Note: Descriptions are shown in the official language in which they were submitted.
CA 02847759 2014-03-28
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,
A METHOD OF ENHANCING RESOURCE RECOVERY FROM SUBTERRANEAN RESERVOIRS
FIELD
[0001] The present disclosure relates to recovering resources using
thermal recovery
processes. Specifically, the present disclosure relates to enhancing recovery
of heavy oil using
thermal recovery processes or techniques.
BACKGROUND
[0002] This section is intended to introduce various aspects of the
art. This discussion is
believed 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 dependent on the use of
hydrocarbon resources for fuels
and chemical feedstocks. Subterranean rock formations that can be termed
"reservoirs" may
contain resources, such as hydrocarbons, that can be recovered. Removing
hydrocarbons from
the subterranean reservoirs depends on numerous physical properties of the
subterranean rock
formations, such as the permeability of the rock containing the hydrocarbons,
the ability of the
hydrocarbons to flow through the subterranean rock formations, and the
proportion of
hydrocarbons present, among other things.
[0004] Easily produced sources of hydrocarbons are dwindling,
leaving less conventional
sources to satisfy future needs. As the costs of hydrocarbons increase, less
conventional
sources become more economical. One example of less conventional sources
becoming more
economical is that of oil sand production. The hydrocarbons produced from less
conventional
sources may have relatively high viscosities, for example, ranging from 1000
centipoise (cP) to
20 million cP with American Petroleum Institute (API) densities ranging from 8
API, or lower,
up to 20 API, or higher. The hydrocarbons recovered from less conventional
sources may
include heavy oil. However, the hydrocarbons, like heavy oil, produced from
the less
conventional sources are difficult to recover using conventional techniques.
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[0005] Several methods have been developed to recover heavy oil
from, for example, oil
sands. Strip or surface mining may be performed to access oil sands. Once
accessed, the oil
sands may be treated with hot water or steam to extract the heavy oil. For
subterranean
reservoirs where heavy oil is not close to the Earth's surface, heat may be
added and/or
dilution may be used to reduce the viscosity of the heavy oil and recover the
heavy oil from the
subterranean reservoir. Heat may be supplied through a heating agent like
steam. The heat
may be injected into the subterranean reservoir via an injection well or
wellbore. If the heating
agent is steam, the steam may be condensed to water at the steam/cooler-oil-
sands interface
in the subterranean reservoir and supply latent heat of condensation to heat
the heavy oil in
the oil sands, thereby reducing viscosity of the heavy oil and causing the
heavy oil to flow more
easily. The heavy oil recovered from the subterranean reservoir may or may not
be produced
via a production well or wellbore. The production well or wellbore may be the
same well or
wellbore as the injection well or wellbore.
[0006] A number of thermal recovery processes or techniques for
recovery of heavy oil
have been developed. These processes or techniques may include, for example,
cyclic steam
stimulation or cyclic solvent stimulation (CSS), steam assisted gravity
drainage (SAGD), vapor
extraction process (VAPEX), steam flooding, in-situ combustion and thermal
enhanced oil
recovery and solvent-assisted steam assisted gravity drainage (SA-SAGD). These
processes may
be cyclic recovery processes in which there is intermittent injection of a
mobilizing fluid to
lower a viscosity of the heavy oil followed by recovery of the reduced
viscosity heavy oil.
[0007] CSS techniques, that are cyclic steam stimulation
techniques, use steam heat to
lower the viscosity of the heavy oil. The steam is injected into the
subterranean reservoir
through a well that raises the temperature of the heavy oil during a heat soak
phase, thus
lowering the viscosity of the heavy oil. As the viscosity of the heavy oil is
reduced, the heavy oil
may flow down towards the well. The well may then be used to produce heavy oil
from the
subterranean reservoir. Solvents may be used in combination with steam in CSS
processes,
such as in mixtures with the steam or in alternate injections between steam
injections.
Exemplary CSS techniques are described in U.S. Patent No. 4,280,559, U.S.
Patent No.
4,519,454, and U.S. Patent No. 4,697,642.
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=
[0008] SAGD is a process where two horizontal wells (a well pair)
are completed in a
subterranean reservoir. The two wells may be first drilled vertically to
different depths within
the subterranean reservoir. Thereafter, using directional drilling technology,
the two wells may
be extended in a horizontal direction that results in two horizontal wells
(i.e., a production well
and an injection well), each vertically spaced from, but otherwise vertically
aligned with, the
other. Ideally, the production well may be located above the base of the
subterranean
reservoir but as close as practical to the bottom of the subterranean
reservoir. A horizontal
portion of the injection well may be located vertically above, such as, for
example, 10 to 30 feet
or 3 to 10 meters above, a horizontal portion of the production well. The
injection well may be
supplied with steam from a facility on the surface. The steam may rise from
the injection well,
permeating the subterranean reservoir to form a vapor chamber (ie., steam
chamber) above
the well pair. As the vapor chamber grows over time towards the top of the
subterranean
reservoir, the steam may condense at the steam/cooler-oil sands interface,
releasing latent
heat of steam, thereby reducing the viscosity of the heavy oil in the
subterranean reservoir.
The heavy oil and condensed steam may then drain downward through the
subterranean
reservoir under the action of gravity and flow into the production well. After
flowing into the
production well, the heavy oil and condensed steam can be pumped to the
surface. At the
surface, the condensed steam and heavy oil may be separated, and the heavy oil
may be
diluted with appropriate light hydrocarbons for transportation by pipeline.
SAGD processes are
described in Canadian Patent No. 1,304,287 and U.S. Patent No. 4,344,485.
[0009] Solvents may be used alone or in combination with steam in a
SAGD or CSS
process. As the solvents blend with the heavy oil, the viscosity of the heavy
oil decreases,
thereby allowing the heavy oil to flow downwards toward a production well. The
mobility of
the heavy oil obtained with a steam and solvent combination may be greater
than that
obtained using steam alone under substantially similar formation conditions.
[0010] The subterranean reservoirs in which SAGD or CSS take place
are generally
composed of a reservoir matrix of rock having hydrocarbons, such as heavy oil,
within a pore
space of the reservoir matrix. In the SAGD process, the steam forming the
vapor chamber
above the SAGD well pair reduces the viscosity of the heavy oil within the
vapor chamber and
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enables the heavy oil to flow through the pore space of the reservoir matrix
down into the
production well. The vapor chamber has a generally triangular cross section
with the
production well and/or the injection well at an apex of this triangular shape.
This generally
results in an area between vapor chambers of adjacent SAGD well pairs in which
the heavy oil is
not mobilized for recovery.
[0011] Processes combining SAGD and CSS have been proposed to
recover bypassed
heavy oil located between SAGD well pairs. In one such proposal disclosed in
U.S. Patent No.
6,257,334, a horizontal injector-producer CSS well is placed offset to a SAGD
well pair at a
depth of a production well of the SAGD well pair. The CSS well starts
injecting steam into the
subterranean reservoir after the SAGD well pair has been in operation for a
period described as
3 years and is illustrated as being at a time when the vapor chamber has
reached an
overburden of the subterranean reservoir. The CSS well continues to inject
steam into the
subterranean reservoir until fluid communication is established between the
CSS well and the
SAGD well pair. A similar process was proposed in U.S. Patent No. 7,556,099
with the CSS well
being described as starting its process when the vapor chambers from two
surrounding SAGD
well pairs have already merged. In the technique of U.S. Patent No. 7,556,099,
steam is
injected into the subterranean reservoir at a pressure that is high enough for
the reservoir
matrix of the subterranean reservoir to fracture. When injections from a CSS
well in a SAGD
technique commence after vapor chambers of SAGD well pairs have merged and/or
reached
the overburden, a vapor chamber formed by steam injections from the CSS well
will grow in a
primarily vertical direction in order to merge with the vapor chambers already
formed by the
SAGD process. Such timing of the commencement of injections from the CSS well
can still leave
an area between the CSS well and the SAGD well pairs in which the heavy oil is
not mobilized
for recovery of the resources due to the primarily vertical growth of the
vapor chamber from
the CSS well. Further, steam from the CSS well may be exposed to the
overburden of the
subterranean reservoir due to the primarily vertical growth of the vapor
chamber of the CSS
well, possibly resulting in a portion of the steam energy from the CSS well
being lost to rock
forming the overburden above the subterranean reservoir.
