Note: Descriptions are shown in the official language in which they were submitted.
CA 02830741 2013-10-23
IMPROVING RECOVERY FROM A HYDROCARBON RESERVOIR
FIELD
The present disclosure relates to harvesting hydrocarbon resources using
gravity drainage
processes. Specifically, improved methods are disclosed involving steam
assisted gravity
drainage of heavy oil from underground reservoirs.
BACKGROUND
This section is intended to introduce various aspects of the art, which may be
associated
with the present disclosure. This discussion is believed to assist in
providing a framework to
facilitate a better understanding of particular aspects of the present
disclosure. Accordingly,
it should be understood that this section should be read in this light, and
not necessarily as
admissions of prior art.
Modern society is greatly dependent on the use of hydrocarbons for fuels and
chemical
feedstocks. Hydrocarbons are generally found in subsurface rock formations
that can be
termed "reservoirs." Removing hydrocarbons from the reservoirs depends on
numerous
physical properties of the rock formations, such as the permeability of the
rock, sand or soil
containing the hydrocarbons, the ability of the hydrocarbons to flow through
the rock, sand
or soil formations, and the proportion of hydrocarbons present, among other
things.
Easily harvested sources of hydrocarbon are dwindling, leaving less-accessible
sources to
satisfy future energy needs. However, 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 degrees API, or lower, up to 20
degrees 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.
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Several methods have been developed to remove hydrocarbons from reservoirs 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
into 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 (i.e. production wells) and brought to the
surface.
A number of techniques have been developed for harvesting heavy oil from
subsurface
formations using well-based recovery techniques. These operations include a
suite of steam
based in-situ thermal recovery techniques, such as cyclic steam stimulation
(CSS), steam
flooding and steam assisted gravity drainage (SAGD) as well as surface mining
and their
associated thermal based surface extraction techniques.
Various embodiments of the SAGD process are described in Canadian Patent No.
1,304,287 to Butler and U.S. Patent No. 4,344,485. 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 10 to 30 feet (3 to 10 meters) above the
horizontal well
used for production.
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 vapor
chamber (steam 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 downwardly
through the
reservoir under the action of gravity and may flow into the lower production
well, from which
these liquids can be pumped to the surface. At the surface of the well, the
condensed
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steam and heavy oil are separated, and the heavy oil may be diluted with
appropriate light
hydrocarbons for transport by pipeline.
Significant portions of oil sands, at least in the Athabasca region of Canada,
have either
water zones (water-containing sands) positioned on top of the heavy oil
bearing sands or
have gas caps (zones of gas-containing ground overlying the heavy oil bearing
sands), or
combinations of the two (layers containing both water and gas). These zones
may act as
"thief zones" into which steam can be lost or channeled away from the target
depletion zone
(the heavy oil bearing layers), or they may cause cold water to permeate the
heavy oil-
bearing layers, thus reducing the reservoir temperature. This can severely
degrade the
performance of SAGD processes and may be detrimental to the economics of the
development project. Where there is a top water zone, steam will rise up into
the water
zone and cold water from the top water zone may drain down into the well.
Where there is
a gas cap, if the gas cap is at low pressure, this will limit the pressure of
the SAGD process,
and it may not be economical to operate SAGD at such a low pressure due to
consequent
lower production rates.
SUMMARY
A method of recovering heavy oil from a hydrocarbon reservoir in which a water
and/or gas
containing layer overlies a heavy oil containing layer, may comprise providing
an injection
well in the water and/or gas containing layer above at least one pair of
horizontal wells in
the heavy oil containing layer for heavy oil recovery by a steam assisted
gravity drainage
process, injecting a blocking agent into the water and/or gas containing layer
via the
injection well to form a region of the water and/or gas containing layer
containing the
blocking agent adjacent an interface between the water and/or gas containing
layer and the
heavy oil containing layer above the at least one pair of horizontal wells,
and operating the
steam assisted gravity drainage process via the at least one pair of wells by
injecting steam
into the heavy oil containing layer and recovering heavy oil from the heavy
oil containing
layer. The blocking agent is injected into the water and/or gas containing
layer before
operating the steam assisted gravity drainage process or before heat generated
by the
steam assisted gravity drainage process reaches the region of the water and/or
gas
containing layer that will contain the blocking agent. The blocking agent,
when present in
the region, undergoes a change of viscosity, density or solidity when elevated
to a
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temperature between an initial ambient reservoir temperature in the region and
175 C by
heat from steam used in the process, and thereby creates a seal within the
reservoir above
the at least one pair of horizontal wells limiting or preventing movements of
fluid through the
seal.
The foregoing has broadly outlined the features of the present disclosure so
that the
detailed description that follows may be better understood. Additional
features will also be
described herein.
DESCRIPTION OF THE DRAWINGS
These and other features, aspects and advantages of the present disclosure
will become
apparent from the following description, appending claims and the accompanying
drawings,
which are briefly discussed below.
FIG. 1 is a drawing of a steam assisted gravity drainage process.
FIGS. 2A to 2D illustrate steps in a method of heavy oil recovery.
FIGS. 3A and 3B illustrate steps in a method of heavy oil recovery.
