Note: Descriptions are shown in the official language in which they were submitted.
THERMALLY INDUCED EXPANSION DRIVE IN HEAVY OIL RESERVOIRS
FIELD OF THE INVENTION
[0001] The invention is in the field of hydrocarbon reservoir engineering,
particularly
thermal recovery processes such as steam assisted gravity drainage (SAGD)
systems in
heavy oil reservoirs.
BACKGROUND OF THE INVENTION
[0002] Some subterranean deposits of viscous hydrocarbons can be extracted
in situ by
lowering the viscosity of the petroleum to mobilize it so that it can be moved
to, and
recovered from, a production well. Reservoirs of such deposits may be referred
to as
reservoirs of heavy hydrocarbon, heavy oil, bitumen, tar sands, or oil sands.
The in situ
processes for recovering oil from oil sands typically involve the use of
multiple wells drilled
into the reservoir, and are assisted or aided by thermal recovery techniques,
such as
injecting a heated fluid, typically steam, into the reservoir from an
injection well. One
process of this kind is steam-assisted gravity drainage (SAGD).
[0003] The SAGD process is in widespread use to recover heavy hydrocarbons
from
the Lower Cretaceous McMurray Formation, within the Athabasca Oil Sands of
northeastern Alberta, Canada. A thick sequence of marine shales and siltstones
of the
Clearwater Formation unconformably overlies the McMurray Formation in most
areas of
northeastern Alberta. In some areas, glauconitic sandstones of the Wabiskaw
member are
present at the base of the Clearwater. The Grand Rapids Formation overlies the
Clearwater Formation, and quaternary deposits unconformably overlie the
Cretaceous
section. The pattern of hydrocarbon deposits within this geological context is
complex and
varied.
[0004] Atypical SAGD process is disclosed in Canadian Patent No. 1,130,201
issued
on 24 August 1982, in which the functional unit involves two wells that are
drilled into the
deposit, one for injection of steam and one for production of oil and water.
Steam is
injected via the injection well to heat the formation. The steam condenses and
gives up its
1
Date Recue/Date Received 2021-02-01
latent heat to the formation, heating a layer of viscous hydrocarbons. The
viscous
hydrocarbons are thereby mobilized, and drain by gravity toward the production
well with
an aqueous condensate. In this way, the injected steam initially mobilises the
in-place
hydrocarbon to create a "steam chamber" in the reservoir around and above the
horizontal
injection well. The term "steam chamber" accordingly refers to the volume of
the reservoir
which is saturated with injected steam and from which mobilized oil has at
least partially
drained. Mobilized viscous hydrocarbons are typically recovered continuously
through the
production well. The conditions of steam injection and of hydrocarbon
production may be
modulated to control the growth of the steam chamber, to ensure that the
production well
remains located at the bottom of the steam chamber in an appropriate position
to collect
mobilized hydrocarbons.
[0005] In the ramp-up stage of the SAGD process, after communication has
been
established between the injection and production wells during start-up,
production begins
from the production well. Steam is continuously injected into the injection
well (usually at
constant pressure) while mobilized bitumen and water are continuously removed
from the
production well (usually at constant temperature). During this period the zone
of
communication between the wells is expanded axially along the full well pair
length and the
steam chamber grows vertically up to the top of the reservoir. The reservoir
top may be a
thick shale (overburden) or some lower permeability facies that cause the
steam chamber
to stop rising.
[0006] Heavy oil recovery techniques such as SAGD create mobile zone
chambers in a
reservoir, from which at least some of the original oil-in-place has been
recovered. However,
reservoirs depleted by such processes typically contain a significant volume
of residual
hydrocarbons, often in reservoir zones that are hydraulically segregated from
a mobile
production zone, separated from the production zone for example by lower
permeability
facies such as a shale overburden. There remains a need for methods that may
be used to
recover these residual hydrocarbons.
2
Date Recue/Date Received 2021-02-01
[0007] In the context of the present application, various terms are used in
accordance
with what is understood to be the ordinary meaning of those terms. For
example,
"petroleum" is a naturally occurring mixture consisting predominantly of
hydrocarbons in
the gaseous, liquid or solid phase. In the context of the present application,
the words
"petroleum" and "hydrocarbon" are used to refer to mixtures of widely varying
composition.