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[0012] Processes to improve horizontal distribution of vapor from wells
have been
proposed, for example in Canadian Patent Publication No. 2,744,749. The
figures of Canadian
Patent Publication No. 2,744,749 illustrate a technique in which injection
wells in a
subterranean reservoir may be horizontally offset as well as vertically offset
from production
wells. The technique of Canadian Patent Publication No. 2,744,749 is in
contrast with a typical
SAGD process in which an injection well and a production well are generally
horizontally
aligned. However, the technique of Canadian Patent Publication No. 2,744,749
is applied to
new installations and processes in a subterranean reservoir and not to
existing installations and
processes.
[0013] Fig. 2 shows a temperature distribution in a subterranean reservoir
during a CSS-
SAGD technique when injections from the CSS well are commenced after vapor
chambers from
adjacent SAGD well pairs 204 have merged. The SAGD well pair 204 and the CSS
well 206,
through steam injections, each form a vapor chamber which in turn forms an
area of increased
temperature that is depleted of heavy oil that has already been mobilized,
possibly for recovery
of the heavy oil. But, an area between the SAGD well pair 204 and the CSS well
206, for which
the temperature does not increase, as shown in dark portions 202 in Fig. 2, is
an area where
heavy oil has not been mobilized for recovery.
[0014] Improving a vapor distribution throughout the subterranean reservoir
is desired
during thermal recovery processes to mobilize a greater amount of the heavy
oil, and thereby
recover a greater amount of heavy oil from the subterranean reservoir.
SUMMARY
[0015] The present disclosure provides systems and methods for enhancing
oil recovery
during thermal recovery processes.
[0016] A method of recovering heavy oil from a subterranean reservoir via a
thermal
recovery well pair, the thermal recovery well pair comprising an injection
well, for injecting
injection vapor into the subterranean reservoir to form a vapor chamber, and a
production
well, at an elevation below the injection well, for recovering heavy oil from
the subterranean
reservoir, may comprise providing an infill well in an area laterally spaced
apart from the
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thermal recovery well pair. The method may also comprise injecting an injected
fluid via the
infill well into the subterranean reservoir at a time during which the
injected fluid establishes a
horizontal planar communication path between the infill well and the vapor
chamber. The
horizontal planar communication path may enable substantially horizontal
planar distribution
of the injection vapor within the subterranean reservoir. The method may also
comprise
producing a produced fluid from the infill well to at least partially recover
heavy oil from the
horizontal planar communication path. The horizontal planar communication path
may provide
the horizontal planar communication. The method may also comprise producing
heavy oil from
at least one of (i) the infill well after the horizontal planar communication
has been established
and (ii) the production well to recover the heavy oil from the subterranean
reservoir.
[0017] A method of recovering heavy oil from a subterranean reservoir may
comprise
providing two thermal recovery well pairs laterally spaced apart from each
other. Each of the
two thermal recovery well pairs may comprise an injection well, for injecting
injection vapor
into the subterranean reservoir, and a production well, at an elevation below
the injection well,
for removing heavy oil from the subterranean reservoir. The injection vapor
may form a vapor
chamber above each of the two thermal recovery well pairs. The method may also
comprise
providing an infill well between and laterally spaced apart from each of the
two thermal
recovery well pairs. The method may also comprise injecting the injection
vapor from each of
the injection wells to form the vapor chamber above each of the two thermal
recovery well
pairs and establishing horizontal planar communication between the infill well
and the vapor
chambers of the two thermal recovery well pairs by injecting an injected fluid
via the infill well
into the subterranean reservoir after forming the vapor chambers. The method
may also
comprise producing the heavy oil from the production wells.
[0018] 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 herein.
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BRIEF DESCRIPTION OF THE DRAWINGS
[0019] 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:
[0020] Fig. 1 is a drawing of a SAGD process used for recovering heavy oil
in a
subterranean reservoir;
[0021] Fig. 2 is an illustration of a simulated temperature distribution in
a CSS-SAGD
process;
[0022] Fig. 3 is a cross section of a SAGD process;
[0023] Fig. 4A is an illustration of a simulated temperature distribution
in the
subterranean reservoir after horizontal planar communication is established in
a horizontal
planar heating assisted-SAGD (HPHA-SAGD) process;
[0024] Fig. 4B is an illustration of a simulated temperature distribution
in the
subterranean reservoir in the HPHA-SAGD process after 856 days;
[0025] Fig. 4C is an illustration of a simulated temperature distribution
in the
subterranean reservoir in the HPHA-SAGD process after 1000 days;
[0026] Fig. 4D is an illustration of a simulated temperature distribution
in the
subterranean reservoir in the HPHA-SAGD process after 1300 days;
[0027] Fig. 5 is a plot diagram showing a simulated comparison of a
cumulative oil-steam
ratio for the HPHA-SAGD process in comparison with SAGD processes;
[0028] Fig. 6 is a plot diagram showing a simulated comparison of oil
production rates for
the HPHA-SAGD process in comparison with SAGD processes;
[0029] Fig. 7 is a plot diagram showing a simulated comparison of a
cumulative oil
production for the HPHA-SAGD process in comparison with SAGD processes; and
[0030] Fig. 8 is a possible flow diagram showing the HPHA-SAGD process.
[0031] 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.
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DETAILED DESCRIPTION
[0032] For the purpose of promoting an understanding of the principles of
the disclosure,
reference will now be made to the features illustrated in the drawings and
specific language will
be used to describe the same. It will nevertheless be understood that no
limitation of the
scope of the disclosure is thereby intended. Any alterations and further
modifications, and any
further applications of the principles of the disclosure as described herein
are contemplated as
would normally occur to one skilled in the art to which the disclosure
relates. It will be
apparent to those skilled in the relevant art that some features that are not
relevant to the
present disclosure may not be shown in the drawings for the sake of clarity
[0033] At the outset, for ease of reference, certain terms used in this
disclosure 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.
[0034] 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. However, the techniques described are not
limited to heavy
oils but may also be used with any number of other subterranean reservoirs to
improve gravity
drainage of liquids. Hydrocarbon compounds may be aliphatic or aromatic, and
may be straight
chained, branched, or partially or fully cyclic.
[0035] "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);
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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.
[0036] "Heavy oil" includes oils which are classified by the American
Petroleum Institute
("API"), as heavy oils, extra heavy oils, or bitumens. The term "heavy oil"
includes bitumen.
Heavy oil may have a viscosity of about 1,000 centipoise (cP) or more, 10,000
cP or more,
100,000 cP or more, or 1,000,000 cP or more. In general, a heavy oil has an
API gravity
between 22.3 API (density of 920 kilograms per meter cubed (kg/m3) or 0.920
grams per
centimeter cubed (g/cm3)) and 10.0 API (density of 1,000 kg/m3 or 1 g/cm3).
An extra heavy
oil, in general, has an API gravity of less than 10.0 API (density greater
than 1,000 kg/m3 or 1
g/cm3). For example, a source of heavy oil includes oil sand or bituminous
sand, which is a
combination of clay, sand, water and bitumen. The recovery of heavy oils is
based on the
viscosity decrease of fluids with increasing temperature or solvent
concentration. Once the
viscosity is reduced, the mobilization of fluid by steam, hot water flooding,
or gravity is possible.
The reduced viscosity makes the drainage quicker and therefore directly
contributes to the
recovery rate.
[0037] Two locations in a subterranean reservoir are in "fluid
communication" when a
path for fluid flow exists between the two locations. For example, fluid
communication exists
between an injection well and a production well when mobilized material can
flow down to the
production well from the injection well for collection and production.
[0038] A "fluid" includes a gas or a liquid and may include, for example,
hot or cold water,
a produced or native reservoir hydrocarbon, an injected mobilizing fluid, hot
or cold liquid
hydrocarbon, solvent, steam, wet steam, gas (e.g., C1, CO2, etc., where C
represents Carbon and
0 represents Oxygen), or a mixture of these, among other materials. "Vapor"
refers to steam,
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wet steam, mixtures of steam and wet steam, any of which could possibly be
used with a
solvent and other substances, and any material in the vapor phase.
