Note: Descriptions are shown in the official language in which they were submitted.
CA 02779121 2012-06-07
RECOMPACTION OF SAND RESERVOIRS
FIELD
[0001] The present techniques are directed to recompacting sand reservoirs.
More
specifically, the recompaction may be used to mitigate sand override in such
reservoirs.
BACKGROUND
[0002] This section is intended to introduce various aspects of the art, which
may be
associated with exemplary embodiments of the present techniques. This
discussion is
believed to assist in providing a framework to facilitate a better
understanding of
particular aspects of the present techniques. Accordingly, it should be
understood that
this section should be read in this light, and not necessarily as admissions
of prior art.
[0003] Modern society is greatly dependant on the use of hydrocarbons for
fuels and
chemical feedstocks. Hydrocarbons are generally found in subsurface rock
formations
that can be termed "reservoirs." Removing hydrocarbons from the reservoirs
depends on
numerous physical properties of the rock formations, such as the permeability
of the rock
containing the hydrocarbons, the ability of the hydrocarbons to flow through
the rock
formations, and the proportion of hydrocarbons present, among others. Easily
harvested
sources of hydrocarbons are dwindling, leaving less accessible sources to
satisfy future
energy needs. However, as the costs of hydrocarbons increase, these less
accessible
sources become economically attractive.
[0004] Recently, the harvesting of oil sands to remove bitumen has become more
economical. Hydrocarbon removal from the 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 then be collected by other wells and brought to the
surface.
In another technique, strip or surface mining may be performed to access the
oil sands,
which can then be treated with hot water or steam to extract the oil. However,
this
technique produces a substantial amount of waste or tailings that must be
disposed.
[0005] Another process for harvesting oil sands, which may generate less
surface
waste, is the slurrified hydrocarbon extraction process. In the slurrified
hydrocarbon
extraction process, the entire contents of a reservoir, including sand and
hydrocarbon,
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can be extracted from the subsurface via wellbore for processing at the
surface to remove
the hydrocarbons. The tailings are then reinjected via welibores back into the
subsurface
to prevent subsidence of the reservoir and allow the process to sweep the
hydrocarbon
bearing sands from the reservoir to the wellbore producing the slurry.
100061 U.S. Patent No. 5,832,631 to Herbolzheimer, et al., discloses one such
slurrified hydrocarbon recovery process that uses a slurry that is injected
into reservoir.
In this process, hydrocarbons that are trapped in a solid media, such as
bitumen in oil
sands, can be recovered from deep formations. The process is performed by
relieving the
stress of the overburden and causing the formation to flow from an injection
well to a
production well, for example, by fluid injection. A oil sand/water mixture is
recovered
from the production well. The bitumen is separated from the sand and the
remaining sand
is reinjected in a water slurry.
[00071 International Patent Application Publication No. WO/2007/050180, by
Yale
and Herbolzheimer, discloses an improved slurrified heavy oil recovery
process. The
application discloses a method for recovering heavy oil that includes
accessing a
subsurface formation from two or more locations. The formation may include
heavy oil
and one or more solids. The 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 formation between
the one or
more high pressure locations and the one or more low pressure locations to
mobilize at
least a portion of the solids and a portion of the heavy oil in the formation.
The
mobilized solids and heavy oil then flow toward the one or more low pressure
locations
to provide a slurry comprising heavy oil, water and one or more solids. The
slurry
comprising the heavy oil and 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
formation, for example, as backfill.
[00081 The method discussed above converts the hydrocarbon bearing reservoir
into
a formation resembling a moving bed. When the reservoir moves toward the
producer
wells, void space is filled by the reinjected clean slurry stream. The
reinjected stream
must have permeability that is higher than the relative permeability to water
of the target
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formation. Thus, the slurry is not pushed, but rather dragged by the
percolating fluid
flow.
[00091 As mentioned, the formation can be conditioned to relieve the pressure
of the
overburden, for example, by injecting water until the pressure normalizes.
This is
described in U.S. Patent Application Publication No. 2010/0218954 by Yale, et
al.,
entitled "Application of Reservoir Conditioning in Petroleum Reservoirs." The
application provides methods for recovering heavy oil. The process includes
conditioning a reservoir of interest, then initially producing fluids and
particulate solids
such as sand to increase reservoir access. The initial production of a slurry
may generate
high permeability channels or wormholes in the formation, which may be used
for
hydrocarbon production processes such as cold flow (CHOPS) or enhanced
production
processes such as steam assisted gravity drainage (SAGD) or vapor extraction
(VAPEX)
techniques.
[00101 Most processes to recover hydrocarbons from subsurface formations
involve
the reduction in fluid pressure in the reservoir which can lead to compaction
of the
formation. The magnitude of this compaction is dependent upon the degree of
pressure
reduction and the stiffness of the formation. The compaction is sometimes used
to help
drive out fluids from the formation into the production wells and to the
surface. Injection
of fluid into formations during hydrocarbon recovery is also often used to
either keep
fluid pressure up (to help maintain sufficient pressure to drive fluids to the
production
wells) or to help sweep the in-situ hydrocarbons to the production wells. In
general,
significant compaction in reservoir formations is avoided due to the problems
it can
cause with the stability of weilbores into these formations and potential
problems with
the subsidence of the surface.
SUMMARY
[001.11 An embodiment provides a method for recompacting a reservoir
comprising
detecting a slurry override condition and reducing a pressure within the
reservoir so as to
reapply a stress from an overburden to mitigate override during a hydrocarbon
recovery
process.
[0012] Another embodiment provides a method for harvesting a hydrocarbon from
a
sand reservoir. The method includes detecting a slurry override condition and
reducing a
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pressure within the sand reservoir so as to reapply a stress from an
overburden onto the
reservoir sand.
