Note: Descriptions are shown in the official language in which they were submitted.
CA 02886934 2015-03-31
ESTABLISHING FLUID COMMUNICATION FOR HYDROCARBON RECOVERY
USING SURFACTANT
FIELD
[0001] The present invention relates generally to hydrocarbon recovery
from reservoirs of bituminous sands, and particularly to establishment of
fluid
communication between horizontal wells or in the case of a single well prior
to
hydrocarbon recovery.
BACKGROUND
[0002] Hydrocarbon resources such as bituminous sands (also commonly
referred to as oil sands) present significant technical and economic recovery
challenges due to the hydrocarbons in the bituminous sands having high
viscosities at initial reservoir temperature. Steam-assisted gravity drainage
(SAGD) is an example of an in situ (or in-situ) steam injection-based
hydrocarbon recovery process used to extract heavy oil or bitumen from a
reservoir of bituminous sands by reducing viscosity of the oil via steam
injection.
[0003] A SAGD system typically includes at least one pair of steam
injection and oil production wells (a "well pair) located in a reservoir of
bituminous sands. The injection (upper) well has a generally horizontal
section used for injecting a fluid such as steam into the reservoir for
softening
the bitumen in a region of the reservoir and reducing the viscosity of the
bitumen. Heat is transferred from the injected steam to the reservoir
formation, which softens the bitumen. The softened bitumen and condensed
steam can flow and drain downward due to gravity, thus leaving behind a
porous region, which is permeable to gas and steam and is referred to as the
steam chamber. Subsequently injected steam rises from the injection well,
permeates the steam chamber, and condenses at the edge of the steam
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CA 02886934 2015-03-31
chamber. In the process, more heat is transferred to the bituminous sands
and the steam chamber grows over time. The mobilized hydrocarbons and
condensate that drain downward under gravity are collected by a generally
horizontal section of the production well, which is typically disposed below
the
injection well and from which the hydrocarbons (oil) are (is) produced.
[0004] Several well pairs may be arranged within the reservoir to form a
well pattern or pad. Additional injection or production wells, such as a well
drilled using Wedge WellTM technology, may also be provided.
[0005] To permit drainage of the mobilized hydrocarbons and condensate
to the production well, fluid communication between the wells in the well pair
must be established (referred to as the start-up process or stage in a SAGD
operation). Fluid communication refers to fluid flow between the injection and
production wells. Establishment of such fluid communication typically
involves mobilizing viscous hydrocarbons in the reservoir to form a reservoir
fluid and removing the reservoir fluid to create a porous pathway between the
wells. Viscous hydrocarbons may be mobilized by heating such as by
injecting pressurized steam or hot water through the injection well or the
production well. In some cases, the start-up process involves injecting steam
and producing returned fluids from both the injection and production wells. A
pressure differential may be applied between the injection and production
wells to promote steam/hot water penetration into the porous geological
formation that lies between the wells of the well pair. The pressure
differential
promotes fluid flow and convective heat transfer to facilitate communication
between the wells. However, establishment of fluid communication between
the wells in a well pair can be challenging, for example due to poor fluid
mobility at initial reservoir conditions, due to the presence of reservoir
heterogeneity, or due to the presence of reservoir rocks with varying
wettability. It may take several days, weeks or even months before enough
heat can be transferred to the reservoir to establish such fluid
communication.
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[0006] Instead of a well pair, one or more single horizontal or vertical
wells
may be used for injection and production in in-situ hydrocarbon recovery
processes such as, but not limited to, steam-assisted gravity drainage
(SAGD) or a solvent aided process (SAP). For example, CA 2,844,345 to
Gittins, et al. discloses a thermal/solvent oil recovery process for producing
hydrocarbons using a single vertical or inclined well. The process may be
preceded by start-up acceleration techniques to establish communication in
the formation between an injection means and a production means within the
single well.
[0007] In general, start-up time can be accelerated by modifying the
porous formation (e.g., via dilation), or by reducing fluid (bitumen or water)
viscosity, thus increasing mobility. For example, CA 2,757,125 to Abbate, et
al. discloses a process for establishing communication between wells in a
well pair in oil sands by dilation with steam or water circulation at elevated
pressures. CA 2,698,898 to Pugh, et al. teaches the addition of solvents such
as xylene, benzene, toluene or phenol for reducing bitumen viscosity during
establishment of fluid communication between the wells in a well pair. CA
2,831,928 to Bracho Dominguez, et al. describes the use of one or more
microorganisms to increase overall fluid mobility in a near-wellbore region in
an oil sands reservoir, for example in connection with a start-up process
associated with SAGD.
SUMMARY
[0008] In one aspect of the present invention, there is provided a method
for establishing or accelerating fluid communication between a pair of
horizontal wells in a bituminous sands reservoir, the method comprising
delivering a surfactant into a region of the reservoir between the horizontal
wells; and forming a reservoir fluid in the region. The surfactant is used to
enhance mobility of fluid in the region, such as by reducing interfacial
tension
(IFT) between reservoir fluids or between one or more fluids and formation
rock. A reservoir fluid flows from a first one of the horizontal wells to a
second
3
one of the horizontal wells, or flows to a nearby thief zone or in general
within a
portion of the reservoir that has limited mobility, e.g., when driven by
gravity or by an
applied fluid pressure, thereby establishing the fluid communication between
the first
and second horizontal wells.