[0039] "Facility" is a tangible piece of physical equipment through which
hydrocarbon
fluids are either produced from a subterranean reservoir or injected into a
subterranean
reservoir, or equipment that 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 subterranean reservoir and its delivery outlets.
Facilities may comprise
production wells, injection wells, well tubulars, wellbore head equipment,
gathering lines,
manifolds, pumps, compressors, separators, surface flow lines, steam
generation plants,
processing plants, and delivery outlets. In some instances, the term "surface
facility" is used to
distinguish those facilities other than wells.
[0040] "Pressure" is the force exerted per unit area by gas on the walls of
the volume.
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.
[0041] A "reservoir" or "subterranean reservoir" is a subsurface rock or
sand formation
from which a production fluid or resource can be harvested. The rock 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). The resource is
generally a
hydrocarbon, such as a heavy oil impregnated sand bed.
[0042] "Thermal recovery processes" include any type of hydrocarbon
recovery process
that uses a heat source to enhance the recovery, for example, by lowering the
viscosity of a
hydrocarbon. These processes may use injected mobilizing fluid, such as hot
water, wet steam,
CA 02847759 2014-03-28
dry steam, or solvents alone, or in any combination, to lower the viscosity of
the hydrocarbon.
Such processes may include subsurface processes, such as thermal steam-based
processes, and
processes that use surface processing for the recovery, such as sub-surface
mining and surface
mining. Any of the thermal recovery processes may be used with solvents. For
example,
thermal recovery processes may include CSS, steam flooding, SAGD, SA-SAGD,
thermal
enhanced oil recovery, VAPEX, in-situ combustion, and other such processes.
[0043] "Substantial" when used in reference to a quantity or amount of a
material, or a
specific characteristic of the material, 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.
[0044] 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-
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.
[0045] The term "base" indicates a lower boundary of resources in a
subterranean
reservoir that are practically recoverable, by a thermal recovery process
using an injected
mobilizing fluid, such as steam, solvents, hot water, gas and the like. The
base may be
considered a lower boundary of a pay zone. The lower boundary may be an
impermeable rock
layer, including, for example, granite, limestone, sandstone, shale, and the
like. The lower
boundary may also include layers that, while not completely impermeable,
impede the
formation of fluid communication between a well on one side and a well on the
other side.
Such layers may include inclined heterolithic strata (IHS) of broken shale,
mud, silt, and the like.
The resources within the subterranean reservoir may extend below the base, but
the resources
below the base may possibly not be recoverable, or at least easily
recoverable, with gravity
assisted techniques.
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[0046] "Overburden" refers to the material overlying a subterranean
reservoir. The
overburden may contain rock, soil, and ecosystem above the subterranean
reservoir. During
surface mining the overburden is removed prior to the start of mining
operations.
[0047] "Permeability" is the capacity of a structure to transmit fluids
through the
interconnected pore spaces of the structure. The customary unit of measurement
for
permeability is the milliDarcy (mD).
[0048] "Reservoir matrix" refers to the solid porous material forming the
structure of the
subterranean reservoir. The subterranean reservoir is composed of the solid
reservoir matrix,
typically rock or sand, around pore spaces in which resources such as heavy
oil may be located.
The porosity and permeability of a subterranean reservoir is defined by the
percentage of
volume of void space in the rock or sand reservoir matrix that potentially
contains resources
and water.
[0049] "Fracture" refers to the splitting, breaking, dilating or other
displacement of the
reservoir matrix of the subterranean reservoir.
[0050] "Fracture pressure" refers to the pressure required to fracture a
reservoir matrix
of a subterranean reservoir. Different reservoir matrices in different
subterranean reservoirs
may have different fracture pressures and fracture orientations (i.e.,
vertical or horizontal)
depending upon numerous factors, including but not limited to, geotechnical
stresses, induced
thermal stresses in thermal processes, pore pressure induced stresses, a
timing of pressure
alteration in the subterranean reservoir, a composition of the reservoir
matrix, a size of the
pores of the reservoir matrix, etc.
[0051] "Horizontal planar communication" refers to a fluid communication
that is in a
primarily horizontal plane direction. There may also be a vertical component
to the fluid
communication that is smaller than a horizontal component of the fluid
communication such
that the fluid communication has a substantially horizontal planar
distribution.
[0052] "Minimum" and "maximum" when used in conjunction with a discussion
of
stresses and stress states carry their known and accepted geomechanical
definitions. In
particular, "minimum" stress generally refers to a state in which a stress in
a subterranean
reservoir in one direction is at a minimum when compared with the stress in an
opposing
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direction. Similarly, "maximum" stress is also generally defined in relation
to stress in an
opposing direction.
[0053] In the following description, as an example of a thermal recovery
process,
reference is made to a SAGD process for recovering heavy oil from a
subterranean reservoir.
For better understanding, a brief explanation of a SAGD process is provided
below in order to
highlight some general techniques of a thermal recovery process.
[0054] Fig. 1 illustrates a SAGD process 100 used for accessing resources
in a
subterranean reservoir 102. In the SAGD process 100, injection vapor 104, such
as steam,
solvent and steam-solvent mixtures, can be injected through an injection well
106 into the
subterranean reservoir 102. The injection well 106 may be vertically and then
horizontally
drilled through the subterranean reservoir 102 as shown. A production well 108
may be drilled
vertically and then horizontally through the subterranean reservoir 102 such
that the
production well 108 may lie below the injection well 106 in a SAGD well pair.
Specifically a
horizontal section of the production well 108 may lie below a horizontal
section of the injection
well 106. The injection well 106 and the production well 108 may be drilled
from the same pad
110 at a surface 112 or from a different pad at the surface 112. The surface
112 may be a
surface of the subterranean reservoir 102. Drilling the injection well 106 and
the production
well 108 from the same pad may make it easier for the production well 108 to
track (i.e., follow
a similar path of) the injection well 106. The injection well 106 and the
production well 108
may be vertically separated by a suitable distance, such as about 3 to 10 m.
For example, the
injection well 106 and the production well 108 may be vertically separated by
about 5 m. The
injection well 106 and the production well 108 may be vertically separated by
the
aforementioned amounts in the horizontal and/or vertical sections of the
respective injection
well 106 and production well 108. Any of the aforementioned ranges may be
within a range
that includes or is bounded by any of the preceding examples.
[0055] At start-up of the SAGD process, both the injection well 106 and the
production
well 108 may circulate the injection vapor 104 so that heavy oil between the
injection well 106
and the production well 108 is heated enough to flow and be produced through
at least one of
the injection well 106 and the production well 108. Other start-up techniques
may also be used
13
CA 02847759 2014-03-28
such as liquid solvent injection from the injection well 106 and fluid
production from the
production well 108. Bull-heading techniques may also be used for start-up in
which steam or
hot water is injected at pressures, which are higher than normal operating
pressures (e.g.,
normal operating pressures typically being 1.3 to 5MPa) for the SAGD process,
through the
injection well 106 and fluid is produced from the production well 108.
Further, cyclic steam
stimulation may be used in the injection well 106 and in the production well
108. Other
methods not mentioned above may also be used for start-up of the SAGD process.
[0056] The injection of the injection vapor 104 via the injection well 106
may result in the
mobilization of heavy oil 114 as mobilized heavy oil. The mobilized heavy oil
114 may form a
drainage chamber 118 (i.e., within a vapor chamber) having a generally
triangular cross section
with the production well 108 located at a lower apex 121 of the triangular
cross section as the
mobilized heavy oil 114 possibly drains to the production well 108. The
production well 108
may be switched to a continuous production mode and the injection well 108 may
be placed in
a continuous injection mode, which involves injecting the injection vapor into
the subterranean
reservoir 102. The mobilized heavy oil 114 may be removed to the surface 112
via the
production well 108 in a mixed fluid stream 116 that may contain heavy oil,
condensate and
other material, such as water, gases and the like. Sand filters may be used in
the production
well 108 to decrease sand entrapment of the heavy oil.
