quickly than if the
conditioning fluid is only injected into the at least one injection well 104.
[0081] 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
has 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
injection well, the at least
one production well, 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 injection well and the at least one production well. 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).
[0082] Once the conditioning process ends, a first differential pressure
between the at least
one injection well 104 and the at least one production well 106 may be
created, 502 (Figure 5).
Creating the first differential pressure may impose a pressure gradient. The
creation of the first
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CA 02912275 2015-11-18
differential pressure between the at least one injection well 104 and the at
least one production
well 106 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 differential
pressure in a given portion of the subsurface formation 124 between the at
least one injection
well 104 and the at least one production well 106 increases to a point where
it overcomes the
friction holding the reservoir 102 in place, some of a primary sweep volume
130 may move
toward the at least one production well 106. In other words, the first
differential pressure may
move or flow the subsurface formation 124 toward the at least one production
well 106.
[0083] The first differential pressure may be created by continuing to
inject the conditioning
fluid into the at least one injection well 104 and by starting to produce
primary sweep volume
130 from the at least one production well 106 (Figures 2a, 3a and 4a). The
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 primary sweep
volume 130 into
the at least one production well 106 may create the first differential
pressure near the at least one
production well 106.
[0084] The first differential pressure may be created by increasing a rate
or pressure at the
least one injection well 104. The rate or pressure may be increased such that
it is higher than the
rate or pressure used during the conditioning process.
[0085] Once the first differential pressure alleviates and/or substantially
balances the
overburden stress opposing the motion or sliding of the material within the
reservoir, which have
been reduced from the initial in situ values due to raising the pore pressure
by injecting the
conditioning fluid, the primary sweep volume 130 may be produced via one or
more of the at
least one production well 106. The primary sweep volume 130 produced may be
the rest of the
primary sweep volume 130 that was not produced while creating the first
differential pressure.
Producing the primary sweep volume 130 may comprise mobilizing the primary
sweep volume
130 along a first subsurface formation path within the subsurface formation
124. The primary
sweep volume 130 moves along the first subsurface formation path away from one
or more of
the at least one injection well 104 to the one or more of the at least one
production well 106.
The primary sweep volume 130 may be only a portion of the reservoir.
- 18 -
CA 02912275 2015-11-18
[0086] The primary sweep volume may be produced via one or more of the at
least one
production well 106, 503 (Figure 5). The one or more of the at least one
production well 106
may be configured to produce primary sweep volume 130 from the subsurface
formation 124.
The one or more of the at least one production well 106 has a structure that
enables it to produce
the primary sweep volume 130. 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 primary
sweep volume to flow into a well. The primary sweep volume 130 travels in a
direction 114
away from the reservoir 102 and toward the surface 112.
[0087] After being produced via the one or more of the at least one
production well 106, the
primary sweep volume 130 may be fed to a pumping station 116. From the pumping
station 116,
the primary sweep volume 130 may be processed in a facility 118 to remove at
least a portion of
the hydrocarbons 120 within the primary sweep volume 130 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 primary sweep volume 130 not
sent to the other
facilities for refining or further processing may enter a pumping station 110.
[0088] After creating the first differential pressure and to produce the
primary sweep volume
130 not produced while creating the first differential pressure, injection
media may be injected
into the at least one injection well 104, 504 (Figure 5). The at least one
injection well 104 may
be configured to receive the injection media. The at least one injection well
104 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 injection
well travels in the at least one injection well 104 in the direction 122. The
injection media may
be fed to the reservoir 102.
[0089] The injection media may be injected while producing the primary
sweep volume 130
and after creating the first differential pressure. As the injection media is
injected into the
subsurface formation 124 via the at least one injection well 104, the primary
sweep volume 130
is swept toward one or more of the at least one production well 106 via the
first subsurface
- 19 -
CA 02912275 2015-11-18
formation path to be produced from the one or more of the at least one
production well 106. The
injection media may fill the void that the produced primary sweep volume 130
left in the
reservoir 102.