[0009] In another aspect, there is provided a method for establishing
fluid
communication between a pair of horizontal wells in a bituminous sands
reservoir,
the method comprising delivering a surfactant into a region of the reservoir
between
the horizontal wells; and forming a reservoir fluid in the region. The fluid
flows from a
first one of the horizontal wells to a second one of the horizontal wells,
thereby
establishing the fluid communication between the first and second horizontal
wells.
At least a region near the first well is soaked with the surfactant or a
mixture of the
surfactant and a solvent for a period of time to increase mobility of a
hydrocarbon in
the region before applying a fluid pressure to drive the fluid flow from the
first well to
the second well.
[0010] In another aspect, there is provided a method of assisting
establishment
of fluid communication between a pair of wells in a bituminous sands
reservoir,
comprising delivering a surfactant into the reservoir. A reservoir fluid is
formed in a
region of the reservoir near a first one of the wells. A fluid pressure is
applied to
drive the reservoir fluid to flow from the first well to a second one of the
wells
thereby establishing fluid communication between the first and second wells.
The
surfactant is mixed with the reservoir fluid and is selected to reduce
interfacial
tension between the reservoir fluid and formation rock and enhance mobility of
the
reservoir fluid in the reservoir. At least the region near the first well is
soaked with
the surfactant or a mixture of the surfactant and a solvent for a period of
time to
increase the mobility of the reservoir fluid in the region before applying the
fluid
pressure to drive the reservoir fluid to flow from the first well to the
second well.
[0011] As noted above, fluid communication between the wells in a well
pair can
be accelerated by modifying the porous formation or by reducing fluid
viscosity, thus
increasing mobility. The application of a surfactant targets a complementary
phenomenon: by reducing interfacial tension between fluids and between fluids
and
4
Date Recue/Date Received 2022-01-31
formation rock, use of a surfactant can enhance the mobility of oil, water and
steam,
facilitate heat transfer, and assist bitumen drainage at lower temperatures.
This can
accelerate establishment of the fluid communication, and may permit such
communication to be achieved at a lower energy cost than is normally required
to
heat and mobilize the inter-well portion of the reservoir.
[0012] In addition to accelerating establishment of the fluid
communication
between the wells, an embodiment of the present invention can also provide for
the
improvement of such fluid communication in those embodiments where fluid
communication already exists between the wells in a well pair, but to an
insufficient
degree or extent to support a sufficient rate of flow of oil between the
injection well
(or from the steam chamber) to the production well. In another aspect of the
present
invention, there is provided a method for establishing fluid communication
between
an injection means and a production means in a single well in a bituminous
sands
reservoir, the method comprising delivering a surfactant into a region of the
reservoir
between the injection means and the production means; and forming a reservoir
fluid in the region; wherein the fluid flows from the injection means to the
production
means, thereby establishing the fluid communication between the injection
means
and the production means, wherein at least a region near the injection means
is
soaked with the surfactant or a mixture of the surfactant and a solvent for a
period of
time to increase mobility of a hydrocarbon in the region before applying a
fluid
pressure to drive the fluid flow from the injection means to the production
means.
Other aspects, features, and embodiments of the present invention will become
apparent to those of ordinary skill in the art upon review of the following
description
of specific embodiments of the invention in conjunction with the accompanying
figures.
BRIEF DESCRIPTION OF THE DRAWINGS
[0013] Embodiments of the present invention will now be described, by way
of
example only, with reference to the attached Figures, wherein:
Date Recue/Date Received 2022-01-31
Fig. 1 is a schematic cross-sectional view of a SAGD well pair in a reservoir,
for
illustrating a method according to an embodiment of the present invention
applied
to the SAGD well pair;
5a
Date Recue/Date Received 2022-01-31
CA 02886934 2015-03-31
Fig. 2 is a schematic side cross-sectional view of the SAGD well pair in the
reservoir of Fig. 1, along line 2-2; and
Fig. 3 is a schematic partial view of regions near the SAGD well pair in Fig.
2,
illustrating an embodiment of the present invention.
DETAILED DESCRIPTION
[0014] Embodiments disclosed herein relate to the establishment of fluid
communication between horizontal wells or in single wells in a bituminous
sands reservoir, and more particularly to the use of a surfactant to
facilitate or
accelerate such a process, or to improve fluid communication. The surfactant
reduces interfacial tension between reservoir fluids, or between a reservoir
fluid and formation rock to enhance fluid mobility, thereby accelerating
establishment of the fluid communication between injection and production
components in a single well or improving communication along a horizontal
length of a well pair. Using a surfactant to accelerate well start-up may be
useful in reservoirs or reservoir regions that are not receptive to steam,
have a
higher than normal initial water saturation, or where other accelerated start-
up
techniques (e.g., steam stimulation, circulation or dilation) have failed or
cannot be easily applied.
[0015] Once fluid communication between the wells in a well pair has been
achieved, the wells can be employed in in-situ thermal recovery processes
that use two or more wells that are required to be in fluid communication,
such as in steam-assisted gravity drainage (SAGD) operations. Improved or
accelerated fluid communication between wells may also be applied in other
in-situ processes such as cyclic steam stimulation (CSS), steam flooding, or a
solvent aided process (SAP).