[00131 Another embodiment provides a system for recompacting a reservoir,
comprising an injection well, wherein the injection well is configured to
inject a slurry
comprising sand and fluid into the reservoir and a production well, wherein
the
production well is configured to produce a slurry comprising sand and
hydrocarbon from
the reservoir, wherein the injection well, the production well, or both is
configured to
allow recompaction of the reservoir.
DESCRIPTION OF THE DRAWINGS
[00141 The advantages of the present techniques are better understood by
referring to
the following detailed description and the attached drawings, in which:
[00151 Fig. 1 is a diagram showing the use of a slurrified heavy oil reservoir
extraction process to harvest hydrocarbons from a reservoir, such as an oil
sands deposit;
[0016] Fig. 2(A) is a schematic of the initial state with the reservoir under
stress from
the pressure of the overburden;
[00171 Fig. 2(B) is a schematic of the conditioning process used to remove the
stress
of the overburden from the reservoir;
100181 Fig. 2(C) is a schematic of a slurry production process, as described
with
respect to Fig. 1;
[0019] Fig. 2(D) is a schematic of an override condition, in which a portion
of the
mixed slurry overrides the reservoir and follows a direct path from the
injection well to
the production well;
[0020] Fig. 3 is a schematic of a recompaction process that recompacts the
sand bed
by producing fluid from both the injection wells and production wells;
[00211 Fig. 4 is a schematic of a recompaction process that recompacts the
sand bed
by shutting in the production well and producing fluid from the injection
well;
[00221 Fig. 5 is a schematic of another recompaction process that recompacts
the
sand bed by shutting in the injection well and allowing fluid to be produced
from the
production well;
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[0023] Fig. 6 is a schematic of a recompaction process based on an controlled
imbalance between the slurry injection rate and the reservoir production rate;
[0024] Fig. 7 is a diagram showing a pattern of injection wells and production
wells
over a hydrocarbon field;
[0025] Fig. 8(A) is a schematic of production changes to injection wells and
production wells that may be performed to recompact a target region of a
reservoir;
[0026] Fig. 8(B) is another schematic of production changes to injection wells
and
production wells that may be performed to recompact a target region of a
reservoir;
[0027] Fig. 9 is a process flow diagram of a method for producing hydrocarbons
from a sand reservoir;
[0028] Fig. 10 is a drawing of a 210 cm diameter sand bed showing a colored
sand
flow (indicated by the hash marked area) through each of four injection arms;
[0029] Fig. 11 is a drawing of a resistivity image of the 210 cm diameter
sandpack,
illustrating loss of flow into one arm; and
[0030] Fig. 12 is a drawing of the resistivity image of a 210 cm diameter
sandpack,
illustrating restoration of flow into the arm after recompaction.
DETAILED DESCRIPTION
[0031] In the following detailed description section, specific embodiments of
the
present techniques are described. However, to the extent that the following
description is
specific to a particular embodiment or a particular use of the present
techniques, this is
intended to be for exemplary purposes only and simply provides a description
of the
exemplary embodiments. Accordingly, the techniques are not limited to the
specific
embodiments described below, but rather, include all alternatives,
modifications, and
equivalents falling within the true spirit and scope of the appended claims.
[0032] At the outset, for ease of reference, certain terms used in this
application and
their meanings as used in this context are set forth. To the extent a term
used herein is
not defined below, it should be given the broadest definition persons in the
pertinent art
have given that term as reflected in at least one printed publication or
issued patent.
Further, the present techniques are not limited by the usage of the terms
shown below, as
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all equivalents, synonyms, new developments, and terms or techniques that
serve the
same or a similar purpose are considered to be within the scope of the present
claims.
[0033] "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 wt. % aliphatics (which can range from 5 wt. %-30 wt. %, or higher);
19 wt. % asphaltenes (which can range from 5 wt. %-30 wt. %, or higher);
30 wt. % aromatics (which can range from 15 wt. %-50 wt. %, or higher);
32 wt. % resins (which can range from 15 wt. %-50 wt. %, or higher); and
some amount of sulfur (which can range in excess of 7 wt. %).
In addition bitumen can contain some water and nitrogen compounds ranging from
less
than 0.4 wt. % to in excess of 0.7 wt. %. The metals content, while small,
must be
removed to avoid contamination of the product synthetic crude oil (SCO).
Nickel can
vary from less than 75 ppm (part per million) to more than 200 ppm. Vanadium
can
range from less than 200 ppm to more than 500 ppm. The percentage of the
hydrocarbon
types found in bitumen can vary.
[0034] "Clark hot water extraction process" ("CHWE") was originally developed
for
releasing bitumen from oil sands, based on the work of Dr. K. A. Clark, and
discussed in
a paper by Corti, et al., "Athabasca Mineable Oil Sands: The RTR/Gulf
Extraction
Process Theoretical Model of Bitumen Detachment," The 4th UNITAR/UNDP
International Conference on Heavy Crude and Tar Sands Proceedings, vol. 5,
Edmonton,
AB, Aug. 7-12, 1988, pp. 41-44, 71. The process uses vigorous mechanical
agitation of
the oil sands with water and caustic alkali to disrupt the granules and form a
slurry, after
which the slurry is passed to a separation tank for the flotation of the
bitumen, or other
hydrocarbons, from which the bitumen is skimmed. The process may be operated
at
ambient temperatures, with a conditioning agent being added to the slurry.
Earlier
methods used temperatures of 85 C, and above, together with vigorous
mechanical
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agitation and are highly energy inefficient. Chemical adjuvants, particularly
alkalis, have
to be utilized to assist these processes.
