U.S. patent application number 14/340369 was filed with the patent office on 2015-04-23 for recovery from a hydrocarbon reservoir.
The applicant listed for this patent is Thomas J. Boone, Tapantosh Chakrabarty, James A. Dunn, Brian C. Speirs. Invention is credited to Thomas J. Boone, Tapantosh Chakrabarty, James A. Dunn, Brian C. Speirs.
Application Number | 20150107833 14/340369 |
Document ID | / |
Family ID | 52825154 |
Filed Date | 2015-04-23 |
United States Patent
Application |
20150107833 |
Kind Code |
A1 |
Boone; Thomas J. ; et
al. |
April 23, 2015 |
Recovery From A Hydrocarbon Reservoir
Abstract
Methods and systems for recovering heavy oil, such as bitumen,
by steam assisted gravity drainage (SAGD) from subterranean
formations having a water and/or gas containing layer overlying a
heavy oil containing layer. A fluid blocking agent is injected into
the water and/or gas containing layer above at least one pair of
horizontal wells. The blocking agent undergoes a change of density,
viscosity or solidity when elevated to a temperature between an
initial ambient reservoir temperature and 175 degrees by heat from
steam used in the SAGD process, thereby creating a seal within the
reservoir above the at least one pair of horizontal wells limiting
or preventing movements of fluid through the seal.
Inventors: |
Boone; Thomas J.; (Calgary,
CA) ; Chakrabarty; Tapantosh; (Calgary, CA) ;
Speirs; Brian C.; (Calgary, CA) ; Dunn; James A.;
(Calgary, CA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Boone; Thomas J.
Chakrabarty; Tapantosh
Speirs; Brian C.
Dunn; James A. |
Calgary
Calgary
Calgary
Calgary |
|
CA
CA
CA
CA |
|
|
Family ID: |
52825154 |
Appl. No.: |
14/340369 |
Filed: |
July 24, 2014 |
Current U.S.
Class: |
166/272.3 |
Current CPC
Class: |
E21B 43/2408
20130101 |
Class at
Publication: |
166/272.3 |
International
Class: |
E21B 43/24 20060101
E21B043/24 |
Foreign Application Data
Date |
Code |
Application Number |
Oct 23, 2013 |
CA |
2830741 |
Claims
1. 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, the method comprising: providing an injection
well in said water and/or gas containing layer above at least one
pair of horizontal wells in said heavy oil containing layer for
heavy oil recovery by a steam assisted gravity drainage process;
injecting a first blocking agent into said water and/or gas
containing layer via said injection well to form a first region of
said water and/or gas containing layer containing said first
blocking agent adjacent an interface between said water and/or gas
containing layer and said heavy oil containing layer above said at
least one pair of horizontal wells; and operating said steam
assisted gravity drainage process via said at least one pair of
horizontal wells by injecting steam into said heavy oil containing
layer and recovering heavy oil from said heavy oil containing
layer; wherein said first blocking agent is injected into said
water and/or gas containing layer before operating said steam
assisted gravity drainage process or before heat generated by said
steam assisted gravity drainage process reaches said first region
of said water and/or gas containing layer; and wherein said first
blocking agent, when present in said first region, undergoes a
change of viscosity, density or solidity when elevated to a
temperature between an initial ambient reservoir temperature in
said first region and 175.degree. C. by heat from steam used in
said steam assisted gravity drainage process, and thereby creates a
seal within the hydrocarbon reservoir above said at least one pair
of horizontal wells limiting or preventing movements of fluid
through said seal.
2. The method of claim 1, wherein said first blocking agent is in a
form selected from the group consisting of a liquid, a flowable
slurry, and a gel.
3. The method of claim 1, wherein said first blocking agent is in a
form of a liquid selected from the group consisting of a solution
and an emulsion.
4. The method of claim 1, wherein said first blocking agent has
inverse-solubility characteristics such that the first blocking
agent is configured to increase in viscosity, density or solidity
with increase of temperature.
5. The method of claim 1, wherein said first blocking agent
increases in viscosity, density or solidity to form said seal
within the reservoir when heated by heat from said steam to a
temperature between initial ambient temperature of said first
region and about 125.degree. C.
6. The method of claim 1, wherein said first blocking agent
increases in viscosity, density or solidity to form said seal
within the reservoir when heated by heat from said steam to a
temperature between initial ambient temperature of said first
region and about 100.degree. C.
