Note: Descriptions are shown in the official language in which they were submitted.
CA 2912303 2017-03-02
METHOD FOR ENHANCING THE RECOVERY OF HEAVY OIL
[0001]
BACKGROUND
Fields of Disclosure
[0002] The disclosure relates generally to the field of recovering heavy
oil and, more
particularly, to a method 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
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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 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. Moreover, inefficiencies in reservoir displacement during primary
production
may lead to production of injected sand during primary production, which may
also be
referred to as primary sweep volume injected sand, before the targeted primary
reservoir
sweep during primary production has been achieved. Once the production of the
primary
sweep volume injected sand commences, the proportion of reservoir being
produced
decreases and may negatively impact the recovery of hydrocarbons from a
reservoir. The
proportion of reservoir produced may decrease and the recovery of hydrocarbons
from the
reservoir may be negativelty impacted due to a decreasing proportion of
hydrocarbons
being produced during primary production relative to the produced primary
sweep volume
injected sand.
[0012] A need exists for addressing the aforementioned disadvantages.
SUMMARY
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[0013] The present disclosure provides a method for enhancing the recovery
of heavy
oil.
[0014] A method for enhancing recovery of heavy oil from a reservoir within
a
subsurface formation may comprise performing primary production within the
subsurface
formation and performing secondary production within the subsurface formation
after
performing primary production. Performing primary production may comprise
increasing a
reservoir pore pressure of the reservoir within a well pattern within the
subsurface
formation, wherein the well pattern includes at least one injection well and
at least one
production well, then creating a first differential pressure between one or
more of the at
least one injection well and one or more of the at least one production well,
then producing
primary sweep volume from less than all of the at least one production well;
and injecting
an injection media into the subsurface formation until the injection media is
produced by
the less than all of the at least one production well. Performing secondary
production may
comprise recompleting the less than all of the at least one production well
that produces
primary sweep volume as a recompleted injection 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.
10018] Figure 2a is a diagram of the use of a slurrified reservoir
hydrocarbon recovery
process during primary production.
[0019] Figure 2b is a diagram of the use of a slurrified reservoir
hydrocarbon recovery
process during secondary production.
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[0020] Figure 3a is a diagram of the use of a slurrified reservoir
hydrocarbon recovery
process during primary production.
[0021] Figure 3b is a diagram of the use of a slurrified reservoir
hydrocarbon recovery
process during secondary production.
[0022] Figure 4a is a diagram of the use of a slurrified reservoir
hydrocarbon process
during primary production.
[0023] Figure 4b is a diagram of the use of a slurrified reservoir
hydrocarbon recovery
process during secondary production.
[0024] Figure 5a is a diagram of the use of a slurrified reservoir
hydrocarbon process
during primary production.
[0025] Figure 5b is a diagram of the use of a slurrified reservoir
hydrocarbon recovery
process during secondary production.
[0026] Figure 6 is a diagram showing a method of a slurrified reservoir
hydrocarbon
recovery process.
[0027] 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
[0028] 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
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that are not relevant to the present disclosure may not be shown in the
drawings for the sake
of clarity.
[0029] 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.
[0030] "Bitumen" is a naturally occurring heavy oil material. Generally, it
is the
hydrocarbon component found in oil sands. Bitumen can vary in composition
depending
upon the degree of loss of more volatile components. It can vary from a very
viscous, tar-
like, semi-solid material to solid forms. The hydrocarbon types found in
bitumen can
include aliphatics, aromatics, resins, and asphaltenes. A typical bitumen
might be
composed of:
19 weight (wt.) % aliphatics (which can range from 5 wt. % - 30 wt. %, or
higher);
19 wt. % asphaltenes (which can range from 5 wt. % - 30 wt. %, or higher);
30 wt. % aromatics (which can range from 15 wt. % - 50 wt. %, or higher);
32 wt. % resins (which can range from 15 wt. % - 50 wt. %, or higher); and
some amount of sulfur (which can range in excess of 7 wt. %).
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.
[0031] "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
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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).
[0032] "Conditioning fluid" is fluid injected into a reservoir prior to
primary production
to increase the pore pressure of the reservoir. The conditioning fluid may be
any suitable
fluid. For example, the conditioning fluid may comprise at least one of water,
fines,
caustic, flocculants, coagulants, sodium silicate, polymeric compounds, salts,
solvents,
brine, hydrocarbons, polymers, and hydrocarbons.
[0033] "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.
[0034] "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,
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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.
[0035] 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.
[0036] "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.
[0037] 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.
[0038] 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.
[0039] "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.
[0040] "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
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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.
[0041] "Permeability" is the capacity of a rock to transmit fluids through
the
interconnected pore spaces of the structure. The customary unit of measurement
for
permeability is the milliDarcy (mD). The term "relatively permeable" is
defined, with
respect to formations or portions thereof (for example, 10 or 100 mD). The
term "relatively
low permeability" is defined, with respect to subsurface formations or
portions thereof, as
an average permeability of less than about 10 mD.
