Note: Descriptions are shown in the official language in which they were submitted.
CA 02830614 2013-10-22
METHODS FOR RECOVERY OF VISCOUS OIL FROM RESERVOIRS WITH
PERMEABLE UPPER BOUNDARIES
FIELD OF THE INVENTION
[0001] Embodiments of the invention relate to methods for recovering
viscous oil, such as
bitumen, from a subsurface reservoir, such as an oil sand reservoir found in
Alberta, Canada.
More particularly, embodiments of the invention relate to methods for
recovering viscous oil
from subsurface reservoirs that have a permeable upper boundary.
BACKGROUND
[0002] This section is intended to introduce various aspects of the art,
which may be
associated with exemplary embodiments of 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.
[0003] Bitumen is any heavy oil with a viscosity more than 10,000 cP at
native in situ
conditions found in porous subsurface geologic formations. Bitumen is often
entrained in
sand, clay, or other porous solids and is resistant to flow at subsurface
temperatures and
pressures. There are hundreds of billions of barrels of these very heavy oils
in the reachable
subsurface in the province of Alberta alone and additional hundreds of
billions of barrels in
other heavy oil areas around the world. Efficiently and effectively recovering
these resources
for use in the energy market is one of the world's toughest energy challenges.
[0004] Current recovery methods inject heat (typically steam) or viscosity
reducing
solvents to reduce the viscosity of the bitumen and allow it to flow through
the subsurface
formations and to the surface through boreholes or wellbores. These methods
are referred to
as in situ recovery methods, a few such methods include steam assisted gravity
drainage
(SAGD) and cyclic steam stimulation (CSS). Another recovery method involves
removing
the overburden overlying the oil sand formation and strip mining the
underlying oil sand
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formation. Mining is usually economic, depending upon the quality of the
underlying oil sand
formation and its depth and volume, at overburden depths up to approximately
80 meters.
[0005] The in situ methods rely on an impermeable topseal above the oil
sand formation,
often a continuous shale layer, to contain the injected steam and/or solvent
within the
underlying oil sand formation. Without the impermeable topseal, applying
conventional in
situ methods which utilize steam or solvent injection tends to be unacceptably
inefficient and
expensive due to losses to the overburden. However, large amounts of viscous
oil, such as
bitumen, are known to occur, primarily in Canada, at depths below economic
mining depths,
i.e., the overburden is greater than approximately 80 m, in reservoirs with
semi-permeable or
no top seals (e.g., without a continuous shale layer). See, for example: L.L.
Schramm et al.,
"Saskatchewan's Place in the Canadian Oil Sands", Paper 2009-116, Canadian
International
Petroleum Conference, 2009. In general, such resources are not commercially
viable due to a
lack of a practical, efficient method for recovery.
[0006] If a method was available for producing viscous oil (e.g., >1000 cp
or >10000 cp
at original in situ conditions) from reservoirs with poor or no topseals, the
method may also
be applicable to bitumen at mineable depths. Although bitumen mining is a well-
established
industry, it disturbs the local environment due to surface removal and the
formation of tailing
ponds. Although reclamation of the environment is performed, temporary
environmental
impacts may be unacceptable to the public under certain conditions.
Additionally, bitumen
mining generally requires huge upfront capital expenditures for massive
facilities and
equipment. If oil could be extracted using an in situ technique suited for
shallow, poorly
sealed bitumen zones, the environmental and capital expenditure issues may be
greatly
reduced.
[0007] Hence, an in situ viscous oil recovery method is desired which is
suitable for
reservoirs with permeable upper boundaries. In particular, a variation on SAGD
is desired
which is suitable and economic for reservoirs with permeable upper boundaries.
Conventional SAGD is a proven, effective method for recovering high viscosity
oil.