[0057] The injection well 106 may comprise injection wells. The production
well 108 may
comprise production wells. If the production well 108 comprises production
wells, the mixed
stream 116 from the production wells may be combined and then sent to a
processing facility
120. If the production well 108 comprises a single well, the mixed stream 116
from the
production well 108 may be sent to the processing facility 120. At the
processing facility 120,
the mixed stream 116 may be separated. The heavy oil 114 in the mixed stream
may be sent
on for further refining 122. The water in the mixed stream 116 may be recycled
to a vapor
generation unit within the processing facility 120 and used to generate the
injection vapor 104
used for the SAGD process 100.
14
CA 02847759 2014-03-28
[0058] Although the injection well 106 may receive the injection vapor 104,
the
production well 108 may also receive the injection vapor 104 or the production
well 108 may
receive the injection vapor 104 instead of the injection well 106.
[0059] In a subterranean reservoir containing heavy oil, a thermal recovery
process, such
as a SAGD process, of the above kind, can be carried out to reduce a viscosity
of the heavy oil
enabling production of the heavy oil. Within such a subterranean reservoir,
one or more
thermal recovery well pairs may be placed for the production of the heavy oil.
A vapor
chamber having a generally triangular cross section forms above each thermal
recovery well
pair due to the injection vapor injected via the injection well of the thermal
recovery well pair.
The injection vapor reduces the viscosity of the heavy oil for mobilization
and possibly
production of the heavy oil. The vapor chamber forms an area from which the
heavy oil may be
mobilized and eventually possibly drained and depleted during the thermal
recovery process.
[0060] Total heavy oil recovery from the thermal recovery process is
affected by a
distribution of injection vapor in the subterranean reservoir and fluid
communication within the
subterranean reservoir, both of which affect a temperature distribution in the
subterranean
reservoir. Given that the vapor chambers have a generally triangular cross
section, injection
vapor is distributed in the subterranean reservoir within the generally
triangular shape of the
vapor chambers. This generally triangular cross section may exacerbate uneven
distribution of
injection vapor within the subterranean reservoir when thermal recovery well
pairs are placed
nearly parallel to each other in the subterranean reservoir. Portions of the
subterranean
reservoir that fall between the generally triangular cross section of the
vapor chambers may
not receive a temperature increase from the injection vapor, which may result
in heavy oil in
the portions of the subterranean reservoir that are outside of the vapor
chambers not being
heated by the injection vapor. The lack of heating may result in heavy oil
between thermal
recovery well pairs that may remain unmobilized and thus not recovered after
recovery
operations in the subterranean reservoir have finished.
[0061] The present disclosure may include methods of recovering heavy oil
from a
subterranean reservoir.
CA 02847759 2014-03-28
[0062] The thermal recovery well pair may be shown by way of example in
Fig. 3 which
illustrates an example cross section of multiple thermal recovery well pairs
304, 306. While Fig.
3 shows two thermal recovery well pairs 304, 306 as an example, there may be
only a single
thermal recovery well pair 304, 306 or there may be more than two thermal
recovery well pairs
304, 306. The general discussion below will use the example of one thermal
recovery well pair
304, 306. Further discussion of other examples will follow.
[0063] The thermal recovery well pair 304, 306 may be any suitable well
pair in a thermal
recovery process. The thermal recovery well pair 304, 306 may include an
injection well 314,
316 and a production well 324, 326. The injection well 314, 316 may receive
injection vapor.
The injection well 314, 316 may therefore be for injecting the injection vapor
into a
subterranean reservoir 302. The injection vapor may be steam, solvent or a
steam-solvent
mixture. The injection vapor injected into the subterranean reservoir 302 may
form a vapor
chamber 334, 336. The production well 324, 326 may receive heavy oil from the
subterranean
reservoir 302. The production well 324, 326 may therefore be for recovering
heavy oil from the
subterranean reservoir 302. The production well 324, 326 may be at an
elevation below the
injection well 314, 316. Specifically, a horizontal portion of the production
well 324, 326 may
be at an elevation below a horizontal portion of the injection well 314, 316.
The injection well
314, 316 may include the horizontal portion of the injection well 314, 316
(i.e., horizontal
injection well portion) and a vertical portion of the injection well 314, 316
(i.e., vertical injection
well portion). Similarly, the production well 324, 326 may include the
horizontal portion of the
production well 324, 326 (i.e., horizontal production well portion) and a
vertical portion of the
production well 324, 326 (i.e., vertical production well portion). The
horizontal injection well
portion may extend from the vertical injection well portion. The horizontal
production well
portion may extend from the vertical production well portion.
[0064] The method of recovering heavy oil may comprise providing an infill
well in an
area laterally spaced apart from the thermal recovery well pair.
[0065] The infill well may be shown by way of example in Fig. 3 which
illustrates an
example cross section of an infill well 310. While Fig. 3 shows a single
infill well 310 as an
16
CA 02847759 2014-03-28
. .
example, there may be more than one infill well 310. The general discussion
below will use the
example of one infill well 310. Further discussion of other examples will
follow.
[0066] The infill well 310 may be, for example, a well in a CSS
process. The infill well 310
may be placed in an area of the subterranean reservoir 302 containing heavy
oil that has not or
is not being mobilized by the thermal recovery process. The infill well 310
may be placed in this
area to establish horizontal planar communication in the area thereby
assisting in the
mobilization and production of heavy oil from this area. A horizontal portion
of the infill well
310 may be positioned at the same elevation, lower than, higher than or at
variable elevation
compared to the horizontal portion of the production well 324, 326. While Fig.
3 illustrates the
horizontal portion of the infill well 310 being positioned at or below the
elevation of the
horizontal portion of the production well 324, 326, this relative position may
change according
to the position of the thermal recovery well pair 304, 306 within the
subterranean reservoir 302
and/or the geological features of the subterranean reservoir 302.
[0067] The method of recovering heavy oil may comprise injecting
injected fluid via the
infill well 310 into the subterranean reservoir 302. The injected fluid may be
a gas or a liquid
and may include, for example, hot or cold water, a produced or native
reservoir hydrocarbon,
an injected mobilizing fluid, hot or cold liquid hydrocarbon, solvent, steam,
wet steam, gas (e.g.,
C1, CO2, etc., where C represents Carbon and 0 represents Oxygen), or a
mixture of these,
among other materials.
[0068] The injected fluid may be injected at a time during which
the injected fluid
establishes a horizontal planar communication path between the infill well 310
and the vapor
chamber 334, 336 of the thermal recovery well pair 304, 306. The initiation of
the infill well's
injections of the injected fluid can be based on a start time of the thermal
recovery well pair
304, 306 operations or according to a progress of the thermal recovery well
pair 304, 306
operations. The initiation can be affected by the individual properties of the
subterranean
reservoir 302. The primary objective of the injections of the injected fluid
from the infill well
310 is to create a horizontal planar communication, which is a type of fluid
communication,
between the infill well 310 and the vapor chamber 334, 336.
17
CA 02847759 2014-03-28
[0069] The infill well 310 injects the injected fluid into the subterranean
reservoir 302
early in the thermal recovery process at a time when such horizontal planar
communication can
be used to distribute injection vapor injected from the injection well 314,
316 in a generally
horizontal plane and improve heat distribution within the subterranean
reservoir 302. "Early"
in the thermal recovery process may be at any time when the establishment of
horizontal
planar communication can distribute the injection vapor in a substantially
horizontal plane. The
time during which the injected fluid is injected from the infill well 310 may
be any suitable time
during which the injected fluid establishes the horizontal planar
communication path between
the infill well 310 and the vapor chamber 334, 336 of the thermal recovery
well pair 304, 306.
For example, the time may be upon formation of the vapor chamber 334, 336,
prior to multiple
vapor chambers 334, 336 merging, prior to the vapor chamber 334, 336 reaching
an
overburden of the subterranean reservoir 302, no later than when a height of
the vapor
chamber 334, 336 is no more than 5% of a height of the subterranean reservoir
302 above the
thermal recovery well pair 304, 306, or after the injection vapor causes a
primarily minimum
vertical stress state in a reservoir matrix of the subterranean reservoir 302.
A primarily
minimum vertical stress state in the subterranean reservoir 302 will be
discussed in greater
detail below.