[0042] "Pressure" is a force exerted per unit area which is defined as
being equal in all
directions and is typically used here in reference to the pore fluids in the
reservoir or to
describe, in part, the fluid or material in the injection wells and production
wells. Pressure
can be shown as pounds per square inch (psi), kilopascals (kPa), or
megapascals (MPa).
"Atmospheric pressure" refers to the local pressure of the air. "Absolute
pressure" (psia)
refers to the sum of the atmospheric pressure (14.7 psia at standard
conditions) plus the
gauge pressure. "Gauge pressure" (psig) refers to the pressure measured by a
gauge, which
indicates only the pressure exceeding the local atmospheric pressure (i.e., a
gauge pressure
of 0 psig corresponds to an absolute pressure of 14.7 psia). The term "vapor
pressure" has
the usual thermodynamic meaning. For a pure component in an enclosed system at
a given
pressure, the component vapor pressure is essentially equal to the total
pressure in the
system.
[0043] "Pressure gradient" represents the pressure differences divided by
the distance
between the locations where those pressure differences are measured (e.g., the
change in
pore pressure per unit of depth). Depth may refer to length or width. Pressure
gradient is a
measure of driving force moving the sand through the subterranean reservoir or
the
pressure moving slurries through a pipe. The "pressure gradient" may
interchangeably be
referred to as a "pore pressure gradient" or, when the distance over which the
pressure
varies, a "differential pressure."
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[0044] "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.
[0045] "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.
[0046] "Production well" refers to a well or wellbore that produces a
material.
[0047] 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.
[0048] A "recompleted production well" is a well that initially served as
an injection
well but has been completed to serve as a production well. In other words,
such a well is a
well that initially received materials to be injected, such as but not limited
to injection
media, and later produces materials, such as but not limited to primary sweep
volume
and/or secondary sweep volume.
[0049] "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,
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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.
[0050] "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.
[0051] "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.
[0052] 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).
[0053] "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."
[0054] A "Sand breakthrough indicator" refers to a way of detecting
breakthrough. For
example, a sand breakthrough indicator may refer to a way of detecting the end
of primary
production and/or secondary production at a given production well along a
subsurface
formation path that material travels from one or more injection wells to the
given
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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.
[0055] "Secondary production," secondary recovery or secondary sweep is the
second
stage of hydrocarbon recovery. Secondary production occurs after primary
production.
100561 "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
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include some of the volume produced during primary production as this volume
may be
reinjected into the reservoir and produced during secondary production. The
secondary
sweep volume may comprise at least one of heavy oil, sand, silt, clay,
conditioning fluid,
reconditioning fluid, and injection media. The secondary sweep volume may
comprise a
portion of the conditioning fluid. The secondary sweep volume may comprise a
portion of
the reconditioning fluid. The secondary sweep volume may comprise a portion of
the
injection media.
[0057] "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.
[0058] "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.
[0059] 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.
[0060] 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
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injecting into the one or more injection well and producing from the one or
more
production well.
[0061] A "wellbore" is a hole or access path in the subsurface made by
drilling or
inserting a conduit into the subsurface. A wellbore may have a substantially
circular cross
section or any other cross-section shape, such as an oval, a square, a
rectangle, a triangle, or
other regular or irregular shapes. The term "well," when referring to an
opening in the
formation, may be used interchangeably with the term "wellbore." Further,
multiple pipes
may be inserted into a single wellbore, for example, as a liner configured to
allow flow
from an outer chamber to an inner chamber.
[0062] "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.
[0063] 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.
[0064] 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.
[0065] 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.
[0066] 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.
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[0067] 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.
[0068] 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.
[0069] 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.
[0070] 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.
[0071] "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
- 15-
CA 02912303 2015-11-18
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.
[0072] 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.
[0073] Where two or more ranges are used, such as but not limited to 1 to 5
or 2 to 4,
any number between or inclusive of these ranges is implied.
[0074] As depicted in Figures 1-6 and set forth above and below, the
present disclosure
relates to a system 100 and method 1000 for recovering heavy oil, and more
particularly to
a system and method for enhancing the recovery of heavy oil. The system and
method
make it possible to design a reservoir production scheme aimed at increasing
recovery
beyond the 20-70% achievad by producing primary sweep volume. The system and
method may make it possible to avoid a recompaction and/or reconditioning
process before
secondary production. The system and method may make it possible to avoid a
recompaction and/or reconditioning process before secondary production (or
later
productions) because the system and method may not make it necesary to modify
an
effective overburden stress distribution on the reservoir. The system and
method may not
make it necessary to modify an effective overburden stress distribution on the
reservoir
because the system and method may comprise sweeping a subsurface formation
during, for
example but not limited to, primary production in such a manner that the
resultant effective
overburden stress distribution does not lead to inefficient secondary
production (or later
productions) without first having to reapply stress because the stresses in
the subsurface
formation are such that the subsurface formation only follows a path that was
previously
swept.
[00751 The recompaction process may be a process where after injecting an
injection
media and producing a primary sweep volume, a reservoir pore pressure may be
reduced.