It should be noted that the figures are merely examples and no limitations on
the scope of
the present disclosure are intended thereby. Further, the figures are
generally not drawn to
scale, but are drafted for the purpose of convenience and clarity in
illustrating various
aspects of the disclosure.
DETAILED DESCRIPTION
For the purpose of promoting an understanding of the principles of the
disclosure, reference
will now be made to the features illustrated in the drawings and specific
language will be
used to describe the same. It will nevertheless be understood that no
limitation of the scope
of the disclosure is thereby intended. Any alterations and further
modifications, and any
further applications of the principles of the disclosure as described herein
are contemplated
as would normally occur to one skilled in the art to which the disclosure
relates. It will be
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_
apparent to those skilled in the relevant art that some features that are not
relevant to the
present disclosure may not be shown in the drawings for the sake of clarity.
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. 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.
"Bitumen" is a naturally occurring heavy oil material. Generally, it is the
hydrocarbon
component found in oil sands. Bitumen can vary in composition depending upon
the
degree of loss of more volatile components. It can vary from a very viscous,
tar-like, semi-
solid material to solid forms. The hydrocarbon types found in bitumen can
include
aliphatics, aromatics, resins, and asphaltenes. A typical bitumen might be
composed of: 19
wt.% aliphatics (which can range from 5 wt.% - 30 wt.%, or higher); 19 wt.%
asphaltenes
(which can range from 5 wt.% - 30 wt.%, or higher); 30 wt.% aromatics (which
can range
from 15 wt.% - 50 wt.%, or higher); 32 wt.% resins (which can range from 15
wt.% -
50 wt.%, or higher); and some amount of sulfur (which can range in excess of 7
wt.%). In
addition bitumen can contain some water and nitrogen compounds ranging from
less than
0.4 wt.% to in excess of 0.7 wt.%. The metals content, while small, must be
removed to
avoid contamination of the product synthetic crude oil (SCO). Nickel can vary
from less
than 75 ppm (part per million) to more than 200 ppm. Vanadium can range from
less than
200 ppm to more than 500 ppm. The percentage of the hydrocarbon types found in
bitumen can vary. As used herein, the term "heavy oil" includes bitumen, as
well as lighter
materials that may be found in a sand or carbonate reservoir. Heavy oil may
have a
viscosity of about 1000 cP or more, 10,000 cP or more, 100,000 cP or more or
1,000,000
cP or more.
As used herein, two locations in a reservoir are in "fluid communication" when
a path for
fluid flow exists between the locations. For example, fluid communication
between a
production well and an overlying steam chamber can allow mobilized material to
flow down
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to the production well for collection and production. 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.
"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.
"Heavy oil" includes oils which are classified by the American Petroleum
Institute (API), as
heavy oils, extra heavy oils, or bitumens. Thus the term "heavy oil" includes
bitumen and
should be regarded as such throughout this description. In general, a heavy
oil has an API
gravity between 22.30 (density of 920 kg/m3 or 0.920 g/cm3 ) and 10.00
(density of 1,000
kg/m3 or 1 g/cm). An extra heavy oil, in general, has an API gravity of less
than 10.00
(density greater than 1,000 kg/m3 or greater than 1 g/cm). For example, a
source of heavy
oil includes oil sand or bituminous sand, which is a combination of clay,
sand, water, and
bitumen. The thermal recovery of heavy oils is based on the viscosity decrease
of fluids with
increasing temperature or solvent concentration. Once the viscosity is
reduced, the
mobilization of fluids by steam, hot water flooding, or gravity is possible.
The reduced
viscosity makes the drainage quicker and therefore directly contributes to the
recovery rate.
A "hydrocarbon" is an organic compound that primarily includes the elements
hydrogen and
carbon, although nitrogen, sulfur, oxygen, metals, or any number of other
elements may be
present in small amounts. As used herein, hydrocarbons generally refer to
components
found in heavy oil or in oil sands. However, the techniques described herein
are not limited
to heavy oils, but may also be used with any number of other reservoirs to
improve gravity
drainage of liquids.
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"Permeability" is the capacity of a rock to transmit fluids through the
interconnected pore
space s of the rock. The customary unit of measurement for permeability is the
millidarcy.
"Pressure" is the force exerted per unit area by the gas on the walls of the
volume. Pressure
may be shown in this disclosure as pounds per square inch (psi), kilopascals
(kPa) or
megapascals (MPa). Unless otherwise specified, the pressures disclosed herein
are
absolute pressures, i.e. the sum of gauge pressure plus atmospheric pressure
(generally
14.7 psi at standard conditions).
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,
granite, silica, carbonates, clays, and organic matter, such as bitumen, heavy
oil, 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 ml. The resource is generally a hydrocarbon,
such as a heavy
oil impregnated into a sand bed.
As discussed herein, "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. Although SAGD is used as an exemplary process herein, it can be
understood
that the techniques described can include any gravity driven process, such as
those based
on steam, solvents, or any combinations thereof.
"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.
"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
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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, steam flooding, solvent
injection, and SAGD,
among others, and processes that use surface processing for the recovery, such
as sub-
surface mining and surface mining. Any of the processes referred to herein,
such as SAGD,
may be used in concert with solvents.