[0070] When vapor chambers 334, 336 of multiple thermal recovery well pairs
304, 306
have merged, the likelihood of creating a horizontal planar communication is
reduced and a
probability of creating a vertical fluid communication between the infill well
310 and the
merged vapor chamber 334, 336 is increased. The increased probability of
creating a vertical
fluid communication after the vapor chambers 334, 336 have merged is due to a
vapor
chamber created by the infill well 310 growing in a primarily vertical
direction in order to merge
with the merged vapor chambers 334, 336, which is promoted by temperature
distribution in
the subterranean reservoir 302 caused by the injection vapor from the
injection well 314, 316.
Distributing the injection vapor in a primarily vertical plane does not
improve heat distribution
and hydrocarbon recovery as effectively as a process taking advantage of
horizontal planar
communication. By injecting the injected fluid via the infill well 310 at a
time that is early in the
thermal recovery process, the resulting fluid communications are primarily
horizontal planar
18
CA 02847759 2014-03-28
fluid communications and not primarily vertical fluid communications.
Injecting the injected
fluid early in the thermal recovery process results in a vapor chamber from
the infill well 310
that is not encouraged to grow in the vertical direction in order to merge
with the merged
vapor chambers 334, 336. Further, injecting the injected fluid at high
pressures from the infill
well 310 and/or by having the subterranean reservoir 302 in a state favoring
maximum
horizontal stress, the resulting fluid communications are primarily horizontal
planar fluid
communications and not primarily vertical fluid communications.
[0071] The infill well 310 may inject injected fluid into the subterranean
reservoir 302 at a
pressure that may be greater than a fracture pressure of the surrounding
reservoir matrix of
the subterranean reservoir 302. The pressure may be sufficient to cause
fracture or dilation of
the reservoir matrix of the subterranean reservoir 302 in the area between the
infill well 310
and the thermal recovery well pair 304, 306. Injection of the injected fluid
at such a pressure
may cause the reservoir matrix of the subterranean reservoir 302 to fracture
or dilate. As a
result of an appropriate timing of the injections of the injected fluid from
the infill well 310, a
stress distribution in the reservoir matrix between the infill well 310 and
the thermal recovery
well pair 304, 306 can be at a minimum vertical stress state and a maximum (or
primarily)
horizontal stress state. Injections of the injected fluid from the infill well
310 at such a time
may cause horizontal fractures in the reservoir matrix of the subterranean
reservoir 302, which
provide the horizontal planar communication path and result in the horizontal
planar
communication.
[0072] The fracture pressure and orientation (i.e., vertical, horizontal,
or a mixture of
both) in the subterranean reservoir 302 is dependent upon geomechanical
stresses in the
reservoir matrix. The geomechanical stress can be due to a natural
geotechnical state of
stresses in the reservoir matrix. The geomechanical stress could be induced
due to pore
pressure induced stresses or by temperature changes, which will be thermal
induced stress.
The initial geomechanical stress state (e.g., pore, geotechnical, etc.) in a
shallow heavy oil
subterranean reservoir matrix generally has minimum vertical effective stress
favoring a
horizontal fracture if fluid is injected at or above fracture pressure. For
example, in the
Athabasca oil sand region that has relatively low depths (e.g., less than 400
meters), the weight
19
CA 02847759 2014-03-28
of the overburden released due to the melting of an ancient glacier results in
natural
geotechnical stresses that are mainly at a minimum vertical stress state. If
the reservoir
pressure is increased above the weight of the overburden, the subterranean
reservoir may part
in a horizontal planar manner causing the overburden to lift. Induced thermal
and pore
pressure stresses can convert a subterranean reservoir that is in a minimum
horizontal stress
state to a minimum vertical stress state due to lateral expansion of the
reservoir matrix and
increasing the horizontal stresses.
[0073] In shallow subterranean reservoirs with a minimum effective vertical
stress state,
by starting injected fluid injections from the infill well 310 relatively
early, a horizontal fracture
and therefore a horizontal planar communication between the thermal recovery
well pair 304,
306 can be established. In cases where the subterranean reservoir is deeper
(e.g., possibly
having a larger or heavy overburden) or has an initial maximum vertical stress
state, the stress
state may favor a vertical fracture. However, due to a temperature increase in
the
subterranean reservoir caused by the thermal recovery process through
injections from the
thermal recovery well pair 304, 306 and the infill well 310, thermally induced
stresses may shift
a geomechanical stress state of such a subterranean reservoir in a region
between the thermal
recovery well pair 304, 306 to a minimum vertical stress state, enabling
horizontal fractures
between the infill well 310 and the thermal recovery well pair 304, 306 to
produce horizontal
planar communication.
[0074] Commencement of injections from the infill well 310 can be
determined, for
example, by using a geomechanical simulation of the reservoir matrix to
determine the best
time for starting fluid injections based on properties of the subterranean
reservoir 302. A
geologic model of the subterranean reservoir may be created and may include,
for example,
open hole log data, cased hole log data, core data, recovery process well
trajectories, 2-
dimensional (2D) seismic data, 3-dimensional (3D) seismic data, or other
remote surveying
data, or any combination of these. For example, prior to the start of the
thermal recovery
process, a geologic model can be created for the development area. Available
open hole, cased
hole log, 2D and 3D seismic data, and knowledge of the depositional
environment setting can
all be used in the construction of this model. The information generated by
the model may
CA 02847759 2014-03-28
. .
then be used in a reservoir simulation model to provide predictions of fluid
flow, reservoir
geometry, and the like. The geologic model, reservoir model and knowledge of
surface access
constraints can then be used to complete the layout of the infill well(s)
and/or the thermal
recovery well pair(s). After the infill well(s) and/or the thermal recovery
well pair(s) have been
drilled, data collected during their drilling in addition to data collected
during the operation of
the thermal recovery process, such as cased hole logs including temperature
logs, observation
wells, additional time lapse seismic or other remote surveying data, can be
used to update the
geologic model, which may be used to predict the evolution of the depletion
patterns as the
recovery process matures. The depletion patterns within the subterranean
reservoir may be
influenced by well placement decisions, geological heterogeneity, well
failures, and day to day
operating decisions.
[0075] The infill well 310 may start injecting the injected fluid
after a small vapor chamber
334, 336 has formed above the thermal recovery well pair 304, 306. Such a
"small" vapor
chamber 334, 336 can be, for example, a height of no more than 5% of the
height of the
subterranean reservoir 302 above the thermal recovery well pair 304, 306, or
any height within
this range. An actual height of the vapor chamber 334, 336 at the time that
infill well
operations start may be determined on an individual basis according to the
factors outlined
above.
[0076] The horizontal planar communication path may enable
substantially horizontal
planar distribution of the injection vapor from the injection well 314, 316.
Typically there is an
emphasis on growth and expansion of the vapor chamber 334, 336 of the thermal
recovery well
pair 304, 306 in a vertical direction. As the injection vapor is injected into
the subterranean
reservoir 302, the vapor chamber 334, 336 grows vertically until the vapor
chamber 334, 336
eventually reaches the overburden of the subterranean reservoir 302. Injecting
injected fluid
into an area between thermal recovery well pairs 304, 306 or beside a thermal
recovery well
pair 304, 306 during an early stage of a thermal recovery process (e.g., prior
to the vapor
chambers of different thermal recovery well pairs 304, 306 merging or reaching
the overburden
of the subterranean reservoir 302) promotes fluid communication in a
substantially horizontal
direction, which may create the horizontal planar communication path. The
injection vapor
21
CA 02847759 2014-03-28
from the injection wells 314, 316 may travel along the horizontal planar
communication path
between the thermal recovery well pair 304, 306 and the infill well 310. The
horizontal planar
communication path may enable the injection vapor from the injection well 314,
316 to
traverse through the subterranean reservoir 302 in a generally horizontal
direction. Such
horizontal traversal of the injection vapor provides improved fluid
communication between the
thermal recovery well pair 304, 306 and the infill well 310 and promotes
mobilization of heavy
oil in an area between the thermal recovery well pair 304, 306 and outside the
vapor chamber
334, 336.