The production of petroleum from a reservoir necessarily involves the
production of
hydrocarbons, but is not limited to hydrocarbon production. Similarly,
processes that
produce hydrocarbons from a well will generally also produce petroleum fluids
that are not
hydrocarbons. In accordance with this usage, a process for producing petroleum
or
hydrocarbons is not necessarily a process that produces exclusively petroleum
or
hydrocarbons, respectively. "Fluids", such as petroleum fluids, include both
liquids and
gases. Natural gas is the portion of petroleum that exists either in the
gaseous phase or in
solution in crude oil in natural underground reservoirs, which is gaseous at
atmospheric
conditions of pressure and temperature. Natural gas may include amounts of non-
hydrocarbons. The abbreviation POIP stands for "producible oil in place" and
in the context
of the methods disclosed herein is generally defined as the exploitable or
producible oil
structurally located above the production well elevation.
[0008] It is common practice to segregate petroleum substances of high
viscosity and
density into two categories, "heavy oil" and "bitumen". For example, some
sources define
"heavy oil" as a petroleum that has a mass density of greater than about 900
kg/m3.
Bitumen is sometimes described as that portion of petroleum that exists in the
semi-solid or
solid phase in natural deposits, with a mass density greater than about 1000
kg/m3 and a
viscosity greater than 10,000 centipoise (cP; or 10 Pa.$) measured at original
temperature
in the deposit and atmospheric pressure, on a gas-free basis. Although these
terms are in
common use, references to heavy oil and bitumen represent categories of
convenience,
and there is a continuum of properties between heavy oil and bitumen.
Accordingly,
references to heavy oil and/or bitumen herein include the continuum of such
substances,
and do not imply the existence of some fixed and universally recognized
boundary between
the two substances. In particular, the term "heavy oil" includes within its
scope all "bitumen"
including hydrocarbons that are present in semi-solid or solid form.
3
Date Recue/Date Received 2021-02-01
[0009] A "reservoir" is a subsurface formation containing one or more
natural
accumulations of moveable petroleum, which are generally confined by
relatively
impermeable rock. An "oil sand" or "tar sand" reservoir is generally comprised
of strata of
sand or sandstone containing petroleum. A "zone" in a reservoir is an
arbitrarily defined
volume of the reservoir, typically characterised by some distinctive property.
Zones may
exist in a reservoir within or across strata, and may extend into adjoining
strata. In some
cases, reservoirs containing zones having a preponderance of heavy oil are
associated
with zones containing a preponderance of natural gas. This "associated gas" is
gas that is
in pressure communication with the heavy oil within the reservoir, either
directly or
indirectly, for example through a connecting water zone.
[0010] "Thermal recovery" or "thermal stimulation" refers to enhanced oil
recovery
techniques that involve delivering thermal energy to a petroleum resource, for
example to a
heavy oil reservoir. There are a significant number of thermal recovery
techniques other
than SAGD, such as cyclic steam stimulation, in situ combustion, hot water
flooding, steam
flooding and electrical heating. In general, thermal energy is provided to
reduce the
viscosity of the petroleum to facilitate production. The addition of heat may
also have
geophysical effects within the reservoir, for example causing the expansion of
reservoir
fluids, which may in turn lead to increases in pore pressures. In oil sand
reservoirs, thermal
expansion of bitumen within a reservoir may for example create pore pressures
that are
high enough to produce reservoir expansion, in effect moving sand grains apart
(R.M.
Butler, The expansion of tar sands during thermal recovery, Journal of
Canadian Petroleum
Technology, 1986, volume 25, issue 5, p. 51-56). The evolution of temperature
and heat
flow within a reservoir depends upon the thermal properties of the reservoir
materials,
including volumetric heat capacity, thermal conductivity, thermal diffusivity
and the
coefficients of thermal expansion.
[0011] A "chamber" within a reservoir or formation is a region that is in
fluid/pressure
communication with a particular well or wells, such as an injection or
production well. For
example, in a SAGD process, a steam chamber is the region of the reservoir in
fluid
4
Date Recue/Date Received 2021-02-01
communication with a steam injection well, which is also the region that is
subject to
depletion, primarily by gravity drainage, into a production well.
[0012] "Reservoir compartmentalization" is a term used to describe the
segregation of a
petroleum accumulation into a number of distinct fluid/pressure compartments.
