Note: Descriptions are shown in the official language in which they were submitted.
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DUAL MOBILIZING AGENTS IN BASAL PLANAR GRAVITY DRAINAGE
FIELD
[0001] The
present techniques relate to the use of steamflooding to recover
hydrocarbons. Specifically, techniques are disclosed for utilizing dual
mobilizing
agents between spaced horizontal wells at different levels in a reservoir.
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. However, easily harvested sources of hydrocarbon are
dwindling, leaving less accessible sources to satisfy future energy needs. As
the
costs of hydrocarbons increase, these less accessible sources become more
economically attractive. For
example, the harvesting of oil sands to remove
hydrocarbons has become more extensive as it has become more economical. The
hydrocarbons harvested from these reservoirs may have relatively high
viscosities,
for example, ranging from 8 API, or lower, up to 20 API, or higher.
Accordingly, the
hydrocarbons may include heavy oils, bitumen, or other carbonaceous materials,
collectively referred to herein as "heavy oil," which are difficult to recover
using
standard techniques.
[0004] Several
methods have been developed to remove hydrocarbons from oil
sands. For example, 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, deeper formations may not be accessible using a strip mining
approach.
For these formations, a well can be drilled to the reservoir and steam, hot
air,
solvents, or combinations thereof, can be injected to release the
hydrocarbons. The
released hydrocarbons may then be collected by the injection well or by other
wells
and brought to the surface.
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[0005] A number of techniques have been developed for harvesting heavy
oil
from subsurface formations using thermal recovery techniques. Thermal recovery
operations are used around the world to recover liquid hydrocarbons from both
sandstone and carbonate reservoirs. These operations include a suite of in-
situ
recovery techniques that may be based on steam injection, solvent injection,
or both.
These techniques may include cyclic steam stimulation (CSS), steamflooding,
and
steam assisted gravity drainage (SAGD), as well as their corresponding solvent
based techniques.
[0006] For example, CSS techniques include a number of enhanced recovery
methods for harvesting heavy oil from formations that use steam heat to lower
the
viscosity of the heavy oil. The CSS process may raise the steam injection
pressure
above the formation fracturing pressure to create fractures within the
formation and
enhance the surface area access of the steam to the heavy oil, although CSS
may
also be practiced at pressures that do not fracture the formation. The steam
raises
the temperature of the heavy oil during a heat soak phase, lowering the
viscosity of
the heavy oil. The injection well may then be used to produce heavy oil from
the
formation. The cycle is often repeated until the cost of injecting steam
becomes
uneconomical, for instance if the cost is higher than the money made from
producing
the heavy oil. However, successive steam injection cycles reenter earlier
created
fractures and, thus, the process becomes less efficient over time. CSS is
generally
practiced in vertical wells, but systems are operational in horizontal wells.
[0007] 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.
The liquid hydrocarbons may be directly mixed and flashed into the injected
steam
lines or injected into the CSS wellbores and further transported as vapours to
contact
heavy oil surrounding steamed areas between adjacent wells. The injected
hydrocarbons may be produced as a solution in the heavy oil phase. The loading
of
the liquid hydrocarbons injected with the steam can be chosen based on
pressure
drawdown and fluid removal from the reservoir using lift equipment in place
for the
CSS.
[0008] As a field ages, the use of CSS may gradually be replaced with non-
cyclic
techniques, for example, in which steam is continuously injected into a first
well, and
fluids are continuously produced from a second well. These techniques may
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generally be termed steamflooding, and are generally based on vertical wells.
However, steam and injected fluids have a tendency to override the
hydrocarbons in
the formation, and directly travel from injector to producer, lowering the
potential
recovery.
[0009] Another group of techniques is based on a continuous injection of
steam
through a first well to lower the viscosity of heavy oils and a continuous
production of
the heavy oil from a lower-lying second well. Such techniques may be termed
"steam assisted gravity drainage" or SAGD.
[0010] In SAGD, two horizontal wells are completed into the reservoir.
The two
wells are first drilled vertically to different depths within the reservoir.
Thereafter,
using directional drilling technology, the two wells are extended in the
horizontal
direction that result in two horizontal wells, vertically spaced from, but
otherwise
vertically aligned with the other. Ideally, the production well is located
above the
base of the reservoir but as close as practical to the bottom of the
reservoir, and the
.. injection well is located vertically 3 to 10 metres (10 to 30 feet) above
the horizontal
well used for production.
[0011] The upper horizontal well is utilized as an injection well and is
supplied
with steam from the surface. The steam rises from the injection well,
permeating the
reservoir to form a vapour chamber that grows over time towards the top of the
reservoir, thereby increasing the temperature within the reservoir. The steam,
and
its condensate, raise the temperature of the reservoir and consequently reduce
the
viscosity of the heavy oil in the reservoir. The heavy oil and condensed steam
will
then drain downward through the reservoir under the action of gravity and may
flow
into the lower production well, whereby these liquids can be pumped to the
surface.
At the surface, the liquids flow into processing facilities where the
condensed steam
and heavy oil are separated, and the heavy oil may be diluted with appropriate
light
hydrocarbons for transport by pipeline.
[0012] The techniques discussed above may leave a substantial remainder
of
hydrocarbons in the reservoir. For example, each SAGD well pair may harvest
hydrocarbons from a limited area of a reservoir, requiring a substantial
number of
wells. IdII wells are generally designed in a similar fashion to the lower,
drainage
wells in SAGD having a horizontal run placed between two SAGD pairs. Further,
current steamflooding techniques may allow steam to override the hydrocarbons
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SUMMARY
[0013] An embodiment provides a method for harvesting resources in a
reservoir. The method includes drilling a first horizontal well substantially
proximate
to a base of a reservoir and drilling a second horizontal well at a horizontal
offset
from the first horizontal well. Fluid communication is established between the
first
horizontal well and the second horizontal well through a cyclic production
process.
A vertical mobilizing agent is injected into the reservoir and a lateral
mobilizing agent
is used in the reservoir. Fluids are produced from the first horizontal well.