7. The method of claim 1, wherein said first blocking agent
comprises an aqueous solution of sodium silicate.
8. The method of claim 7, further comprising introducing an
additive into said aqueous solution, said additive being at least
one compound selected from the group consisting of acids, chelating
agents, pH modifiers and anti-scalants.
9. The method of claim 7, wherein said sodium silicate is present
in said aqueous solution at a concentration in a range of 1 to 10
wt. %.
10. The method of claim 7, wherein said sodium silicate is present
in said aqueous solution at a concentration in a range of 3 to 5
wt. %.
11. The method of claim 1, wherein said first blocking agent
comprises an aqueous solution of sodium bicarbonate.
12. The method of claim 1, wherein said first blocking agent
comprises colloidal silica.
13. The method of claim 1, wherein said first blocking agent
comprises a solution of silica and a soluble compound of a metal
selected from the group consisting of Ca, Mg and Fe that forms
insoluble metal silicates when subjected to heat from said
steam.
14. The method of claim 1, wherein, after injecting said first
blocking agent into said water and/or gas containing layer, a
second blocking agent is injected into said water and/or gas
containing layer to form a second region above said at least one
pair of horizontal wells, said second blocking agent undergoing an
increase of density, viscosity or solidity when situated within
said second region.
15. The method of claim 14, wherein said second blocking agent is
injected into said water and/or gas-containing layer via said
injection well used for injection of said first blocking agent.
16. The method of claim 14, wherein said second blocking agent is
injected into said water and/or gas-containing layer via at least
one injection well different from said injection well used for
injection of said first blocking agent first.
17. The method of claim 14, wherein said second blocking agent is a
thermally-activated blocking agent having normal solubility
characteristics such that said second blocking agent is configured
to increase in viscosity, density or solidity with decrease of
temperature when injected at elevated temperature into said water
and/or gas containing layer.
18. The method of claim 14, wherein said second blocking agent
comprises an aqueous solution of silica injected into said water
and/or gas containing layer at an elevated temperature above said
ambient reservoir temperature.
19. The method of claim 18, wherein said elevated temperature is a
temperature of at least 80.degree. C.
20. The method of claim 1, wherein said steam assisted gravity
drainage process comprises: injecting steam into said heavy oil
containing layer via an uppermost one of said at least one pair of
horizontal wells to heat heavy oil in said heavy oil containing
layer to reduce viscosity of said heavy oil; and removing the heavy
oil from said heavy oil containing layer via a lowermost one of
said at least one pair of horizontal wells.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the priority benefit of Canadian
Patent Application number 2,830,741 filed Oct. 23, 2013 entitled
IMPROVING RECOVERY FROM A HYDROCARBON RESERVOIR, the entirety of
which is incorporated by reference herein.
FIELD
[0002] 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
[0003] 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.
[0004] 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.
[0005] 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.
[0006] 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.
[0007] 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.
[0008] Various embodiments of the SAGD process are described in
Canadian Patent No. 1,304,287 to Butler and U.S. Pat. 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.
[0009] 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 steam and heavy oil are separated, and the heavy oil may
be diluted with appropriate light hydrocarbons for transport by
pipeline.
[0010] 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
[0011] 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
temperature between an initial ambient reservoir temperature in the
region and 175.degree. 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.
[0012] 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
[0013] 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.
[0014] FIG. 1 is a drawing of a steam assisted gravity drainage
process.
[0015] FIGS. 2A to 2D illustrate steps in a method of heavy oil
recovery.
[0016] FIGS. 3A and 3B illustrate steps in a method of heavy oil
recovery.
[0017] 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
[0018] For the purpose of promoting an understanding of the
principles of the disclosure, reference will now be made to the
features illustrated in the drawings and specific language will be
used to describe the same. It will nevertheless be understood that
no limitation of the scope of the disclosure is thereby intended.
Any alterations and further modifications, and any further
applications of the principles of the disclosure as described
herein are contemplated as would normally occur to one skilled in
the art to which the disclosure relates. It will be apparent to
those skilled in the relevant art that some features that are not
relevant to the present disclosure may not be shown in the drawings
for the sake of clarity.
[0019] 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.
[0020] "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.
[0021] 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 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.
[0022] "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.
