Note: Descriptions are shown in the official language in which they were submitted.
1
STAGING PRODUCTION WELL DEPTH
TECHNICAL FIELD
[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
[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] A typical 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 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
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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] 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
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generally defined as the exploitable or producible oil structurally located
above the
production well elevation.
[0007] 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.
[0008] 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.
[0009] "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, electrical heating, and solvent-aided processes
(SAP). In
general, thermal energy is provided to reduce the viscosity of the petroleum
to facilitate
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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.
[0010] A "chamber" or "zone" 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 communication with a steam injection well, which is
also the region
that is subject to depletion, primarily by gravity drainage, into a production
well.
[0011] Heavy oil recovery techniques such as SAGD create mobile zones or
chambers in a reservoir, for example zones 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 geologically segregated from a mobile production zone, separated from
the
production zone for example by lower permeability facies such as a shale
layers.
Accordingly, the term "barrier" or "baffle" may be used herein to mean a
geological
formation having some distinct geological characteristic that at least
partially separates
two or more zones in a formation, such as one or more low permeability streaks
that
together at least partially segregate two or more heavy oil containing strata.
A barrier
may accordingly be of varying degrees of impermeability and/or continuity, for
example
preventing or impeding hydraulic flow between at least some portions of the
reservoir
under some reservoir conditions, or more typically serving as a semi-permeable
barrier
under select reservoir conditions that allows some degree of reservoir fluid
mobility,
for example discontinuous streaks of reduced permeability that act as baffles
to fluid
flow between reservoir zones. There remains a need for methods that may be
used to
recover residual hydrocarbons, particularly from formations that include
barriers to
fluid flow.
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SUMMARY
[0012] Various aspects of the innovations disclosed herein involve the
production
of hydrocarbons from reservoir zones that are initially segregated by
permeability
barriers, such as lower permeability facies. Thermal recovery techniques
applied to a
primary recovery zone are used so as to provide thermal energy to an
underlying
secondary recovery zone. Production from the primary recovery zone is managed
in
conjunction with effecting thermal communication into the secondary recovery
zone.
Conductive heating of the secondary recovery zone circumvents the permeability
barriers, to increase the potential for mobility of heavy oil in the secondary
recovery
zone. When hydrocarbon mobility has been potentiated in the secondary recovery
zone in this way, the arrangement of production wells in the reservoir may be
changed,
dropping functional segments of the production well into the secondary
recovery zone.
Once this is done, the reconfigured well pairs may be operated so as to
recover
hydrocarbons from both the primary and secondary recovery zones, in effect
recovering what may otherwise have been a bypassed 'pay' zone. In other words,
the
present disclosure identifies and capitalizes on efficiencies resulting from a
well
configuration featuring two vertically-displaced production wells. The
efficiencies are
associated with the conduction of heat energy between segregated zones and the
capture of hydrocarbons which may not be recoverable by either of the
production
wells in isolation. In some instances, processes in accordance with the
present
disclosure have been shown to provide increased hydrocarbon recovery volumes
of
greater than about 10 vol.%.