[0016] In the case of single well start-up, fluid communication refers to
fluid flow in the formation between the injection means (or an injection
component) and the production means (or a production component) in the
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CA 02886934 2015-03-31
single well. For example, the injection and production components may be
conduits, optionally tubing, and may be isolated from one another by way of a
packer, by positioning the injection and production means a suitable distance
apart, by positioning the injection means in the wellbore closer to the
surface
than the production means in the case of a vertical well, or by way of
openings or perforations in the tubing or well casing over selected wellbore
interval(s) to permit both outlet of injected fluids and inlet of production
fluids.
It will be appreciated by a person of skill in the art that the positioning of
the
injection and production means will depend on the particular well and
formation. One or more surfactants can be used to facilitate or accelerate a
single well start-up process, or to improve fluid communication.
[0017] Once fluid communication has been achieved between the injection
and production components of the single well, the well can be employed in in-
situ thermal recovery processes such as, but not limited to, SAGD.
[0018] In some embodiments, improvements in well conformance may be
achieved by use of a surfactant during establishment of the fluid
communication between the wells. Well conformance is a measure of the
uniformity of fluid communication (and hence the rate of oil collection) along
the length of the production well during oil extraction. As the reservoir
conditions may vary along the length of the well pair, fluid communication
may not be achieved uniformly along the length of the well pair. Formation of
"hot spots" may result, to which regions of fluid communication may initially
be
limited. Use of a surfactant in the start-up process may improve well
conformance by facilitating fluid communication in reservoir regions initially
having relatively lower bitumen mobility.
[0019] Referring to Figs. 1 and 2, a typical SAGD recovery system 10 is
shown, having an injection well 20 for injecting steam and a production well
30 completed for producing fluids from a bituminous reservoir 40. A portion of
injection well 20 is open to reservoir 40 via a horizontal injection well
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CA 02886934 2015-03-31
completion 50. Similarly, a portion of production well 30 is open to reservoir
40 via a horizontal production well completion 60. These horizontal well
completions typically include perforations, slotted liner, screens, outflow
control devices such as in an injection well, inflow control devices such as
in a
production well, or a combination thereof known to one skilled in the art.
[0020] In order to assist establishment of fluid communication between
injection well 20 and production well 30, a surfactant is delivered to the
region
of the reservoir between the horizontal wells via injection well 20 or
production well 30 or both wells 20, 30.
[0021] In an embodiment, the surfactant may be co-injected with a heated
fluid such as steam or hot water. The heated fluid may be injected and
pressurized as in a typical SAGD start-up process, with the modification that
the surfactant is added at surface or down hole to the heated fluid. For
example, a surfactant may be mixed with steam or hot water before injection
into well 20 or 30. In some embodiments, the concentration of the surfactant
in the injected heated fluid may be from about 1 ppm to about 3,000 ppm by
weight. In some embodiments, the surfactant concentration may be up to
about 50,000 ppm.
[0022] The amount of surfactant used may be selected based on a cost
and benefit basis. Also, the minimum required or optimum amount of a
surfactant is determined based on the physical properties of the surfactant
(i.e., the ability of the surfactant to reduce IFT), the presence of formation
salt
and other cations and anions, clays, and other species, as well the
composition of the oil in the reservoir.
[0023] It is possible that the surfactant will be dispersed throughout the
region near and between wells 20 and 30. However, it can be expected that,
in some embodiments, dispersing the surfactant in a limited region near a well
20 or 30 can still have a beneficial effect on the development of fluid
communication between wells 20, 30. For example, in an embodiment, the
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CA 02886934 2015-03-31
surfactant may be initially dispersed within a region that is about a few
centimeters around well 20 or 30.
[0024] As is known to those skilled in the art, heating reservoir 40 such
as
by steam injection, or soaking reservoir 40 with a solvent, can mobilize the
viscous hydrocarbons in reservoir 40, thus forming a reservoir fluid that can
drain downward by gravity, and can be produced through well 20 or 30. In
another embodiment, the surfactant may be injected alone or co-injected with
a solvent such as butane or a heated fluid for soaking the formation.
[0025] Without being limited to any particular theory, it is expected that
the
presence of the surfactant can lower interfacial tension between the reservoir
fluid and the formation rock, or between an aqueous phase and an oil phase
of the reservoir fluid, thus facilitating or improving the flow rate of the
reservoir
fluid. It is also expected that the surfactant may reduce the critical
saturation
in the formation, thus allowing the reservoir fluid to become mobilized at a
lower saturation point. The combined effects may allow the reservoir fluid to
become mobilized more quickly and to move faster, as compared to a similar
process but without the use of a surfactant.
[0026] The mobilized reservoir fluid may be produced through well 20 or
30 in, for example, a typical SAGD manner. Optionally, at the surface, the
produced fluids may be processed or treated to separate hydrocarbons (oil),
the surfactant, and water for further use.
[0027] Referring to Fig. 3, in a selected embodiment, delivery of a non-
vapourized surfactant via the injection well 20a will produce a region 70 in
which there is reduced interfacial tension between the reservoir fluids or
between one or more reservoir fluids and formation rock to enhance mobility
of the fluid(s), in which region the downward flow 90 of fluid and surfactant
will
be enhanced due to gravity and/or applied pressure drawdown. Delivery of a
vapourized surfactant via the production well 30a will also produce a region
80 where there is reduced interfacial tension between fluid and formation rock
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CA 02886934 2015-03-31
to enhance mobility of the fluid, in which region the upward flow 100 of the
vapourized surfactant will be favoured.