[0035] The "front end" of the CHWE, leading up to the production of cleaned,
solvent-diluted bitumen froth, will now be generally described. The as-mined
oil sand is
firstly mixed with hot water and caustic in a rotating tumbler to produce a
slurry. The
slurry is screened, to remove oversize rocks and the like. The screened slurry
is diluted
with additional hot water and the product is then temporarily retained in a
thickener
vessel, referred to as a primary separation vessel ("PSV"). In the PSV,
bitumen globules
contact and coat air bubbles which have been entrained in the slurry in the
tumbler. The
buoyant bitumen-coated bubbles rise through the slurry and form a bitumen
froth. The
sand in the slurry settles and is discharged from the base of the PSV,
together with some
water and a small amount of bitumen. This stream is referred to as "PSV
underflow."
"Middlings," including water containing non-buoyant bitumen and fines, collect
in the
mid-section of the PSV.
[0036] The froth overflows the lip of the vessel and is recovered in a
launder. This
froth stream is referred to as "primary" froth. It typically comprises 65 wt.
% bitumen,
28 wt. % water, and 7 wt. % particulate solids.
[0037] The PSV underflow is introduced into a deep cone vessel, referred to as
the
tailings oil recovery vessel ("TORN"). Here the PSV underflow is contacted and
mixed
with a stream of aerated middlings from the PSV. Again, bitumen and air
bubbles
contact and unite to form buoyant globules that rise and form a froth. This
"secondary"
froth overflows the lip of the TORV and is recovered. The secondary froth
typically
comprises 45 wt. % bitumen, 45 wt. % water, and 10 wt. % solids. The
underflows from
the TORY, the flotation cells and the dilution centrifuging circuit are
typically
discharged as tailings into a pond system. As used herein, the tailings are
sources of
particulate streams that may be separated into two or more substreams, for
example,
including particles of different sizes. Any discussions of particles will
include tailings
and vice-versa. In embodiments of the present techniques, the tailings are
reinjected back
into the formation as backfill. The reinjection both prevents subsidence as
material is
removed from the reservoir and also lowers environmental issues from the waste
tailings.
Water removed from the tailings during the reinjection process may be recycled
for use
as plant process water.
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[00381 "Facility" as used in this description is a tangible piece of physical
equipment
through which hydrocarbon fluids are either produced from a reservoir or
injected into a
reservoir, or equipment which can be used to control production or completion
operations. In its broadest sense, the term facility is applied to any
equipment that may
be present along the flow path between a reservoir and its delivery outlets.
Facilities may
comprise production wells, injection wells, well tubulars, wellhead equipment,
gathering
lines, manifolds, pumps, compressors, separators, surface flow lines, sand
processing
plants, and delivery outlets. In some instances, the term "surface facility"
is used to
distinguish those facilities other than wells. A "facility network" is the
complete
collection of facilities that are present in the model, which would include
all wells and
the surface facilities between the wellheads and the delivery outlets.
[00391 A "hydrocarbon" is an organic compound that primarily includes the
elements hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or
any number
of other elements may be present in small amounts. As used herein,
hydrocarbons
generally refer to components found in bitumen, or other oil sands.
[00401 "Permeability" is the capacity of a rock to transmit fluids through the
interconnected pore spaces of the rock; the customary unit of measurement is
the
millidarcy. The term "relatively permeable" is defined, with respect to
formations or
portions thereof, as an average permeability of 10 millidarcy or more (for
example, 10 or
100 millidarcy). The term "relatively low permeability" is defined, with
respect to
formations or portions thereof, as an average permeability of less than about
10
millidarcy.
[00411 "Pressure" is the force exerted per unit area by the gas on the walls
of the
volume. Pressure can be shown as pounds per square inch (psi). "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 gage pressure
(psig).
"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.
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[0042] As used herein, "pressure gradient" represents the pressure differences
divided by the distance between the locations where those pressure differences
are
measured. Pressure gradient is a measure of driving force moving the sand
through the
reservoir or the pressure moving slurries through a pipe.
100431 As used herein, "overburden stress" is the stress 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 sand. As such it is a
measure of
the stresses the sand grains in the reservoir sand exert on each other due to
the weight of
the overburden.
[0044] As used herein, "override" is a condition where the injected fluids or
slurries
flow from injector to producer with little or reduced movement of the
hydrocarbon
bearing sand in between the injector and producer. This override is generally
the
overriding of the injected fluids or slurries over the top of the hydrocarbon
bearing sand
due to the density of the reinjected material and/or the lack overburden
stress on that
portion of the hydrocarbon bearing sands in the reservoir. However, in this
context,
override may include any bypass, whether over the top of the sand, under the
sand, or
through the sand, where the reinjected materials pass from the injector to
producer with
significantly reduced pressure gradient between the injector and producer than
before
override and with significantly reduced or nearly zero movement of the
hydrocarbon
bearing sand towards the producing well in the region of the override or
bypass.
[0045] As used herein, a "reservoir" is a subsurface rock formation from which
a
production fluid can be harvested. The rock formation may include granite,
silica,
carbonates, clays, and organic matter, such as oil, gas, or coal, among
others. Reservoirs
can vary in thickness from less than one foot (0.3048 m) to hundreds of feet
(hundreds of
m). The permeability of the reservoir provides the potential for production.
As used
herein a reservoir may also include a hot dry rock layer used for geothermal
energy
production. A reservoir may often be located at a depth of 50 meters or more
below the
surface of the earth or the seafloor.
[0046] A "sand filter" or well screen is a zone of perforated material that is
either
built into an end of a well pipe, or fitted as a sleeve over a very coarsely
perforated part
of the pipe. The well screen can be made from wire mesh, wire wound,
perforated plate,
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or porous metal fiber material. The design of the well screen will be tailored
to the size
of the solid particles to be blocked, which is generally 50 m or more.