[0013] Select embodiments of the present disclosure relate to a process
for
mobilizing fluids in a subterranean formation, the process comprising:
selecting a
hydrocarbon reservoir bearing heavy oil in the formation, the reservoir having
an upper
primary heavy oil zone above a secondary heavy oil zone, the secondary heavy
oil
zone comprising barrier strata that form one or more permeability barriers;
providing
an injection well within the hydrocarbon reservoir, wherein the injection well
comprises
an injection well surface completion in fluid communication with the
hydrocarbon
reservoir through an injection wellbore that comprises an initial segment
having a
vertical component extending downwardly from the injection well surface
completion,
the injection wellbore extending therefrom through an injection well heel
section that
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transitions the injection wellbore from the initial segment thereof to a
longitudinal
extension segment having a generally horizontal component within the upper
primary
heavy oil zone, the longitudinal extension segment terminating in an injection
well toe;
providing a primary production well within the hydrocarbon reservoir, wherein
the
primary production well comprises a production well surface completion in
fluid
communication with the hydrocarbon reservoir through a production wellbore
that
comprises an initial segment having a vertical component extending downwardly
from
the production well surface completion, the production wellbore extending
therefrom
through a production well heel section that transitions the production
wellbore from the
initial segment thereof to a longitudinal extension segment having a generally
horizontal component within the upper primary heavy oil zone, the longitudinal
extension segment terminating in a production well toe, wherein the
longitudinal
extension segment of the production wellbore is generally parallel to and
vertically
spaced apart below the longitudinal extension segment of the injection
wellbore, the
injection well and primary production well thereby forming an injector-primary-
producer well pair having a longitudinal axial dimension within the
hydrocarbon
reservoir; injecting an injection fluid into the primary heavy oil recovery
zone through
the longitudinal extension segment of the injection well and producing fluids
collected
along the longitudinal extension segment of the primary production well,
thereby
operating the injector-primary-producer well pair under a substantially
gravity-
dominated recovery process to form a mobilized fluid recovery zone in the
primary
heavy oil zone, so that thermal energy applied to the primary heavy oil zone
is
communicated downwardly by conduction into the secondary heavy oil zone,
heating
heavy oil in the secondary heavy oil zone across at least one of the one or
more
permeability barriers; providing a secondary production well comprising a
wellbore
having a longitudinal extension segment having a generally horizontal
component
within the secondary heavy oil zone, wherein the longitudinal extension
segment of
the secondary production wellbore is generally parallel to and vertically
spaced apart
below the longitudinal extension segment of the primary production wellbore,
with
barrier strata located between the longitudinal extension segments of the
primary and
secondary production wells, the injection well and the secondary production
well
thereby forming an injector-secondary-producer well pair along the
longitudinal axial
dimension of the hydrocarbon reservoir vertically spanning the secondary heavy
oil
zone; and producing fluids comprising hydrocarbons collected along the
longitudinal
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extension segment of the secondary production well, in a gravity-dominated
recovery
process, thereby recovering hydrocarbons from the secondary heavy oil zone.
[0014]
Select embodiments of the present disclosure relate to a process for
enhancing hydrocarbon recovery from a subterranean formation comprising an
upper
primary heavy oil zone above a secondary heavy oil zone, the secondary heavy
oil
zone including barrier strata that form one or more permeability barriers, the
process
comprising: providing an injection well comprising an injection well surface
completion
in fluid communication with the subterranean formation through an injection
wellbore
that comprises an initial segment having a vertical component extending
downwardly
from the injection well surface completion, the injection wellbore extending
therefrom
through an injection well heel section that transitions the injection wellbore
from the
initial segment thereof to a longitudinal extension segment having a generally
horizontal component within the upper primary heavy oil zone, the longitudinal
extension segment terminating in an injection well toe; providing a primary
production
well comprising a production well surface completion in fluid communication
with the
subterranean formation through a production wellbore that comprises an initial
segment having a vertical component extending downwardly from the production
well
surface completion, the production wellbore extending therefrom through a
production
well heel section that transitions the production wellbore from the initial
segment
thereof to a longitudinal extension segment having a generally horizontal
component
within the upper primary heavy oil zone, the longitudinal extension segment
terminating in a production well toe, wherein the longitudinal extension
segment of the
production wellbore is generally parallel to and vertically spaced apart below
the
longitudinal extension segment of the injection wellbore, the injection well
and the
primary production well thereby forming an injector-primary-producer well pair
having
a longitudinal axial dimension within the subterranean formation; providing a
secondary production well comprising a wellbore having a longitudinal
extension
segment having a generally horizontal component within the secondary heavy oil
zone, wherein the longitudinal extension segment of the secondary production
wellbore is generally parallel to and vertically spaced apart below the
longitudinal
extension segment of the primary production wellbore, with at least one of the
one or
more permeability barriers located between the longitudinal extension segments
of the
primary and secondary production wells, the injection well and the secondary
production well thereby forming an injector-secondary-producer well pair along
the
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longitudinal axial dimension of the subterranean formation vertically spanning
the
secondary heavy oil zone; forming a mobilized fluid recovery zone in the
primary heavy
oil zone through injection of an injection fluid into the primary heavy oil
zone through
the longitudinal extension segment of the injection well and collecting fluids
along the
longitudinal extension segment of the primary production well, such that the
injector-
primary-producer well pair is operated under a substantially gravity-dominated
recovery process to form a mobilized fluid recovery zone in the primary heavy
oil zone,
wherein thermal energy applied to the primary heavy oil zone is communicated
downwardly by conduction into the secondary heavy oil zone, heating heavy oil
in the
secondary heavy oil zone across the one or more permeability barriers; and
producing
fluids comprising hydrocarbons collected from the secondary heavy oil zone
along the
longitudinal extension segment of the secondary production well, such that
ultimate
hydrocarbon recovery is enhanced beyond that obtained from the substantially
gravity-
dominated recovery process in the primary production zone.