[0014] Another embodiment provides a system for harvesting resources in a
reservoir. The system includes a first horizontal well substantially proximate
to the
base of the reservoir and a second horizontal well at a horizontal offset from
the first
horizontal well, wherein the second horizontal well is vertically offset from
the first
horizontal well. A cyclic production system is configured to establish fluid
communication between the wells. A continuous injection and production system
is
.. configured to inject a vertical mobilizing fluid into the reservoir, use a
lateral
mobilizing agent in the reservoir, and produce a fluid from the first
horizontal well.
[0015] Another embodiment described herein provides a method for producing
hydrocarbons. The method includes producing fluids from a number of production
wells in a reservoir and imposing a lateral mobilizing agent on the reservoir
from a
number of injection wells. Each of the injection wells is adjacent to one of
the
production wells and each of the injection wells is laterally offset from each
of the
adjacent production wells. Fluid communication has been established between
each injection well and an adjacent production well using a cyclic production
process. A vertical mobilizing agent is heated using heat transferred from the
lateral
mobilizing agent and a hydrocarbon stream is separated from the fluids
produced
from the plurality of production wells.
[0015a] Another embodiment described herein provides a method for harvesting
resources in a reservoir, comprising: drilling a first horizontal well
substantially
proximate to a base of a reservoir; drilling a second horizontal well at a
horizontal
offset from the first horizontal well, wherein the second horizontal well is
greater
than about three metres shallower than the first well, establishing fluid
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communication between the first horizontal well and the second horizontal well
through a cyclic production process; after establishing fluid communication
between
the first horizontal well and the second horizontal, converting the first
horizontal well
into an injection well and the second horizontal well into a production well
and
operating the first horizontal well and the second horizontal under a
continuous
injection/production process; injecting a vertical mobilizing agent into the
reservoir,
wherein the vertical mobilizing agent comprises a light hydrocarbon vapour
under
reservoir conditions which promotes the rise of a depleted bitumen chamber
within
the reservoir; contacting the mobilizing agent with bitumen located at the top
and
sides of the depleted bitumen chamber, thereby condensing the vertical
mobilizing
agent, lowering the viscosity of the bitumen, and expanding the depleted
bitumen
chamber; injecting a lateral mobilizing agent into the reservoir, wherein the
lateral
mobilizing agent comprises hot water; using the heat from the lateral
mobilizing
agent to flash the condensed vertical mobilizing agent back into a vapour; and
producing fluids from the first horizontal well.
(0015b] Another embodiment described herein provides a system for harvesting
resources in a reservoir, comprising: a first horizontal well substantially
proximate
to the base of the reservoir; a second horizontal well at a horizontal offset
from the
first horizontal well, wherein the second horizontal well is vertically offset
from the
.. first horizontal well and wherein the second horizontal well is greater
than about
three metres shallower than the first well; a cyclic production system
configured to
establish fluid communication between the wells; and the cyclic production
system
reconfigured into a continuous injection and production system, wherein the
continuous injection and production system is configured to: inject a vertical
mobilizing fluid into the reservoir wherein the vertical mobilizing agent
comprises a
light hydrocarbon vapour under reservoir conditions which promotes the rise of
a
depleted bitumen chamber within the reservoir; allow the mobilizing agent to
contact
with bitumen located at the top and sides of the depleted bitumen chamber,
thereby
condensing the vertical mobilizing agent, lowering the viscosity of the
bitumen, and
expanding the depleted bitumen chamber; inject a lateral mobilizing agent into
the
reservoir, wherein the lateral mobilizing agent comprises hot water; use the
heat
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from the lateral mobilizing agent in the reservoir to flash the vertical
mobilizing agent
back into a vapour; and produce a fluid from the first horizontal well.
DESCRIPTION OF THE DRAWINGS
[0016] The advantages of the present techniques are better understood by
referring to the following detailed description and the attached drawings, in
which:
[0017] Fig. 1 is a drawing of a steamflood process using basal planar
gravity
drainage (BPGD);
[0018] Figs. 2(A), (B), and (C) are perspective views of a cyclic
production
process showing the establishment of fluid communications between adjoining
wells;
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[0019] Fig. 3 is a cross sectional view of a cyclic production process
showing the
establishment of fluid communications between adjoining wells;
[0020] Fig. 4 is a cross-section of a portion of a reservoir, showing two
horizontal
wells through the reservoir;
[0021] Fig. 5 is a plot showing the efficacy of dry and wet steam in a BPGD
process where the steam volume for the wet steam (60% quality) has been
adjusted
to be equivalent thermally equivalent to dry steam (90% quality) (i.e. a dry
steam
equivalent basis);
[0022] Fig. 6 is a plot showing an increase in total production that can
be
obtained using a BPGD process;
[0023] Fig. 7 is a plot showing an increase in efficiency that can be
obtained
using a BPGD process; and
[0024] Fig. 8 is process flow diagram of a method for using dual
mobilizing agents
in BPGD to produce hydrocarbons.
DETAILED DESCRIPTION
[0025] 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.
[0026] 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 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.
[0027] As used herein, the term a "base" of a reservoir indicates a lower
boundary of the resources in a reservoir that are practically recoverable, by
a gravity-
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assisted drainage technique, for example, 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, e.g., the zone from which hydrocarbons may generally
be
removed by gravity drainage. 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 broken shale, mud, silt, and the
like.
The resources within the reservoir may extend below the base, but the
resources
.. below the base may not be recoverable with gravity assisted techniques.
[0028]
"Bitumen" is a naturally occurring heavy oil material. Generally, it is the
hydrocarbon component found in oil sands. Bitumen can vary in composition
depending upon the degree of loss of more volatile components. It can vary
from a
very viscous, tar-like, semi-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. A), 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 sulphur (which can range in excess of 7 wt. /0).
In addition bitumen can contain some water and nitrogen compounds ranging from
less than 0.4 wt. % to in excess of 0.7 wt. A. As used herein, the term
"heavy oil"
includes bitumen, as well as lighter materials that may be found in a sand or
carbonate reservoir.