[0090] The system 100 and method 1000 may comprise ceasing injecting the
injection media
into the subsurface formation 124 before the injection media is produced by
the at least one
production well 106 and ceasing producing the primary sweep volume 130 from
the subsurface
formation before the injection media is produced by the at least one
production well 106, 505
(Figure 5). The injection media may be injected into the subsurface formation
124 at the same
time that the primary sweep volume is produced from the subsurface formation
124. In other
words, injecting the injection media into the subsurface formation 124 and
producing the primary
sweep volume 130 from the subsurface formation may occur simultaneously. The
system 100
and method 1000 may comprise ceasing injecting the injection media into the
subsurface
formation 124 before breakthrough occurs at the least one production well 106.
The system 100
and method 1000 may comprise ceasing producing the primary sweep volume 130
from the
subsurface formation before the injection media is produced. The system 100
and method 1000
may comprise ceasing injecting the injection media into the subsurface
formation 124 before the
end of primary production. The system 100 and method 1000 may comprise ceasing
producing
the primary sweep volume 130 from the subsurface formation before the end of
primary
production.
[0091] Ceasing injecting the injection media into the subsurface formation
124 and ceasing
producing the primary sweep volume 130 from the subsurface formation 124
before the injection
media is produced by the at least one production well 106 may comprise
measuring an injection
well pressure of one or more of the at least one injection well 104. Ceasing
injecting the
injection media into the subsurface formation 124 and ceasing producing the
primary sweep
volume 130 from the subsurface formation 124 before the injection media is
produced by the at
least one production well 106 may comprise measuring a production well
pressure of one or
more of the at least one production well 106.
[0092] Measuring the injection well pressure of one or more of the at least
one injection well
104 may comprise using at least one pressure sensor 138 (Figure 1). Each of
the at least one
injection well 104 from which the injection well pressure is being measured
may include the at
- 20 -
CA 02912275 2015-11-18
least one pressure sensor 138. The at least one pressure sensor 138 may be any
suitable sensor.
The at least one pressure sensor 138 may be at any location within the at
least one injection well
104. For example, the at least one pressure sensor 138 may be one of at the
bottom of the at least
one injection well 104 and/or the at least one pressure sensor 138 may be at
the top of the at least
one injection well 104. The injection well pressure measured by the at least
one pressure sensor
138 may be outputted to any suitable device, such as but not limited to a
computer.
[0093] Measuring the production well pressure of one or more of the at
least one production
well 106 may comprise using at least one pressure sensor 139 (Figure 1). Each
of the at least one
production well 106 from which the production well pressure is being measured
may include the
at least one pressure sensor 139. The at least one pressure sensor 139 may be
any suitable
sensor. The at least one pressure sensor 139 may be at any location within the
at least one
production well 106. For example, the at least one pressure sensor 139 may be
one of at the
bottom of the at least one production well 106 and/or the at least one
pressure sensor 139 may be
at the top of the at least one production well 106. The production well
pressure measured by the
at least one pressure sensor 139 may be outputted to any suitable device, such
as but not limited
to a computer.
[0094] Ceasing injecting the injection media into the subsurface formation
124 and ceasing
producing the primary sweep volume 130 from the subsurface formation 124
before the injection
media is produced by the at least one production well 106 may comprise
determining a pressure
differential between one of the at least one injection well 104 and one of the
at least one
production well 106 by comparing the injection well pressure of the one of the
at least one
injection well 104 to the production well pressure of the one of the at least
one production well
106. Any suitable mechanism may determine the pressure differential. For
example, a computer
may determine the pressure differential. The suitable mechanism may determine
the pressure
differential by comparing the injection well pressure to the production well
pressure to determine
the difference between the injection well pressure and the production well
pressure.
[0095] Ceasing injecting the injection media into the subsurface formation
124 and ceasing
producing the primary sweep volume 130 from the subsurface formation 124
before the injection
media is produced by the at least one production well 106 may comprise
identifying a maximum
pressure differential with respect to time and determining whether the
pressure differential has
- 21 -
CA 02912275 2015-11-18
decreased from a maximum pressure differential. More specifically, ceasing
injecting the
injection media into the subsurface formation 124 and ceasing producing the
primary sweep
volume 130 from the subsurface formation 124 before the injection media is
produced may
comprise injecting the injection media into the subsurface formation while
determining the
pressure differential between one of the at least one injection well 104 and
one of the at least one
production well 106. The pressure differential may be determined at different
times while
injecting the injection media into the subsurface formation 124. The pressure
differential may be
determined at different times while injecting the injection media until the
pressure differential
has decreased from the maximum pressure differential. Each pressure
differential may be
compared to the immediately preceding pressure differential to see whether the
pressure
differential is lower than the immediately preceding pressure differential.