BRIEF DESCRIPTION OF THE DRAWINGS
[0015] 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.
[0016] Figure 2 is schematic illustration of cretaceous stratigraphy of
the
Athabasca oil sands.
[0017] Figure 3 is a schematic illustration of a compartmentalized heavy
oil
reservoir.
[0018] 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.
[0019] 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.
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[0020] 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.
[0021] Figure 7 is a cross sectional view of an alternative completion
for a
production well.
[0022] Figure 8 is a schematic view in longitudinal cross section
showing the
trajectory of an exemplified well arrangement that includes an injector (top)
a primary
producer (middle) and a secondary producer (bottom), with arrows showing the
vertical offset of the secondary producer from the primary producer (by an
average of
12m).
[0023] Figure 9 is a graph showing thermocouple temperature log data in
a vertical
observation well positioned 2m from the horizontal well bores, with the top of
the heavy
oil reservoir illustrated by the top line at a depth of approximately 218m
subsea, the
injector well illustrated as the line at approximately 196m, the abandoned
(shut in)
primary producer illustrated as the line at approximately 192m and the active
secondary producer well illustrated as the line at approximately 180m. The
arrow
indicates the increase in temperature over time over 12 months, each
successive line
representing one month's increase in temperature.
[0024] Figure 10 is a graph illustrating historical and projected oil
production from
three deepened production wells, with an arrow indicating the time at which
the
primary production wells were shut in and the use of the secondary production
wells
was initiated.
DETAILED DESCRIPTION
[0025] Select embodiments of the present disclosure relate to processes
for
mobilizing fluids in a subterranean formation, for example in a hydrocarbon
reservoir
bearing heavy oil. Likewise, select embodiments of the present disclosure
relate to
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processes for enhancing hydrocarbon recovery. In select instances, the
reservoir/formation may be characterized as having an upper primary heavy oil
zone
above a secondary heavy oil zone. The secondary heavy oil zone is defined or
segregated from the primary recovery zone by the existence of barrier strata
that form
one or more permeability barriers.
[0026] Injection and production wells may be provided in the primary
recovery
zone, as for example is typical of SAGD well patterns, with the longitudinal
generally
horizontal segments of the injection and primary production wells being placed
within
the upper primary heavy oil zone, forming an injector-primary-producer well
pair within
the hydrocarbon reservoir. This well pair may be operated in accordance with a
wide
variety of approaches to steam assisted gravity drainage (SAGD) or solvent
aided
processes (SAP), to create a mobilized fluid recovery zone in the primary
heavy oil
zone, and this may be accomplished so that thermal energy applied to the
primary
heavy oil zone is communicated downwardly at least in part by conduction, into
the
secondary heavy oil zone. In this way, heavy oil in the secondary heavy oil
zone is
heated, and this heating takes place across the permeability barriers.