[0029] As used
herein, two locations in a reservoir are in "fluid communication"
when a preferential path for fluid flow exists between the locations. Fluid
communication can be manifested as a rapid pressure change at one well in
response to a pressure, fluid injection or fluid withdrawal at another well.
Fluid
communication may also be manifested as temperature change at the production
well or the arrival at the production well of fluids that are known to have
been
injected at another well. For example, the establishment of fluid
communication
between a well and a latterly or vertically offset injection well may allow
steam or
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solvent to flow rapidly and with limited pressure drop from the injection well
to the
production well where it can be collected and produced. As used herein, a
fluid
includes a gas or a liquid and may include, for example, a produced
hydrocarbon, an
injected mobilizing fluid, or water, among other materials.
[0030] As used herein, a "cyclic recovery process" uses an intermittent
injection
of injected mobilizing fluid selected to lower the viscosity of heavy oil in a
hydrocarbon reservoir. The injected mobilizing fluid may include steam,
solvents,
gas, water, or any combinations thereof. After a soak period, intended to
allow the
injected material to interact with the heavy oil in the reservoir, the
material in the
reservoir, including the mobilized heavy oil and some portion of the
mobilizing agent
may be harvested from the reservoir. Cyclic recovery processes use multiple
recovery mechanisms, in addition to gravity drainage, early in the life of the
process.
The significance of these additional recovery mechanisms, for example dilation
and
compaction, solution gas drive, water flashing, and the like, declines as the
recovery
process matures. Practically speaking, gravity drainage is the dominant
recovery
mechanism in most mature thermal, thermal-solvent and solvent based recovery
processes used to develop heavy oil and bitumen deposits, such as steam
assisted
gravity drainage (SAGD). For this reason the approaches disclosed here are
equally
applicable to all recovery processes in which at the current stage of
depletion gravity
drainage is the dominant recovery mechanism.
[0031]
"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, steam generation plants, processing plants,
and
delivery outlets. In some instances, the term "surface facility" is used to
distinguish
those facilities other than wells.
[0032] As used
herein, "heavy oil" includes both oils that are classified by the
American Petroleum Institute (API) as heavy oils and extra heavy oils, which
are also
known as bitumen. In general, a heavy oil has an API gravity between 22.3
(density
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of 920 kg/m3 or 0.920 g/cm3) and 10.00 (density of 1,000 kg/m3 or 1 g/cm3). An
extra
heavy oil, or bitumen, in general, has an API gravity of less than 10.0
(density
greater than 1,000 kg/m3 or greater than 1 g/cm3). For example, a common
source
of heavy oil includes oil sand or bituminous sand, which is a combination of
clay,
sand, water, and heavy oil. The thermal recovery of heavy oils is based on the
viscosity decrease of fluids with increasing temperature. Solvent-based
recovery
processes are based on reducing the liquid viscosity by mixing heavy oil with
a
solvent. Once the viscosity is reduced, the movement or drive of the fluids
may be
forced by steam or hot water flooding, and gravity drainage becomes possible.
The
reduced viscosity makes the drainage quicker and therefore directly
contributes to
the recovery rate.
[0033] As used herein, a "horizontal well" generally refers to a well
bore with a
section having a centerline which departs from vertical by at least about 65 .
This
nearly horizontal section is often used for harvesting hydrocarbons in a
reservoir.
Generally, the nearly horizontal section of a well bore that is used for
gravity
production of heavy oils extends for several hundred meters in a reservoir
from the
"heel" to the "toe." The heel is closest to the portion of the well bore that
leads to the
surface, while the toe is farthest from the portion of the well bore that
leads to the
surface. In practice, the horizontal well will often be drilled such that it
conforms to
the base of the reservoir so that the toe may be shallower or deeper than the
heel of
the well.
[0034] A "hydrocarbon" is an organic compound that primarily includes the
elements hydrogen and carbon, although nitrogen, sulphur, oxygen, metals, or
any
number of other elements may be present in small amounts. As used herein,
hydrocarbons generally refer to components found in heavy oil, or other oil
sands.
Liquid hydrocarbon solvents are hydrocarbons that are substantially in the
liquid
phase under the temperature and pressure conditions found in an oil-sands
reservoir, such as hexane, heptanes, heavier hydrocarbons, or mixtures
thereof.
Light hydrocarbon solvents, such as ethane, propane, butane, pentanes, or
mixture
thereof, are hydrocarbons that are substantially in the gas phase or cycling
between
the liquid and gas phase, under the temperature and pressure conditions found
in an
oil-sands reservoir.
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[0035] A non-condensable gas is a gas that is in the gas phase under the
temperature and pressure conditions found in an oil-sands reservoir. Such
gases
can include carbon dioxide (CO2), methane (CH4), and nitrogen (N2), among
others.
[0036] "Permeability" is the capacity of a rock or sand to transmit
fluids through
the interconnected pore spaces. The customary unit of measurement is the
millidarcy. Relative permeability refers to the fractional permeability of the
absolute
permeability for a specific phase, such as oil, water or gas.
[0037] As used herein, a "reservoir" is a subsurface rock or sand
formation from
which a production fluid, or resource, can be harvested. The rock formation
may
include sand, sandstone, granite, silica, carbonates, clays, shales 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
common feature of a reservoir is that it has pore space within the rock that
may be
impregnated with a heavy oil.
[0038] As discussed above, "steam assisted gravity drainage" (SAGD), is a
thermal recovery process in which steam, or combinations of steam and
solvents, is
injected into a first well to lower a viscosity of a heavy oil, and fluids are
recovered
from a second well. Both wells are generally horizontal in the formation and
the first
well lies above the second well. Accordingly, the reduced viscosity heavy oil
flows
down to the second well under the force of gravity, although pressure
differential
may provide some driving force in various applications.
[0039] "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.