[0028] In some embodiments, particularly when reservoir 40 has relatively
higher initial water mobility, a suitable surfactant may be injected alone, or
co-
injected with an unheated fluid such as water.
[0029] The surfactant may also be injected after a period of pre-heating,
such as by steam or hot water injection, or by a heater located along well 20
or 30.
Surfactants
[0030] Surfactants are compounds that lower the surface tension of a
liquid, the interfacial tension between two liquids, or the interfacial
tension
between a liquid and a solid. A surfactant can be classified according to the
composition of its different chemical functional groups. The hydrophilic part
of
a surfactant is referred to as the head of the surfactant, while the
hydrophobic
part of a surfactant is referred to as the tail. Surfactants may be ionic,
zwitterionic, or non-ionic. An ionic surfactant carries a net positive
(cationic)
or negative (anionic) charge that is balanced by a counter-ion of the opposite
charge. A zwitterionic surfactant possesses a head with two oppositely
charged groups, making the surfactant neutral overall. Unlike an ionic
surfactant, a non-ionic surfactant does not dissociate into ions in aqueous
solution.
[0031] A number of factors may be considered when selecting surfactants
suitable for use in the present invention. One factor is whether the
surfactant
can increase the mobility of a hydrocarbon (or oil) in the region. The term
"mobility" is used herein in a broad sense to refer to the ability of a
substance
to move about, and is not limited to the flow rate or permeability of the
substance in the reservoir. For example, the mobility of oil may be increased
when the oil becomes easier to detach from the sand it is attached to, or
CA 02886934 2015-03-31
when the oil has become mobile, even if its viscosity or flow rate remains the
same. The mobility of oil may also be increased when its viscosity is
decreased, or when its effective permeability through the bituminous sands is
increased.
[0032] Another factor is whether the surfactant can significantly reduce
the
IFT between oil and water and gas or between the oil or water or gas and
sand or other solid materials. A further factor is whether the surfactant can
serve as a wetting agent, alter the sand wettability and promote the
detachment of oil from sand grains thereby increasing the flow rate of oil or
the fluid mixture. A further factor is whether the critical micelle
concentration
(CMC) of a surfactant may be exceeded at the temperature, pressure or
chemical conditions of the start-up operation. Once the CMC is exceeded, IFT
reduction is inhibited and the start-up process may be less effective or
excess
surfactant may be wasted.
[0033] In various embodiments of the invention, the term "surfactant"
refers to a compound that reduces IFT between two liquids or a liquid and a
solid in bituminous sands. In various embodiments of the invention, a suitable
surfactant for use has one or more of the following additional
characteristics:
chemical stability (e.g., at temperatures and pressures that are typical for
various start-up procedures); enhancement of water-wetness of the reservoir
rock; improvement of the oil relative permeability, with optional reduction of
viscosity of hydrocarbon flow; compatibility with formation water; reduction
of
hydrocarbon-water or hydrocarbon-sand IFT at reservoir conditions; or a
combination of characteristics thereof. In some embodiments, the surfactant
can also be vapourizable at delivery conditions, alone or in admixture with a
further component, e.g., steam.
[0034] Surfactants that are useful for the recovery of hydrocarbons from
reservoirs of bituminous sands, i.e., extraction of hydrocarbons once fluid
communication between the wells of a well pair has been established, are
11
disclosed in US patent application publication No. US 2013-0081808 Al. A
similar
disclosure is made in "Surfactant-Steam Process: An Innovative Enhanced Heavy
Oil Recovery Method for Thermal Applications", Zeidani, et al., SPE 165545,
June
2013. Reference is also made to Energy Resources Conservation Board (ERCB)
Supplemental Information Request application No. 1724747 (May 2012).
[0035] In one embodiment, the surfactant may be ionic (anionic or
cationic). In
another embodiment, the surfactant may be water-soluble.
[0036] Anionic surfactants contain anionic functional groups at the
surfactant
heads, such as sulfates, sulfonates, phosphates, and carboxylates.
[0037] For example, anionic surfactants include alkyl sulfates, such
as ammonium lauryl sulfate, sodium lauryl sulfate (SDS, or sodium dodecyl
sulfate),
alkyl-ether sulfates, sodium laureth sulfate (or sodium lauryl ether sulfate,
SLES),
and sodium myreth sulfate.
[0038] Anionic surfactants also include docusates such as dioctyl sodium,
sulfosuccinates, perfluorooctanesulfonates (PFOS), perfluorobutanesulfonates,
line
ar alkylbenzene sulfonates (LABs), alkyl-aryl ether phosphates, and alkyl
ether
phosphates.
[0039] Carboxylates include alkyl carboxylates such as sodium stearate,
sodium
lauroyl sarcosinates, and carboxylate-based fluorosurfactants such
as perfluorononanoate (deprotonated PFNA) and perfluorooctanoate (deprotonated
PFOA or PFO).
[0040] Some surfactants may include cationic head groups such as primary,
secondary, or tertiary amines.