[0027] At a selected point in the mobilizing/recovery process, a
secondary
production well may be provided, typically generally parallel to and
vertically spaced
apart below the generally horizontal portion of the primary production
wellbore. In this
way, barrier strata may be located between the primary and secondary
production
wells, such that the injection and secondary production wells, which together
form an
injector-secondary-producer well pair, vertically span the secondary heavy oil
zone. In
order to determine the point at which to initiate the provision and operation
of the
secondary production well, a number of factors should be considered including
the
quality of the reservoir, the saturation of heavy oil in the secondary
recovery zone, and
the downward temperature gradient induced by thermal stimulation in the
primary
recovery zone. The downward temperature gradient induced by thermal
stimulation
may be of particular importance in determining the point at which to initiate
the
provision and operation of the secondary production well. For example,
provision
of/production from the secondary production well may be timed to coincide with
the
point at which the desired ultimate depth receives enough waste heat to reach
the
temperature of heavy oil mobilization.
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[0028]
Fluid recovery from the primary production well may be suspended before
or after the secondary production well is in place. In select embodiments,
fluid recovery
from the primary production well is suspended before the secondary production
well
is in place, and then shut in after fluid recovery from the secondary
production well is
established. Postponing shutting in the primary production well until after
fluid recovery
from the secondary production well is established may reduce the risk of
reservoir-
limiting production. For example, in the event that the secondary production
well
encounters unexpectedly poor reservoir quality that is unfavorable to
production, the
primary production well may be reverted to. Alternatively, production may
continue for
a time from both the primary and secondary production wells, for example
shutting in
the primary production well when the liquid levels in the primary heavy oil
zone are
pulled below the depth of the primary production well (i.e. when the primary
producer
is "steamed out").
[0029] The
depth at which the horizontal component of the secondary production
well should be provided may be influenced by a variety of factors such as
reservoir
quality, underlying heavy oil saturation, heavy oil chemistry, and the
downward
temperature gradient induced by thermal stimulation in the primary recovery
zone. In
select embodiments, the secondary production well may be spaced below the
primary
production well by at least about 3m, 10m, 15m, or 25m. In a preferred
embodiment,
the secondary production well may be spaced below the primary production well
by
about llm as averaged along the lateral length of the primary production well.
Those
skilled in the art will recognize that the horizontal components of such wells
are
typically non-uniform. For example, the horizontal component of the secondary
production well may be spaced below the horizontal component of the primary
production well by an average of about llm but have segments ranging from
about
9m to about 13m below the horizontal component of primary production well.
Overall,
the displacement of the horizontal component of the secondary production well
from
the horizontal component of the primary production well should be large enough
to
produce sufficient volumes of heavy oil to justify the risk and capital
investment
associated with the provision and operation of the secondary production well.
[0030]
Recovery processes in accordance with the present disclosure may for
example be carried out by way of a gravity-dominated recovery process, such as
SAGD or SAP, thereby recovering hydrocarbons from both the primary and the
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secondary heavy oil zones. In particular, recovery form the secondary heavy
oil zone
may be facilitated by thermal stimulation of the secondary heavy oil zone by
way of
the secondary production well. For example, in instances where the depth of
the
secondary production well is selected to penetrate a section of the secondary
recovery
zone that is substantially below the temperature at which the heavy
hydrocarbons of
the secondary recovery zone are mobile, steam, solvent, or a combination
thereof may
be injected into the secondary recovery zone by way of the secondary
production well
prior to production from the secondary production well.
[0031] Select embodiments of the present disclosure will now be
described by
reference to Figures 1-10.
[0032] 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, and 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.
[0033] 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
recovery
zone 28 is separated from a secondary heavy oil zone 30 by one or more
permeability
barriers 20. The top of the primary heavy oil recovery zone 28 is
hydraulically confined,
for example by shale cap rock 40.