Generally, the
sand in a heavy oil reservoir can vary in particle size from about 62.5 m to
greater than
about 500 m, so the screen aperture may be important. If the aperture is too
large in
relation to the sand's particle size, then a fluid rate will be higher, but
too much sand will
penetrate the screen. If the aperture is too close to the size of the
particles, then the fluid
may be clean, but the flow rate may be low and the screen may quickly block.
As used
herein, a sand filter may be included as a segment of a pipe in an injection
well or a
production well that is used during a recompaction process. The resulting
fluid flow may
not be completely free of sand, but may be substantially free of sand, e.g.,
without
containing enough sand to effect the reservoir sand content.
[0047] "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.
[0048] A "wellbore" is a hole 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-sectional shape, such as an oval, a square, a rectangle, a
triangle, or other
regular or irregular shapes. As used herein, 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, to limit
frictional
forces in any one pipe.
Overview
[0049] As previously mentioned, hydrocarbons can be harvested from sand
reservoirs by producing a slurry that includes both sand and hydrocarbons from
a
production well. The sand is processed to remove hydrocarbons, and reinjected
as a
slurry into the reservoir. However, in certain situations, the reinjected
slurry can override
the reservoir due to its lower density relative to the in-situ density of the
reservoir and/or
reduction in stress on the reinjection sand and/or excessive fluid in the
reinjected slurry.
In these cases, the reinjected slurry can travel directly from the injection
wells to the
production wells, decreasing or eliminating the pressure gradients needed to
move the in-
situ reservoir sand from the injector to producer. This is likely to reduce
the ultimate
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recovery of the process, hurting the economics of the project. Further, the
overall
recovery from the slurrified heavy oil recovery process may be decreased by
slurry
override. Embodiments of the present invention provide a method and a system
for
recompacting a sand reservoir to prevent a lower viscosity slurry from
overriding a lower
layer and move from an injection well to a production well while bypassing
hydrocarbon.
[0050] For effective injection of tailings, two conditions can be met. First,
the
permeability of the backfill solids can be controlled within a predetermined
range of
about 0.5 to about 100 times of the initial permeability of the injected fluid
through the
porous material of the subsurface formation into which the mixture is
injected. Second,
the slurry rheology can be controlled to manage pipe pressure losses. When
both criteria
are met, the backfill may be placed correctly, water consumption can be
optimal, and
subsidence may be prevented. More dilute slurries, i.e., higher water
fraction, are
sometimes needed in this initial startup phase as the extra water may helps to
start the
process. This leads to the potential for override of the less dense slurry if
the excess
water does not flow away from the reinjected slurry fast enough or the less
dense slurry
is injected for too long of a period.
Recompaction to improve performance
[0051] Some embodiments of current invention include various mining or civil
engineering operations which rely on backfilling, such as reinjection or
replacement, of
part or the whole of produced formation underground. In particular in situ
heavy oil
mining operations, such as a slurrified heavy oil reservoir extraction method
shown in
Fig. 2, may benefit from the current invention.
[0052] Fig. 1 is a diagram 100 showing the use of a slurrified heavy oil
reservoir
extraction process to harvest hydrocarbons from a reservoir, such as an oil
sands deposit.
The slurry recompaction techniques described herein are not limited to the
slurrified
reservoir process but may be used with any number of other processes. For
example, the
techniques described herein may be used to recompact a separation column,
recompact a
slurry fill in a subsurface cavity, or perform any number of other
recompaction
operations. In the diagram 100, a reservoir 102 is accessed by an injection
well 104 and a
production well 106 drilled through an overburden 108 above the reservoir 102.
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[0053] The reservoir is a subsurface formation that may be at a depth greater
than
about 50 meters. Water injection into the wells 104 and 106 can be used to
raise the fluid
pressure in the reservoir 102 and relieve the stress on the reservoir 102 from
the
overburden 108. The pressure at which the stress is relieved on the reservoir
may be
termed the conditioning pressure, as that is the pressure at which the
reservoir is deemed
sufficiently conditioned to allow sand flow from the reservoir. The
conditioning pressure
depends on the pressure from the overburden 108, e.g., due to the depth of the
reservoir
102, and may be about 50 to about 1000 psi greater than the initial pressure.
After the
relief of overburden stress, a water and sand mixture can be injected through
the
injection well 104, for example, from a pumping station 110 at the surface
112. At the
same time, hydrocarbon containing materials 114, such as oil sands, can be
harvested
from the reservoir 102, for example, through another pumping station 116. The
hydrocarbon containing materials 114 may be processed in a facility 118 to
remove at
least a portion of the hydrocarbons 120. The hydrocarbons 120 can be sent to
other
facilities for refining or further processing. The cleaned tailings can be
used to form a
mixed slurry 122, including water and sand or other particulates, which may
then be
backfilled, i.e., reinjected into the reservoir 102, for example, to prevent
subsidence of
the surface 112. The injection well 104 and production well 106 are generally
limited to
single connections to the reservoir 102, but multiple injection and production
wells 104
and 106 are often used over a reservoir.
[0054] The method converts the hydrocarbon bearing sands of the reservoir 102
into
a formation resembling a moving bed that includes sand and hydrocarbon. When
the
reservoir 102 moves toward the production well 106, the void space can be
continuously
filled by a reinjected clean slurry stream, which can include clay, silt,
sand, and fluid,
from the injection well 104.
[0055] The slurry fill process, described above, may also influence the
density of the
sand in the reservoir 102. In combination with the initial conditioning step,
this process
may create a lower density slurry in an upper part of the reservoir 102, which
could
allow an injected mixed slurry 122 to at least partially override the
hydrocarbon bearing
sand and pass through the reservoir 102 without moving the hydrocarbon bearing
slurry
through the reservoir. The slurrified heavy oil recovery process is discussed
further with
respect to Figs. 2(A)-(D).