[0040] As used herein, "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 fluids, such as hot water, wet steam, dry steam, or
solvents
alone, or in any combinations, to lower the viscosity of the hydrocarbon. Such
processes may include subsurface processes, such as cyclic steam stimulation
(CSS), cyclic solvent stimulation, steamflooding, solvent injection, and SAGD,
among others, and processes that use surface processing for the recovery, such
as
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= sub-surface mining and surface mining. Any of the processes referred to
herein,
such as SAGD may be used in concert with solvents.
[0041] A "wellbore" is a hole in the subsurface made by drilling and
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, as a liner configured to allow flow from an outer chamber to an inner
chamber.
Overview
[0042] Current techniques for harvesting heavy oils may require a
significant
number of wells to produce hydrocarbons over a large area of a reservoir. As
the
costs associated with these wells can be very high, the techniques may become
prohibitively expensive as a reservoir ages. Further, current techniques may
bypass
significant amounts of hydrocarbons as the reservoir ages.
[0043] In an embodiment, a basal planar gravity drainage (BPGD)
process is
implemented by drilling at least two horizontal wells through the reservoir. A
first
horizontal well is drilled at or close to the base of the reservoir. A second
horizontal
well is laterally offset and may be vertically offset from the first well, for
example, with
an axis that is around 50 to 200 metres laterally away from the axis of the
first well
and may be about three metres, or more, shallower than the first well. Both
wells are
initially used to produce from the reservoir using cyclic production
techniques, such
as injecting a mobilizing fluid, letting the mobilizing fluid soak in the
reservoir, and
then producing the mobilizing fluid and hydrocarbons from the wells. The
mobilizing
fluid may be steam, water, solvents, or mixtures of both.
[0044] Over time, as production cycles are completed, the first
horizontal well and
the second horizontal well will achieve fluid communication, allowing fluids
injected
through one well to pass to the other well. After fluid communication is
achieved, a
continuous production process may be implemented in which the second, or
higher,
horizontal well may be used as an injection well, and the first, or lower,
horizontal
well may be used as a production. As for the cyclic production process, the
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= continuous production process may use steam, solvents, water, or
mixtures, as
mobilizing agents.
[0045] In an embodiment, a dual mobilizing agent recovery process is
used to
enhance production. One mobilizing agent, termed herein a vertical mobilizing
agent, promotes the rise of the depleted bitumen chamber and the vertical
drainage
of the bitumen. A second mobilizing agent, termed the lateral mobilizing
agent,
promotes the lateral flow of bitumen along a basal plane between the second
horizontal well and the first horizontal well. The lateral mobilizing agent is
not limited
to a fluid, but may include water, solvent, or electrical heating, for
example, using a
brine injection to carry a current. The lateral mobilizing agent and the
vertical
mobilizing agent can be selected to balance a volumetric rate of vertical
drainage
and lateral drainage to maintain a vapour chamber between an injection well
and a
production well.
[0046] The combination of a BPGD process and dual mobilizing agents
may
increase the amount of hydrocarbons that can be harvested from a reservoir.
The
combination may also increase the efficiency of steam, solvent usage, or
electrical
usage in the recovery process.
[0047] Fig. 1 is a drawing of a hydrocarbon recovery process 100 in
accordance
with embodiments. In the hydrocarbon recovery process 100, a reservoir 102 is
accessed by a first set 104 and a second set 106 of horizontal wells. As
described
herein, the wells can have a lateral spacing 108 of about 50 to 200 metres
between
each of the wells. The first set 104 may be drilled substantially proximate to
a base
110 of the reservoir 102. The second set 106 of horizontal wells may be
drilled at a
vertical spacing 112 of about three metres, or more, above the first set 104.
Although only two wells of each type are shown in the hydrocarbon recovery
process
100, any number may be used, for example, from one well of each type to
several
hundred wells of each type, depending on the size of the reservoir 102. The
first set
104 of horizontal wells may be coupled together by lines 114 at the surface.
Similarly, the second set 106 of horizontal wells may be coupled together by
lines
118 at the surface. One or more surface facilities 120 produce steam or
solvent
streams that can be injected into the reservoir through the sets of wells 104
or 106
and produce fluids from the sets of wells 104 or 106. The produced fluids may
be
separated at the surface facility 120 to produce a hydrocarbon stream 122,
which
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can then be sent on for further processing. The surface facility 120 can also
include
electrical generation equipment or connections that can be configured to
impose an
electrical current in the reservoir 102. The electric current can provide
resistive
heating to the reservoir contents and may be used to flash a vertical
mobilizing agent
and also to lower the viscosity of heavy oil, e.g., acting as a lateral
mobilizing agent.
[0048] After the sets of wells 104 and 106 are drilled, a cyclic
production process,
such as cyclic steam stimulation, may be used on both sets 104 and 106 of
horizontal wells in concert. During this period, the surface lines 114 and 118
may be
tied together so that the sets of wells 104 and 106 are used in concert. The
cyclic
production process is repeated until fluid communication between the first set
104
and the second set 106 of wells is detected.
[0049] After fluid communication is established, dual mobilizing agents
can be
used to perform a continuous recovery operation. In some embodiments, a
vertical
mobilizing agent can be injected into the second set 106 of wells. The
vertical
mobilizing agent can include a low flashpoint solvent, which can flash into a
vapour
in the reservoir. The vertical mobilizing agent may condense in contact with
the
bitumen at the top and sides of the chamber and condense, lowering the
viscosity of
the fluid and expanding the chamber. A horizontal mobilizing agent, such as
hot
water, may be injected to carry fluids that flow down to the first set 104 of
wells. The
heat from the horizontal mobilizing agent can be used to flash the vertical
mobilizing
agent back into a vapour, repeating the cycle.
Establishing Fluid Communication
[0050] Figs. 2(A), (B), and (C) are 30 seismic views of a cyclic
production
process 200 showing the establishment of fluid communications between
adjoining
wells. In Fig. 2, the particular cyclic production process used was cyclic
steam
stimulation (CSS), although any cyclic production technique could be used in
techniques described herein. Fig. 2(A) is an initial view showing accessed
areas
202, for example, areas that may be in heated and in fluid communication with
horizontal wells 204 after one cycle of cyclic steam injection and production
has
been performed from the reservoir 206. The accessed areas 202 may be termed
the
steam invaded region. The darker, shaded areas indicate regions 208 are not
yet in
fluid communication with the wells 204. As can be seen, the wells 204 are not
substantially in fluid communication with each other at this point in the
process, as
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indicated by the lack of overlap of the accessed areas 202 across adjacent
wells
204.