A "wellbore" is a hole in the subsurface made by drilling or inserting a
conduit into the
subsurface. A wellbore may have a substantially circular cross section or any
other cross-
sectional shape, such as an oval, a square, a rectangle, a triangle, or other
regular or
irregular shapes. As used herein, the term "well," when referring to an
opening in the
formation, may be used interchangeably with the term "wellbore." Further,
multiple pipes
may be inserted into a single wellbore, for example, as a liner configured to
allow flow from
an outer chamber to an inner chamber.
"Thermally and/or chemically-activated blocking agents" are materials that are
flowable
through the porous medium of a reservoir when injected into the porous medium
of the
reservoir and that, when activated by a change of temperature or chemical
reaction, solidify,
densify or gel, or shed a solid precipitate, and thus block pores in the
reservoir to hinder or
prevent the passage of gas or water through the reservoir.
A "steam chamber" is a region of a heavy oil containing layer of a reservoir
that forms
around a steam injection well and that is generally at or close to the
temperature of steam at
the pressures within the reservoir. The chamber may comprise pores from which
heavy oil
has at least partially flowed upon being heated by the steam to be replaced at
least in part
by steam itself. In practice, heavy oil containing layers may not necessary
have pores
containing 100% heavy oil and may naturally contain only 70 - 80 vol.% heavy
oil with the
remainder usually water. In contrast, a water and/or gas containing layer may
comprise
100% water and/or gas in the pores, but normally contains 5 - 70 vol.% gas and
20 - 30
vol.% water with any remainder being heavy oil.
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For a better understanding of the techniques of the present disclosure, a
brief explanation of
one form of steam assisted gravity drainage is first provided below.
Steam Assisted Gravity Drainage (SAGD)
SAGD may be carried out in geological formations wherein a water layer or gas
cap lies
above heavy oil containing strata. Good recovery of heavy oil may be achieved
by injecting
a thermally and/or chemically-activated blocking agent into the water or gas
layer,
preferably adjacent to the heavy oil / water or gas layer interface to reduce
or prevent
escape of extraction steam into the water- or gas-containing layer, and to
reduce or prevent
leakage of water into the heavy oil strata or steam chamber produced by the
extraction
steam.
Fig. 1 is a drawing of a SAGD process 100 used for accessing hydrocarbon
resources in a
reservoir 102. In the SAGD process 100, steam 104 can be injected through
injection wells
106 to the reservoir 102. The injection wells 106 may be horizontally drilled
through the
reservoir 102. Production wells 108 may be drilled horizontally through the
reservoir 102,
with a production well 108 underlying each injection well 106. The injection
wells 106 and
production wells 108 may be drilled from the same pad 110 at the surface 112.
Drilling from
the same pad 110, may make it easier for the production well 108 to track the
injection well
106. Alternatively, the injection well 106 and the production 108 may be
drilled from different
pads 110. For example, the injection well 106 and the production well 108 may
be drilled
from different pads 110 if the production well 108 is an infill well.
The injection of steam 104 into the injection wells 106 may result in the
mobilization of
hydrocarbons 114. Once mobilized, the hydrocarbons 114 may drain to the
production
wells 108 and be removed to the surface 112 in a mixed stream 116 that may
contain
hydrocarbons, condensate and other materials, such as water, gases, and the
like. Sand
filters may be used in the production wells 108 to decrease sand entrainment
in the
hydrocarbons removed to the surface 112.
A mixed stream 116 from a number of production wells 108 may be combined and
sent to a
processing facility 118. At the processing facility 118, the water and
hydrocarbons 120 can
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be separated, and the hydrocarbons 120 sent on for further refining. Water
from the
separation may be recycled to a steam generation unit within the facility 118,
with or without
further treatment, and may be used to generate the steam 104 used for the SAGD
process
100.
The production wells 108 may have a segment that is relatively flat, which, in
some
developments, may have a slight upward slope from the heel 122, at which the
pipe
branches to the surface, to the toe 124, at which the pipe ends. When present,
an upward
slope of this horizontal segment may result in the toe 124 being around one to
five meters
1.0 higher than the heel 122, depending on the length of the horizontal
segment. The slight
slope can assist in draining fluids that enter the horizontal segment to the
heel 122 for
removal.
It should be appreciated that, while one form of SAGD is described above, the
present
disclosure may relate to any and all forms of SAGD.
SAGD may be carried out in geological formations wherein a water containing
layer (water
zone) and/or a gas containing layer (gas cap) lies directly above and in
contact with heavy
oil containing strata, e.g. layer 102 of FIG. 1. Good recovery of heavy oil
may be achieved
by injecting a blocking agent into the water and/or gas containing layer to
reduce or prevent
escape of extraction steam into the water and/or gas containing layer, and/or
to reduce or
prevent leakage of water from the water and/or gas containing layer into the
heavy oil strata
or steam chamber produced by the extraction steam.