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[00561 Fig. 2(A) is a schematic of the initial state with the reservoir 102
under stress
from the pressure of the overburden 108. In Figs. 2(A)-(D), like numbered
items are as
discussed with respect to previous figures. Two wells may be completed to the
reservoir
102, an injection well 104 and a production well 106. The wells 104 and 106
are not
limited to injection or production, but may be converted as needed to serve
either
purpose, for example, during a conditioning or recompaction process. Further,
as
discussed further with respect to Figs. 7 and 8, a number of injection wells
104 and
production wells 106 may be used to access the reservoir 102.
[00571 Fig. 2(B) is a schematic of the conditioning process used to remove the
stress
of the overburden 108 from the reservoir 102. The conditioning is generally
performed
by fluid injection, for example, through one or more of the wells 104 and 106,
as
indicated by arrows 202. Once conditioning is completed, the stresses on the
reservoir
102 are balanced, and frictional forces, which may tend to prevent the
reservoir from
being harvested, are decreased enough to allow the reservoir 102 to move.
After this
conditioning process, there remains some limited overburden stress on the
hydrocarbon
bearing reservoir sands. The magnitude of this stress is generally small
(generally in the
range of 10 to 400kPa out of the 1MPa to 10MPa overburden stress that would
have been
on the sands before conditioning.
[00581 Fig. 2(C) is a schematic of a slurry production process, as described
with
respect to Fig. 1. In the production process, the clean, mixed slurry 122 is
injected into
the reservoir 102, creating a zone 204 containing the mixed slurry 122, which
causes the
reservoir 102 to slide from the vicinity of the injection well 104 to the
vicinity of the
production well 106, as indicated by arrow 206. From the production well 106,
the
hydrocarbon containing materials 114 can be produced.
[00591 Fig. 2(D) is a schematic of an override condition, in which a portion
208 of
the mixed slurry 122 overrides the reservoir 102 and follows a direct path
from the
injection well 104 to the production well 106. In this case, the injected
slurry bypasses
the hydrocarbon containing materials of the reservoir 102. Based on
experiments,
override may occur because the overburden stresses on the sands within the
overriding
mixed slurry nearly completely disappear, for example, due to the presence of
excess
fluid pressure in the region or to the overburden stresses being supported by
nearby non-
moving portions of the reservoir sand. The override condition may be directly
detected
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CA 02779121 2012-06-07
by the composition of the extracted material. The override condition may also
be
detected by a significant drop in the pressure gradient between the injector
and producer,
since it may take less pressure to drive the overriding material between
injector and
producer, than to drive the reinjected sands and hydrocarbon bearing sands
between
injector and producer when override is not occurring. Further, the loss of
pressure
gradient between injector and producer due to override may slow down or stop
the
movement of the hydrocarbon bearing sand and, thus, reduce the production of
hydrocarbon bearing sand from the area in which override is occurring.
[00601 In an embodiment, override may be mitigated by recompaction of the
reservoir sand. For example, the reservoir 102 may be either partially
recompacted or
returned to its original stress state. In some embodiments, the recompaction
may be
directed to the portion 208 of the mixed slurry 122 that is overriding the in-
situ material.
The recompaction of the reservoir 102 or the portion 208 may be used to bring
the
density of sand throughout the reservoir 102 to nearly the same state.
[00611 The recompaction may be performed by reducing the pressure in the
reservoir
102, for example, by slowing or stopping the injection of the mixed slurry 122
or
production of the hydrocarbon bearing materials 114, while allowing water
production
from the injection wells 104, production wells 106, or from both. This allows
the stress
from the overburden 108 to be at least partially reapplied to the reservoir
102,
recompacting at least a portion of the sand in the reservoir 102. The
reservoir pressure
after the recompaction may be higher than the initial pressure in the
reservoir 102, or
may be at the initial pressure of the reservoir 102. In an embodiment, the
reinjected sand
in the portion 206 of the slurry mixture 122 that is overriding the reservoir
102 may be
recompacted, sealing the path of the slurry override. In another embodiment,
the pressure
in the reservoir could be allowed to bleed off to other parts of the reservoir
that may be at
lower pressure.
[00621 The slurrified heavy oil recovery process can then restarted by
repeating the
conditioning phase discussed with respect to Fig. 2(B). The conditioning phase
may be
accomplished in a shorter times due to the presence of some higher
permeability
reinjected slurry and the higher water saturation of the recompacted reservoir
system
versus the original in-situ reservoir system and restarting slurry production
and
reinjection. As the sands have been recompacted, it is believed the process
will allow
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CA 02779121 2012-06-07
ultimate recoveries to be similar to what they would have been if override
never
occurred. The techniques that may be used for recompacting the reservoirs in
various
embodiments is discussed in greater detail with respect to Figs. 3-6.
[0063J Fig. 3 is a schematic of a recompaction process 300 that recompacts the
sand
bed by producing fluid from both the injection wells 104 and production wells
106. In
Fig. 3, like numbered items are as discussed with respect to previous figures.
The fluid
production, indicated by arrows 302, may be performed by allowing flow at a
reduced
rate, which may lower entrainment of sand. The fluid production 302 may also
be
performed through a sand filter, such as a limited entry perforation (LEP)
segment. The
LEP may be included as a portion of the well during the initial completion or
may be
placed in one or both wells 104 and 106 at a later time.
100641 Fig. 4 is a schematic of a recompaction process 400 that recompacts the
sand
bed by shutting in the production well 106 and producing fluid 302 from the
injection
well 104. In Fig. 4, like numbered items are as discussed with respect to
previous figures.