[0051] After a second cycle of steam injection and production, heated
features
extend out to at least about 25m from each well. In this example, the wells
are about
170 metres apart and fluid communication has not been completely established.
However, if the wells had been placed about 50 to 75 metres apart, basal
connections would have been established at this point. Thus, after two cycles
of
CSS the shown in Fig. 2(B), the accessed area 202 has substantially increased
in
size, and is overlapping a number of adjacent wells 204, for example, as
indicated by
reference number 210.
[0052] After a third cycle of injection and production, as shown in Fig.
2(C), the
accessed region 202 has placed all adjacent wells 204 in fluid communication,
allowing fluid flow from any well to an adjacent well 204. Creating uniform
connections along the wells may present a challenge. For example, reference
number 212 identifies a region where the fluid communication is not extensive,
indicating that further cycles may be useful. However, the fluid communication
may
be extensive enough to begin continuous steamflooding. The wells shown in
Figures
2 (A), (B) and (C) were completed with specially designed completion which
facilitated uniform steam distribution, such as limited entry perforations
(LEPs) which
may be used in concert with a wire screen.
[0053] Fig. 3(A), (B), and (C) are cross sectional views 300 of the
cyclic
production processes of Fig. 2(A), (B), and (C), respectively, showing the
establishment of fluid communications between adjoining wells 204. In Fig. 3,
like
numbers are as discussed above. In this figure, not every well 204 is labelled
in
order to simplify the diagram. The center 302 of the production zone 304
around
each well 204 is at a lateral spacing 108 of about 170 metres apart in this
example.
The increase in the accessed area 202 (Fig. 2) after each year of cyclic
production is
shown as the increase in size of the production zones 304 around each well
204.
Further, other layers 306 may develop accessed zones 308, which can contribute
to
fluid communication between wells. If the lateral spacing 108 between were
closer,
fluid communications between wells 204 would be established more quickly. For
example, if the spacing around the production zones 304 was at 100 metres, as
indicated by reference number 310, the wells 204 could start to interact after
only
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two cycles of injection and production. The wells 204 could be converted to
alternating injectors and producers, as discussed with respect to Fig. 4. In
some
embodiments, the lateral well spacing 108 will be about 50 metres. The lateral
well
spacing 108 may range from about 20 metres to about 200 metres.
Changing to Continuous Production
[0054] Fig. 4 is a cross-section of a portion 400 of a reservoir 102,
showing two
horizontal wells 104 and 106 in the reservoir 102 used in a continuous
production
process, e.g., after fluid communication is established by a cyclic production
process. A first horizontal well 104 is drilled near a base of the reservoir
102. A
second horizontal well 106 is drilled at a lateral offset 108 and at a
shallower level,
i.e., with a positive vertical offset 112. In an embodiment, the vertical
offset 112 is
greater than about three metres. The second horizontal well 106 may be used as
an
injection well to inject a mobilizing fluid to move hydrocarbons in the
reservoir 102
towards the first horizontal well 104.
[0055] This may be performed by using a lateral mobilizing agent 402. The
lateral mobilizing agent 402 may be a fluid, such as water, that remains a
fluid at
reservoir conditions and acts to sweep hydrocarbons towards the production
well
104. The lateral mobilizing agent 402 may also provide heat into the
formation,
which may be used to flash a vertical mobilizing agent 404 into a vapour. In
some
embodiments, the lateral mobilizing agent 402 is not an injected fluid, but
is, instead,
an electric current flowing between the wells 104 and 106. The current can add
heat
to the reservoir, flashing the vertical mobilizing agent 402 into a vapour.
[0056] The vertical mobilizing agent 404 rises forming a production
chamber 406.
Liquids 408, including mobilized bitumen, condensate, condensed solvents, and
the
like, fall back towards the basal plane. The liquids 408 drain to the first
horizontal
well 104, which is used as a production well to remove the fluids from the
production
chamber 410. In contrast to a typical steam assisted gravity drainage (SAGO)
process, which has no lateral spacing between the injection and production
well, the
production chamber 406, at or near the base of the reservoir, is formed by the
vertical mobilizing agent 404 rising from the basal plane between the two
horizontal
wells 102 and 104.
Various combinations of lateral mobilizing agents 402 and vertical mobilizing
agents 404 may be used in embodiments, such as those shown in Table 1. The
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agents 402 and 404 may be independently selected for specific purposes, such
as
temperature of flashing, among others, allowing the recovery to be adjusted
for the
conditions in a reservoir. For example, hot water may be used as a lateral
mobilizing
agent 402 in a system in which a light hydrocarbon is used as the vertical
mobilizing
agent 404. In this embodiment, the hot water flashes the light hydrocarbon and
sweeps recovered bitumen to the second horizontal well 106 for production.
Further,
the lateral mobilizing agents 402 and vertical mobilizing agents 404 can be
changed
over time, for example, to different types of agents, different compositions,
and the
like.
Table 1: Dual mobilizing agents for BPGD
Lateral Mobilizing Agent 402 Vertical Mobilizing Agent 404
Hot Water (liquid) Water Vapour (steam)
Liquid hydrocarbon solvents (05+) Light hydrocarbon vapour (02 to C7)
Electric resistive heating between injector Non-condensible additive gases
such as
and producer methane (C1) or carbon-dioxide (c02)
Electric resistive heating between injector
and producer, with injection of an
electrically conductive liquid such as
brine
[0057] The selection of mobilizing agents 402 and 404 may be separately
considered based on the desired conditions. For example, hot water, or steam
condensate, can be used as the lateral mobilizing agent 402 as they flow along
the
basal plane and can transfer energy to a vertical mobilizing agent 404. Other
lateral
mobilizing agent 402 that can perform these functions include non-vaporising
liquid
solvents, such as paraffinic oils, among others. The non-vaporising liquid
solvents
may also mix with draining hydrocarbons, reducing the viscosity of the
recovered
hydrocarbons. The lateral mobilizing agent 402 is not limited to a physical
material
added to the reservoir. In an embodiment, the lateral mobilizing agent 402 may
be
heat, generated in the reservoir by a current flow between the wells 104 and
106.