Reducing the reservoir pore pressure may allow an overburden stress to be at
least partially
reapplied to a reservoir, thereby recompacting at least a portion of the
reservoir, reducing
theporosity and/or increasing the mechanical stiffness of a portion of the
sand matrix
comprising the reservoir. One or more of at least one injection well and at
least one
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CA 02912303 2015-11-18
production well may allow for recompaction of the reservoir by being wells for
withdrawing fluids from the reservoir in order to lower the reservoir pore
pressure.
[0076] The reconditioning process may be a process where a reconditioning
fluid is
injected into a subsurface formation. The reconditioning process may end once
the stresses
on a reservoir that are caused by the overburden stress are alleviated and/or
substantially
balanced by the reconditioning process. The reconditioning process may entail
increasing a
reservoir pore pressure by injecting a reconditioning fluid into a subsurface
formation. The
reconditioning fluid may be injected via one or more of the at least one
injection well, the at
least one production well, a recompleted production well and a recompleted
injection well.
As the reconditioning fluid is injected, the reservoir pore pressure may
increase to alleviate
and/or substantially balance the stresses on the reservoir that are caused by
an overburden
stress of the overburden on the reservoir. The pressure of the reconditioning
fluid injected
may help make it possible to increase the reservoir pore pressure.
[0077] The system 100 and method 1000 may include at least one injection
well 104
and at least one production well 106 (Figure 1). The at least one injection
well 104 may
just be referred to as an injection well for simplicity. The at least one
production well 106
may just be referred to as a production well for simplicity. The at least one
injection well
104 and the at least one production well 106 may access a reservoir 102 within
a subsurface
formation 124. The at least one injection well 104 and the at least one
production well 106
may extend through an overburden 108 of the subsurface formation 124 to access
the
reservoir 102. The overburden 108 may be above the reservoir 102. The
overburden 108
may be closer to the Earth's surface 112 than the reservoir 102. The reservoir
102 may be
at depths greater than or equal to about 50 meters from the Earth's surface
112. The depths
may include any number within or inclusive of the preceeding range.
[0078] 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
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CA 02912303 2015-11-18
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.
[0079] 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.
[0080] The system 100 and method 1000 may comprise performing primary
production
within the subsurface formation 124, 1001 (Figure 6). The system 100 and
method 1000
may comprise performing secondary production within the subsurface formation
124, after
performing primary production, 1002 (Figure 6). The system 100 and method 1000
may
comprise performing any amounts of production, such as but not limited to
primary
production, secondary production, tertiary production, etc. The system 100 and
method
1000 may comprise performing primary production within the subsurface
formation 124 in
one or more well patterns. The system 100 and method 1000 may comprise
performing
secondary production within the subsurface formation 124 within one or more
well
patterns.
[0081] Performing primary production may comprise increasing a reservoir
pore
pressure of the reservoir within a well pattern within the subsurface
formation 124. The
well pattern may include the at least one injection well 104 and the at least
one production
well 106. The well pattern may comprise one of a four-spot well pattern, an
inverted four-
spot well pattern, a five-spot well pattern 1110 (Figures 2a-2b), an inverted
five-spot well
pattern, a seven-spot well pattern 1111 (Figures 3a-3b), an inverted seven-
spot well pattern
1112 (Figures 4a-4b), a nine-spot well pattern 1113 (Figures 5a-5b) and an
inverted nine-
spot well pattern. Figures 2a-2b show multiple five-spot well patterns where
Figure 2a
depicts primary production and Figure 2b depicts secondary production. Figures
3a-3b
show multiple seven-spot well patterns where Figure 3a depicts primary
production and
Figure 3b depicts secondary production. Figures 4a-4b show multiple inverted
seven-spot
- 18 -
CA 02912303 2015-11-18
well patterns where Figure 4a depicts primary production and Figure 4b depicts
secondary
production. Figures 5a-5b show multiple nine-spot well patterns where Figure
5a depicts
primary production and Figure 5b depicts secondary production. Other well
patterns not
previously mentioned are also possible for the well pattern. Not all well
patterns in a
subsurface formation need to be the same well pattern. For example, one well
pattern could
comprise a four-spot well pattern and another well pattern could comprise a
five-spot well
pattern. Different well patterns may be considered for reasons of surface
facility
constraints, geologic variability of the subsurface 124, or well behavior
issues.
[0082] Performing primary production may comprise increasing the reservoir
pore
pressure of the reservoir within a well pattern by injecting a conditioning
fluid into the at
least one injection well 104. The at least one injection well 104 may be
configured to
receive the conditioning fluid from the surface to be injected into the
reservoir 102. The at
least one injection well 104 may have 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.
100831 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.
[00841 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
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CA 02912303 2015-11-18
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.
[0085] The injection of the conditioning fluid into the at least one
injection well 104
may be referred to as the conditioning process. During the conditioning
process, the
conditioning fluid may be injected into the at least one production well 106.
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. When the conditioning fluid is injected into the at least one
injection well
104 and/or the at least one production well 106, the stresses on the reservoir
102 may be
alleviated and/or substantially balanced more quickly than if the conditioning
fluid is only
injected into the at least one injection well 104.