However, as currently practiced SAGD is operated so that much of the oil
produced occurs
during the so-called "spreading phase" where injected steam spreads laterally
along an
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impermeable upper boundary after it rises up to the boundary. This allows well
spacings of
greater than 100 m between SAGD horizontal wells. If the upper boundary of a
reservoir is
permeable, however, a spreading phase may not be possible or may be much
reduced in
extent. Moreover, conventional SAGD requires separate injector and producer
wells to be
drilled, which adds to the capital cost. If an equally effective method could
be devised which
used only a single wellbore, the economics could be significantly improved and
closer well
spacing could be economic. Closer well spacing might be desirable if there is
no, or only a
weak, spreading phase of the injected steam.
SUMMARY OF THE INVENTION
[0008] In one embodiment of the present disclosure, a method for producing
a viscous oil
such as bitumen from a subsurface reservoir with a permeable upper boundary
include
injecting a heated vapor into the subsurface reservoir at a pressure below a
fracture pressure to
reduce the viscosity of the oil and form a vapor chamber within the subsurface
reservoir. The
vapor injection into the vapor chamber is stopped when the top of the vapor
chamber is
proximate to the permeable upper boundary. The vapor may include steam or
steam plus a
hydrocarbon which is soluble in the bitumen. The method may further include
evaluating the
position of the top of the vapor chamber, wherein evaluating the position of
the top of the
vapor chamber comprises monitoring subsurface temperatures using temperature
sensors
placed subsurface.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] The foregoing and other advantages of the present invention may
become apparent
upon reviewing the following detailed description and drawings of non-limiting
examples of
embodiments in which:
[0010] FIG. 1 is an illustration of a conventional steam assisted gravity
drainage (SAGD)
bitumen production method;
[0011] FIG. 2 is an illustration of one exemplary embodiment of a viscous
oil production
system according to the present disclosure;
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[0012] FIGS. 3A and 3b are illustrations of another exemplary embodiment of
a viscous
oil production system according to the present disclosure;
[0013] FIG. 4 is an illustration of an exemplary embodiment of a viscous
oil production
system with the injection of a noncondensable gas according to the present
disclosure;
[0014] FIG. 5 is an illustration of an exemplary embodiment of a viscous
oil production
system utilizing interacting vapor chambers;
[0015] FIG. 6 is an illustration of one exemplary embodiment of a viscous
oil production
system with a cooling system;
[0016] FIG. 7 is an illustration of one exemplary embodiment of a flow
barrier for a
viscous oil production system according to the present disclosure;
[0017] FIG. 8 is an illustration of another exemplary embodiment of a flow
barrier for a
viscous oil production system according to the present disclosure.
DETAILED DESCRIPTION OF THE INVENTION
[0018] In the following detailed description section, the specific
embodiments of the
present disclosure are described in connection with preferred embodiments.
However, to the
extent that the following description is specific to a particular embodiment
or a particular use
of the present disclosure, this is intended to be for exemplary purposes only
and simply
provides a description of the exemplary embodiments. Accordingly, the
disclosure is not
limited to the specific embodiments described below, but rather, it includes
all alternatives,
modifications, and equivalents falling within the scope of the appended
claims.
DEFINITIONS
[0019] Various terms as used herein are defined below. To the extent a term
used in a
claim 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.
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[0020] The terms "a" and "an," as used herein, mean one or more when
applied to any
feature in embodiments of the present inventions described in the
specification and claims.
The use of "a" and "an" does not limit the meaning to a single feature unless
such a limit is
specifically stated.
[0021] The term "about" is intended to allow some leeway in mathematical
exactness to
account for tolerances that are acceptable in the trade. Accordingly, any
deviations upward or
downward from the value modified by the term "about" in the range of 1% to 10%
or less
should be considered to be explicitly within the scope of the stated value.
[0022] In the claims, as well as in the specification above, all
transitional phrases such as
"comprising," "including," "carrying," "having," "containing," "involving,"
"holding,"
"composed of," and the like are to be understood to be open-ended, i.e., to
mean including but
not limited to. Only the transitional phrases "consisting of' and "consisting
essentially of'
shall be closed or semi-closed transitional phrases, respectively, as set
forth in the United
States Patent Office Manual of Patent Examining Procedures, Section 2111.03.