[0023] "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/m.sup.3 or 0.920 g/cm.sup.3) and 10.00.degree. (density of 1,000
kg/m.sup.3 or 1 g/cm). An extra heavy oil, in general, has an API
gravity of less than 10.00.degree. (density greater than 1,000
kg/m.sup.3 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.
[0024] 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.
[0025] "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.
[0026] "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).
[0027] 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.
[0028] 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.
[0029] "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.
[0030] "Thermal recovery processes" include any type of hydrocarbon
recovery process that uses a heat source to enhance the recovery,
for example, by lowering the viscosity of a hydrocarbon. These
processes may use injected mobilizing fluids, such as hot water,
wet steam, dry steam, or solvents alone, or in any combinations, to
lower the viscosity of the hydrocarbon. Such processes may include
subsurface processes, such as cyclic steam stimulation (CSS),
cyclic solvent stimulation, 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.
[0031] 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.
[0032] "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.
[0033] 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.
[0034] 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)
[0035] 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.
[0036] 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.
[0037] 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.
[0038] 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 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.
[0039] 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 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.
[0040] 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.
[0041] 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.
[0042] 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 from
thermally-activated and chemically-activated blocking agents. Some
blocking agents may undergo activation by both thermal and chemical
effects.
[0043] 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.degree. 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.degree.
C.). The thermally activated blocking agents of this type may
undergo a transformation at higher temperatures, e.g. at
temperatures between ambient and 175.degree. C., for example,
ambient up to 125.degree. C. or ambient up to 100.degree. 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.
[0044] 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.degree. 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.degree. C.), the saturated or supersaturated solutions are
activated by forming solid or semi-solid 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.
[0045] 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.
[0046] 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 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.
[0047] 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.
[0048] 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.
[0049] 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 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.
[0050] Sodium silicate is the common name for the compound sodium
metasilicate, Na.sub.2SiO.sub.3 or (SiO.sub.2).sub.n:Na.sub.2O,
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. % HCl) 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
(SiO.sub.2).sub.n:Na.sub.2O 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. HCl added under agitation in an amount of wt. % of the 2.0 M
HCl 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: [0051] Burns L., et al., "New Generation
Silicate Gel 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, Okla., U.S.A., 19-23
Apr., 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.
[0052] 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 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:
Na.sub.2Si.sub.2O.sub.5.H.sub.2O.sub.(liquid)+CO.sub.2(gas).fwdarw.SiO.s-
ub.2(gel)+Na.sub.2CO.sub.3.H.sub.2O.sub.(glass)
[0053] 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 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: [0054] 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:
[0054]
Ca.sup.2+(aq)+2HCO.sub.3-(aq).fwdarw.CaCO.sub.3(s)+H.sub.2O+CO.su-
b.2(l)
or
Ca(HCO.sub.3).sub.2.fwdarw.CO.sub.2(g)+H.sub.2O(l)+CaCO.sub.3(s).
More information about calcium carbonate deposits may be obtained
from the following publication, the disclosure of which is
incorporated herein by reference: [0055] John E. Oddo, et al.,
"Simplified Calculation of CaCO.sub.3 Saturation at High
Temperatures and Pressures in Brine Solution", Journal of Petroleum
Technology, Vol. 34, No. 7, pp. 1583-1590, July 1982.
[0056] 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 (SiO.sub.2). 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: [0057] a) Injecting water with a high silica
concentration (e.g. a saturated or supersaturated solution) at high
temperature (e.g. 80.degree. C. or higher) into the reservoir so
that, as the solution cools as it encounters ambient temperatures
within the reservoir, SiO.sub.2 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. CO.sub.2) 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. [0058] 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.
[0059] 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 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 m.sup.3. 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.
[0060] 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-scalants 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.
[0061] 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 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.
[0062] 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.
[0063] 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.
[0064] 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.degree. C., for extended periods of time, e.g. several
days, weeks or months.
[0065] 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 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.
[0066] 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.
[0067] 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 the
steam chambers formed by one or more pairs of SAGD wells to form an
effective seal for all such SAGD wells.
[0068] 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.
[0069] 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.
[0070] 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 SAGD process in the manner shown in FIGS. 2C 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 CO.sub.2 escape from the heavy-oil containing layer
202 during the SAGD process.
[0071] 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.
[0072] 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.
[0073] 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.
* * * * *