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[0034] In the embodiment illustrated in Figure 3, injection 19 and
primary
production 17 wells are present in primary recovery zone 29, as for example is
typical
of SAGD well patterns as illustrated in Figure 1, with the longitudinal
generally
horizontal segments of the injection 19 and primary production 17 wells being
placed
within upper primary heavy oil zone 29, forming an injector-primary-producer
well pair
within the hydrocarbon reservoir. A thermal recovery technique, such as SAGD,
may
be applied to the primary heavy oil zone 29, for example forming steam chamber
28
around injection well 19, to mobilize heavy oil for production through primary
production well 17. Thermal energy applied to primary heavy oil zone 29 by way
of
steam chamber 28 is communicated across permeability barriers 20 to secondary
heavy oil zone 30 to heat heavy oil in the secondary heavy oil zone 30. In
this sense,
the secondary heavy oil zone 30 is defined, or segregated or partially
segregated from
the primary recovery zone 29, by the barrier strata that form one or more
permeability
barriers 20, such as clasts, shale lenses, or IHS. The heating of the
secondary heavy
oil zone 30 may be primarily by way of conductive heating of the fluids in
secondary
zone 30, in contrast to the considerable degree of convective heating in the
primary
recovery zone 29 associated with steam chamber 28. In alternative embodiments,
the
injector-primary-producer well pair may be operated in accordance with a wide
variety
of approaches to thermal recovery, such as cyclic steam stimulation, hot water
flood,
steam flood, and SAGD with or without solvents, to create the mobilized fluid
recovery
zone 28 in the primary heavy oil zone 29. In this way, heavy oil in the
secondary heavy
oil zone 30 is heated to a selected point of practical mobility. This minimum
temperature point may for example be determined based on a function of the
vertical
depth offset from the original well pair, the well length, reservoir fluid
saturations,
artificial lift method, and surface and downhole pressures. In select
embodiments, the
selected point at which there is a transition to production from the secondary
heavy oil
zone 30 is when the average or aggregate fluid viscosity in the secondary zone
30 is
low enough that flow rates through the new producer well are stable and
sustainable.
[0035] At the selected point in the recovery process, a secondary
production well
27 may be provided, typically with a horizontal segment that is generally
parallel to
and vertically spaced apart below the generally horizontal portion of the
primary
production wellbore 17. In this way, barrier strata 20 are located between the
primary
17 and secondary 27 production wells. The injection 19 and secondary
production 27
wells accordingly together form an injector-secondary-producer well pair,
vertically
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spanning secondary heavy oil zone 30. Once the secondary production well 27 in
in
place, fluid recovery from the primary production well 17 may be suspended or
shut
in, and the production of fluids commenced from the secondary production well
27.
This recovery process may for example be carried out by way of a gravity-
dominated
recovery process, such as SAGD, thereby recovering hydrocarbons from both the
primary and the secondary heavy oil zones.
[0036] The inventors have recognized that the abandonment of fully-
functioning,
high-productivity oil producer well located in the primary recovery zone in
favour of a
new producer well(s) with trajectories that are capable of capturing by-passed
oil
enable a new recovery scheme for producing oil from both the primary and
secondary
recovery zones. The new producer well 27 is located within the secondary
recovery
zone. In alternative embodiments, the secondary producer 27 may for example
located at least about 1m, 2m, 3m, 4m, 5m, 6m, 7m, 8m, 9m, 10m, 11m, 12m, 13m,
14m, 15m, 20m or 25m from the primary producer 17. In general, greater offset
distances will require more time for conductive heating of the secondary zone
30
before production is initiated from the new producer 27.
[0037] 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. The selection of an appropriate set of configurations is
within the
purview of a person skilled in the art having the benefit of the present
disclosure and
having regard to the parameters of the specific formation under consideration.
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[0038] In accordance with various aspects of the disclosure, 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 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
[0039] In an exemplary embodiment of the processes of the disclosure,
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
CA 3004235 2018-05-08
16
continued heating of Wabiskaw. In general terms, the geology of the
exemplified
embodiment was characterized by a large, relatively clean, bitumen saturated
and high
permeability sand package, with the notable exception of several known mud
barriers
(having virtually zero permeability) of unknown variable extent located below
the
primary producer, but above the secondary producer. In
the exemplified
implementation, had the primary producer been originally placed below these
mud
barriers, the steam chamber would not have properly developed as the mud
barriers
would have interfered with fluid communication within the recovery zone, and
the
overall ultimate recovery of hydrocarbons would have been far lower.