[0023] The term "exemplary" is used exclusively herein to mean "serving as
an example,
instance, or illustration." Any embodiment described herein as "exemplary" is
not necessarily
to be construed as preferred or advantageous over other embodiments.
[0024] The term "formation" refers to a body of rock or other subsurface
solids that is
sufficiently distinctive and continuous that it can be mapped. A "formation"
can be a body of
rock of predominantly one type or a combination of types. A formation can
contain one or
more hydrocarbon-bearing zones. Note that the terms "formation," "reservoir,"
and "interval"
may be used interchangeably, but will generally be used to denote
progressively smaller
subsurface regions, zones or volumes. More specifically, a "formation" will
generally be the
largest subsurface region, a "reservoir" will generally be a region within the
"formation" and
will generally be a hydrocarbon-bearing zone (a formation, reservoir, or
interval having oil,
gas, heavy oil, and any combination thereof), and an "interval" will generally
refer to a sub-
region or portion of a "reservoir."
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[0025] The term "heavy oil" refers to hydrocarbons having an API gravity less
than about
22 , such as bitumen.
[0026] The term "hydrocarbon-bearing zone," as used herein, means a portion
of a
formation that contains hydrocarbons. One hydrocarbon zone can be separated
from another
hydrocarbon-bearing zone by zones of lower permeability such as mudstones,
shales, or
shaley (highly compacted) sands. In one or more embodiments, a hydrocarbon-
bearing zone
includes heavy oil in addition to sand, clay, or other porous solids.
[0027] The term "overburden" refers to the sediments or earth materials
overlying the
formation containing one or more hydrocarbon-bearing zones. The term
"overburden stress"
refers to the load per unit area or stress overlying an area or point of
interest in the subsurface
from the weight of the overlying sediments and fluids. In one or more
embodiments, the
"overburden stress" is the load per unit area or stress overlying the
hydrocarbon-bearing zone
that is being conditioned and/or produced according to the embodiments
described.
[0028] The terms "preferred" and "preferably" refer to embodiments of the
inventions that
afford certain benefits under certain circumstances. However, other
embodiments may also
be preferred, under the same or other circumstances. Furthermore, the
recitation of one or
more preferred embodiments does not imply that other embodiments are not
useful, and is not
intended to exclude other embodiments from the scope of the inventions.
[0029] The terms "substantial" or "substantially," as used herein, mean a
relative amount
of a material or characteristic that is sufficient to provide the intended
effect. The exact
degree of deviation allowable may in some cases depend on the specific
context.
[0030] The definite article "the" preceding singular or plural nouns or
noun phrases
denotes a particular specified feature or particular specified features and
may have a singular
or plural connotation depending upon the context in which it is used.
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DESCRIPTION OF EMBODIMENTS
[0031] Typical impermeable upper boundaries for oil sand formations, those
that form
high quality topseals, are continuous shale layers, which may be tens of
centimeters thick to
many meters thick. As mentioned in the Background section, there are many oil
sand
formations that do not have a high quality topseal, but rather have permeable
upper
boundaries. Examples of permeable upper boundaries may include, fractured
shales, faulted
shales, unfractured shales with limited lateral continuity, shales penetrated
by injection sands,
glacial till, low permeability sands, sandstones, silts, siltstones, or
mudstones (which may or
may not contain viscous oil). Low permeability sands may reflect a presence of
a wide
distribution of grain sizes or of significant clay content.
[0032] In SAGD, leakage of heated vapor into a permeable upper boundary
significantly
reduces efficiency of the process since the overburden becomes heated but does
not produce
oil or is only poorly productive. As illustrated in Fig. 1, SAGD 100 is
operated so that much
of the oil which is produced occurs during a so-called "spreading phase" where
injected steam
102 forms vapor chambers 107 that spread laterally through the oil sand
formation 103 along
an impermeable upper boundary 104 after the vapor chambers rise up to the
boundary. The
impermeable upper boundary 104 is positioned below additional overburden 108.