[0041] The surfactants may also include octenidine dihydrochloride,
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Date Re9ue/Date Received 2021-06-28
CA 02886934 2015-03-31
alkyltrimethylammonium salts such as cetyl trimethylammonium
bromide (CTAB) a.k.a. hexadecyl trimethyl ammonium bromide, cetyl
trimethylammonium chloride (CTAC), cetylpyridinium chloride (CPC),
benzalkonium chloride (BAG), benzethonium chloride (BZT), 5-bromo-5-nitro-
1,3-dioxane, dimethyldioctadecylammonium chloride, cetrimonium bromide,
dioctadecyldimethylammonium bromide (DODAB).
[0042] Zwitterionic (amphoteric) surfactants have both cationic and anionic
centers attached to the same molecule. The cationic part may be based on
primary, secondary, or tertiary amines or quaternary ammonium cations. The
anionic part can be more variable and include sulfonates, as in CHAPS (3-[(3-
cholamidopropyl)dimethylammonio]-1-propanesulfonate). Other anionic
groups include sultaines illustrated by cocamidopropyl hydroxysultaine,
betaines such as cocamidopropyl betaine, and phosphates such as lecithin.
[0043] In another embodiment, the surfactant may be non-ionic, and
optionally be vapourizable at delivery conditions. In another embodiment, a
suitable surfactant is one that vapourizes at the temperature and pressure of
co-injected steam.
[0044] Non-ionic surfactants include long chain alcohols such as fatty
alcohols, cetyl alcohol, stearyl alcohol, and cetostearyl alcohol (consisting
predominantly of cetyl and stearyl alcohols), and ()ley! alcohol.
[0045] Possible surfactants also include polyoxyethylene glycol alkyl
ethers such as CH3¨(CH2)10-16¨(0-C21-14)1_25-0H (BRIJTm), octaethylene
glycol monododecyl ether and pentaethylene glycol monododecyl ether,
polyoxypropylene glycol alkyl ethers such as CH3¨(CH2)1o.-16¨(0-C3Fle)1-25¨
OH, glucoside alkyl ethers such as CH3¨(CH2)10-16¨(0-glucoside)1_3-0H
including decyl glucoside, lauryl glucoside, and octyl glucoside,
polyoxyethylene glycol octylphenol ethers: C81-117¨(06H4)¨(0-C2H4)1-25-0H
such as TRITON TM X-100, polyoxyethylene glycol alkylphenol ethers such as
C9H19¨(C6H4)¨(0-C2F14)1-25¨OH including nonoxyno1-9, glycerol alkyl esters
such as glyceryl laurate, polyoxyethylene glycol sorbitan alkyl esters such as
polysorbate, sorbitan alkyl esters such as spans, cocamide MEA, cocamide
DEA, dodecyldimethylamine oxide, copolymers of polyethylene glycol and
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polypropylene glycol such as poloxamers, polyethoxylated tallow
amine (POEA).
[0046] Non-limiting examples of surfactants for use in embodiments of the
present invention include alcohol ethoxylates, phenol ethoxylates, alkylphenol
ethoxylates, tertiary acetylenic diols including tertiary acetylenic diol
ethoxylates, alkylmercaptan ethoxylates, alkylpropoxy ethoxylates, amine
ethoxylates, amide ethoxylates, alcoholamides, and amino alcohols including
monoethanolamine (MEA), diethanolamine (DEA), or triethanolamine (TEA).
[0047] The surfactant can be water-soluble. The surfactant can have a
relatively high hydrophile-lipophile balance (HLB), such as greater than 7,
greater than 8 or greater than 9. The surfactant may function at a relatively
low vapour pressure, reduce IFT between different adjacent materials, and
improve oil-water relative permeability.
[0048] Examples of such a surfactant include, but are not limited to,
alcohol ethoxylates such as TERGITOLTm 15-S-9 (T-15-S-9), CARBOWETTm
76 (C-76), NOVELFROTHTm 190 (E-190) and NOVELFROTHTm 234 (E-234),
and alkylphenol ethoxylates such as TRITONTm X-100 (TX-100), or the like.
Tertiary acetylenic diol ethoxylates may also be suitable.
[0049] The surfactant can be water-insoluble, and it may also be soluble in
oil. The surfactant can have a HLB less than 8, for example a HLB less than
5.5.
[0050] Examples of such a surfactant include, but are not limited to,
tertiary acetylenic diols, such as SURFYNOLTM 82 (S-82) and SURFYNOLTM
104PA (S-104 PA).
[0051] In various embodiments of the invention, the surfactant may be a
compound represented by the chemical formula of
A 1 C1-12CH20 __ H
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wherein (i) m is 1, and A is -NH2 or -N(H)CH2CH2OH; or (ii) m is 1 or greater
than 1, and A is -01R1, wherein R1 is an alkyl group.
[0052] The alcohol ethoxylate may be a primary, secondary, or tertiary
alcohol ethoxylate. In various embodiments of the invention, the alcohol
ethoxylate may have the chemical formula of
R1 __ 0 __ cH20H20 __ H
wherein R1 is a linear or branched alkyl group having more than 5 carbon
atoms, and m is .?1. The alcohol ethoxylate may also have the chemical
formula of
C12_14F-125-290[CH2CH20]9H; C12-15H25-310[CH2CH20]2 8H;
______________ 0 __ cH2cH20 __ H= ___________ 0 __ CH2CH20 __ H
2 3 =
R2
CH3¨(CH2)n ___ C __ 0 __ CH2CH20 __ H
- m
Or R2
wherein m is 2 or 3, n is 2 or 3, and R2 is methyl or ethyl.