[0040] The
trajectory of the exemplified wells is illustrated in Figure 8. The
conductive heating of bitumen in the secondary recovery zone is illustrated in
Figure
9. This graph provides data beginning two months before the secondary producer
well
was drilled, then shows the jump in temperature that coincides with a 30 day
steam-
stimulation of the secondary producer. The continued increase in the heating
of the
secondary recovery zone that accompanies production of reservoir fluids
through the
secondary producer is also illustrated. The earliest temperature plots
according
illustrate the degree to which the secondary recovery zone was above the
mobility
threshold (defined as 60 C for this well configuration and facility operating
conditions)
prior to the initiation of recovery from the secondary producer. In select
embodiments,
secondary producers may for example be offset from a primary producer by up to
10m,
15m, 20m or 25. Primary and secondary producer offsets are possible at
progressively
greater distances, for example greater than 20m or 25m, provided there has
been
sufficient time and heat input for conductive heating to adequately increase
the
mobility of oil in the secondary recovery zone. The transition to production
from the
secondary producers may for example take place at a selected mobility
threshold,
such as a secondary producer well bottom temperature of approximately 50 C, 60
C
or 70 C, or any selected value within the range of 50 C to 70 C. The mobility
threshold
may for example be chosen in conjunction with the selection of a start up
regime for
the secondary producer, for example with or without an initial period of
heating, for
example by cycling steam through the secondary producer, and/or applying a
solvent
start up process. In some embodiments, recovery may be initiated from the
secondary
producer without any additional heat being applied, with the necessary
mobility being
conferred exclusively by conductive heating from the primary recovery process.
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17
[0041] Figure 10 is a graph illustrating actual and forecast oil
production rates from
a set of three primary production wells, followed by the recoveries from three
corresponding secondary production wells, with the arrow at the beginning of
2016
identifying the date corresponding to the initiation of processes for the
recovery of
hydrocarbons from the secondary zone, with the onset of production from the
secondary producer wells occurring shortly thereafter. The simulated combined
production from the primary and secondary zones through the secondary
producers
is shown as line superimposed on the initial cumulative production figures. As
illustrated, following the three well redevelopment, oil rates increased by
about
3600bb1/d, with one of the new secondary producers alone having a number of
weeks
producing above 3400bb1/d. In conjunction with the switch to the secondary
production
wells, the SOR for the three well-pairs dropped from 2.6 to 1.3. This is a
further
indication of the degree to which the primarily conductive heating of the
secondary
recovery zone mobilizes the oil therein during recovery from the primary
recovery
zone.
[0042] The present disclosure identifies and capitalizes on efficiencies
resulting
from a well configuration featuring two vertically-displaced production wells.
The
efficiencies are associated with the conduction of heat energy between
segregated
zones and the capture of hydrocarbons which may not be recoverable by either
of the
production wells in isolation. In some instances, processes in accordance with
the
present disclosure have been shown to provide increased hydrocarbon recovery
volumes of greater than about 10 vol.%. The potential for processes in
accordance
with present disclosure to increase the ultimate hydrocarbon recovery volume
for a
reservoir has been verified independently. In one instance, an independent
qualified
reservoir evaluator (IQRE) determined a reservoir to have an estimated bitumen
in
place (EBIP) volume of about 145 mmbbl for a first pad. This estimate is
independent
of the depth/number/configuration of the production wells utilized. After the
provision
of five secondary production wells, the IQRE increased the recoverable volumes
for
the pad from about 30.0 mmbbl in 2015 to about 34.1 mmbbl in 2017 ( a 4.1
mmbbl
increase). The vast majority of this increase was attributed directly to the
provision of
the secondary production wells, and it represents an increase in ultimate
recovery of
the original EBIP of about 9% (from -66% to -76%), and a 14% increase in
recoverable volume.
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[0043]
Although various embodiments of the disclosure are provided herein, many
adaptations and modifications may be made within the scope of the disclosure
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 disclosure, 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
disclosure 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 "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 disclosure. Any priority document(s) and all
publications,
including but not limited to patents and patent applications, cited in this
specification
are incorporated herein by reference as if each individual publication were
specifically
and individually indicated to be incorporated by reference herein and as
though fully
set forth herein. The disclosure includes all embodiments and variations
substantially
as hereinbefore described and with reference to the examples and drawings.
CA 3004235 2018-05-08