Because of
the impermeable upper boundary 104, the vapor chambers 107 are confined
vertically and
then spread laterally through the oil sand formation 103. This typically
allows well spacings
of greater than 100 m between SAGD horizontal well pairs 106. However if the
upper
boundary of a reservoir is permeable, a spreading phase may not be possible or
may be much
reduced in extent. In the modified SAGD embodiments disclosed herein, vapor
injection is
not, or is not significantly, continued into the so-called "spreading phase."
[0033] To effectively recover viscous oil, especially bitumen, from
reservoirs with
permeable upper boundaries it is proposed that a modified version of steam
assisted gravity
drainage (SAGD) be applied. Referring to Fig. 2, as mobilized oil is produced
through
producer well 202 in well pair 204, a vapor chamber 206 is formed within the
reservoir 208 in
the region drained of oil. In some embodiments, heated vapor injection 209
from injection
well 212 is permanently halted, and optionally the vapor chamber is then blown
down, when
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the vapor chamber is proximate to the top of the reservoir zone 208. This
halting may occur
somewhat prior to the vapor chamber reaching the upper permeable boundary 210,
soon
afterwards, or even after the vapor chamber has partially penetrated the upper
permeable
boundary 210. However, it is preferred that the vapor chamber not
substantially extend into
the upper permeable boundary (e.g., <10% to <25% of the distance from the
injection depth to
the bottom of the upper permeable boundary). The permeable upper boundary 210
is
positioned below additional overburden 212.
[0034] In one embodiment of the invention, horizontal wells are used to
inject a heated
vapor into a reservoir zone with a permeable upper boundary. The heated vapor
is preferably
steam but may also be a steam/hydrocarbon solvent mixture or vaporized
hydrocarbon
solvent. Injection of heated vapor is performed through a flowpath in a
horizontal well. In
some embodiments, the injection is distributed over the horizontal section of
a horizontal
well.
[0035] The injected heated vapor mobilizes the viscous oil in the reservoir
allowing it to
gravity drain to a production flowpath in a horizontal well. In some
embodiments, the
production is distributed over the horizontal section of the horizontal well.
In some
embodiments, as shown in Fig. 2, the injection and production flowpaths are in
separate
horizontal wells which are vertically separated from each other in the
reservoir, as is the case
in conventional SAGD. However in some embodiments, as illustrated in Figs. 3A
and B,
injection and production flowpath pairs are contained in common wellbores 302.
In such
embodiments, the flowpaths may comprise separate, adjacent injection 304 and
production
flowlines 306 as shown in Fig. 3A, or a single flowline 308 which is
alternately used for
injection and then production, as shown in Fig. 3B. In the case where the
injection and
production flowlines are within a common wellbore, the injection and
production may be
performed alternately in cycles. In some embodiments, temperature sensors 310
at the surface
312 and/or in shallow wells 314 may be used to directly or indirectly detect
vapor chamber
316 position. In other embodiments, the steam chamber location may be
estimated using
pressure sensing in the permeable overburden, seismic methods, or monitoring
for
biodegradation chemical species in production fluids indicative of fluids
being produced near
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a top-water contact. In still other embodiments, the top of the chamber
position may be
estimated based on reservoir production modeling, metering of oil production,
metering of
fluid injection, or metering of fluid production.
[0036] Referring to Fig. 4, in some embodiments, a noncondensable gas 402,
such as nitrogen
or natural gas, may be added to injected steam 403, particularly when the
vapor chamber
approaches or just reaches the upper boundary. The noncondensable gas will
concentrate near
the top of the vapor chamber 416 as the steam condenses and drains downward.
The
noncondensable will form a buffer zone 404 of noncondensable gas 402 which
will help
divert steam 403 and heat from the permeable upper boundary 406 and promote
lateral growth
of the vapor chamber 416.