[0077] Early establishment of the horizontal planar communication path
enabling the
injection vapor to travel in a somewhat horizontal manner and provide heating
in an area of the
subterranean reservoir 302 along the horizontal planar communication path
helps improve
performance of the thermal recovery process as well as improves heavy oil
production rates
early in the life span (e.g., prior to 1500 days) of the thermal recovery
process. Fig. 6 shows
performance and improvement of heavy oil production rates with an early
establishment of the
horizontal planar communication where SAGD is the thermal recovery process.
When SAGD is
used as the thermal recovery process, the process of establishing horizontal
planar
communications in the manner set out above may be called horizontal planar
heating assisted
SAGD (HPHA-SAGD).
[0078] The horizontal planar communication path may provide the horizontal
planar
communication. The horizontal planar communication may allow for the
substantially
horizontal planar distribution of the injection vapor.
[0079] The method of recovering heavy oil may comprise producing produced
fluids from
the infill well 310 to at least partially recover heavy oil from the
horizontal planar
communication path. The produced fluids may include the injected fluid that is
injected via the
infill well 310, heavy oil, and other fluids from within the subterranean
reservoir 302, such as,
for example, water. The heavy oil may flow to the infill well 310 by natural
conditions or as a
result of some temperature increase from a thermal recovery process occurring
as a result of
the thermal recovery well pair or due to mobilization from the injected fluid
(e.g., reduced
viscosity from a solvent if the injected fluid includes a solvent, or reduced
viscosity from
22
CA 02847759 2014-03-28
. .
increased temperature if the injected fluid is a heated fluid, or increased
pressure from
injection of the injected fluid at a pressure higher than that currently in
the subterranean
reservoir 302, etc.). The produced fluids may be the result of the injected
fluid moving through
the reservoir matrix to create the horizontal planar communication path. That
is, the produced
fluid may include components, such as heavy oil, that are in the horizontal
planar
communication path and are to be removed from the horizontal planar
communication path.
The produced fluids may also be components, such as water or heavy oil that
has an already
reduced viscosity, that would drain under gravity to the infill well 310.
[0080] The infill well 310 may be in an area laterally spaced
apart from the thermal
recovery well pair 304, 306. The infill well 310 may be substantially parallel
to or angular to the
thermal recovery well pair 304, 306. The relative configuration of the thermal
recovery well
pair 304, 306 and the infill well 310 may be based on geological
configurations and properties
of the subterranean reservoir 302. The infill well 310 may be placed within
the subterranean
reservoir 302, and spaced appropriately from the thermal recovery well pair
304, 306, to enable
the establishment of horizontal planar communication with the vapor chamber
334, 336 of the
thermal recovery well pair 304, 306. The infill well 310 may be placed in an
area of the
subterranean reservoir 302 containing heavy oil that has not or is not being
mobilized by the
thermal recovery process.
[0081] The thermal recovery well pair 304, 306 may comprise two
thermal recovery well
pairs 304, 306 or more than two thermal recovery well pairs 304, 306. If the
thermal recovery
well pair 304, 306 comprises two thermal recovery well pairs 304, 306, the
infill well 310 may
be between the two thermal recovery well pairs 304, 306 and laterally spaced
apart from each
of the two thermal recovery well pairs 304, 306. If the thermal recovery well
pair 304, 306
comprises more than two thermal recovery well pairs304, 306, the infill well
310 may comprise
infill wells 310. One of the infill wells 310 may be between two or more than
two thermal
recovery well pairs 304, 306 and be laterally spaced apart from each of the
two or more than
two thermal recovery well pairs304, 306.
[0082] There may be multiple infill wells 310 that may be
generally parallel to or angular
to one or more thermal recovery well pairs 304, 306 and/or with respect to
other infill well(s)
23
CA 02847759 2014-03-28
310. The relative configuration of the thermal recovery well pairs 304, 306
and the infill well(s)
310 can be determined based on configurations of possible existing thermal
recovery well pairs
304, 306 and the geological configuration and properties of the subterranean
reservoir 302.
For example, if there is a large lateral spacing between the thermal recovery
well pairs 304, 306
(e.g., greater than 150 meters depending on the properties of the subterranean
reservoir 302),
then there may be multiple infill wells 310 spaced between each thermal
recovery well pair
304, 306 to create horizontal planar communication between the thermal
recovery well pairs
304, 306. Closer lateral spacing of the thermal recovery well pairs 304, 306
and the infill well(s)
310 contributes to quicker establishment of horizontal planar communications
but may add to
a cost of recovering the heavy oil. In general, the infill wells may be in a
generally alternating
configuration with the thermal recovery well pairs with at least one infill
well possibly being
provided in between adjacent thermal recovery well pairs.
[0083] The method of recovering heavy oil may comprise producing heavy oil
from at
least one of (i) the infill well after the horizontal planar communication has
been established
and (ii) the production well to recover the heavy oil from the subterranean
reservoir. The
heavy oil may flow down to the production well due to a reduction in viscosity
as previously
described and be produced from the production well or the infill well.
[0084] The infill well 310 may be an injector-producer well in that the
infill well 310 can
act as an injection well by injecting the injected fluid into the subterranean
reservoir 302 as well
as act as a production well by producing the produced fluids or heavy oil from
the subterranean
reservoir 302. After the horizontal planar communications have been
established, the infill well
310 may operate in a production mode producing heavy oil from the subterranean
reservoir
202.
[0085] The method of recovering heavy oil may comprise repeatedly injecting
the
injected fluid and producing the produced fluid. The infill well 310 may
alternate between
operating as an injection well and as a production well.
[0086] The infill well 310 may inject a mobilizing fluid into the
subterranean reservoir 302
and then inject an infill well vapor into the subterranean reservoir 302. The
mobilizing fluid
may be cold water, hot water, cold liquid hydrocarbon solvent, hot liquid
hydrocarbon solvent,
24
CA 02847759 2014-03-28
,
steam, wet steam, gas and a mixture of at least two of cold water, hot water,
cold liquid
hydrocarbon solvent, hot liquid hydrocarbon solvent, steam, wet steam and gas.
The infill well
vapor may be steam, solvent and steam-solvent mixture. The infill well 310 may
repeatedly
inject the infill well vapor and produce the produced fluids.
[0087] The infill well 310 generally initiates its operations by
performing a first fluid
injection cycle. The first fluid injection cycle injects the injected fluid
into the subterranean
reservoir 302 to establish horizontal planar communication between the thermal
recovery well
pair 304, 306 and the infill well 310. The injected fluid during this first
fluid injection cycle can
be, for example, hot or cold water, gas (such as C1, CO2, etc.), steam, wet
steam, cold or hot
liquid hydrocarbon solvent or any mixture of these or any other similar
suitable fluid. The
injected fluid is injected from the infill well 310 until either an injection
pressure drops or a high
pressure is observed at the thermal recovery well pair 304, 306, which may
indicate that
horizontal planar communication has been established at least between the
thermal recovery
well pair 304, 306 and the infill well 310.
[0088] The properties of the subterranean reservoir 302 and the
heavy oil may be such
that the heavy oil begins to drain down towards the infill well 310 as soon as
the infill well 310
has been drilled. In such a case, the infill well 310 may operate as a
production well prior to
performing the first fluid injection cycle to remove the heavy oil that has
already been
mobilized.
[0089] Depending upon the injected fluid used for the first fluid
injection cycle, the infill
well 310 may switch to a production cycle after being used in an injection
cycle. If the injected
fluid from the first fluid injection cycle is a vapor that has mobilized the
heavy oil above the
infill well 310 then the production cycle may commence immediately after the
first fluid
injection cycle and may continue for either a specified period of time or
until no more produced
fluid is produced. If the injected fluid in the first fluid injection cycle is
a mobilizing fluid other
than vapor (e.g., hot or cold water, gas, hot or cold liquid hydrocarbon
solvent, etc.) then the
first fluid injection cycle may be followed by a vapor injection cycle
injecting an infill well vapor
to heat the heavy oil along the horizontal planar communication path
established after
injection of the mobilizing fluid. The infill well vapor may be, for example,
steam, solvent, and
CA 02847759 2014-03-28
steam-solvent mixtures. Such subsequent injections of the infill well vapor
may continue until,
for example, the injection pressure drops (e.g. to below an initial injection
pressure) or until
high pressure is observed at the thermal recovery well pair 304, 306. The
first few cycles of
injections of the injected fluid, the mobilizing fluid and/or the infill well
vapor create a
horizontal planar communication path within the reservoir matrix of the
subterranean reservoir
302 and mobilize heavy oil along that horizontal planar communication path for
possible
removal by the infill well 310 during the production cycle with the produced
fluids. If the
injected fluid injected during the first fluid injection cycle is the
mobilizing fluid but does
mobilize the heavy oil for production, then injection of the infill well vapor
may not be
performed prior to the production cycle.