As in the previous recompaction process, the injection well 104 may have an
LEP
segment to allow the fluid production 302 without entrained sand. However, the
proportion of fines in the reinjected slurry mixture 122 may be lower than in
the sand of
the reservoir 102. This may allow for higher production rates of fluid 302
without solid
entrainment from the injection well 104 as the zone 204 comprising the mixed
slurry 122
may act as a sand filter. In addition, since the reinjected sand would have
substantially no
hydrocarbons, with the possible exception of a small amount left over after
the surface
extraction process, the ability to produce water out of the injection wells
would likely be
easier than producing it out of the production wells due to the higher
permeability to
water of the sands around the injection well as compared to that around the
producing
wells.
[00651 Fig. 5 is a schematic of another recompaction process 500 that
recompacts the
sand bed by shutting in the injection well 104 and allowing fluid 302 to be
produced
from the production well 106. In Fig. 5, like numbered items are as discussed
with
respect to previous figures. As described herein, a LEP segment may be
included in the
production well 106 to allow the fluid 302 to be produced without entrained
sand. In
addition, other methods may be used to prevent sand production while water
production
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CA 02779121 2012-06-07
is being attempted. These could include, but are not limited to, sand screens,
slotted
liners, or gravel packs in addition to the LEPs mentioned earlier.
[00661 The recompaction does not have to be performed by completely shutting
in
the wells 104 or 106. In an embodiment of the process, slurry injection can be
continued,
while only fluid is withdrawn from the production well 106 rather than a fluid
and sand
slurry, as described with respect to Fig. 6. In an embodiment, slurry
injection could
continue in some injection wells while other injection wells are used to
produce fluid
only for reasons stated above.
[00671 Fig. 6 is a schematic of a recompaction process 600 based on a
controlled
imbalance between the slurry injection rate and the reservoir production rate.
In Fig. 6,
like numbered items are as discussed with respect to previous figures. This
may be
performed using any number of combinations of injection and production rates.
For
example, the injection rate of the slurry may be decreased, as indicated by
the dotted
arrow 602, while the production rate, indicated by the solid arrow 604 is held
constant.
[0068] In other embodiments, the injection rate 602 of the slurry may be held
constant while only fluid is produced from the production well 106. In this
embodiment,
a LEP segment may be included in the production well 106 to assist in the
production of
fluid without entrained sand. The production of only fluid while injecting
denser slurry
allows the reinjected material in the override area 208 to become denser and
thus support
the overburden stress.
[00691 Fig. 7 is a diagram showing a pattern 700 of injection wells 702 and
production wells 704 over a hydrocarbon field 706. The hydrocarbon field 706
generally
overlies a single reservoir 102, for example, as discussed above. The pattern
700 may
generally be referred to as a "five-spot pattern," in which four injection
wells 702
surround a central production well 704. Generally, the pattern 700 can be
repeated
multiple times across a hydrocarbon field 706, so that the number of injection
wells 702
and production wells 704 are matched, which assists with maintaining a mass
balance of
material entering and exiting the reservoir. As shown in Fig. 7, the pattern
700 may be
regularly spaced across a field. In other embodiments, the wells 702 and 704
may be
irregularly spaced, for example, placed to improve interaction with the
reservoir
geometry. Any number of other patterns may be used in embodiments.
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CA 02779121 2012-06-07
[0070] While the slurrified heavy oil recovery method relies on multiple,
repeated
patterns of injectors and producers, the selected recompaction scheme does not
necessarily need to be applied to the entire reservoir 102. For example, if an
override
condition is detected only in on portion of the reservoir 102, a recompaction
process may
be implemented only on that section. This is discussed further with respect to
various
patterns in Fig. 8. The patterns are not limited to those shown in Fig. 8, but
may be
implemented using any number of patterns. A pattern-by-pattern decision can be
made
based on local production and injection information, for example, depending on
the size,
shape, or reservoir configuration in the area of the override.
[0071] FIG. 8 (A) is a schematic of production changes to injection wells and
production wells that may be performed to recompact a target region 800 of a
reservoir.
In this example, production rates for injection wells 802 and production wells
804
outside of the target region 800 may not be changed. However, production wells
806
surrounding the target region 800 may be operated at a reduced rate and wells
808 within
the target region 800 may be shut-in. This may allow a slow subsidence of the
target
region, for example, by fluid draining to other regions or to the surrounding
formations,
providing recompaction of the sand bed within the target region 800.
[0072] Fig. 8(B) is another schematic of production changes to injection wells
and
production wells that may be performed to recompact a second target region 810
of a
reservoir. In this example, the second target region 810 includes the opposing
"arms" of
a five-spot pattern. A partial recompaction, for example, a few psi to a few
tens of psi,
may be performed by shutting in a single producer 812 and two opposing
injection wells
814, and reducing rates from the surrounding production wells 806.
[0073] The techniques are not limited to the patterns and embodiments shown
above,
but may use any combinations of wells that are shut-in, producing at reduced
rates, or
merely producing fluid. For example, production or production and injection
maybe shut
down in an area and the pressures in the area may be allowed to equilibrate
before
starting up production and injection again. This may be performed to mitigate
the
pressure gradients causing an override.
[0074] The techniques described herein allow for the re-application or re-
distribution
of overburden stresses on the reservoir sand. In some cases, such as a full or
nearly full
reapplication of overburden stresses, the stresses are redistributed so that
certain parts of
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CA 02779121 2012-06-07
the reservoir sand, such as the non-moving sections, are compacted. This may
redistribute the stresses on those portions of the reservoir to the parts of
the sand where
slurry injection and slurry production were occurring. In other cases, the
redistribution of
stresses and pore pressure may be milder and the override can be avoided upon
restart
due to the bleed off of fluid pressures from the override area as much as by
the
redistribution of stresses.