The heating effect may be enhanced by a continuous or intermittent injection
of a
brine to enhance the current flow. In another embodiment, the heating may be
performed using a fixed fracture location with a conductive proppant.
[0058] Similar considerations may influence the selection of the vertical
mobilizing
agent 404. The vertical mobilizing agent 404 may be water vapour injected as
wet
steam. In SAGD applications, dry steam is more effective than wet steam, but
this is
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not necessarily the case for a BPGD recovery. This is discussed further with
respect
to Fig. 5.
[0059] As noted above, solvent vapour may be used as the vertical
mobilizing
agent 404. The solvent vapour tends to rise vertically and mobilize the heavy
oil with
.. heat. Thus, one consideration to be accounted for in the selection of the
mobilizing
agents 402 and 404 is the amount of heat to be provided by the lateral
mobilizing
agent 402 for vaporising the vertical mobilizing agent 404. The mobilizing
effect may
vary from a predominately solvent mixing effect to a predominately heating
effect,
depending on the selection of solvent, operating temperature, and operating
pressure.
[0060] The elongated production chamber 406 in the basal planar recovery
process may increase the total amount of hydrocarbons that can be produced
from
the reservoir in a given period of time, versus a vertical SAGD steam chamber.
This
may increase the efficiency of the injected mobilizing fluid. This is
discussed in
further detail with respect to Figs. 6 and 7.
[0061] The production changes that may result from the techniques may be
modeled by creating a geologic model of the reservoir and using the geologic
model
to calculate the amounts of hydrocarbons produced. The geologic model may
include open hole log data, cased hole log data, core data, recovery process
well
trajectories, 2D seismic data, 3D seismic data, or other remote surveying
data, or
any combinations thereof. For example, prior to the start of recovery
operations, a
geologic model can be created for the development area. Available open hole
and
cased hole log, core, 2D and 3D seismic data, and knowledge of the
depositional
environment setting can all be used in the construction the geologic model.
The
information generated by the geologic model may then be used in a reservoir
simulation model to provide predictions of fluid flow, reservoir geometry, and
the like.
[0062] The geologic model, reservoir model, and knowledge of surface
access
constraints can then be used to complete the layout of the spaced horizontal
wells
and surface pads. After the horizontal wells have been drilled, data collected
during
their drilling as well as data collected during the operation of the 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
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as the recovery process matures. The depletion patterns within the reservoir
will be
influenced by well placement decisions, geological heterogeneity, well
failures, and
day to day operating decisions.
[0063] Following the operation of the thermal, thermal-solvent or solvent
based
recovery process for a suitable period of time, intervals of high hydrocarbon
depletion will create a series of discrete connections between adjacent wells
or well
pairs, depending on the recovery process. Knowledge of these connections is
gained through observances of interwell or interpattern communication of
fluids,
convergence of operating pressures, as well as via ongoing reservoir depletion
monitoring with tools such as time lapse 3D seismic. This information may then
be
used to determine the appropriate time to convert from a cyclic production
process to
a continuous production process.
[0064] Fig. 5 is a plot 500 showing the efficacy of dry and wet steam in
a BPGD
process where the steam volume for the wet steam (60% quality) has been
adjusted
to be equivalent thermally equivalent to dry steam (90% quality) (i.e. a dry
steam
equivalent basis). The x-axis 502 represents cumulative production from a
field in
units of volume (m3 or barrels), while the y-axis 504 represents the SOR
(steam-to-
oil ratio), which is the volume of steam injected per volume of oil produced.
SOR is a
key measure of the performance of a thermal process where a lower SOR is
typically
a more economic process. On this plot 500, a SOR of two 506 is good, while a
SOR
of four 508 is acceptable. For a SAGD process, in which the injection well is
nearly
directly above the production well, 90% quality steam provides the steam-to-
oil ratio
shown in curve 510. As used herein, the quality of steam is a ratio of the
weight of
the steam flow that is water vapour versus the weight of entrained water
droplets. A
higher number represents a larger amount of water vapour in the steam flow. In
contrast, if 60% quality is utilized with SAGD it will have a higher (poorer)
steam-to-
oil ratio as shown by curve 512. Accordingly, SAGD recovery processes are
generally developed using the highest steam quality available.
[0065] The facilities designed for SAGD usually generate high quality
steam
because any injected liquid condensate does not enhance production. Since BPGD
makes effective use of the liquid condensate simpler lower cost facilities
steam
generation facilities can be employed.
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[0066] Lower quality or "wet" steam provides an example of the use of a
dual
mobilizing agent, in which steam is the vertical mobilizing agent, while the
hot water
and condensate is the lateral mobilizing agent. The steam-to-oil ratio for the
use of
60 `)/0 quality steam (wet steam) in a basal planar recovery process is shown
by
curve 514. By comparison, the steam-to-oil ratio for the use of dry steam,
shown as
curve 516, is nearly identical. Both curves 514 and 516 are lower than the
curves
510 and 512 for SAGD, indicating that wet steam acts as an effective dual
mobilizing
agent. The increased efficiency for BPGD over SAGD is further indicated by the
plots discussed with respect to Figs. 6 and 7. It can be noted that these
plots were
generated using dry steam for both cases.
[0067] Fig. 6 is a plot 600 showing a simulation of the increase in total
production
rate that may be obtained using a BPGD process. In the plot 600, the x-axis
602
represents the time since production was started, while the y-axis 604
represents the
cumulative oil volume produced from the reservoir using BPGD. The total
production
606 that could be achieved using the present techniques 606 quickly reaches a
maximum, allowing a much faster production of the resources. In contrast, the
production 608 from a SAGD process may reach the same amounts, but only after
many years.