[0053] Possible alcohol ethoxylates may also have the chemical formula of
CH3 __ cH2-FcH2 0-1--cH2cH20 __ H
wherein n is greater than 3 and m is greater than 1.
[0054] In various embodiments of the invention, the phenol ethoxylate may
have the chemical formula of
R3 0 __ CH2CH20m H
CA 02886934 2015-03-31
wherein R3 is hydrogen, or a linear or branched alkyl group, and m is greater
than 1. R3 may be a linear or branched alkyl group having more than 2
carbon atoms_
[0055] The phenol ethoxylate may comprise an alkylphenol ethoxylate.
The alkylphenol ethoxylate may have the chemical formula of
OH 3 CH3
H3c __ H2c 04CH2CH20} H
9-10
CH3 CH3
=
[0056] Other possible alkylphenol ethoxylates may have the chemical
formula of
cH3 ____________________ cH2 * 0- CH2CH20 H
m ,
wherein m is greater than 1, and n is greater than 1.
[0057] Other possible phenol ethoxylates may have the chemical formula
of
= ______________________ 0-{---CH2CH20 H
wherein m is greater than or equal to 1.
[0058] In various embodiments of the invention, the tertiary acetylenic
diol
may have the chemical formula of
CH3 OH OH CH3
HC¨(CH2)p C C ____________ C C¨(CH2)p¨CH
R4 CH3 CH3
R4 ;
wherein R4 is hydrogen or methyl, and p is 1 or 2.
[0059] The tertiary acetylenic dial may also have the chemical formula of
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/CH2CH2O¨H ,CH2CH2O¨H
CH3 0 0 CH3
HC ____________________ (CH2)p ___ C C ________ C C __ (CH2)p CH
a.
R4 CH3 CH3
R4 ,
wherein R4 is hydrogen or methyl, and p is 1-3, or
cH3 0R5 0R5 cH3
HC ______________ (CH2)p C C __ c c __ (CH2)p¨CH
b. R4 CH3 CH3
R4 ,
wherein R4 is hydrogen or methyl, R5 is hydrogen or hydroxyethyl, and p is 1 -
3 when R5 is hydroxyethyl, or is less than 3 when R5 is hydrogen.
[0060] In various embodiments of the invention, the alkylmercaptan
ethoxylate may have the chemical formula of
R7 ¨S __ 0H20H20 Im H
wherein R7 is a linear or branched C6¨C10 alkyl group, and m is 2-4.
[0061] In various embodiments of the invention, the alkylpropoxy
ethoxylate may have the chemical formula of
CH3
CH3 __ (CH2)n __ 0 ____ CH2CH0 J
CH2CH20 _____________________________ H
m
wherein m is 2 or 3, n is 3 or 4 and p is 1 or 2.
[0062] Other non-ionic surfactants may be acetylenic diol ethoxylates
having the formula
17
CA 02886934 2015-03-31
,,CH2CH2O-H {,CH2CH20]-H
CH3 0 -z y CH3
HC __ (CH2)q __ CC __ C C __ (CH2)q __ CH
R6 CH3 CH3
R6 ,
wherein R6 is hydrogen, or a linear or branched alkyl group, q is greater than
1, and at least one of y and z is greater than or equal to 1, or a combination
thereof.
[0063] Some commercially available surfactants and their main chemical
components are listed below.
[0064] T-15-S-9 contains a C12¨C14 secondary alcohol ethoxylate with nine
[CH2CH20-] groups, with the chemical formula of C12-14F125_290[CH2CH20]9H.
[0065] TX-100 contains is a tertiary alkylphenol ethoxylate with 9-10 [-
CH2CH20-] groups), with the chemical formula of
cH3 cH3
H3c ___ H2c 04CH2CH201-H
CH3 CH3 9-10
[0066] S-82 contains a tertiary acetylenic diol with the chemical formula
of
OH OH
CH3CH2-C-C-C-C-CH2CH3
CH3 CH3
[0067] S-104PA contains a tertiary acetylenic diol with the chemical
formula of
CH3 OH OH CH3
HC-CH2 _____ c __ c __ C __ CH2 CH
CH3 CH3 CH3
CH3.
18
CA 02886934 2015-03-31
[0068] C-76 contains a C12-018 alcohol ethoxylate with 2.8 [-CH2CH20-]
groups, with the chemical formula of C12-15F125-310[CH2CH20]28H.
[0069] E-190 contains a C6 alcohol ethoxylate with 2 [-CH2CH20-] groups,
with the chemical formula of
CH2CH20 ___________________ 2 H
[0070] E-234 contains a C6 alcohol ethoxylate with 3 [-CH2CH20-] groups,
with the chemical formula of
______________ 0 __ cH2cH20 __ H
3
[0071] ALFONICTM 1012-5 (A-1012-5) has the chemical formula of
ci-13 __ cH2 I cH2 0 ______ CH2CH20 H
wherein n is 8-10 and m is 5.
[0072] Other surfactants, such as an oil-soluble monohydric alcohol, more
specifically, an octylphenoxypolyethyleneoxy ethanol, may also be suitable in
some applications.
[0073] In different embodiments, different surfactants may be used.
[0074] For example, in some embodiments, ammonia or amines may be
used.