[0075] In addition to reducing fluid pressure and recompacting the sand, the
techniques described herein have the beneficial outcome of making the sand,
fluid
pressures, and stresses on the sand in the reservoir more homogenous. The
processes
discussed above may lead to inhomogeneities in sand permeability or pressure
or stress
distributions, which can lead to override or bypass. As such, the
homogenization of those
properties of the sand in the reservoir also act as a method to help prevent
override once
injection and production is restarted.
100761 Fig. 9 is a process flow diagram of a method 900 for producing
hydrocarbons
from a sand reservoir. The method 900 begins at block 902 when an injection
well is
completed to a reservoir. Although the injection well will generally be used
for slurry
injection, the injection well may also include a limited entry perforation
(LEP) section,
or other type of sand trap, that allows fluid to flow without entrained sand
when selected.
At block 904, a production well is completed to the reservoir. As in the case
of the
injection well, the production well may also have a segment containing a sand
trap.
[0077] At block 906, the reservoir can be conditioned for slurry flow. This is
performed by injecting fluid into the reservoir through the injection wells,
the production
wells, or both, until the pressure in the reservoir is normalized with the
pressure of the
overburden. The normalization releases friction in the reservoir, allowing the
reservoir to
move from the injection well to the production well.
[0078] At block 908, slurry may be injected in the injection well to cause the
reservoir to flow towards the production well. At block 910, hydrocarbon
containing
slurry can be produced from the reservoir through the production well.
Produced
materials can be cleaned and reinjected as a mixed slurry, while the
hydrocarbon may be
transported for further processing. The reinjected mixed slurry replaces the
material that
is produced. However, under some circumstances the reinjected mixed slurry may
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CA 02779121 2012-06-07
override the hydrocarbon containing sands of the reservoir, leading to the
production of
lower amounts of hydrocarbon than would otherwise occur.
100791 At block 912, the override condition may be detected. This may be
performed
using any number of techniques. For example, a sudden decrease in expected
hydrocarbon from certain wells may be noted. Further, a change in particle
size
distribution may indicate that the injected mixed slurry is passing directly
from the
injection well to the production well, bypassing the reservoir.
[00801 At block 914, pressure is lowered on the reservoir to recompact the
sand bed.
As discussed herein, this may be performed by any number of techniques that
allow
increased production of fluids or slurry from the reservoir versus injection
of slurry into
the reservoir. For example, in an embodiment, injection may be slowed or
stopped, while
keeping production constant. In another embodiment, injection and production
may be
stopped in the area of the override, while production at reduced rates
continues from
wells surrounding the area of the override. In another embodiment, injection
may be
halted and fluid may be produced from injection wells, production wells, or
both.
[00811 At block 916, injection and production may be resumed. This may be
proceeded by a repeat of the conditioning step to relieve pressure on the
reservoir. The
conditioning step may take less time or less fluid than the initial
conditioning step. The
method 900 may be repeated any number of times during the life of the
reservoir.
Examples
100821 The techniques described herein were tested in a laboratory at two
different
scales, using a 25 cm diameter sandpack and a 210 cm diameter sandpack as
model
reservoirs. The test procedures and apparatus for the 210 cm diameter sandpack
are as
described in David P. Yale, et al., "Large-Scale Laboratory Testing of the
Geomechanics
of Petroleum Reservoirs," SPE 134313, presented at the 44th US Rock Mechanics
Symposium and 5th U.S.-Canada Rock Mechanics Symposium, held in Salt Lake
City,
UT, June 27-30, 2010. The test procedures for the 25cm are similar to those
described in
Yale et. al.
[00831 Fig. 10 is a drawing 1000 of a 210 cm diameter sand bed showing a
colored
sand flow (indicated by the hash marked area) through each of four injection
arms 1002
- 1008. An injection arm is the area between any given injection well 1010 and
the
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CA 02779121 2012-06-07
production well 1012. The colored sand was mixed with the injected sand as a
material
marker. As shown in this drawing 1000, the tests were set up as single five-
spot patterns,
using four equidistant injector wells 1010 and a center single producer well
1012. Real
reservoir sands and model fluids were used to mimic actual reservoir mobility
and ensure
the slurrified heavy oil recovery experiments were representative. A similar
configuration was used for the sandbed in the 25 cm diameter cell. In this
example, the
flow into all four injection arms 1002 - 1008 is visually illustrated, showing
a restoration
of flow after an override condition, as is discussed further with respect to
Figs. I 1 and
12.
[00841 In one such test in the 25 cm diameter cell, production of the colored
reinjected sand was observed well before mass balance calculations suggested
the
majority of the in-situ sand had been produced. This, in addition to pressure
gradients
measured in the cell, suggested that the re-injected slurries were overriding
the in-situ
sands and not allowing as much of the in-situ sands to be produced. In one
such test, this
override was observed to occur in just one of the four injection arms. In
another test, this
override was observed in two of the injection arms. In these tests, the
injection and
production of slurries was suspended and fluid only production was done until
the fluid
pressure in the cell was reduced to nearly the same pressure as was in the
cell before the
"conditioning" portion of the test. This reapplied the stress on the sandpack
in the cell
that simulated the stress on a reservoir sand before the start of the
"conditioning" part of
a slurrified heavy oil extraction process.
[00851 After the pressure reduction and stress re-application, the
conditioning was
repeated, i.e., fluid pressure raised to nearly the overburden pressure
applied to the sand.
Then the slurry production and injection process was restarted as described in
Yale and
Herbolzheimer. In this test, the slurry production and slurry injection was
able to proceed
to full production of the in-situ sand and achieve a sweep efficiency of over
70%, i.e.,
70% of the in-situ or initial sand in the area between the injectors and
producers was
swept to and produced up the production well.
[00861 During two tests in the 210 cm diameter cell, recompaction was used to
allow
slurry injection-production to be re-started after early breakthrough and
other problems.