[0068] Fig. 7 is a plot 700 showing a simulation of the increase in
efficiency
relative to the steam volume employed that can be obtained using a BPGD
process.
The x-axis 702 represents the total amount of steam injected into the
reservoir, while
the y-axis represents the total volume of oil produced from the reservoir. As
can be
seen in the plot 700, if large volumes of steam are injected the SAGD and BPGD
processes result in the same recovery levels. However, economic limits will
dictate
the actual volume of steam that can be practically injected. The benefit of
the BPGD
process is indicated by comparing curve 706 to a normal SAGD process, as
indicated by curve 708. For example, comparing the two cases at 200,000 m3 of
steam injection volume, SAGD will have produced about 75,000 m3 of oil whereas
the BPGD process will have produced about 110,000 m3 of oil.
[0069] An assumption inherent in a BPGD process is that a connection can be
created between the injection well and the production well early in the
recovery
process. In the SAGD process a connection is typically established through a
warm-
up phase during which conductive heating is used to establish the connection.
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Because conductive heating is a relatively slow process the wells are spaced
about
metres apart. It may also be useful to establish a distributed connection
along the
full length of the wells. If the connection or heated zone does not extend
over the full
length of the well then steam override may occur. For example, in areas within
the
5 .. reservoir, the steam chamber will rise to the top of the reservoir
quickly and will then
flow along the top of the reservoir to the producer. A similar situation often
occurs
when vertical wells are utilized for steamflooding. In order for a BPGD
process to be
most effective, the well can be configured such that the well lengths are much
longer
than the well spacing. Further, the wells can be completed with some form of
flow
control devices on the injector and producer such that the spacing of such
devices is
less than the well spacing, such as less than half than a distance between
adjacent
wells or less than a quarter of the distance between adjacent wells. The
tighter the
spacing of the perforations, the better the basal conformance. For example,
the well
lengths may be in the 300 to 1500 metres range, the well spacing in the 50 to
150
metres range and the flow control devices spaced every 10 to 50 metres along
the
well.
[0070] Fig. 8 is process flow diagram of a method 800 for using dual
mobilizing
agents in a BPGD production of hydrocarbons. The method 800 begins at block
802
with the drilling of a first horizontal well proximate to the base of the
reservoir. The
first horizontal well may be around 500 to 1500 metres long. The base of the
reservoir, or target production zone, may be determined by vertical evaluation
wells,
a geological model, seismic imaging, or any number of techniques. The first
horizontal well, which will be a production well during continuous operations,
may be
completed with LEP screen-type completions that are sized to allow distributed
liquid
in-flow along the length of the well. The total area of the perforations may
be
selected to limit the influx of vapour during continuous production.
[0071] At block 804, a second horizontal well is drilled parallel to the
first
horizontal well and can be of the same length. The second horizontal well may
be
laterally offset between about 50 and 200 metres from the first horizontal
well. The
second horizontal well may be drilled three or more metres above the
completion
depth of the first horizontal well. In a field having multiple horizontal
wells, the
depths of the horizontal wells may vary, depending on the base of the
reservoir.
However, neighbouring horizontal wells will generally have alternating depths.
The
second horizontal well, which will be an injection well during continuous
operations,
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may be completed with limited-entry perforation (LEP) screen-type completions
that
provide for evenly distributed steam injection where the steam is injected in
the
vapour phase. Typically, the LEP's in the second horizontal well will have a
larger
open area than those in the first horizontal well when the mobilizing fluid is
injected
as predominantly a vapour, for example, as steam, and produced as a liquid.
[0072] At block 806, fluid communication may be established between the
wells.
This may be performed by any number of cyclic production processes. For
example,
as discussed with respect to Fig. 2, cyclic steaming of horizontal wells with
LEP's
completions can create uniform basal heating that establishes fluid
communications
between adjacent wells. In other embodiments, continuous solvent injection or
cyclic
solvent recovery processes may be used to establish fluid communication. After
about two to three cycles of CSS, the heated features between wells may
overlap,
and the wells may be converted to a BPGD process.
[0073] In some types of reservoirs, a basal plane gravity-drainage layer
may be
established by injecting a fluid at rates that induce fracturing. As such,
this
connection process is particularly suited to reservoirs where the stress state
favours
horizontal fractures. Most commonly reservoirs that favour horizontal
fractures are
found at depths shallower than about 500 m. It may also be possible in some
reservoirs to precondition the reservoir to favour horizontal fractures
through
pressurization. This may allow horizontal fractures to be generated at greater
depths. For example, this may be performed by injecting water, steam, or
solvents
to raise the reservoir pressure.
[0074] In reservoirs where the stress state may not favour horizontal
fractures,
solvent fingering may offer an alternate mechanism for generating connections.
Solvent fingering is a mechanism whereby a less viscous injected fluid invades
a
reservoir that is saturated with a more viscous fluid, and occurs when solvent
is
injected into heavy oil. It is known that solvent fingers will propagate
towards regions
of lower pressure. The connection can be generated by the cyclic injection and
production of solvent into the first horizontal, or production, well in order
to establish
a finger network of high mobility. Solvent may then be injected into the
second
horizontal, or injection well, generating a second network of fingers while
producing
from the first horizontal well. The shortest pathways between the injection
well and
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production well would be expected to dominate the flow paths and establish a
basal
communication path.
[0075] Once fluid communication is established between the first and
second
horizontal wells, at block 808, the dual mobilizing agents may be used. In
some
embodiments, this includes a single injection of vertical and lateral
mobilizing agents.
For example, the injection may include a mixture of a solvent that vaporizes
at a low
temperature, such as about 50 ¨ 75 C and hot water. The hot water can
vaporize
the solvent as it enters the reservoir or the solvent may be vaporized in the
facilities
before entering the formation, providing a vertical mobilizing agent. The hot
water
acts as the lateral mobilizing agent, as it flows from injection well to
production well
near the base of the reservoir. As additional hot water is injected any
solvent that
has condensed and flowed down may once again be vaporized. This mechanism of
repeated condensation and vaporization within the reservoir can be termed
refluxing.