In general,
this segregation takes place when fluid flow is prevented across sealed
boundaries in the
reservoir. These boundaries may for example be caused by a variety of
geological and fluid
dynamic factors, involving: static seals that are completely sealed and
capable of
withholding (trapping) petroleum deposits, or other fluids, over geological
time; and
dynamic seals that are low to very low permeability flow barriers that
significantly reduce
fluid cross-flow to rates that are sufficiently slow to cause the segregated
chambers to have
independent fluid pressure dynamics, although fluids and pressures may
equilibrate across
a dynamic seal over geological time-scales (Reservoir compartmentalization: an
introduction, Jolley et al., Geological Society, London, Special Publications
2010, v. 347, p.
1-8). A reservoir compartment may be hydraulically confined, so that fluids
are prevented
from moving beyond the compartment by sealed boundaries confining the
compartment.
SUMMARY OF THE INVENTION
[0013] The invention involves the production of hydrocarbons from reservoir
compartments that are initially segregated into distinct fluid/pressure
compartments, with
the compartments in thermal communication. Thermal recovery techniques applied
to one
compartment are used so as to provide thermal energy to a second, adjoining
but distinct
fluid/pressure compartment, in which the second compartment is hydraulically
confined by
sealed boundaries. Production from the first compartment is managed in
conjunction with
effecting thermal communication from the first compartment to the second
compartment.
Heating of the second, confined compartment, increases fluid pressures within
the second
compartment. This increase in fluid pressure in the second compartment, which
may be
coupled to production of fluids from the first compartment, gives rise to a
pressure
differential that is used to drive hydrocarbons from the second compartment to
the first
compartment, so that hydrocarbons originating from the second compartment are
produced
Date Recue/Date Received 2021-02-01
from the first compartment. The hydrocarbons may for example be a heavy oil
that is
originally immobile in the second compartment, which is mobilized by the
thermal energy
communicated from the first compartment, and driven by the pressure
differential to the
first compartment for production.
BRIEF DESCRIPTION OF THE DRAWINGS
[0014] Figure 1 is a schematic illustration of a typical SAGD well pattern,
showing
paired injector and producer well pairs, each have a heel and a toe within the
hydrocarbon
rich pay zone of the formation.
[0015] Figure 2 is schematic illustration of cretaceous stratigraphy of the
Athabasca oil
sands.
[0016] Figure 3 is a schematic illustration of a compartmentalized heavy
oil reservoir.
[0017] Figure 4 is a cross sectional view of an exemplary completion for an
injector
well, referring to the use of slotted liners, as for example disclosed in
Canadian Patent
Application 2,616,483 of Cenovus Energy Inc. published 29 June 2008.
[0018] Figure 5 is a cross sectional view of an exemplary completion for a
production
well, in a start up configuration for circulation, illustrating an embodiment
employing gas lift.
[0019] Figure 6 is a cross sectional view of an exemplary completion for a
production
well, illustrating an embodiment employing an electric submersible pump (ESP)
for
production operations following start up. Typically, after circulation start-
up, the 2" coiled
tubing string will be removed and the well equipped with a high temperature
ESP capable
of pumping fluid from the well into production gathering facilities.
[0020] Figure 7 is a cross sectional view of an alternative completion for
a production
well.
6
Date Recue/Date Received 2021-02-01
DETAILED DESCRIPTION OF THE INVENTION
[0021] Various aspects of the invention may involve the drilling of SAGD
well pairs
within a reservoir 11, as illustrated in Figure 1, with each injector well 13,
19, 23, paired
with a corresponding producer well 15, 17 and 21. Each well has a completion
14, 12, 16,
18, 20 and 22 on surface 10, with a generally vertical segment leading to the
heel of the
well, which then extends along a generally horizontal segment to the toe of
the well. In very
general terms, to provide a general illustration of scale in selected
embodiments, these well
pairs may for example be drilled in keeping with the following parameters.
There may be
approximately 5 m depth separation between the injection well and production
well. The
SAGD well pair may for example average approximately 800 m in length. The
lower
production well profile may generally be targeted so that it is approximately
1 to 2 m above
the SAGD base. The development of steam chambers around each well pair may be
illustrated in cross sectional views along axis 24, which is perpendicular to
the longitudinal
axial dimension of the horizontal segments of the well pairs.
[0022] As illustrated in Figure 2, the stratigraphy of the Athabasca oil
sands varies
geographically, and in places includes oil sand deposits that are separated by
distinct
barrier layers, such as marine shales. Figure 3 is a cross sectional view
along axis 24 of
Figure 1, illustrating a hydrocarbon reservoir in which a primary heavy oil
compartment 30
is hydraulically separated from a secondary heavy oil compartment 40 by a
permeability
barrier 32, so that under initial reservoir conditions heavy oil does not flow
across the
permeability barrier. The secondary heavy oil compartment 40 is hydraulically
confined, for
example by shale cap rock 42.