[0096] Ceasing injecting the injection media into the subsurface formation
124 and ceasing
producing the primary sweep volume 130 from the subsurface formation 124
before the injection
media is produced by the at least one production well 106 may comprise
continuing to inject the
injection media into the subsurface formation 124 until the pressure
differential has decreased
from the maximum pressure differential. In other words, when the pressure
differential
compared to the immediately preceding pressure differential is greater than
the immediately
preceding pressure differential, the immediately preceding pressure
differential is determined not
to be the maximum pressure differential and injection of the injection media
into the subsurface
formation 124 and production of the primary sweep volume 130 from the
subsurface formation
124 continues. The pressure differential may be determined as an instantaneous
value or a time-
averaged value over a specified time period. The immediately preceding
pressure differential
may be determined as an instantaneous value or a time-averaged value over a
specified time
period. When the pressure differential compared to the immediately preceding
pressure
differential is lower than the immediately preceding pressure differential,
the immediately
preceding pressure differential is determined to be the maximum pressure
differential and
injection of the injection media into the subsurface formation 124 ceases.
[0097] After ceasing to inject the injection media into the subsurface
formation and ceasing
to produce the primary sweep volume 130 from the subsurface formation, the
reservoir pore
pressure may be reduced. Reducing the reservoir pore pressure may allow the
overburden stress
to be at least partially reapplied to the reservoir 102, thereby recompacting
at least a portion of
- 22 -
CA 02912275 2015-11-18
the reservoir 102, reducing the porosity or increasing the mechanical
stiffness of a portion of the
sand matrix comprising the reservoir 102. One or more of the at least one
injection well 104 and
the at least one production well 106 may allow for this recompaction of the
reservoir 102 by
being wells for withdrawing fluids from the reservoir in order to lower the
reservoir pore
pressure. The reservoir pore pressure may be reduced by ceasing the injection
of the injection
media into the at least one injection well 104. 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 production well 106. The reservoir pore pressure
may be reduced by
ceasing injection of injection media into the at least one injection well 104
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 injection well 104 and by ceasing production of the primary sweep
volume 130 by the
at least one production well 106 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.
[0098] Reducing the reservoir pore pressure to recompact at least the
portion of the reservoir
102 may seal the first subsurface formation path, which is beneficial. Sealing
the 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 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.
[0099] While producing the primary sweep volume 130 and/or injecting the
injection media,
the reservoir 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 130 may not be able to be mobilized or only a portion of the
primary sweep
volume 130 may be mobilized with a portion of the injection media bypassing
the primary sweep
volume 130. When the primary sweep volume is not able to be mobilized or only
a portion of
the primary sweep volume 130 is mobilized, the reservoir pore pressure may be
reduced in a
- 23 -
CA 02912275 2015-11-18
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 130 may be produced.
[0100] While producing the primary sweep volume 130 and/or injecting the
injection media,
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 130 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 the effective
stresses on the
reservoir 102, due to the overburden stress, have been alleviated and/or
substantially balanced 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 130 may be
produced.
[0101] While producing the primary sweep volume 130 and/or injecting the
injection media,
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 previously described, and then the
reservoir pore pressure is
not high enough for the primary sweep volume 130 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 130 may be produced.
[0102] While producing the primary sweep volume 130 and/or injecting the
injection media,
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
130 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
- 24 -
CA 02912275 2015-11-18
then the injection media includes too much water, so the reservoir pore
pressure is reduced in a
manner similar to how previously described. After the increase and reduction
stops, injection
media may again be injected so that primary sweep volume 130 may be produced.
[0103] After the injection media ceases being injected into the subsurface
formation 124 and
the primary sweep volume 130 ceases being produced from the subsurface
formation 124, the
system 100 and method 1000 may comprise shutting in one or more of the at
least one injection
well 104 and the at least one production well 106, 506 (Figure 5). In other
words, after the
injection media ceases being injected into the subsurface formation 124 and
the primary sweep
volume 130 ceases being produced from the subsurface formation 124, the system
100 and
method 1000 may comprise shutting in one or more of the at least one injection
well 104 or
shutting in one or more of the at least one production well 106.