[0086] 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
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CA 02912303 2015-11-18
the end of the conditioning process is generally small (generally in the range
of 10 to 500
kilopascals (kPa) out of the 1 megapaseal (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).
[0087] Once the conditioning process ends, performing primary production
may
comprise creating a first differential pressure between the at least one
injection well 104
and the at least one production well 106 in a well pattern. Creating the first
differential
pressure may impose a pressure gradient. The creation of the first
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
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.
[0088] 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 from the at least one production well 106. 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 into
the at least one production well 106 may create the first differential
pressure near the at
least one production well 106.
[0089] 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.
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CA 02912303 2015-11-18
[0090] 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, performing primary production may comprose
producing
primary sweep volume 130 from less than all of the at least one production
well 106.
Primary production may comprise producing primary sweep volume 130 from less
than all
of the at least one production well 106 because the system 100 and method 1000
may
comprise producing from less than all of the available area in a well pattern
1110, 1111,
1112, 1113 during primary production. In other words, only a portion of a well
pattern
1110, 1110, 1112, 1113 may be swept and, therefore, produced as the primary
sweep
volume during primary production.
[0091] Producing the primary sweep volume 130 may comprise mobilizing the
primary
sweep volume along a first subsurface formation path within the subsurface
formation 124
within a well pattern. The primary sweep volume 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.
[0092] The primary sweep volume 130 may be produced via less than all of
the at least
one production well 106. The primary sweep volume 130 may be produced via less
than all
of the at least one production well 106 in a well pattern. In other words,
less than all of the
at least one production well 106 in a well pattern may be used to produce
primary sweep
volume 130. The less than all of the at least one production well 106 may be
configured to
produce the primary sweep volume from the subsurface formation 124. The less
than all of
the at least one production well 106 may have 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 travels in
a
direction 114 away from the reservoir 102 and toward the surface 112.
[0093] After being produced via less than all of of the at least one
production well 106,
the primary sweep volume 130 may be fed to a pumping station 116. From the
pumping
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CA 02912303 2015-11-18
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.
[0094] After creating the first differential pressure and to produce the
primary sweep
volume not produced while creating the first differential pressure, performing
primary
production may comprise injecting injecton media into the subsurface formation
124 until
the injection media is produced by the less than all of the at least one
production well 106.
The injection media may be injected into the at least one injection well 104.
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.
[0095] The injection media may be injected while producing the primary
sweep volume
from less than all of the at least one production well 106 and after creating
the first
differential pressure. The injection media may be injected within one or more
well pattern.
As the injection media is injected into the subsurface formation 124 via the
at least one
injection well 104, the primary sweep volume is swept toward less than all of
the at least
one production well 106 via the first subsurface formation path to be produced
from the
less than all of the at least one production well 106. The injection media may
fill the void
that the produced primary sweep volume left in the reservoir 102.
[0096] The injection media may be injected into the subsurface formation
124 via the at
least one injection well 104 until the injection media is produced by the less
than all of the
- 23 -
CA 02912303 2015-11-18
at least one production well 106. Specifically, the injection media may be
injected into the
subsurface formation 124 until breakthrough occurs at the less than all of the
at least one
production well 106. The injection media being produced by the less than all
of the at least
one production well 106 marks the end of primary production when the injection
media
being produced comprises the reinjected sand. The reinjected sand may start to
be
produced from the less than all of the at least one production well 106 when a
portion of the
reinjected sand reaches the less than all of the at least one production well,
when the
reinjected sand is travelling through the less than all of the at least one
production well 106,
when the reinjected sand is exiting the less than all of the at least one
production well 106,
or when the reinjected sand is moving through the surface processing facility
118.
[0097] The actual determination of when to stop injecting injection media
via any of
the one or more injection well 104 into the subsurface formation 124, because
the injection
media is being produced by the one or more of the less than all of the at
least one
production well 106, may be determined by the sand breakthrough indicator.
[0098] While producing the primary sweep volume and/or injecting the
injection
media, the reservoir pore pressure may be reduced. The reservoir pore pressure
may be
reduced in at least one well pattern. This reduction may occur as a mitigation
during a
process upset. One example of a process upset includes, but is not limited to,
when the
injection media includes too much water. When the injection media includes too
much
water, the primary sweep volume may not be able to be mobilized or only a
portion of the
primary sweep volume may be mobilized with a portion of the injection media
bypassing
the primary sweep volume. When the primary sweep volume is not able to be
mobilized or
only a portion of the primary sweep volume is mobilized, the reservoir pore
pressure may
be reduced. 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 through the less than all 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
- 24 -
CA 02912303 2015-11-18
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 by the
less than all of 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.
After reducing the
reservoir pore pressure, injection media may again be injected so that primary
sweep
volume may be produced.