[0075] In some embodiments, alkylxylene sulfonates may be used.
[0076] In some embodiments, lipid surfactants may be used.
[0077] In some embodiments, a polyvinylalcohol may be used.
[0078] In some embodiments, alkoxylated surfactants may be used.
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CA 02886934 2015-03-31
[0079] In some embodiments, sulfonates and sulfonated derivatives, such
as alkyl benzene sulfonates, alkyl benzene disulfonates, alkaryl sulfonates,
or
alkaryl naphthenic sulfonates, may be used. They may be provided in the
forms of sodium, potassium, ammonium or substituted ammonium salts.
[0080] In some embodiments, alkyl polyglycosides or aromatic alcohols
may be used.
[0081] In some embodiments, acetylenic surfactants may be used.
[0082] In some embodiments, ethoxylated alkylphenols may be used.
[0083] In some embodiments, ethoxylated alcohols such as ethoxylated n-
alcohols may be used.
[0084] In some embodiments, alkyl alcohols may be used.
[0085] In some embodiments, sulfates such as ethoxylated sulfates may
be used. In some embodiments, alkyl ethoxy sulfates or alkyl phenol ethoxy
sulfates, may be used.
[0086] In some embodiments, phosphates may be used.
[0087] In some embodiments, a surfactant may be formed in-situ from a
surfactant precursor such as ammonia, or acid and alkaline compounds. The
surfactant precursor may be injected with steam into the reservoir.
[0088] In some embodiments, a biosurfactant may be produced in-situ by
introducing surfactant-producing bacteria, such as Bacillus species, into the
reservoir. The surfactant-producing bacteria may be co-injected with steam
into the reservoir.
[0089] In some embodiments, a lipopeptide surfactant may be used.
[0090] In some embodiments, ethoxylated polyoxypropylenes may be
used.
CA 02886934 2015-03-31
[0091] In some embodiments, block copolymers of propylene or ethylene
oxides may be used.
[0092] In some embodiments, polyethylene oxide or polypropylene oxide
surfactants may be used.
[0093] In some embodiments, a polyoxamer such as a polyoxypropylene
and polyoxyethylene block copolymer may be used.
[0094] In some embodiments, the surfactant can be used in liquid form.
When the surfactant is a solid under given conditions such as at lower
temperatures, it may be dissolved in a solvent to prepare a liquid solution
for
injection into the reservoir. Non-limiting examples of solvents.for
solubilizing
a surfactant, such as S-82, include propylene glycol (PG), ethylene glycol
(EG), isopropyl alcohol (IPA) and water, alone or in combination. Suitable
solubilizing solvents or combination of solvents can be selected based on the
characteristics of the solution to be obtained, such as the freezing point,
and
stability and viscosity at storage and injection conditions. The solvent may
also be selected for its ability to reduce IFT. For example, IPA reduces oil-
water IFT. PG and EG may also reduce IFT.
[0095] For example, a mixture of 50% S-82 and 50% IPA, or a ratio from
about 5:95 S-82:IPA to about 95:5 S-82:1PA, may be used. It is expected that
such a mixture may be more robust at low temperatures than mixtures of 50%
S-82 in PG/water. While the mixtures discussed in the above paragraph do
not freeze at room temperature (they have a freezing point -35 C), their
viscosities at reservoir conditions are different. For instance, at -8 C, 50%
S-
82 in IPA has a viscosity of 120 cP, 50% S-82 in PG has a viscosity of 4,200
cP, 50% 3-82 in 4:1 PG:water has a viscosity of 1,250 cP, and 50% S-82 in
2:1 PG:water has a viscosity of 700 cP. Stabilities can also differ. For
example, presence of water may lead to the formation of clathrates at low
temperatures.
21
CA 02886934 2015-03-31
[0096] A concentration of the surfactant effective at accelerating fluid
communication can vary depending on the selection of processing conditions
(e.g., injection rate and manner, temperature and pressure of co-injected
steam, surfactant type and properties at reservoir conditions, reservoir
properties such as permeability, or a combination thereof). In various
embodiments of the invention, the surfactant may have a concentration from
about 10 ppm to about 50,000 ppm by weight, measured at room temperature
based on the liquid volumes of the surfactant and the carrier fluid such as
steam, heated water, a solvent or a combination thereof. In some
embodiments of the invention, the surfactant concentrations may be from
about 10 ppm to about 10,000 ppm, such as from about 10 ppm to about
3,000 ppm.
[0097] In various embodiments of the invention, a suitable concentration of
the surfactant may be defined as that sufficient to produce a reduction in IFT
between fluids in the formation, or between a fluid and the formation rock. In
some embodiments, IFT may be reduced to about %, to about 1/100, or to
about 1/10,000 of its original value. In various embodiments of the invention,
a suitable concentration of the surfactant may be further defined as that
sufficient to reduce viscosity of the oil. The amount of the surfactant to be
used in a start-up process should also be selected with consideration of
economic factors, such as surfactant cost or ability to recycle the surfactant
for re-use.
[0098] In various embodiments of the invention, the term "surfactant"
further includes a surfactant precursor, which under selected conditions may
form a surfactant in-situ. A mix of two or more surfactants may be used to
produce a more optimal result for a given process.
22
CA 02886934 2015-03-31
Injection
[0099] The surfactant
may be delivered, such as via a horizontal well, into
the surrounding reservoir, using any suitable delivery mechanism or route.