[0104] After the injection media ceases being injected into the subsurface
formation 124 and
the primary sweep volume 130 ceases being produced from the subsurface
formation 124, the
system 100 and method 1000 may comprise one of recompleting one or more of the
at least one
production well 106 as a recompleted injection well 105 and recompleting one
or more of the at
least one injection well 104 as a recompleted production well 107, 507 (Figure
5). In other
words, after the injection media ceases being injected into the subsurface
formation 124 and the
primary sweep volume 130 ceases being produced from the subsurface formation
124, the
system 100 and method 1000 may comprise recompleting one or more of the at
least one
production well 106 as a recompleted injection well 105 or recompleting one or
more of the at
least one injection well 104 as a recompleted production well 107. The system
100 and method
1000 may comprise recompleting one or more of the at least one production well
106 as a
recompleted injection well 105 if the system 100 and method 1000 comprises
shutting in one or
more of the at least one injection well 104. The system 100 and method 1000
may comprise
recompleting one or more of the at least one injection well 104 as a
recompleted production well
107 if the system 100 and method 1000 comprises shutting in one or more of the
at least one
production well 106. The system 100 and method 1000 may comprise one of
recompleting one
or more of the at least one production well 106 as a recompleted injection
well 105 and
recompleting one or more of the at least one injection well 104 as a
recompleted production well
107 before, after or while shutting in one of one or more of the at least one
injection well 104
and the at least one production well 106.
- 25 -
CA 02912275 2015-11-18
[0105] After one of recompleting one or more of the at least one production
well 106 as a
recompleted injection well 105 and recompleting one or more of the at least
one injection well
104 as a recompleted production well 107, the system 100 and method 1000 may
comprise
injecting a reinjection media into the subsurface formation 124 via one or
more of the at least
one injection well 104 and the at least one recompleted injection well 105.
The at least one
recompleted injection well 105 and/or the one or more of the at least one
injection well 104 has a
structure that enables it to receive the reinjection 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 reinjection media received by the at
least one
recompleted injection well 105 and/or the one or more of the at least one
injection well 104
travels in the at least one recompleted injection well 105 or the one or more
of the at least one
injection well 104 in a direction. The reinjection media may be fed to the
reservoir 102.
[0106] The reinjection media may be injected into the subsurface formation
124 via the at
least one recompleted injection well 105 and/or the one or more of the at
least one injection well
104 until the reinjection media is produced by the at least one recompleted
production well 107
and/or the one or more of the at least one production well 106. Specifically,
the reinjection
media may be injected into the subsurface formation 124 until breakthrough
occurs at the at least
one recompleted production well 107 and/or the one or more of the at least one
production well
106. The reinjection media being produced by the at least one recompleted
production well 107
or the one or more of the at least one production well 106 marks the end of
secondary production
when the reinjection media being produced comprises the reinjected sand. The
reinjected sand
may start to be produced from the at least one recompleted production well 107
and/or the one or
more of the at least one production well 106 when a portion of the reinjected
sand reaches the at
least one recompleted production well 107 and/or the one or more of the at
least one production
well 106, when the reinjected sand is travelling through the at least one
recompleted production
well 107 and/or the one or more of the at least one production well 106, when
the reinjected sand
is exiting the at least one recompleted production well 107 and/or the one or
more of the at least
one production well 106, or when the reinjected sand is moving through the
surface processing
facility 118.
[0107] The actual determination of when to stop injecting reinjection media
via any of the at
least one recompleted injection well 105 and/or the one or more of the at
least one injection well
- 26 -
CA 02912275 2015-11-18
104 into the subsurface formation 124, because the reinjection media is being
produced by the at
least one recompleted production well 107 or the one or more of the at least
one production well
106, may be determined by the sand breakthrough indicator.
[0108] After one of recompleting one or more of the at least one production
well 106 as a
recompleted injection well 105 and recompleting one or more of the at least
one injection well
104 as a recompleted production well 107, the system 100 and method 1000 may
comprise
producing a secondary sweep volume 131 (Figures 2b, 3b and 4b) from the
subsurface formation
124 via one or more of the at least one production well 106 and the at least
one recompleted
production well 107. The one or more of the at least one recompleted
production well 107 and
the at least one production well 106 may be configured to produce the
secondary sweep volume
131 from the subsurface formation 124. The one or more of the at least one
production well 106
and/or the at least one recompleted production well 107 may each have a
structure that enable
them to produce the secondary sweep volume 131. Examples of structure may
include, but are
not limited to, a caseless wellbore or a cased wellbore. The secondary sweep
volume 131 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 (Figure 1).