[0023] In the embodiment illustrated in Figure 3, a SAGD thermal recovery
technique is
applied to the primary heavy oil compartment 30, forming steam chamber 28
around
injection well 19, to mobilize heavy oil for production through production
well 17. Thermal
energy applied to the primary heavy oil compartment 30 by way of steam chamber
28 is
communicated across permeability barrier 32 to secondary heavy oil compartment
40 to
7
Date Recue/Date Received 2021-02-01
heat heavy oil in the secondary heavy oil compartment 40. This is carried out
so as to
increase fluid pressure within the secondary heavy oil compartment 40 by way
of thermal
expansion of the confined fluids in secondary compartment 40.
[0024] By adjusting the production and/or injection of fluids in primary
heavy oil
compartment 30, as well as the delivery of thermal energy to secondary heavy
oil
compartment 40, conditions may be arranged so that the fluid pressure in the
secondary
heavy oil compartment 40 rises above the fluid pressure in the primary heavy
oil
compartment 30, to create a fluid pressure differential between the
compartments. Under
these circumstances, a fluid flow path may be provided across the permeability
barrier, for
example by a well completed so as to drain mobilized heavy oil from secondary
heavy oil
compartment 40 to primary heavy oil compartment 30, driven by the fluid
pressure
differential between the compartments. In this way, fluids may be recovered
from primary
heavy oil compartment 30 that include heavy oil from secondary heavy oil
compartment 40,
for example by way of SAGD production well 17.
[0025] In alternative embodiments, the relative positions of primary and
secondary
heavy oil compartments may be varied. For example, the primary compartment may
be
above or below the secondary compartment, with an intervening permeability
barrier that is
substantially horizontal. Alternatively, the compartments may be spaced apart
horizontally,
with a substantially vertical permeability barrier. In practice, the adjoining
compartments will
typically have a complex geometric relationship, with vertical and horizontal
components of
offset.
[0026] The hydraulic confinement of the secondary compartment may be by way of
a
static seal formed by a geological pattern of surrounding permeability
barriers.
Alternatively, hydraulic confinement may be caused or enhanced by the
imposition of
dynamic fluid flow barriers that are not naturally present, such as synthetic
permeability
barriers formed by pressurization of a hydraulically adjoining overlying gas
zone, or
underlying or overlying water zones, or laterally adjacent gas or water zones.
Alternatively,
immobile bitumen may form part of a permeability barrier around the secondary
8
Date Recue/Date Received 2021-02-01
compartment, zones of fluid injection may form a production seal or natural
static or
dynamic seals may form the production seal.
[0027] Once a fluid flow path is provided for fluids to exit the secondary
compartment,
the drive mechanism for that flow may consist principally of expansion of
pressurized
liquids from the secondary compartment as it travels towards the pressure sink
afforded by
the lower pressure primary compartment. Alternatively, the drive mechanism may
involve a
solution gas drive due to expansion of gases, or may involve combinations of
these
alternative mechanisms. The basic drive mechanism provided by fluid expansion
within the
confined compartment may also be enhanced by the addition of other drive
mechanisms,
such as cyclic steam stimulation, hot water flood, or steam flood, or
combinations thereof.
[0028] The fluid flow path for hydrocarbons from the secondary compartment
to the
primary compartment may for example be by way of a conduit, such as a well,
introduced
to guide the flow of mobilized hydrocarbons. In the event that formation
geology in the
secondary comparment is characterized by poor effective vertical permeability
(e.g., clasts,
shale lenses, IHS), vertical or inclined wells may for example be employed to
drain fluids
horizontally (i.e., in the preferred direction of flow) from the secondary
compartment into
the wellbore that provides a fluid flow path across the permeability barrier
to the primary
compartment.
[0029] Alternative aspects of the invention involve completing wells in
various
configurations. Exemplary completions for injector, producer on gas lift,
producer on
electric submersible pump (ESP) and simulated producer are shown in Figures 4,
5, 6 and
7 respectively.