[0037] Blowing down (i.e., producing vapors from) a chamber may be done to aid
final
recovery of oil by providing a strong, but temporary, pressure drive.
Furthermore, blowing
down a chamber can improve the halting of the vapor chamber growth by removing
remaining steam and its associated latent heat or by removing injected
solvents. In some
embodiments, the chamber may be purged with nitrogen, natural gas, or carbon
dioxide to
remove hot steam and vapors.
[0038] Referring to Fig. 5, wells 502 may be laterally spaced so that groups
of vapor
chambers 504, for example consisting of 3 to 8 chambers, interact or coalesce
prior to the
vapor chambers reaching the upper boundary 506. However, interacting groups
are isolated
from other interacting groups so that pressure blowdowns can be performed
locally and as
needed. By "isolated", it is meant that a gap 508, for example 20-100 m, of
undrained viscous
oil exists between adjacent vapor chamber groups so that pressures in adjacent
vapor chamber
groups are essentially independent.
[0039] In some embodiments, pressure within a vapor chamber or group of vapor
chambers is
controlled so that the pressure at the chamber top is near to or below
hydrostatic pressure. By
controlling pressure in this way the chance of vapor leakage into or beyond
the upper
permeable boundary is minimized. In some embodiments, the pressure is
controlled so that
the pressure at the top of the vapor chamber is kept within 25% of the
hydrostatic pressure at
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the top of the vapor chamber. Steam-only may be used for injection (i.e., no
solvent addition)
in order to minimize environmental impact due to any unexpected leakage to the
near-surface
or atmosphere.
[0040] In some embodiments, as previously mentioned, the invention utilizes a
single-well,
cyclic injection-production, gravity drainage concept. In some embodiments,
the injector and
producer line may be the same line. In another embodiment, separate injector
and producer
lines are used. The lines may or may not be of equal diameter. Moreover, in an
embodiment,
the wellbore has a long, substantially horizontal section where the injection
into and
production from the reservoir is performed. "Substantially horizontal" may be
understood to
mean within 100 of true horizontal. The injector well may have limited-entry
perforations
along its length to allow steam to be relatively evenly injected along its
length, which may be
several hundred meters. Likewise, the production line may have limited-entry
perforations to
allow suction of fluids relatively evenly along its length. The wellbore
itself may, in some
embodiments, be lined with a screen. Limited-entry perforations, known to one
of ordinary
skill in the art, are holes through the walls of tubing which permit inflow or
outflow but keep
flow rates relatively constant despite pressure variations along the length of
the tubing.
Various limited entry perforations are known in the art and practiced in the
field. Some
utilize the principle of critical flow through an orifice so that the rate of
flow is relatively
insensitive to pressure difference across a perforation if the pressure
difference is greater than
a certain amount.
[0041] For the single-well embodiment, the injection and production may be
performed
cyclically; that is, inject heated vapor then stop injection and, optionally
after a soak period,
produce oil and condensed injectant then repeat. A soak period may occur
between the
injection and production periods. Several control schemes may be applied. For
example, for
each cycle, the amount of vapor injected may be controlled to be a
predetermined volume,
such as, for example, 10-25% of the total produced oil, i.e., voided space,
where the vapor
volume is calculated on a condensed liquid basis. Injection may be done at
constant pressure,
such as, for example, approximately 60-90% of lithostatic pressure, and then
production of
liquids performed until a vapor production rate becomes unacceptably high or a
liquids
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production rate becomes unacceptably low. Alternatively the control scheme may
be that the
end of an injection, production, or soak period occurs when an estimated or
measured
pressure or temperature which is representative of the formation reaches a
predetermined
value.
[0042] It is preferred that pressure be kept below a fracturing pressure and
even a dilation
pressure, for example, keep the pressure below approximately 90% of the
fracturing pressure,
except perhaps for start-up. In certain embodiments, cycle times may be
several hours (e.g., 1
to 24) to several days (e.g., 1 to 30). Start-up may be accomplished by
cycling steam between
the injector and producer lines if they are separate lines.