A variety of materials, both aqueous and non-aqueous, may be employed as
blocking
agents. The blocking agents may be employed singly or in combination, as will
be
described later. The blocking agents may undergo a transformation when in situ
in a
reservoir formation from a form in which the blocking agents may freely
penetrate a
permeable region of a rock, sand or soil substrate, to a form in which the
blocking agents
prevent or substantially limit the movement of fluids through the region that
they have
penetrated. When the blocking agents assume this form, they have become a seal
limiting
or preventing fluid flow through the affected substrate. The blocking agents
may be chosen
CA 02830741 2013-10-23
from thermally-activated and chemically-activated blocking agents. Some
blocking agents
may undergo activation by both thermal and chemical effects.
Thermally-activated blocking agents may be fluids, generally liquids. When
ready for
injection into water and/or gas containing layers, one type of thermally
activated blocking
agents may be at ambient temperatures (temperatures that are ambient at the
surface, e.g.
nominally 21 C), or at initial ambient temperatures within the reservoir where
they are to be
injected (temperatures before the start of recovery processes, generally 6 to
15 C). The
thermally activated blocking agents of this type may undergo a transformation
at higher
temperatures, e.g. at temperatures between ambient and 175 C, for example,
ambient up
to 125 C or ambient up to 100 C, after which the blocking agents exhibit
higher viscosity,
density or solidity (e.g. form a precipitate or become solid). The thermally
activated
blocking agents of this type may contain compounds that exhibit inverse
solubility
characteristics. In other words, the thermally activated blocking agents may
contain
compounds that are less soluble in solvents at higher temperatures than at
lower
temperatures, so that solutions of these compounds may have low viscosity at
low
temperature but may form precipitates or gels or solids or glasses, etc., at
higher
temperatures. The thermally activated blocking agents of this type may rely on
absorbing
heat for activation when present in a reservoir. The thermally activated
blocking agents
may absorb heat from steam used for SAGD.
Other types of thermally-activated blocking agents may include those
containing
compounds having normal solubility characteristics, i.e. compounds that become
more
soluble in solvents as temperature increases, or conversely and more
importantly,
compounds that become less soluble in solvents as the temperature decreases.
As a
result, the compounds having normal solubility characteristics may precipitate
out of
solution as the temperature of the solution falls. The thermally-activated
blocking agents of
these types may be prepared or obtained as saturated or supersaturated
solutions at high
temperatures (e.g. 80 C or higher) and are injected into the reservoir at such
high
temperatures. As the saturated or supersaturated solutions encounter and
penetrate
reservoir substrates having lower temperatures than the injected saturated or
supersaturated solutions (i.e. initial reservoir ambient temperatures of e.g.
6 to 15 C), the
saturated or supersaturated solutions are activated by forming solid or semi-
solid
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precipitates that act to block pores and interstices in the rock, sand or soil
substrate.
Therefore, in this way, the blocking agents are thermally-activated, but by
cooling rather
than by heating.
Chemically-activated blocking agents may be compounds or compositions that are
fluids,
e.g. liquids, of suitably low viscosity that they may freely penetrate a
region of the rock,
sand or soil of a reservoir formation, but that undergo a chemical
transformation when in
situ in the penetrated region upon encountering one or more chemicals present
in, or
generated within, or introduced into, the formation. The chemical
transformation causes an
increase of viscosity, density or solidity so that the chemically activated
blocking agent then
prevents or limits the movements of fluids through the region that the fluids
occupy. For
example, chemically-activated blocking agents may be reactive with gases or
acids
produced in a heavy-oil containing layer upon exposure of the heavy oil or the
substrate to
the temperatures employed during SAGD. For example, thermolysis of components
of the
heavy oil may produce carbon dioxide or hydrogen sulfide that may then contact
and react
with the chemically activated blocking agents to cause the indicated
transformations.
When a single blocking agent is employed, the blocking agent may be a
thermally-activated
blocking agent that undergoes a transformation as it absorbs heat from steam
used in a
SAGD process. When at least one further blocking agent is employed (i.e. two
or more
blocking agents), a thermally-activated blocking agent (i.e., a first blocking
agent) may first
be injected into the water and/or gas containing layer so that the thermally-
activated
blocking agent occupies a region close to the interface between the water
and/or gas
containing layer and the heavy oil containing layer. The thermally-activated
blocking agent
is, therefore, close to the steam chamber created during SAGD and receives
heat from the
steam for the transformation required by the thermally-activated blocking
agent to form a
seal. After injecting the first blocking agent, a second blocking agent may
then be injected
into the formation to occupy a second region above and/or surrounding the
first region
occupied by the first blocking agent. The second blocking agent may be one
that does not
require heat from the steam to undergo its required transformation. The second
blocking
agent may not necessarily have to be positioned as close to the steam chamber
because it
does not require heat. The second blocking agent may therefore be a thermally-
activated
blocking agent of the kind containing a compound having normal solubility
characteristics
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that is injected hot and undergoes a transformation as it cools, or it may be
a chemically-
activated blocking agent that reacts with gases or fluids present in, or
generated within, the
formation. An advantage of using a second blocking agent of one of these kinds
is that the
second blocking agent may extend the area or thickness of the blocking seal
beyond the
zone penetrated by heat from the steam that is required for transformation of
the first-
injected blocking agent. Of course, a third or even more blocking agents may
be injected
into the formation to further extend the area or thickness of the blocking
seal, but possibly at
the expense of increased cost and/or diminishing effectiveness. If such a
third or more
blocking agent is employed, it may also be one that does not require heat from
the steam to
undergo transformation.