[0109] Injecting the reinjection media may result in the production of the
secondary sweep
volume 131. Producing the secondary sweep volume 131 may comprise mobilizing
the
secondary sweep 131 volume along a second subsurface formation path within the
subsurface
formation 124. The secondary sweep volume 131 may start to be produced some
time after the
reinjection media starts being injected. Once the secondary sweep volume 131
starts being
produced, the secondary sweep volume 131 may be produced at the same time that
the
reinjection media is injected. As the reinjection media is injected into the
subsurface formation
124, the secondary sweep volume 131 may be swept toward one or more of the at
least one
recompleted production well 107 and/or the one or more of the at least one
production well 106
via a second subsurface formation path. The reinjection media may fill the
void that the
produced secondary sweep volume 131 leaves in the reservoir 102.
[0110] The second subsurface formation path may be different from the first
subsurface
formation path. When the second subsurface formation path is different from
the first subsurface
formation path, the recovery of heavy oil may be enhanced because a different
portion of the
reservoir 102 may be swept. The swept portion of the second subsurface
formation path is the
- 27 -
CA 02912275 2015-11-18
secondary sweep volume 131 that may be produced. The second subsurface
formation path may
be different from the first subsurface formation path because the subsurface
formation 124 may
undergo the recompaction after the primary sweep volume 130 is produced. The
recompaction
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 portion
of the reservoir 102 not produced during primary production can be swept and
produced. The
secondary sweep volume 131 may only be a portion of the reservoir.
[0111] After being produced via the one or more of the at least one
recompleted production
well 107 and the at least one production well 106, 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.
[0112] While producing the secondary sweep volume and/or injecting the
reinjection media,
the reservoir pore pressure may be reduced. This reduction may occur during a
process upset.
One example of a process upset includes, but is not limited to, when the
reinjection media
includes too much water. When the reinjection media includes too much water,
the secondary
sweep volume may not be able to be mobilized or only a portion of the
secondary sweep volume
may be mobilized with a portion of the reinjection media bypassing the the
secondary sweep
volume. When the secondary sweep volume is not able to be mobilized or only a
portion of the
secondary 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, reinjection
media may
again be injected so that secondary sweep volume may be produced.
[0113] While producing the secondary sweep volume and/or injecting the
reinjection media,
the reservoir pore pressure may be increased. This increase may occur during a
process upset.
One example of a process upset includes, but is not limited to, when the
reservoir pore pressure
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CA 02912275 2015-11-18
has not been increased enough to mobilize the secondary sweep volume when the
reinjection
media is injected. The reservoir pore pressure may not be increased enough if
the reconditioning
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 reconditioning process. Increasing
the reservoir pore
pressure may be stopped when it appears that the the effective stresses on the
reservoir 102, due
to the overburden stress, have been alleviated and/or substantially balanced
by the increased
reservoir pore pressure. After increasing the reservoir pore pressure has
stopped, reinjection
media may again be injected so that secondary sweep volume may be produced.
[0114] While producing the secondary sweep volume and/or injecting the
reinjection media,
the reservoir pore pressure may be reduced and then increased. This reduction
and increase may
occur during a process upset. One example of a process upset includes, but is
not limited to,
when the reinjection 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 secondary
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
reconditioning
process. After the reduction and increase stops, reinjection media may again
be injected so that
secondary sweep volume may be produced.
[0115] While producing the primary sweep volume and/or injecting the
reinjection media,
the reservoir pore pressure may be increased and then reduced. This increase
and reduction may
occur 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 secondary 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 reconditioning
process, and then the
reinjection 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, reinjection
media may again be
injected so that secondary sweep volume may be produced.
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CA 02912275 2015-11-18
[0116] Figures 2a-4b show specific examples of some of the above
description. Figures 2a-
2b show inverted seven-spot well patterns. Figures 2a-2b are diagrams of the
use of a slurrified
reservoir hydrocarbon recovery process during primary production and secondary
production,
respectively. Figures 3a-3b show seven-spot well patterns. Figures 3a-3b are
diagrams of the
use of a slurrified reservoir hydrocarbon recovery process during primary
production and
secondary production, respectively. Figures 4a-4b show an inverted five-spot
well patterns.