[0099] While producing the primary sweep volume and/or injecting the
injection
media, the reservoir pore pressure may be increased. The reservoir pore
pressure may be
increased in at least one well pattern. This increase may occur as a
mitigation during a
process upset. One example of a process upset includes, but is not limited to,
when the
reservoir pore pressure has not been increased enough to mobilize the primary
sweep
volume when the injection media is injected. The reservoir pore pressure may
not be
increased enough if the conditioning process ends before the effective
stresses on the
reservoir 102, due to the overburden stress, are alleviated and/or
substantially balanced by
the increased reservoir pore pressure. The reservoir pore pressure may be
increased in a
similar manner to how the reservoir pore pressure is increased during the
previously
described conditioning process. Increasing the reservoir pore pressure may be
stopped
when it appears that the effective stresses on the reservoir 102, due to the
overburden stress,
have been alleviated and/or substantially 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 may be produced.
[0100] While producing the primary sweep volume and/or injecting the
injection
media, the reservoir pore pressure may be reduced and then increased. The
reservoir pore
pressure may be reduced and then increased in at least one well pattern. 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 to be
mobilized, so the reservoir pore pressure is increased in a similar manner to
how the
- 25 -
CA 02912303 2015-11-18
reservoir pore pressure is increased during the previously described
conditioning process.
After the reduction and increase stops, injection media may again be injected
so that
primary sweep volume may be produced.
[0101] While producing the primary sweep volume and/or injecting the
injection
media, the reservoir pore pressure may be increased and then reduced. The
reservoir pore
pressure may be increased and then reduced in at least one well pattern. This
increase and
reduction may occur as a mitigation during a process upset. One example of a
process
upset includes, but is not limited to, when the reservoir pore pressure is not
high enough for
the primary sweep volume to be mobilized, so the reservoir pore pressure is
increased in a
similar manner to how the reservoir pore pressure is increased during the
previously
described conditioning process, and then the injection media includes too much
water, so
the reservoir pore pressure is reduced in a manner similar to how previously
described.
After the increase and reduction stops, injection media may again be injected
so that
primary sweep volume may be produced.
[0102] After performing primary production, secondary production may be
performed.
Performing secondary production may comprise recompleting the at least one
production
well 106 that produces primary sweep volume as a recompleted injection well
105.
Performing secondary production may comprise recompleting the at least one
production
well 106 that produces primary sweep volume as a recompleted injection well
105 in a well
pattern. The well pattern may be the same well pattern as previously
described. The
recompleted injection well 105 may comprise one or more recompleted injection
wells 105.
[0103] Recompleting the at least one production well 106 that produces
primary sweep
volume as the recomplefd injection well 105 may be referred to as a
recompletion process.
The recompleted injection well 105 may comprise a production well 106 that was
recompleted to act as an injection well such that the recompleted injection
well 105
receives a fluid or reinjection media to inject into the reservoir. In other
words, the
recompleted injection well 105 may have previously acted as a production well
106. The
recompleted injection well 105 may have previously acted as a production well
106 during
primary production. The recompleted injection well 105 may comprise one or
more
- 26 -
CA 02912303 2015-11-18
recompleted injection wells 105. The recompleted injection well 105 may
comprise any
amount of wells bounded by and including the aforementioned range.
101041
Performing secondary production may comprise turning on at least one
production well in each well pattern that was not used during primary
production. Each of
the at least one production well in each well pattern that was not used during
primary
production may be referred to as a secondary production well 206 (Figures 2b,
3b, 4b and
5b). Each well pattern may comprise at least one secondary production well
206. By using
the at least one secondary production well 206 after primary production, the
effective stress
state in the reservoir as applied by the overburden is such that the total
recovery from
primary production and secondary production is greater than primary production
alone if
the at least one secondary production well 206 had been one of at least one
primary
injection well 104. If the at least one secondary production well 206 had
instead been one
of at least one primary injection well 104 during primary production and then
been
recompleted as at least one secondary production well 206 for secondary
production, a
recompaction and recompletion step would be required between primary and
secondary
production. By using the at least one secondary production well 206 after
primary
production, the effective stress state in the reservoir as applied by the
overburden is such
that the total recovery from primary production and secondary production is
greater than
primary production and secondary production if the at least one secondary
production well
206 had produced primary sweep volume during primary production. If the at
least one
secondary production well 206 had produced primary sweep volume during primary
production and, therefore, been one of at least one primary production well
106, then there
may be a portion or portions of the reservoir between adjacent production
wells that are
more inefficiently swept than by using the at least one secondary production
well 206 after
primary production. By using the at least one secondary production well 206
after primary
production, sweep efficiency can be improved to greater than or equal to 70%;
without
producing sweep volume in this way no more than 70% of a reservoir could be
produced.
The at least one secondary production well 206 may be put back in use before,
while or
after recompleting the at least one production well 106 used during primary
production as a
recompleted injection well 105.
- 27 -
CA 02912303 2015-11-18
[0105] After recompleting the at least one production well 106 that
produces primary
sweep volume as the recompleted injection well 105 and turning on the at least
one
secondary production well 206, a second differential pressure may be created
between one
or more of (i) the at least one secondary production well 206 and at least one
of the
recompleted injection well 105 and (ii) the at least one secondary production
well 206 and
the at least one injection well 104. Creating the second differential pressure
may impose a
pressure gradient. The creation of the second differential pressure may cause
water or brine
to flow into the subsurface formation 124. The water or brine may create fluid
drag forces
on solids in the subsurface formation 124. Once the second differential
pressure in a given
portion of the subsurface formation 124 near the at least one secondary
production well 206
increases to a point where it overcomes the friction holding the reservoir 102
in place, some
of a secondary sweep volume 131 may move toward the secondary production well
206. In
other words, the second differential pressure may move or flow the subsurface
formation
124 toward the secondary production well 206.