[0090] The operation of the infill well 310 alternating between injection
of vapor and/or
fluids and production of produced fluids may continue until horizontal planar
communication
between the thermal recovery well pair 304, 306 and the infill well 310 is
established. This
operation may continue until after this horizontal planar communication is
established. This
operation may continue through the life of the thermal recovery process in the
subterranean
reservoir 302.
[0091] There may be multiple cycles of injection and production by the
infill well 310 that
are performed until the horizontal planar communication is established and can
be sustained
and the cold heavy oil does not plug the horizontal planar communication
paths. Even if
horizontal planar communication between the thermal recovery well pair 304,
306 and the infill
well 310 is established after the first injection cycle of the infill well
310, the horizontal planar
communication paths may be blocked by viscous heavy oil not removed during the
production
cycle or that may have flowed into the horizontal planar communication paths
from cold parts
of the subterranean reservoir 302 that are above the horizontal planar
communication paths.
After the horizontal planar communication paths have been established, the
infill well 310 may
operate primarily as a production well. At this point, injection vapor from
the vapor chamber
334, 336 may flow into the horizontal planar communication paths and heat up
the heavy oil
above the horizontal planar communication paths, which will mobilize and drain
down into the
production well 324, 326 and the infill well 310. However, the infill well 310
may also continue
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to have injection cycles to inject the infill well vapor as necessary to
maintain the horizontal
planar communication paths and mobilize viscous heavy oil in the horizontal
planar
communication paths at predetermined times or at requested times if there is a
blockage in the
horizontal planar communication.
[0092] The injected fluid may be cyclically injected from the infill well
310 and the
produced fluid may be produced to create solvent fingers. In subterranean
reservoirs where
the stress state may not favor horizontal fractures, solvent fingering may
offer an alternate
mechanism for generating horizontal planar communication. Solvent fingering is
a mechanism
whereby the injected fluid invades a subterranean reservoir that is saturated
with the heavy oil,
and occurs when solvent is injected into heavy oil. The injected fluid is less
viscous than the
heavy oil in the subterranean reservoir. Solvent fingers will propagate
towards regions of lower
pressure. The horizontal planar communication can be generated by cyclic
injection and
production of solvent from the infill well 310 to establish a finger network
of high mobility. The
solvent fingers form, at least in part, path(s) of the horizontal planar
communication.
[0093] The infill well 310 may operate to inject the injected fluid and
produce the
produced fluid using known processes to establish horizontal planar
communication in
combination with the above mentioned timing of the commencement of operations
from the
infill well 310. For example, the infill well 310 may operate using at least
one of cyclic steam
stimulation, and cycle solvent stimulation.
[0094] The infill well 310 may be completed with flow control devices
configured to
evenly distribute the injected fluid. For example, the infill well 310 may
comprise a flow control
devide of a limited entry perforation (LEP) type in which the infill well 310
has only a limited
number of perforations for injection of the injected fluid. A sufficient fluid
injection rate from
the infill well 310 is used to restrict capacity of the perforations so as to
increase uniformity of
injection rate across the entire infill well 310. The increased uniform
injection rate enhances
uniform vaporing and fracturing in the subterranean reservoir 302. The total
area of
perforations may be selected to limit the influx of vapor during continuous
production. The
infill well 310 may use an inflow-outflow control device (ICD-OCD) to improve
the uniform fluid
27
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. .
injection and production along the infill well 310. This enhances uniform
vapor injection
conformance and fracturing the subterranean reservoir.
[0095] In a case where the infill well 310 and the thermal
recovery well pairs 304, 306 are
not parallel, fracture or communication may be formed in a part of the
subterranean reservoir
302 where the infill well 310 has a closer lateral spacing to a production
wells 324, 326 and not
formed in an area further away from the production wells 324, 326. The use of
an inflow-
outflow control device (ICD-OCD) on the infill well 310 and an inflow control
device on the
production wells 324, 326 may be employed to overcome concerns and improve
uniform
injected fluid injection distribution and conformance along the infill well
310.
[0096] The method of recovering heavy oil may comprise providing
two thermal recovery
well pairs in a subterranean reservoir. The two thermal recovery well pairs
may be any suitable
well pair from a thermal recovery process. The two thermal recovery well pairs
may be laterally
spaced apart from each other. Each of the two thermal recovery well pairs may
include an
injection well and a production well. Each of the injection wells may be
configured as
previously described with each of the injection wells injecting injection
vapor to form a vapor
chamber above each of the thermal recovery well pairs. The injection vapor may
comprise the
injection vapor as previously described. Each of the production wells may be
configured as
previously described.
[0097] The method of recovering heavy oil may comprise providing
an infill well in the
subterranean reservoir. The infill well may be positioned and/or configured
like the infill well
previously described.
[0098] The method of recovering heavy oil may comprise injecting
the injection vapor
from each of the injection wells into the subterranean reservoir. The
injection vapor may form
the vapor chambers above each of the two thermal recovery well pairs when the
injection
vapor is injected into the subterranean reservoir.
[0099] The method of recovering heavy oil may comprise
establishing horizontal planar
communications between the infill well and the vapor chambers of the two
thermal recovery
well pairs. The horizontal planar communications may be established by
injecting the injected
fluid via the infill well into the subterranean reservoir after formation of
the vapor chambers.
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The injected fluid may comprise the injected fluid as previously described.
The injected fluid
may be injected at a time and under conditions and pressures previously
described.
[00100] The method of recovering heavy oil may comprise producing fluids
from each of
the production wells to recover the heavy oil. Details of the production fluid
may be the same
as those previously described in this application. The heavy oil may flow to
the infill well in the
same manner as previously described.
[00101] The infill well may operate in an injection mode or in a production
mode as
previously described. Establishing the horizontal planar communication may
comprise
alternating operating the infill well between an injection mode to inject the
injected fluid and a
production mode to produce the produced fluid from the infill well until the
horizontal planar
communication is established.
[00102] The method of recovering heavy oil may comprise operating the
infill well in a
production mode to produce a produced fluid after establishing the horizontal
planar
communication.
[00103] The method of recovering heavy oil may comprise operating the
infill well in one
of a production mode to produce the produced fluid and an injection mode to
inject the
injected fluid after establishing the horizontal planar communication. The
infill well may
operate in the injection mode at predetermined intervals to ensure that the
horizontal planar
communication remains established as previously described. The infill well may
operate in the
injection mode at requested times when there is a blockage in the horizontal
planar
communication as previously described.
[00104] The infill well 310 may inject a mobilizing fluid into the
subterranean reservoir
302, inject an infill well vapor into the subterranean reservoir 302 and then
produce the
produced fluid. The mobilizing fluid may be the mobilizing fluid as previously
described. The
infill well vapor may be the infill well vapor as previously described. The
infill well 310 may
repeatedly inject the infill well vapor and produce the produced fluids until
the horizontal
planar communication is established.
[00105] Establishing the horizontal planar communication may be performed
by any
thermal recovery process.
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[00106] The horizontal planar communication path may enable the injection
vapor from
the injection wells 314, 316 to travel along the horizontal planar
communication paths forming
the horizontal planar communication between the thermal recovery well pairs
304,306 and the
infill well 310. By providing such horizontal planar communication paths, the
distribution of the
injection vapor between the thermal recovery well pairs 304, 306 is improved.
With an
improved injection vapor distribution, a heat distribution and mobilization of
the heavy oil
within the subterranean reservoir 302 improves and contact of the injection
vapor or injected
fluid with the overburden is reduced, which in turn reduces heat loss to the
overburden and
improves the oil-to-steam ratio of the thermal recovery process, which is
illustrated in Fig. 5
with SAGD as the specific thermal recovery process.