[0030] In accordance with various aspects of the invention, detailed
computational
simulations of reservoir behaviour may be carried out. The thermal properties
of the
reservoir may for example be characterized using two rock types. Rock type one
may for
example represent clean sand of the McMurray formation in Alberta, Canada. A
second
rock type representing an relatively impermeably strata, such as shale, may be
used to
9
Date Recue/Date Received 2021-02-01
simulate a permeability barrier. Exemplary properties of the two such rock
types may for
example be defined with the following properties:
Rocktype 1 (Sand)
Porosity Reference Pressure = 100 kPa
Compressibility = le-6 1/kPa
Volumetric Heat Capacity 2.39e6 J/(m3*C)
Rock Thermal Conductivity = 196,820 J/(m*day*C)
Water Thermal Conductivity = 552,960 J/(m*day*C)
Oil Thermal Conductivity = 0
Gas Thermal Conductivity = 0
Rocktype 2 (Shale Overburden & Underburden)
Porosity Reference Pressure = 100 kPa
Compressibility = 1e6 1/kPa
Volumetric Heat Capacity 2.39e6 J/(m3*C)
Rock Thermal Conductivity = 146,880 J/(m*day*C)
Water Thermal Conductivity = 0
Oil Thermal Conductivity = 0
Gas Thermal Conductivity = 0
[0031]
In an exemplary embodiment of the processes of the invention, carried out in
the
McMurray and Wabiskaw formations, typical values of the relevant formation
thicknesses
are as follows: McMurray Formation in which SAGD is being conducted 38 m;
impermeable
mudstone immediately overlying the McMurray 6 m; affected Wabiskaw zone
immediately
overlying the mudstone 7 m. In this embodiment, the ascent within the McMurray
Formation of the SAGD steam chamber was confirmed with temperature profiles.
It was
also confirmed with 4D (Time Lapse) Seismic data. Progressive heating of the
overlying
Wabiskaw was clearly evident in the 4D seismic data, over time: year 1 - No
seismic
anomalies evident in Wabiskaw; year 2 - anomalies appear, indicating some
heating of
Wabiskaw; year 3 ¨ anomalies signal continued heating of Wabiskaw.
Date Recue/Date Received 2021-02-01
[0032] Because of the Wabiskaw zone's geological confinement, the pressure
within the
Wabiskaw compartment increased markedly as it was heated conductively from
below.
This thermally induced over-pressuring of the Wabiskaw was first identified in
year 3, while
attempting to drill a steam chamber core. Whereas the normal formation
pressure at this
depth and in this area is approximately 2000 kPa, the pressure measured via
drill stem test
was approximately 6500 kPa. To utilize this pressure increase, a production
well was
drilled into the Wabiskaw, producing significant quantities of oil on a
sustained basis,
gradually reducing the reservoir pressure in the Wabiskaw.
[0033] These results indicate that conductive heating of bitumen in the
confined
Wabiskaw zone, with heat arriving from the underlying SAGD steam chamber in
the
McMurray formation, induced an increase in reservoir pressure within the
Wabiskaw from
-2000 kPa to -6500 kPa. Field data confirm that the mudstone separating the
underlying
McMurray Formation from the overlying Wabiskaw zone is competent, allowing no
hydraulic communication between the two zones. If the two zones were
hydraulically
communicating, the pressure in the Wabiskaw would equilibrate at a value
closer to that of
the McMurray Formation (e.g., -2000 kPa). Instead, the Wabiskaw reached a
pressure of
-6500 kPa, illustrating that high pressure may be induced by conductive
heating of the
Wabiskaw due to its geological confinement.
[0034] Although various embodiments of the invention are disclosed herein,
many
adaptations and modifications may be made within the scope of the invention in
accordance with the common general knowledge of those skilled in this art. For
example,
any one or more of the injection, production or vent wells may be adapted from
well
segments that have served or serve a different purpose, so that the well
segment may be
re-purposed to carry out aspects of the invention, including for example the
use of
multilateral wells as injection, production and/or vent wells. Such
modifications include the
substitution of known equivalents for any aspect of the invention in order to
achieve the
same result in substantially the same way. Numeric ranges are inclusive of the
numbers
defining the range. The word "comprising" is used herein as an open-ended
term,
substantially equivalent to the phrase "including, but not limited to", and
the word
11
Date Recue/Date Received 2021-02-01
"comprises" has a corresponding meaning. As used herein, the singular forms
"a", "an" and
"the" include plural referents unless the context clearly dictates otherwise.
Thus, for
example, reference to "a thing" includes more than one such thing. Citation of
references
herein is not an admission that such references are prior art to the present
invention.
12
Date Recue/Date Received 2021-02-01