[0106] The second differential pressure may be created by injecting
reinjection media
into one or more of the at least one recompleted injection well 105 and the at
least one
injection well 104 and by starting to produce secondary sweep volume from the
at least one
secondary production well 206. The flow of the reinjection media, fluid within
the
subterranean formation, a portion of the primary sweep volume, and/or a
portion of the
secondary sweep volume, into the at least one secondary production well 206
may create
the second differential pressure near the at least one secondary production
well 206.
[0107] The second differential pressure may be created by increasing a rate
or pressure
at one or more of the at least one of the recompleted injection well 105 and
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 reconditioning process.
[0108] Once the second differential pressure is large enough to overcome
the friction
holding the portion of the reservoir 102 near the at least one secondary
production well 206,
secondary sweep volume may be produced via the at least one secondary
production well
206. The secondary sweep volume produced may be the rest of the secondary
sweep
volume that was not produced while creating the second differential pressure.
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[0109] Producing the secondary sweep volume may comprise mobilizing the
secondary
sweep volume along a second subsurface formation path within the subsurface
formation
124. 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 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 undergoes the recompleting processes
after the
primary sweep volume 130 is produced and because the at least one secondary
production
well 206 are used during secondary production. The recompletion process and
the use of
the at least one secondary production well 206 help provide an alternative
path for
reinjection media to enter the subsurface formation 124 and for secondary
sweep volume to
be produced from the subsurface formation 124 so that a new portion of the
reservoir 102
can be swept and produced.
[0110] During production, the secondary sweep volume 131 moves along the
second
subsurface formation path away from the one ore more of the at least one
recompleted
injection well 105 and the at least one injection well 104 to the at least one
secondary
production well 206. The secondary sweep volume 131 may only be a portion of
the
reservoir.
[0111] The secondary sweep volume 131 may be produced via the at least one
secondary production well 206. The at least one secondary production well 206
may be
configured to produce the secondary sweep volume from the subsurface formation
124.
The at least one secondary production well 206 may have a structure that
enables them to
produce the secondary sweep volume. Examples of structure may include, but are
not
limited to, a caseless wellbore or a cased wellbore. The secondary sweep
volume travels in
a direction 114 away from the reservoir 102 and toward the surface 112 such
that a
secondary sweep volume may be swept in a second subsurface formation path.
Similar to
primary production, secondary production may end when breakthrough occurs.
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[0112] After being produced via the at least one secondary production well
206, the
secondary sweep volume 131 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.
[0113] After creating the second differential pressure and producing the
secondary
sweep volume, reinjection media may be injected into one or more of the at
least one
recompleted injection well and the at least one injection well 104. The one or
more of the at
least one recompleted injection well 105 and the at least one injection well
104 may be
configured to receive the reinjection media. The one or more of at least one
recompleted
injection well 105 and the at least one injection well 104 have a structure
that enable them
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 one or
more of at least
one recompleted injection well 105 and the at least one injection well 104
travel in the one
or more of at least one recompleted injection well 105 and the at least one
injection well
104 in a direction. The reinjection media may be fed to the reservoir 102.
[0114] The reinjection media may be injected while producing the secondary
sweep
volume and after creating the second differential pressure. As the reinjection
media is
injected into the subsurface formation 124 via one or more of at least one
recompleted
injection well 105 and the at least one injection well 104, the secondary
sweep volume is
swept toward the at least one secondary production well 206 via the second
subsurface
formation path to be produced from the at least one secondary production well
206. The
reinjection media may fill the void that the produced secondary sweep volume
may leave in
the reservoir 102.
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[0115] The reinjection media may be injected into the subsurface formation
124 via the
one or more of at least one recompleted injection well 105 and the at least
one injection
well 104 until the reinjection media is produced by the at least one secondary
production
well 206. Specifically, the reinjection media may be injected into the
subsurface formation
124 until breakthrough occurs at the at least one secondary production well
206. The
reinjection media being produced by the at least one secondary production well
206 may
mark 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 secondary production well 206 when a portion of the reinjected sand
reaches the
at least one secondary production well 206, when the reinjected sand is
travelling through
the at least one secondary production well 206, when the reinjected sand is
exiting the at
least one secondary production well 206, or when the reinjected sand is moving
through the
surface processing facility 118. Although, continued production of the
reinjection media
may produce a mixture of sand and reinejcted slurry, the sweep efficiceny may
grow while
the reinjection media continues to be produced.
[0116] The actual determination of when to stop injecting reinjection media
via one or
more of at least one recompleted injection well 105 and the at least one
injection well
104into the subsurface formation 124, because the reinjection media is being
produced by
at least one secondary production well 206, may be determined by the sand
breakthrough
indicator.