[00107] Some subterranean reservoirs have a high mobility water saturated
sand zone
located at or near the bottom of a pay zone containing the heavy oil. This
high mobility zone
may be used for sub-fracture fluid injections to establish horizontal planar
communication. For
example, the infill well 310 may be placed within this high mobility zone and
fluid or vapor may
be injected from the infill well 310 into this high mobility zone to establish
horizontal planar
communication.
[00108] Fig. 4A-4D illustrates simulated temperature distributions in the
subterranean
reservoir after the horizontal planar communication between the infill well
310 and the thermal
recovery well pair 304, 306 has been attained at various time points. Figs. 4A-
4D illustrate the
use of SAGD as the exemplary thermal recovery process. The darkest areas 402
in Figs. 4A-4D
show areas in the subterranean reservoir containing immobilized, unrecovered
heavy oil while
the middle grey areas 404 illustrate a depleted zone in which the heavy oil
has been mobilized
and recovered. The lighter transition areas 406 between the dark areas 402 and
the middle
grey areas 404 in Figs. 4A-4D show areas in the subterranean reservoir in
which the heavy oil
has been heated for mobilization and recovery of these heavy oil has
commenced. Fig. 4A
illustrates the temperature distribution in the subterranean reservoir after
horizontal planar
communication between an infill well 408 and a SAGD well pair 410 has been
established (at
approximately 538 days, which is considered to be relatively early in the life
of SAGD
operations). The temperature distribution shown in Fig. 4A is for the infill
well 408 that started
CA 02847759 2014-03-28
. .
injecting the injected fluid to establish horizontal planar communication with
the SAGD well
pair 410 shortly after the vapor chamber of the SAGD well pair 410 was
established according
to the discussions above (e.g., approximately 500 days). Fig. 48 illustrates a
simulated
temperature distribution in the subterranean reservoir with the infill well
408 and the SAGD
well pair 410 (e.g., at approximately 800 days). Fig. 48 illustrates a
temperature distribution in
the subterranean reservoir after approximately 3-4 cycles of
injection/production from the infill
well 408 with the third and fourth cycles opening horizontal planar
communication paths again
that were established in the first and second injection/production cycles.
Fig. 4C illustrates a
simulated temperature distribution in the subterranean reservoir with the
infill well 408 and
the SAGD well pair 410 after 1000 days. Fig. 4D illustrates a simulated
temperature distribution
in the subterranean reservoir with the infill well 408 and the SAGD well pair
410 after
approximately 1300 days.
[00109] As can be seen from Figs. 4A-4D, in comparison with Fig. 2,
timing the injected
fluid injections from the infill well to just after formation of the SAGD
vapor chambers and
establishing a horizontal planar communication results in improved heat
distribution and
vertical growth of a horizontal planar vapor chamber formed from merging of
the vapor
chambers of the SAGD well pairs and a vapor chamber of the infill well. This
improved
performance is in comparison with injecting the injected fluid to attempt to
establish fluid
communication with the SAGD vapor chamber after the SAGD vapor chambers have
formed
and merged (state shown at 1470 days in Fig. 2). In this case, the infill well
206 tends to form a
vapor chamber having a generally triangular cross section similar to the SAGD
vapor chambers
and not a vapor chamber having an increased horizontal planar distribution
with a heat
distribution in the subterranean reservoir between the infill well 206 and the
SAGD well pairs
204 that is not as effective as the horizontal planar vapor chamber in heating
cold unrecovered
heavy oil in the subterranean reservoir and minimizing vapor exposure to the
overburden to
reduce heat loss.
[00110] Fig. 5 illustrates simulated cumulative oil-steam ratios
for traditional SAGD
operations, CSS-SAGD operations and horizontal planar heating assisted SAGD
(HPHA-SAGD)
operations (presently described process). Fig. 6 illustrates simulated oil
production rates for
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traditional SAGD operations, CSS-SAGD operations and HPHA-SAGD operations
(presently
described process). Fig. 7 illustrates simulated cumulative oil production for
traditional SAGD
operations, CSS-SAGD operations and HPHA-SAGD operations (presently described
process). As
can be seen in Figs. 5-7, the process described herein provides improved
cumulative oil-steam
ratios sooner than SAGD and CSS-SAGD operations as well as higher oil rates
and cumulative oil
production sooner than the compared other processes.
[00111] Fig. 8 is a drawing illustrating an exemplary flow diagram of a
method 800.
Thermal recovery well pairs, each comprising an injection well and a
production well, are
provided in step 802 and operated in step 804. The infill well is provided in
step 806. The
thermal recovery process in the subterranean reservoir may have already
commenced when
the infill well is drilled, although the infill well may be provided prior to
such commencement
(e.g., prior to step 804). A timing of the start of injected fluid injections
by the infill well into
the subterranean reservoir is determined in step 808. The infill well may
start injections when
the injected fluid injected from the infill well into the subterranean
reservoir can establish
horizontal planar communication paths that may enable the horizontal planar
communications.
Such a time may also be prior to the merging of the vapor chambers of
different thermal
recovery well pairs. Such a time may also be when injection vapor injected
from one of the
injection wells has caused a primarily vertical stress state in a reservoir
matrix of the
subterranean reservoir. The infill well injects the injected fluid into the
subterranean reservoir
at the determined time in step 810. Thereafter, the infill well may perform
cyclic operations,
alternating between injecting the injected fluid into the subterranean
reservoir and recovering
produced fluids therefrom as a production well in step 812 until horizontal
planar
communication between the thermal recovery well pair vapor chambers is
established. The
recovered produced fluids may include heavy oil along with some of the
injected fluids. With
the infill well injecting the injected fluid into the subterranean reservoir,
the infill well forms an
infill well horizontal planar vapor chamber in a depleted zone. Once the
infill well and the
thermal recovery well pair vapor chambers are in fluid communication, as
determined in step
814, the infill well may operate in a production well mode in step 816. An
infill well production
mode condition is assessed in step 818. The infill well production mode
condition may be
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based on whether the horizontal planar communication is still active, the
infill well is still
producing heavy oil or a predetermined period of time has passed since the
horizontal planar
communications have been established. For example, the infill well production
mode condition
may be satisfied if the horizontal planar communication is still active, or if
the infill well is still
producing heavy oil, or if a time is within a predetermined period of time
after the horizontal
planar communication has been established and within the predetermined period
of time the
production mode for the infill well is to continue. If the infill well
production mode condition is
satisfied then the infill well may continue in the production mode. If the
infill well production
mode condition is not satisfied the infill well may temporarily operate in an
injection mode in
step 820 before checking the infill well production condition again and
possibly returning to the
production mode.
[00112] While the above have discussed the use of infill well(s) to
establish horizontal
planar communication in the presence of a thermal recovery process in which a
SAGD process is
specifically described, the above techniques can be used with other processed,
such as, for
example, VAPEX (vapor extraction process), cyclic steam stimulation, steam
flooding, solvent
assisted SAGD, thermal enhanced oil recovery, in-situ combustion, etc.
[00113] As utilized herein, the terms "approximately," "about," and similar
terms are
intended to have a broad meaning in harmony with the common and accepted usage
by those
or ordinary skill in the art to which the subject matter of this disclosure
pertains. It should be
understood by those of skill in the art who review this disclosure that these
terms are intended
to allow a description of certain features described without restricting the
scope of these
features to any numerical ranges provided. Accordingly, these terms should be
interpreted as
indicating that insubstantial or inconsequential modifications or alterations
of the subject
matter described and are considered to be within the scope of the disclosure.
[00114] It should be understood that numerous changes, modifications, and
alternatives of
the preceding disclosure can be made without departing from the scope of the
disclosure. The
preceding description, therefore, is not meant to limit the scope of the
disclosure. It is also
contemplated that structures and features in the present examples can be
altered, rearranged,
substituted, deleted, duplicated, combined, or added to each other.
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[00115]
The articles "the," "a," and "an" are not necessarily limited to mean only
one, but
rather are inclusive so as to include, optionally, multiple such elements.
34