Figures 4a-4b are diagrams of the use of a slurrified reservoir hydrocarbon
recovery process
during primary production and secondary production, respectively.
[0117] Figure 2a shows use of a slurrified reservoir hydrocarbon recovery
process during
primary production. As shown in Figure 2a, each inverted seven-spot well
pattern includes a
center injection well 104 surrounded by six production wells 106. Figure 2a
shows seven
inverted seven-spot well patterns but there may be any number of well patterns
within a
slurrified reservoir hydrocarbon recovery process having multiple inverted
seven-spot well
patterns. The seven inverted seven-spot well patterns in Figure 2a may be
referred to as a first
well pattern, a second well pattern, a third well pattern, a fourth well
pattern, a fifth well pattern,
a sixth well pattern and a seventh well pattern. During primary production,
the center injection
well 104 within each inverted seven-spot well pattern receives injection media
while each
production well 106 within each inverted seven-spot well pattern receives and
produces primary
sweep volume. Injection media ceases being injected into the injection well
104 within each
inverted seven-spot well pattern before the injection media is produced by the
production wells
106 within each inverted seven-spot well pattern. Primary sweep volume 130
ceases being
produced from the subsurface formation 124 before the injection media is
produced.
[0118] Figure 2b shows use of a slurrified reservoir hydrocarbon recovery
process during
secondary production. As shown in Figure 2b, the injection well 104 of each
inverted seven-spot
well pattern is shut-in 204. The injection well 104 of each inverted seven-
spot well pattern is
shut-in 204 after ceasing injecting the injection media and ceasing producing
primary sweep
volume 130. As shown in Figure 2b, every other production well 106 in each
inverted seven-
spot well pattern is recompleted as a recompleted injection well 105. Every
other production
well 106 in each inverted seven-spot well pattern is recompleted as a
recompleted injection well
105 after ceasing injecting the injection media and ceasing producing the
primary sweep volume
130. As a result, each inverted seven-spot well pattern contains three
production wells 106 and
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CA 02912275 2015-11-18
three recompleted injection wells 105 after ceasing injecting the injection
media and ceasing
producing the primary sweep volume 130. During secondary production,
therefore, reinjection
media is injected into the subsurface formation via the three recompleted
injection wells 105 in
each inverted seven-spot well pattern and secondary sweep volume 131 is
produced from the
three production wells 106 in each inverted seven-spot well pattern. The
reinjection media may
be injected into the subsurface formation via the three recompleted injection
wells 105 until the
reinjection media is produced from one or more of the three production wells
106. The
secondary sweep volume 131 of each of the inverted seven-spot well patterns is
shown to be
along the edge of each of the inverted seven-spot well patterns.
[0119] Figure 3a shows use of a slurrified hydrocarbon recovery process
during primary
production. As shown in Figure 3a, each seven-spot well pattern includes a
center production
well 106 surrounded by six injection wells 104. Figure 3a shows seven seven-
spot well patterns
but there may be any number of well patterns within a slurrified reservoir
hydrocarbon recovery
process having multiple seven-spot well patterns. The seven seven-spot well
patterns in Figure
3a may be referred to as a first well pattern, a second well pattern, a third
well pattern, a fourth
well pattern, a fifth well pattern, a sixth well pattern and a seventh well
pattern. During primary
production, the six injection wells 104 surrounding the center production well
106 of each seven-
spot well pattern receive injection media while the center production well 106
receives and
produces primary sweep volume. Injection media ceases being injected into each
injection well
104 within each seven-spot well pattern before the injection media is produced
by the production
well 106 within each seven-spot well pattern. Primary sweep volume 130 ceases
being produced
from the subsurface formation 124 before the injection media is produced.
[0120] Figure 3b shows use of a slurrifed hydrocarbon recovery process
during secondary
production. As shown in Figure 3b, the production well 106 of each seven-spot
well pattern is
shut-in 204. The production well 106 of each seven-spot well pattern is shut-
in 204 after ceasing
injecting the injection media and ceasing producing primary sweep volume 130.