[0117] While producing the secondary sweep volume and/or injecting the
reinjection
media, the reservoir pore pressure may be reduced. The reservoir pore pressure
may be
reduced in at least one well pattern. 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 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 previously described.
After
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reducing the reservoir pore pressure, reinjection media may again be injected
so that
secondary sweep volume may be produced.
101181 While producing the secondary sweep volume and/or injecting the
reinjection
media, the reservoir pore pressure may be increased. The reservoir pore
pressure may be
increased in at least one well pattern. 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
has not been increased enough to mobilize the secondary sweep volume when the
reinjection media is injected. The reservoir pore pressure may be increased in
a similar
manner to how previously described. Increasing the reservoir pore pressure may
be
stopped when it appears that the effective stresses on the reservoir 102, due
to the
overburden stress, have been alleviated and/or substantially 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.
[0119] While producing the secondary sweep volume and/or injecting the
reinjection
media, the reservoir pore pressure may be reduced and then increased. The
reservoir pore
pressure may be reduced and then increased in at least one well pattern. 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 previously described, 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 previously
described. After
the reduction and increase stops, reinjection media may again be injected so
that secondary
sweep volume may be produced.
101201 While producing the secondary sweep volume and/or injecting the
reinjection
media, the reservoir pore pressure may be increased and then reduced. The
reservoir pore
pressure may be increased and then reduced in at least one well pattern. 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 previously described, and then the reinjection media includes
too much
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water, so the reservoir pore pressure is reduced in a manner similar to how
previously
described. After the increase and reduction stops, reinjection media may again
be injected
so that secondary sweep volume may be produced.
[0121] While the above steps discuss producing a primary sweep volume and a
secondary sweep volume, the method and system may comprise producing a
tertiary sweep
volume. Producing a secondary sweep volume may occur if a second differential
pressure
is created by injecting reinjection media into the at least one recompleted
injection well 105
and the at least one injection well 104 or by starting to produce secondary
sweep volume
from the at least one secondary production well 206. If the second
differential pressure is
created by only doing one of the aforementioned steps, there may be a tertiary
sweep
volume that may be produced within at least one well pattern. The tertiary
sweep volume
may be swept and/or produced in a manner similar to the way in which the
secondary
sweep volume has been described to be swept and/or produced.
[0122] 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.
[0123] Figures 2a-5b show specific examples of some of the above
description. In
general, the above description can be described as a process where, during
primary
production, the center well of a well pattern is in-use and every other well
surrounding the
center well of the well pattern is in use; during secondary production the
wells unused
during primary production are operated as secondary production wells and the
production
wells used during primary production are recompleted to operate as recompleted
injection
wells while any wells operated as injection wells during primary production
continue to
operate as injection wells. Figures 2a, 3a, 4a, and 5a show specific examples
of some of
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the above description during primary production. Figures 2b, 3b, 4b and 5b
show specific
examples of some of the above description during secondary production.
[0124] Figures 2a-2b show a specific example of some of the above
description for
several five-spot well patterns 1110. In particular, Figures 2a-2b show a
specific example
of some of the above description for four, five-spot well patterns 1110.
During primary
production, as shown in Figure 2a, two wells in each well pattern operate as
injection wells
104 while one well in each well pattern operates as a production well 106. The
production
well 106 is in the center of each well pattern. Primary sweep volume 130 is
swept from
each of the operated injection wells to the production well 106. During
secondary
production, as shown in Figure 2b, the same two wells in each well pattern
that operated as
injection wells 104 during primary production operate as injection wells 104,
the well that
operated as a production well 106 in each well pattern 1110 during primary
production is
recompleted and operates as a recompleted injection well 105 and the wells
unused during
primary production in each well pattern 1110 operate as secondary production
wells 206
such that there are two secondary production wells 206 in each well pattern
1110. The
recompleted injection well 105 is in the center of each well pattern.
Secondary sweep
volume 131 is swept from each of the injection wells 104 and the recompleted
injection
well 105 to the secondary production wells 206.
[0125] Figures 3a-3b show a specific example of some of the above
description for
several seven-spot well patterns 1111. In particular, Figures 3a-3b show a
specific example
of some of the above description for seven, seven-spot well patterns 1111.
During primary
production, as shown in Figure 3a, three wells in each well pattern operate as
injection
wells 104 while one well in each well pattern operates as a production well
106. The
production well 106 is in the center of each well pattern. Primary sweep
volume 130 is
swept from each of the operated injection wells 104 to the production well
106. During
secondary production, as shown in Figure 3b, the same three wells in each well
pattern that
operated as injection wells 104 during primary production operate as injection
wells 104,
the well that operated as a production well 106 in each well pattern 1111
during primary
production is recompleted and operates as a recompleted injection well 105 and
the wells
unused during primary production in each well pattern 1111 operate as
secondary
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production wells 206 such that there are three secondary production wells 206
in each well
pattern 1111. The recompleted injection well 105 is in the center of each well
pattern.
Secondary sweep volume 131 is swept from each of the injection wells 104 and
the
recompleted injection well 105 to the secondary production wells 206.