In one case override was observed in all four injection arms 1002-1008 after
only about
20% of sweep and thus production was stopped. Investigation of the reason for
the
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CA 02779121 2012-06-07
override suggested that the injected slurry had more water than usual, i.e.,
was less dense
than usual, and this led to the override both from the perspective of a less
dense slurry
but also by allowing overburden stresses on the sands to decrease, which has
been
observed to lead to override.
[00871 Rather than decreasing the fluid pressure to initial conditions, a
slightly
different approach was taken where production of water only was started in the
production well 1012 and injection of a denser (less water) slurry was started
in each of
the four injection wells 1010. After the pressure was decreased by several psi
and
stresses were reasserted on the sand from the dense slurry injection, water
production
was stopped while slurry injection continued. Once fluid pressure recovered to
the levels
sufficient for the start of slurry production/injection (i.e. full
conditioning), production of
slurry was restarted. Injection/production of slurry through to full sweep was
then
achieved.
100881 In addition to early production of colored sand, other techniques were
used to
identify slurry override conditions. For example, the 210 cm diameter cell is
wired with a
number of sensors for resistivity analysis of the sands in the cell. The
resistivity images
can be used to identify which injection arms are showing override conditions,
for
example, by initially charging the sand bed with a high resistivity solution,
then using a
low resistivity solution for the liquid base in a slurry. In addition, a
significant drop in
the pressure gradient between the injector and producer (as evidence by the
measurement
of pressure at a number of points between the injector and producer) was seen
when the
override occurred.
100891 Fig. 11 is a drawing of a resistivity image of a cross-section of the
210 cm
diameter sandpack, illustrating loss of flow through one injection arm 1004.
In Fig. 11,
like numbered items are as discussed with respect to Fig. 10. In both Figs. 11
and 12, a
higher resistivity area of the original sand bed is indicated by small x's,
while a lower
resistivity area is indicated by small o's for the liquid slurry added to the
sandpack by the
injection wells. Further, it should be understood that Fig. I 1 is a two
dimensional cross
section of a three dimensional phenomenon measured along the bottom of the
sandpack.
Accordingly, changes in resistivity may be greater in different layers.
100901 Injection and production was started and sustained in the other three
injection
arms 1002, 1006, and 1008. However, it was surmised that there was an override
of the
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CA 02779121 2012-06-07
initial fluid injected into arm 1004 preventing the establishment of a
sufficient pressure
gradient to move the sand between the injection well 1010 for injection arm
1004 and the
production well 1012. This is seen in Fig. 11 in which the illustrated cross-
section of the
sandpack is below the oven-ride of the injected, low resistivity solution and
the higher
resistivity sand is not being swept towards the production well 1012. After
allowing
injection and production in the other three arms to proceed to full sweep, a
partial
recompaction was attempted to recompact the sand in the injection arm 1004,
and in the
rest of the sandpack, sufficiently to allow for sand flow to be started in
injection arm
1004.
[0091] Fig. 12 is a drawing of the resistivity image of a 210 cm diameter
sandpack,
illustrating restoration of flow into the injection arm 1004 after the
recompaction. In Fig.
12, like numbered items are as discussed with respect to Fig. 10. A
recompaction of 40
psi, or 5% of the conditioning pressure, was applied to the sandpack and then
the
sandpack was reconditioned to full conditioning pressure. The test was
restarted and
slurry injection and production was initiated successfully in all four
injection arms 1002 -
1008. Further, injection and production in injection arm 1004 through to full
sweep was
successful post recompaction. Fig. 10, above, shows the visual image post test
of the
swept sections of the original sand and the effectiveness of the recompaction.
[00921 Repeating the conditioning process to relieve the overburden stress
applied
during the recompaction is required after each recompaction to bring the
sandpack to the
fully conditioned state needed to produce and inject slurry. Slurry production
and slurry
reinjection were then restarted, with the vast majority of the subsequent
production being
from the initial, in-situ material, which indicated successful healing of the
override in the
various examples above.
[0093) The process was run until normal breakthrough occurred, e.g., when the
vast
majority of the production was of the reinjected material. Examination of the
sandpacks
after the test showed a high recovery factor, which was similar to results
from tests
where override did not occur. There was no particular evidence in the
recompacted
sandpack that override had ever occurred.
[00941 The examples above suggest that the recompaction process can be used in
a
number of different embodiments, e.g., a very small amount of recompaction, a
moderate
amount of recompaction, or a full recompaction to the initial reservoir
conditions that
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CA 02779121 2012-06-07
existed before the conditioning process was first applied to the reservoir.
The examples
show that the recompaction can correct a range of override problems from
override of the
reinjected sand to override of just the fluid being injected. The examples
also show that
the override can occur due to a low density of the injected slurry or due to
imbalances in
the application of overburden stress to various portions of reservoir sand.
They also show
that recompaction can be used to correct problems in just one injection arm of
a five-spot
pattern to two or more injection arms of a five-spot pattern. By extension,
they also
suggest that the recompaction process can be used on a single five-spot
pattern or
multiple five-spot patterns and to single or multiple injection arms in each
of those five-
spot patterns.
[00951 The process described herein may be used in slurrified heavy oil
recovery to
recompact the overriding sand to an absolute permeability which is similar
enough to the
permeability to water of the in-situ sand to allow the slurrified process to
work.
Therefore, the pressure drop across both the overriden material and the in-
situ material is
similar during subsequent injection-production and the entire sandpack is
produced
rather than preferential production of the overriding material.
[00961 While the present techniques 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 techniques is
not
intended to be limited to the particular embodiments disclosed herein. Indeed,
the present
techniques include all alternatives, modifications, and equivalents falling
within the
scope of the appended claims.
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