When a second blocking agent is employed, it may be injected into the water
and/or gas
containing layer at any time, e.g. during commencement of the SAGD process,
during start-
up of the SAGD process, or during operation of the SAGD process.
Examples of thermally-activated blocking agents of the type having inverse
solubility
characteristics include, but are not limited to, aqueous solutions of sodium
silicate and
aqueous solutions of calcium bicarbonate. When subjected to heating, sodium
silicate
forms a gel or glass-like solid that forms an effective seal. Calcium
bicarbonate, in contrast,
tends to deposit a solid precipitate that forms a seal. Colloidal silica may
also be effective
as it may form a gel at an elevated temperature.
As an example, solutions of sodium silicate may be injected into a water
and/or gas
containing layer to penetrate a region of the water and/or gas containing
layer and may
remain in liquid form for prolonged periods of time at normal ambient
reservoir
temperatures. However, when heated by heat from a steam chamber created during
SAGD, the solutions, after a certain period of time (hours to days or even
months), form a
glass-like gel that significantly reduces the effective permeability of the
rock, sand or soil so
that fluids can no longer flow through the rock, sand or soil, thereby forming
an effective
barrier acting as a seal. The glass-like gel may have good stability at the
temperatures
encountered, with little tendency to degrade, so that the seal remains
effective and in place
for a suitably long time, even for the duration of the SAGD process and
possibly for the full
productive life of the SAGD wells, which may be from 10 to 30 years. Of
course, if the seal
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is found to break down or leak over time during the SAGD process, further
thermally-
activated blocking agent may be introduced through the blocking agent
injection well to
supplement or repair the seal as required.
Sodium silicate is the common name for the compound sodium metasilicate,
Na2SiO3or
(Si02):Na20, sometimes known as waterglass. It is available commercially as an
alkaline
aqueous solution (pH 11-13) having water-like viscosity, as well as in solid
form that may be
dissolved in water. Upon exposure to heat, the sodium silicate forms silica
aggregates or
polymers creating a gel that reduces the permeability of porous rock, soil or
sand.
Chelating agents (e.g. ethylenediamine tetracetic acid (EDTA) or
nitrilotriacetic acid (NTA))
and/or acids (e.g. 6.5 vol.% HCI) may be added to the sodium silicate solution
to help the
material set or solidify in the presence of heat. The gel formation may take
from several
minutes to several months depending on temperature conditions and additives. A
liquid
form of sodium silicate may be obtained, for example, from BIM Norway under
the
trademark Krystazil 40. This product has a Si02:Na20 ratio of 3.4, a pH of
11.5 and a
concentration of 27.6 wt%. Before use, it may be diluted with water (e.g. to
about 4 wt.%)
and provided with a pH activator (e.g. HCI added under agitation in an amount
of wt.% of
the 2.0 M HCI stock solution). Further information about suitable sodium
silicate gel
systems and their preparation may be obtained from the following publication,
the
disclosure of which is incorporated herein by reference:
Burns L., et al., "New Generation Silicate Ge/ System for Casing Repairs and
Water
Shutoff", Society of Petroleum Engineers, SPE 113490, presented at 2008
SPE/DOE Improved Oil Recovery Symposium held in Tulsa, Oklahoma, U.S.A., 19-
23 April, 2008.
The Burns publication describes sodium silicate solutions containing partially
hydrolyzed
polyacrylamide used in combination with a silica polymer gel initiator and
employing an
organic initiator.
While sodium silicate is described above as a thermally-activated blocking
agent of the kind
having inverse solubility characteristics, it may also operate as a chemically-
activated
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blocking agent. Sodium silicate may operate as a chemically-activated blocking
agent
because it may react with available carbon dioxide (produced, for example, by
heavy oil
thermolysis during SAGD) to form silica gel and a glass-like sodium carbonate,
e.g. by the
following reaction:
Na2S1205.H20 (liquid) + CO2 (gas) ¨ SiO2 (gel) Na2CO3.H20 (glass).
Colloidal silica, which is another example of a thermally-activated blocking
agent of the kind
having inverse solubility characteristics, forms a colloidal solution (sol) or
gel when
1.0 subjected to heat from steam used in the SAGD process. Further details
of the preparation
and characteristics of colloidal silica may be obtained from the following
publication, the
disclosure of which is incorporated herein by reference:
Jurinak J. J. et al., "Oilfield Applications of Colloidal Silica Gel",
Production
Engineering, November 1991, pp. 406-412.
As noted above, calcium bicarbonate, which is another example of a thermally-
activated
blocking agent having inverse solubility characteristics, reacts with heat to
deposit calcium
carbonate according to the reaction below:
Ca2+(aq) + 2HCO3"(aq) --* CaCO3(s) + H20 + CO2(1)
or
Ca(HCO3)2 ¨* CO2(g) + H20(1) + CaCO3(s).
More information about calcium carbonate deposits may be obtained from the
following
publication, the disclosure of which is incorporated herein by reference:
313 John E. Oddo, et al., "Simplified Calculation of CaCO3
Saturation at High
Temperatures and Pressures in Brine Solution", Journal of Petroleum
Technology,
Vol. 34, No. 7, pp. 1583-1590, July 1982.