[0043] In some embodiments, a barrier may be placed over the surface to
control vapor and/or
odor leakage. The barrier may be a geotextile, plastic sheeting, or mining
material, such as,
for example, tailings or removed overburden comprising granular or clay
materials. This may
be particularly useful for very shallow reservoirs; for example, bitumen zones
which are
potentially mineable. Indeed, embodiments of the invention may be used in a
region adjacent
to an oil sands mining pit. This may be advantageous if adjacent resources
exist deeper than
is economically feasible for continued expansion of a mining pit. In some
embodiments,
injection and/or production may be performed via wells connected to the floor
or walls of an
oil sands mining pit.
[0044] In some embodiments the method may be applied adjacent to an oil sands
mining
operation with heat, steam, water, or fluid processing shared with the mining
operation to
improve economics. The targeted bitumen may be of lower quality than is
economic for
mining, for example low bitumen saturation or too deep below the overburden.
[0045] Passing a well carrying a hot fluid through a permeable upper boundary
may promote
vapor leakage through the boundary. In particular if the permeable upper
boundary contains
highly viscous oil at ambient temperatures, a heated well passing through the
upper boundary
may sufficiently raise the temperature and reduce the viscosity of the oil
near the well to
allow the oil to drain down. This in turn would increase the effective
permeability of the
drained region near the well since it would no longer be filled with largely
immobile oil.
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Vapor from the underlying vapor chamber may then readily channel along the
outside of the
well up through the permeable upper boundary. This would reduce recovery
efficiency and
may cause unacceptable leakage of injectant into groundwater or the
atmosphere.
[0046] To guard against such issues, in some embodiments a barrier to flow
along the outside
of the well is constructed. Referring to Fig. 6, in an embodiment, a portion
of a well 602
passing through the permeable upper boundary 604 is cooled through the use of
refrigeration
or cooling system 606 and coolant lines 608. The cooling system keeps the
cooled permeable
upper boundary zone 610 from heating up and draining or losing oil and/or
other fluids that
could be mobilized from the heat of the well. In an embodiment, well 602 may
also include
insulation 612 to decrease the amount of heat transmitted to the permeable
upper boundary
604. In an embodiment, the cooling system 606 may include circulating
refrigerated fluid
down a string in the well and back up to the surface. In some embodiments, the
cooling
comprises a thermosyphon where a liquid flows down a first cooling string, at
least partially
boils within the first cooling string, returns up a second cooling string in
at least a partially
vaporized state, and is recondensed at the surface. In some embodiments, the
cooling lines
may be insulated in certain locations to localize the cooling of the permeable
upper boundary
to a desired depth range and to not pick up heat from the injection and/or
production lines.
[0047] Referring to Fig. 7, as an alternative to, or in conjunction with,
cooling of the
permeable upper boundary, a flow barrier 702 may be constructed adjacent to a
wellbore 704
passing through the permeable upper boundary 706 such that injected vapor 708
largely
cannot travel along the exterior of the wellbore and through the permeable
upper boundary.
The flow barrier 702 may comprise a physical impermeable barrier constructed
via a
hydraulic fracture 705 filled with an impermeable substance such as clay or
grout 710. In
some cases, one may be able to position the vertical portions of wells to
penetrate through and
take advantage of local, but non-extensive, shale barriers (not shown) to act
as the flow barrier
rather than constructing artificial ones. Alternatively, referring to Fig. 8,
a flow barrier 802
may comprise a pressure barrier consisting of a local high pressure zone 804
formed by
injection of a fluid 806, such as gas or water through an injection line 808.
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[0048]
While the present disclosure may be susceptible to various modifications and
alternative forms, the exemplary embodiments discussed above have been shown
only by way
of example. However, it should again be understood that the disclosure is not
intended to be
limited to the particular embodiments disclosed herein. Indeed, the present
disclosure
includes all alternatives, modifications, and equivalents falling within the
scope of the
appended claims.
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