As another example, wet steam may be injected, with or without an added
solvent.
[0076] At block 810, a vertical mobilizing agent may be separately injected
into
the reservoir, for example, using the second horizontal well. After the
injection of the
vertical mobilizing agent, at block 812, a lateral mobilizing agent may be
injected into
the reservoir, or imposed on the reservoir. In some embodiments, the lateral
mobilizing agent may be an electric current that is flowed through the
reservoir, for
example, between the injection and production wells. A non-vaporizing,
electrically
conductive fluid, such as a brine, may be injected continuously or
intermittently such
that it flows between the injection and production well and acts to
concentrate
electric current at the base of the reservoir. The electric current can cause
resistive
heating of the reservoir contents flashing a vertical mobilizing agent and
lowering the
viscosity of heavy oils in the basal plane, assisting in their flow to the
first horizontal
well. The injected mobilizing fluids could be steam, solvent, hot water,
brine, or
mixtures thereof. At block 814, fluids may be continuously produced from the
first
horizontal, or production, well.
[0077] The lateral and vertical mobilizing agents can be selected to
create a
process that is more efficient than, for example, SAGD. It is general practice
in the
industry to inject high quality steam in a thermal process. A commonly
observed
result is what is termed as steam override. Steam override occurs when the
vertical
mobilizing agent acts more quickly than the reservoir can drain the produced
fluids.
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Thus, a lateral mobilizing agent may be useful for increasing the drainage
rate.
Relative to wet steam injection, a slower acting vertical mobilizing agent and
a faster
acting lateral mobilizing agent may limit override that can occur near the
injector.
[0078] The
vertical mobilizing agent can be selected to control the rate of rise of
the vapour chamber. For example, different condensable hydrocarbon solvents,
steam and non-condensable gases, or combinations thereof, can be used to
control
the temperature and pressure of the vapour zone. Similarly, the effectiveness
of the
lateral mobilizing agent can be managed by mechanisms such as injecting higher
temperature fluids, larger solvent volumes, varying fractions of water and
hydrocarbon solvents or additional electrical heating.
[0079] While
the present techniques may be susceptible to various modifications
and alternative forms, the 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 true spirit and scope of the appended claims.
Embodiments
[0080] An
embodiment described herein provides a method for harvesting
resources in a reservoir. The
method includes drilling a first horizontal well
substantially proximate to a base of a reservoir and drilling a second
horizontal well
at a horizontal offset from the first horizontal well. Fluid
communication is
established between the first horizontal well and the second horizontal well
through a
cyclic production process. A vertical mobilizing agent is injected into the
reservoir
and a lateral mobilizing agent is used in the reservoir. Fluids are produced
from the
first horizontal well.
[0081] The
horizontal offset may be between about 50 and 200 metres. The
second horizontal well can be greater than about three metres shallower than
the
first well.
[0082] Using a
lateral mobilizing agent can include flowing an electric current
through the reservoir. An electrically conductive, non vaporizing fluid may be
injected into the reservoir, for example, to assist in carrying the electric
current.
Further, using a lateral mobilizing agent may include injecting hot water into
the
reservoir.
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[0083] The
lateral mobilizing agent may include a liquid hydrocarbon solvent
injected into the reservoir. The liquid hydrocarbon solvent can be heated
before
injection and hot water, steam, or both, may be injected in combination with
the liquid
hydrocarbon solvent. Wet steam may be injected into the reservoir, for
example,
functioning as both a lateral mobilizing agent and a vertical mobilizing
agent.
[0084] Fluid
communication can be established between the first horizontal well
and the second horizontal well by creating solvent fingers using cyclic
solvent
injection and production or using a continuous solvent injection. In some
embodiments, fluid communication is established by cyclic steam stimulation,
cyclic
solvent stimulation, or both.
[0085]
Injecting a vertical mobilizing agent can include injecting steam vapour, a
light hydrocarbon solvent, or both into the second horizontal well. A non-
condensable gas may be injected with the vertical mobilizing agent. The
lateral
mobilizing agents, or the vertical mobilizing agent, or both over time.
[0086] Another
embodiment described herein provides a system for harvesting
resources in a reservoir. The system includes a first horizontal well
substantially
proximate to the base of the reservoir and a second horizontal well at a
horizontal
offset from the first horizontal well, wherein the second horizontal well is
vertically
offset from the first horizontal well. A cyclic production system is
configured to
establish fluid communication between the wells. A continuous injection and
production system is configured to inject a vertical mobilizing fluid into the
reservoir,
use a lateral mobilizing agent in the reservoir, and produce a fluid from the
first
horizontal well.
[0087] The
system can include a steam generation system configured to provide
steam for injection. A
separation system can be configured to separate a
hydrocarbon stream from a produced fluid. The vertical mobilizing agent can
include
steam, solvents, or combinations thereof.
[0088] The
system can include an electrical system configured to flow an
electrical current through the reservoir. The electrical system may be
configured to
flow a current between the first horizontal well and the second horizontal
well. The
lateral mobilizing agent can include hot water, solvent, electric current, or
any
combinations thereof.
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[0089] Another embodiment described herein provides a method for
producing
hydrocarbons. The method includes producing fluids from a number of production
wells in a reservoir and imposing a lateral mobilizing agent on the reservoir
from a
number of injection wells. Each of the injection wells is adjacent to one of
the
production wells and each of the injection wells is laterally offset from each
of the
adjacent production wells. Fluid communication has been established between an
injection well and an adjacent production well using a cyclic production
process. A
vertical mobilizing agent is heated using heat transferred from the lateral
mobilizing
agent and a hydrocarbon stream is separated from the fluids produced from the
plurality of production wells.
[0090] Each of the injection wells may be drilled at a shallower level
than each of
the adjacent production wells. The lateral offset may be between about 50 and
200
metres, and each of the injection wells can be about three metres higher than
a
neighbouring production well. An electric current can be passed between the
plurality of injection wells and the plurality of production wells.
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