As shown in
Figure 2b, every other injection well 104 in each seven-spot well pattern is
recompleted as a
recompleted production well 107. Every other injection well 104 in each seven-
spot well pattern
is recompleted as a recompleted production well 107 after ceasing injecting
the injection media
and ceasing producing the primary sweep volume 130. As a result, each seven-
spot well pattern
contains three injection wells 104 and three recompleted production wells 107
after ceasing
-31 -
CA 02912275 2015-11-18
injecting the injection media and ceasing producing the primary sweep volume
130. During
secondary production, therefore, reinjection media is injected into the
subsurface formation via
the injection wells 104 in each seven-spot well pattern and secondary sweep
volume 131 is
produced from the three recompleted production wells 107 in each seven-spot
well pattern. The
reinjection media may be injected into the subsurface formation via the
injection wells 104 until
the reinjection media is produced from one or more of the three recompleted
production wells
107. The secondary sweep volume 131 of each of the seven-spot well patterns is
shown to be
along the edge of each of the seven-spot well patterns.
[0121] Figure 4a shows use of a slurrified hydrocarbon recovery process
during primary
production. As shown in Figure 4a, each inverted five-spot well pattern
includes a center
injection well 104 surrounded by four production wells 106. Figure 4a shows
four inverted five-
spot well patterns but there may be any number of well patterns within a
slurrified reservoir
hydrocarbon recovery process having multiple inverted five-spot well patterns.
The four
inverted seven-spot well patterns in Figure 4a may be referred to as a first
well pattern, a second
well pattern, a third well pattern and a fourth well pattern. During primary
production, the center
injection well 104 within each inverted five-spot well pattern receives
injection media while each
production well 106 within each inverted five-spot well pattern receives and
produces primary
sweep volume. Injection media ceases being injected into the injection well
104 within each
inverted five-spot well pattern before the injection media is produced by the
production wells
106 within each inverted five-spot well pattern. Primary sweep volume 130
ceases being
produced from the subsurface formation 124 before the injection media is
produced.
[0122] Figure 4b shows use of a slurrified hydrocarbon recovery process
during secondary
production. As shown in Figure 4b, the production well 106 of each inverted
five-spot well
pattern is shut-in 204. The production well 106 of each inverted five-spot
well pattern is shut-in
204 after ceasing injecting the injection media and ceasing producing primary
sweep volume
130. As shown in Figure 4b, every other injection well 104 in each inverted
five-spot well
pattern is recompleted as a recompleted production well 107. Every other
injection well 104 in
each inverted five-spot well pattern is recompleted as a recompleted
production well 107 after
ceasing injecting the injection media and ceasing producing the primary sweep
volume 130. As
a result, each inverted five-spot well pattern contains four shut-in wells 204
and every other
inverted five-spot well pattern contains an injection well 104 or a
recompleted production well
- 32 -
CA 02912275 2015-11-18
107. During secondary production, therefore, reinjection media is injected
into the subsurface
formation via the injection well 104 in every other inverted five-spot well
pattern and secondary
sweep volume 131 is produced from the recompleted production well 107 in every
other inverted
five-spot well pattern. The reinjection media may be injected into the
subsurface formation via
the every other injection well 104 until the reinjection media is produced
from the every other
recompleted production well 107.
[0123] The configuration shown in Figures 2a-2b may be preferred to that
shown in Figures
3a-3b because more primary sweep volume may be produced in the configuration
shown in
Figures 2a-2b than in that shown in Figures 3a-3b. In general, inverted well
patterns (e.g.,
inverted five-spot well pattern, inverted seven-spot well pattern) may be
preferred to well
patterns that are not inverted (e.g., five-spot well pattern, seven-spot well
pattern) when the
injection well of each inverted well-pattern is shut-in and every other
production well 106 of
each inverted well-pattern is recompleted as a production well during
secondary production
because more primary sweep volume 130 may be produced than when this is not
the case, such
as shown in Figures 3a-4b. The configuration shown in Figures 2a-2b may be
preferred to that
shown in Figures 4a-4b because more secondary sweep volume may be produced in
an inverted
well-pattern where the injection well of each inverted well-pattern is shut-in
and every other
production well 106 of each inverted well-pattern is recompleted as a
production well during
secondary production, such as shown in Figures 2a-2b, than in an inverted well-
pattern where all
production wells 106 are shut-in and every other injection well 104 is
recompleted as a
recompleted production well 107 during secondary production, such as shown in
Figures 4a-4b.