CA 02830741 2013-10-23
An example of a material that may be suitable as a thermally- and/or
chemically-activated
blocking agent according to this disclosure is a solution of silica (Si02).
Solutions of silica
are typically removed from boiler feed water as a waste and are consequently
inexpensive.
Unlike sodium silicate or calcium bicarbonate, silica exhibits normal
solubility characteristics
in that its solubility increases or decreases with temperature increase or
decrease,
respectively. Soluble silica at high temperature precipitates out of solution
when its
temperature and/or pH is lowered. Soluble silica may be employed as a blocking
agent by,
for example:
a) Injecting water with a high silica concentration (e.g. a saturated or
super-
saturated solution) at high temperature (e.g. 80 C or higher) into the
reservoir so
that, as the solution cools as it encounters ambient temperatures within the
reservoir, Si02 precipitates from the solution, thereby forming a seal and
blocking
movement of steam or water into or from the water and/or gas containing layer.
If
steam does break through the resulting seal, acid gases (e.g. CO2) formed by
aqua-
thermolysis within the heavy oil-bearing layer will be carried along with the
steam.
This escape of steam and acid gases may lower the pH of the injected silica
solution
and thereby initiate further precipitation of the silica. Silica solutions
having a high
silica concentration are useful as second (or later) blocking agents injected
after a
first blocking agent activated by heat from steam used for the SAGD process.
b) Injecting water with a high concentration of Ca, Mg or Fe as
well as silica into
the formation so that, as heat is encountered from the approaching steam
chamber,
insoluble Ca, Mg or Fe silicates or a combination thereof will form, again
producing a
seal and blocking the advancement of steam into the water and/or gas
containing
layer. Sodium-iron silicates may also be formed from sodium made available in
the
injected solution or present in the connate water. Silica solutions containing
high
concentrations of Ca, Mg or Fe may be used as a sole blocking agent (or the
first of
two or several) as they are activated by heat from the steam used for the SAGD
process.
The amount or volume of the thermally- and/or chemically-activated blocking
agent injected
into the water and/or gas containing layer may be sufficient to form a
penetrated region of
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. .
effective extent to form a gas and/or water seal above the SAGD wells and the
steam
chamber created by the injection of steam. The required amount of the
thermally- and/or
chemically-activated blocking agent may vary from reservoir to reservoir and
from formation
to formation, and/or from well to well, due to differences of rock
permeability, physical
dimensions of the injection and production wells, details of the SAGD process,
etc. An
effective amount may be determined by simple trial and experiment, or may be
calculated in
advance by appropriate reckoning or algorithms. In general, the amount may be
sufficient
to form a seal that is at least as extensive as the top area of the steam
chamber formed in
the heavy oil containing layer when in its steady state of operation. Any
steam rising in the
chamber is then blocked by the seal and is forced to move horizontally into
less heated
structures. Suitable inflow/outflow control devices may be used for the
injection of the
thermally- and/or chemically-activated blocking agent to achieve even
distribution of the
thermally- and/or chemically-activated blocking agent within the rock
formation. In the case
of SAGD wells that are 1000 meters long and provided with a lateral spacing of
100 meters
between adjacent well pairs, drilled through substrate having pores forming
30% of the
volume of the substrate, and aiming for a layer thickness of one meter, the
total targeted
pore space would be about 30,000 m3. Typically, only a fraction of this volume
would need
to be injected with the thermally and/or chemically-activated blocking agent
in order to at
least partially contact most of the pore space. For example, between 1,000 to
20,000 cubic
meters of the thermally and/or chemically-activated blocking agent may be
required in such
a case.
Injection criteria for each specific reservoir may be established to prevent
plugging or
precipitation of the thermally- and/or chemically-activated blocking agent
prior to in-situ
heating by the steam used for the SAGD process. The use of pH modifiers, anti-
scaiants or
similar chemical additives may be employed to achieve the objective of
preventing plugging
or precipitation. Water used for the preparation of the thermally- and/or
chemically-
activated blocking agent may be obtained from any available source, e.g.
locally on-site.
While a thermally-activated blocking agent may be injected into the water
and/or gas
containing layer prior to operation of the SAGD process, or during SAGD start-
up, as
explained above, additional thermally-activated blocking agent may be injected
into the
water and/or gas containing layer during operation of the SAGD process. The
additional
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thermally-activated blocking agent may be injected after the steam chamber has
reached
the top of the heavy oil containing layer to block areas that may potentially
provide leaks of
the steam into the water and/or gas containing layer. As the additional
thermally-activated
blocking agent is being injected, the pressure of steam used for the SAGD may
be
temporarily lowered to draw some of the further thermally-activated blocking
agent into the
heated zone where it will solidify and extend or repair the required seal. The
steam thus
confined to the steam chamber may thus give rise to good production rates and
an efficient
recovery process.
As also noted above, a second blocking agent may be injected into a second
region of the
water and/or gas containing layer before commencement of the SAGD process or
during
SAGD start-up. If so, further amounts of the second blocking agent may be
injected into the
water and/or gas containing layer during these stages, or later as the SAGD
process
proceeds, to further limit movements of fluids through the second region.