101261 Figures 4a-4b show a specific example of some of the above
description for
several inverted seven-spot well patterns 1112. In particular, Figures 3a-3b
show a specific
example of some of the above description for seven, inverted seven-spot well
patterns
1112. During primary production, as shown in Figure 3a, three wells in each
well pattern
operate as production wells 106 while one well in each well pattern operates
as an injection
well 104. The injection well 104 is in the center of each well pattern.
Primary sweep
volume 130 is swept from each of the operated injection well 104 to the three
production
wells 106. During secondary production, as shown in Figure 4b, the same well
in each well
pattern that operated as an injection well 104 during primary production
operates as an
injection well 104, the wells that operated as production wells 106 in each
well pattern
1112 during primary production are recompleted and operate as recompleted
injection wells
105 and the wells unused during primary production in each well pattern 1112
operate as
secondary production wells 206 such that there are three secondary production
wells 206 in
each well pattern 1112. Secondary sweep volume 131 is swept from each of the
injection
wells 104 and the recompleted injection well 105 to the secondary production
wells 206.
101271 Figures 5a-5b show a specific example of some of the above
description for
several nine-spot well patterns 1113. In particular, Figures 5a-5b show a
specific example
of some of the above description for four nine-spot well patterns 1113. During
primary
production, as shown in Figure 5a, four wells in each well pattern operate as
injection wells
104 while one well in each well pattern operates as a production well 106. The
production
well 106 is in the center of each well pattern. Primary sweep volume 130 is
swept from
each of the operated injection wells 104 to the production well 106. During
secondary
production, as shown in Figure 5b, the same four wells in each well pattern
that operated as
injection wells 104 during primary production operate as injection wells 104,
the well that
operated as a production well 106 in each well pattern 1113 during primary
production is
recompleted and operates as a recompleted injection well 105 and the wells
unused during
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primary production in each well pattern 1113 operate as secondary production
wells 206
such that there are four secondary production wells 206 in each well pattern
1111. The
recompletcd injection well 105 is in the center of each well pattern.
Secondary sweep
volume 131 is swept from each of the injection wells 104 and the recompleted
injection
well 105 to the secondary production wells 206.
[0128] It is important to note that the steps depicted in Figure 6 are
provided for
illustrative purposes only and a particular step may not be required to
perform the inventive
methodology. The claims, and only the claims, define the inventive system and
methodology.
[0129] Disclosed aspects may be used in hydrocarbon management activities.
As used
herein, "hydrocarbon management" or "managing hydrocarbons" includes
hydrocarbon
extraction, hydrocarbon production, hydrocarbon exploration, identifying
potential
hydrocarbon resources, identifying well locations, determining well injection
and/or
extraction rates, identifying reservoir connectivity, acquiring, disposing of
and/ or
abandoning hydrocarbon resources, reviewing prior hydrocarbon management
decisions,
and any other hydrocarbon-related acts or activities. The term "hydrocarbon
management"
is also used for the injection or storage of hydrocarbons or CO2, for example
the
sequestration of CO2, such as reservoir evaluation, development planning, and
reservoir
management. The disclosed methodologies and techniques may be used to extract
hydrocarbons from a subsurface region. Hydrocarbon extraction may be conducted
to
remove hydrocarbons from the subsurface region, which may be accomplished by
drilling a
well using oil drilling equipment. The equipment and techniques used to drill
a well and/or
extract the hydrocarbons are well known by those skilled in the relevant art.
Other
hydrocarbon extraction activities and, more generally, other hydrocarbon
management
activities, may be performed according to known principles.
[0130] 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
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CA 02912303 2015-11-18
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.
[0131] 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.
[0132] The basic physics that govern waterflooding are the flow of fluids
through a
porous and/or permeable media. The physics of flow through porous and/or
permeable
media show that the pressures between injection wells and production wells is
governed by
the rate at which fluids are injected and produced and the mobility of those
fluids through
the porous and/or permeable media. That mobility is controlled by the
permeability of the
media divided by the viscosity of the fluid flowing in the media. Thus for the
single media
(i.e. single permeability), water with it viscosity of 1 (centipoise) cP will
have a higher
mobility than hydrocarbons which generally have a higher to much higher
viscosity than
water (generally 5-500 cP). It is this physics that dictates that when the
injected fluid (most
often water) "breaks through" to a production well during a waterflood, the
production rate
of hydrocarbons drops dramatically due both to the higher mobility of the
water versus the
hydrocarbons and to the drop in pressure differential between injection wells
and
production wells due to the ease for water now to flow between the injection
wells and
production wells. This break through of water may substantially decrease the
effectiveness
of an injection well to aid in the production of hydrocarbons from production
wells in the
area as for the same injection rate, as its injection pressure now is much
lower and thus its
pressure differential even with non-break through production wells is much
less.
[0133] 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.
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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.
[0134] The different physics of fluid flow with porous and/or permeable
media flow
envisioned for the system and method described above relative to waterflooding
makes it
extremely unlikely that one of ordinary skill in the art of flow through
porous and/or
permeable media would extrapolate waterflooding to the flow of porous and/or
permeable
media as described for the above system and method.
[0135] 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.
[0136] 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.
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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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