[0124] As illustrated in the examples depicted in Figures 2a-4b, one of
recompleting one or
more of the at least one production well 106 as a recompleted injection well
105 and
recompleting one or more of the at least one injection well 104 as a
recompleted production well
107 may comprise recompleting one or more of the at least one production well
106 in at least
one of a first well pattern and a second well pattern as the recompleted
injection well 105 or
recompleting one or more of the at least one injection well 104 in at least
one of a first well
pattern and a second well pattern as the recompleted production well 107. As
illustrated in the
examples depicted in Figures 2a-4b, the first well pattern, the second well
pattern, etc. may be
any of a number of well patterns. For example, the first well pattern and the
second well pattern
may comprise one of a line-drive well pattern, a four-spot well pattern, an
inverted four-spot well
- 33 -
CA 02912275 2015-11-18
pattern, a five-spot well pattern, an inverted five-spot well pattern, a seven-
spot pattern, an
inverted seven-spot pattern, a nine-spot pattern and an inverted nine-spot
pattern.
[0125] As illustrated in the examples depicted in Figures 2a-4b, shutting
in one or more of
the at least one injection well 104 and the at least one production well 106
may comprise
shutting in one or more of the at least one injection well 104 or one or more
of the at least one
production well 106. For example, as shown in Figure 2b, shutting in one or
more of the at least
one injection well 104 and the at least one production well 106 comprises
shutting in the
injection well 104 in each well pattern; as shown in Figure 3b, shutting in
one or more of the at
least one injection well 104 and the at least one production well 106
comprises shutting in the
production well 106 in each well pattern; as shown in Figure 4b, in one or
more of the at least
one injection well 104 and the at least one production well 106 comprises
shutting in the
production wells in each well pattern. Shutting in one or more of the at least
one injection well
104 and the at least one production well 106 may comprise shutting in the
injection wells in each
pattern (not shown).
[0126] If shutting in one or more of the at least one injection well 104
and the at least one
production well 106 comprises shutting in the injection well 104 in each
pattern than
recompleting the one or more of the at least one injection well 104 and the at
least one
production well 106 may comprise recompleting every other production well 106
in a pattern as
a recompleted injection well 105 (Figures 2a-2b). If shutting in one or more
of the at least one
injection well 104 and the at least one production well 106 comprises shutting
in the injection
wells 104 in each pattern than recompleting the one or more of the at least
one injection well 104
and the at least one production well 106 may comprise recompleting every other
production well
106 as a recompleted injection well 107 where the production wells 106 and
recompleted
injection wells 107 are in a plurality of well patterns (not shown). If
shutting in one or more of
the at least one injection well 104 and the at least one production well 106
comprises shutting in
the production well 106 in each pattern than recompleting the one or more of
the at least one
injection well 104 and the at least one production well 106 may comprise
recompleting every
other injection well 104 in a pattern as a recompleted production well 107
(Figures 3a-3b). If
shutting in one or more of the at least one injection well 104 and the at
least one production well
106 comprises shutting in the production wells 106 in each pattern than
recompleting the one or
more of the at least one injection well 104 and the at least one production
well 106 may comprise
- 34 -
CA 02912275 2015-11-18
recompleting every other injection well 104 as a recompleted production well
105 where the
injection wells 104 and the recompleted production wells 107 are in a
plurality of well patterns
(Figures 4a-4b).
[0127] 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 or
depth. The second elevation 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.
[0128] While the above steps discuss only primary production and secondary
production,
additional productions may be performed. For example, tertiary production may
be performed.
While the above steps discuss only one cycle of primary production and/or
secondary production
within primary production and secondary production, each production may
include more than
one cycle of primary production and/or secondary production. One of the cycles
or tertiary
production may include, but is not limited to, shutting in at least one
production well used during
primary production, converting the shut-in well during secondary production to
an injection well
and producing from the at least one production well and/or recompleted
production well.
[0129] It is important to note that the steps depicted in Figure 5 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.
[0130] 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
- 35 -
CA 02912275 2015-11-18
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.
[0131] 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
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.
[0132] 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.
[0133] 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
- 36 -
CA 02912275 2015-11-18
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.
[0134] 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
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.
[0135] 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
-37-
CA 02912275 2015-11-18
media would extrapolate waterflooding to the flow of porous and/or permeable
media as
described for the above system and method.
[0136] 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.
[0137] 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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