Alternatively, a
second blocking agent may be injected into the water and/or gas containing
layer for the
first time as SAGD proceeds, i.e. after commencement and startup of the SAGD,
if
supplementation of the seal formed by the first blocking agent appears to be
necessary to
improve or maintain heavy oil production. The second blocking agent may be
injected into
the water and/or gas containing layer (i) before commencement of the SAGD
process
and/or during SAGD start-up and (ii) as SAGD proceeds (i.e., after
commencement and
startup of the SAGD). Further addition(s) of the second blocking agent may
then also be
made as the SAGD process proceeds further in time.
Figs. 2A through 2D show examples of steps in which a blocking agent is
employed to
create a seal between a hydrocarbon-containing layer 202 of an oil sands
formation 200
and a water-containing and/or gas-containing layer 204 situated above the
hydrocarbon-
containing layer 202. As well as providing an injection well 206 and a
production well 208 in
the heavy oil-containing layer 202 as in conventional SAGD, at least one
blocking agent
injection well 210 is drilled into the water and/or gas containing layer 204.
The at least one
blocking agent may be drilled close to the interface 205 between layers 204
and 202. The
blocking agent injection well 210 may be of similar length to the injection
well 206 and the
production well 208, or longer. The blocking agent injection well 210 may be
positioned
directly vertically above and parallel to such wells.
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CA 02830741 2013-10-23
Prior to the operation of the SAGD process or before a steam chamber 216
produced by
such process approaches the interface 205, a fluid thermally-activated
blocking agent 212
may be injected into the water and/or gas containing layer 204. A region 214
may
subsequently be formed containing the blocking agent in the pores or
interstices of the rock,
sand or soil of the layer 204 adjacent to or in contact with the interface 205
between the
layers 202 and 204. While reference is made to region 214, it will be
appreciated that the
blocking agent will, in fact, occupy pores or interstices in the solid
components of the layer
and thus will not normally form an exclusively liquid body in the region.
Although not
shown, a further well or wells may be drilled into the water and/or gas
containing layer 204
to remove water and/or gas as the blocking agent is being injected into the
layer, thereby
providing a uniform displacement of fluids. Such further well or wells may be
positioned
higher in the layer 204 than the blocking agent injection well 210 to avoid
withdrawal of the
blocking agent itself. The well(s) may be in the vicinity of injection well
210 to provide the
necessary "venting" effect effective for fluid displacement. As noted, the
region 214
containing the blocking agent introduced via injection well 210 may be created
before the
SAGD process is commenced, or at least before significant heat from the SAGD
process
permeates the water and/or gas containing layer 204. The blocking agent may be
such that
it remains fluid at the initial ambient temperatures normally found within
such reservoirs,
e.g. 6 to 15 C, for extended periods of time, e.g. several days, weeks or
months.
The SAGD process is operated by injecting steam into the oil-containing layer
202 through
the injection well 206 to heat the formation and to create a steam chamber 216
that
expands in volume as the geological formation is gradually heated by the
steam. The
steam heats the heavy oil within the porous substrate and consequently the
heavy oil
becomes more fluid and descends within the formation so that it can be removed
via the
production well 208, e.g. by pumping. Pores partially drained of heavy oil in
this way are
occupied by further steam to expand the steam chamber 216. By heat conduction,
the
steam within the steam chamber also creates a heated zone 218 in the rock or
soil
formation above the steam chamber itself, and this eventually penetrates into
the
region 214 containing the blocking agent within the water and/or gas
containing layer 204.
The thermally-activated blocking agent within the region 214 is such that,
when it is
exposed to heat from the steam, it hardens, solidifies, precipitates solids,
densifies, gels, or
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otherwise creates a fluid-blocking seal 220 above the heavy oil containing
layer 202,
thereby blocking pores within the rock, sand or soil formation. The seal
restricts or prevents
the flow of fluids. The seal serves to isolate, either partially or fully, the
heavy oil containing
layer 202 from the water and/or gas containing layer 204, at least in the
region of the steam
chamber 216 formed around the injection well 206. The seal may minimize or
prevent the
water and/or gas containing layer 204 from acting as a "thief layer" that
nullifies the effects
of the steam and pressure used for the SAGD process. The seal may therefore
enable
improved recovery of heavy oil. The blocking seal 220 may help to prevent
water from layer
204 descending into the steam chamber 216 and heated zone 218 and causing an
undesired cooling effect.
It has been stated above that the blocking agent injection well 210 may be
positioned close
to the interface 205. However, sometimes the blocking agent may be injected
close to the
top of a water and/or gas containing layer, or at least significantly above
the interface 205,
and allowed to descend under gravity through the pores or interstices towards
the interface.
The blocking agent may be injected close to the top when layer 204 forms a gas
cap. Gas
is less likely to prevent the descent of the blocking agent than water. If
there is a layer of
high permeability within the gas cap, the injection of the thermally and/or
chemically-
activated blocking agent may target the high permeability layer. Target the
high
permeability layer may aid in ensuring that the blocking agent is well
distributed above the
SAGD wells 206, 208.
While one blocking agent injection well 210 may be provided for each steam
injection
well/production well pair 206, 208 (i.e. the SAGD wells), a single blocking
agent injection
well 210 may be provided for two or more such well pairs. The single blocking
agent
injection well 210 may be provided when the blocking agent injection well is
suitably
positioned (e.g. mid-way between and above two adjacent well pairs) and/or is
of such a
capacity for fluid delivery relative to the permeability of the substrate, to
provide a blocking
agent region 214 extending above such multiple pairs of SAGD wells. Moreover,
while the
blocking agent injection well 210 may be horizontal or close thereto as shown,
the blocking
agent injection well 210 may alternatively be vertical or more angularly
sloped. The
blocking agent injection well may be vertical or more angularly sloped if the
resulting
blocking agent region 214 forms above the heavy oil containing layer 202 in
the region of
CA 02830741 2013-10-23
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...
the steam chambers formed by one or more pairs of SAGD wells to form an
effective seal
for all such SAGD wells.
The blocking agent 212 may be in the form of a liquid, e.g. a solution or
emulsion, or in the
form of a flowable slurry or gel, or in any other form that allows the
blocking agent to be
injected (e.g. allowed to flow under gravity or pumped) into the relevant
layer to form an
extensive region 214 containing the blocking agent which forms a seal when the
blocking
agent is transformed. The SAGD process is then capable of operating as it
would in an
equivalent reservoir having a relatively impermeable layer positioned above
the heavy oil
containing layer 202.
It will be understood that FIGS. 2A to 2D show an extremely simplified
illustration of an
underground reservoir in that the interface 205 may not be a distinct flat
horizontal stratum
as shown, but may vary in thickness (i.e. have varying heavy oil, water and/or
gas content
over its height) and may be of complex shape or arrangement. Moreover, the
seal 220
formed at the interface may not be always form complete barrier to steam, gas
and water,
but may only increase the resistance to the penetration of such fluids through
the seal. The
seal may of course be such that the increase in such resistance produces a
measurable
increase in heavy oil recovery compared to the absence of such a seal in the
same
reservoir formation.
FIGS 3A and 3B illustrate a procedure in which two blocking agents of
different categories
or types are injected into a formation to form an effective seal. In the case
of FIG. 3A, the
arrangement is similar to that of FIG. 2A but an additional blocking agent
injection well 310
has been drilled into the water and/or gas containing layer 204 above the
original blocking
agent injection well 210. A heat-activated blocking agent 212 of the kind
having inverse
solubility characteristics is injected through input well 210, as before, to
produce a blocking
agent-containing region 214. A second blocking agent 312 of a different kind,
e.g. a
chemically-activated blocking agent or a thermally-activated blocking agent of
the type
having normal solubility characteristics, is then injected into layer 204
through the additional
blocking agent injection well 310. The second blocking agent 312 forms a
region 314
overlying and extending horizontally beyond the margins of the region 214
containing the
first-injected blocking agent 212. The first blocking agent may be activated
by heat from a
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CA 02830741 2013-10-23
SAGD process in the manner shown in FIGS. 20 and 2D to form a seal. The second
blocking agent 312 may be present to extend the seal in the regions where
there is
insufficient heat from the SAGD process to activate the blocking agent 212, or
where
reactive gases such as CO2 escape from the heavy-oil containing layer 202
during the
SAGD process.
In the case of Fig. 3B, as in Fig. 2A, there is only a single blocking agent
injection
wellbore 210 drilled into the water and/or gas containing layer 204. A first
thermally-
activated blocking agent 212 having inverse solubility characteristics may be
injected into
the layer through the wellbore 210. The first blocking agent 212 may be
allowed to descend
to the level of the interface 205 to form a first blocking agent containing
region 214. A
second blocking agent 312 of a different kind, e.g. a chemically-activated
blocking agent or
a thermally-activated blocking agent having normal solubility characteristics,
may then be
injected into the layer 204 through the same wellbore 210 to form a second
blocking agent
containing region 315 overlying and surrounding the region 214, just as in the
case of
FIG. 3A. The arrangement of Fig. 3B avoids the extra cost of drilling the
additional wellbore
310 of FIG. 3A and is advantageous if the rock, sand or soil substrate of
layer 204 is
sufficiently porous to allow rapid and uniform percolation of the first-
injected blocking agent
212 through the layer towards the interface 205. It may also be advantageous
to drill the
injection wellbore 210 slightly higher in the layer 204 in the case of FIG. 3B
to allow room
above the interface 205 and below the wellbore 210 to accommodate the entire
region 214.
While detailed information has been provided above, it will be understood that
numerous
changes, modifications, and alternatives to the preceding disclosure can be
made without
departing from the scope of the disclosure. The preceding description,
therefore, is not
meant to limit the scope of the disclosure. Rather, the scope of the
disclosure is to be
determined only by the appended claims and their equivalents. It is also
contemplated that
structures and features in the present examples can be altered, rearranged,
substituted,
deleted, duplicated, combined, or added to each other in any effective manner.
The articles "the," "a" and "an" are not necessarily limited to mean only one,
but rather are
inclusive and open ended so as to include, optionally, multiple such elements.
22