For example, delivery can be achieved using the injection well, the production
well, or both, or in the case of a single well, using the injection component,
the production component, or both. In some embodiments of the invention,
two or more surfactants may be used in combination, separately or
independently.
[00100] In one embodiment, the surfactant is delivered into all or part of
a
near-wellbore region of the surrounding reservoir. In selected embodiments,
having a well pair wherein the inter-well distance is X meters, the near-
wellbore region can be defined as the volume of reservoir occupied within a
radius of X/2 m from the wellbore(s) in question. For example, for a well pair
in which the wells are 5 m apart, the near-wellbore region may be defined to
include up to a 2.5 m radius from each of the two wellbores. In some
embodiments, the near-wellbore region includes the volume defined by a
radius of 2-3 m from the well, wherein this 2-3 m radius is not necessarily
constant (i.e., is variable) along the length of the wellbore. In general, the
near-wellbore region contains the wellbore. The near-wellbore region may be
associated with: (i) an injector well of the well pair, (ii) a producer well
of the
well pair, or (iii) both the injector well and the producer well.
[00101] In various
embodiments of the invention, the surfactant may
be delivered in a number of forms. For example, the surfactant may be
injected as a liquid (pre-heated or at ambient temperature) or as a vapour at
the wellhead or downhole, or the surfactant may be injected as a liquid and
vapourized at the wellhead, in the wellbore, or downhole.
[00102] In selected
embodiments of the invention, the surfactant or a
combination of surfactants may be injected as vapour separate from steam or
23
CA 02886934 2015-03-31
as vapour co-injected with steam. The surfactant may be injected as a
mixture of steam and surfactant (e.g., mixed ex-situ) or as separate streams
for mixing in the well or mixing in-situ. In various embodiments, the
surfactant
may be injected as an aerosol or spray. In some embodiments, the surfactant
may be co-injected with heated water or a solvent. The co-injected solvent
may be a solvent suitable for soaking the reservoir prior to applying a fluid
pressure to the reservoir.
[00103] In one embodiment, the surfactant is injected with steam, the
steam temperature ranging from about 158.8 C to about 325 C. According to
various embodiments of the invention, the surfactant may be selected such
that it is chemically stable at such temperatures and therefore remains
effective after co-injection.
[00104] In one embodiment, the surfactant is injected alone, but
optionally water, steam, a solvent, or a combination thereof may be
separately injected into the same region of the reservoir, to improve fluid
mobility in the region. In one embodiment, a surfactant-containing
composition delivered to the formation does not contain an additional
component such as NaOH for emulsifying the oil in the reservoir.
[00105] In one embodiment, a surfactant is provided to the reservoir
via an injection well, wherein the surfactant is not vapourized or remains at
least partially in a liquid or solution phase when the surfactant is provided
to
the reservoir. The surfactant may be in a liquid form at surface and at
reservoir conditions. The surfactant may be mixed with heated water or a
solvent at surface, or the surfactant may be co-injected with heated water or
a
solvent, and provided to the reservoir as a heated liquid or solution.
[00106] In one embodiment, a surfactant is provided to the reservoir
via the production well, wherein the surfactant is in vapour form or at least
partially vapourized when the surfactant is provided to the reservoir.
Depending on the properties of the surfactant, the surfactant may be in a
24
CA 02886934 2015-03-31
solid, liquid, or gas phase at surface and may be optionally co-injected with
steam to at least partially vapourize the surfactant at the wellhead, in the
wellbore, or down hole.
[00107] In a further embodiment, the two embodiments above are
carried out sequentially or simultaneously, i.e., a non-vapour surfactant is
provided to the reservoir via the injection well, and a surfactant vapour is
provided to the reservoir via the production well optionally with steam. While
not wishing to be bound by theory, this combined injection technique may
form a countercurrent flow of fluids between the injection and production
wells
to accelerate establishment of fluid communication between the wells.
Injecting a surfactant in liquid or solution phase into the reservoir via an
upper
injection well may cause the surfactant to disperse or increase mobility of
hydrocarbons between the injection and production wells and allow gravity to
act in favour of fluid mobility or faster drainage of heated bitumen towards
the
production well. At the same time, injecting a surfactant in vapour form
optionally with steam via a lower production well may cause the surfactant to
disperse or increase mobility of hydrocarbons between the injection and
production wells by allowing the surfactant vapour and/or steam to percolate
upwards in the formation or promote upward mobility towards the injection
well. Injection of surfactant(s) in this manner may lead to faster inter-well
communication compared to either providing a surfactant to the reservoir (i)
in
the liquid phase via the injection well or (ii) in the vapour phase via the
production well alone.
[00108] In one embodiment, the surfactant is water-soluble and is
provided to the reservoir via the injection well. Without wishing to be bound
by theory, it is believed that providing a water-soluble surfactant to the
reservoir via the injection well may enhance the mobility of water present in
the reservoir, allowing hot water and optionally subsequently steam to flow
towards the production well.
CA 02886934 2015-03-31
[00109] In another embodiment, the surfactant is water-insoluble (or
oil-soluble) and is provided to the reservoir via the production well. Without
wishing to be bound by theory, it is believed that providing an oil-soluble
surfactant to the reservoir via the production well may afford accelerated
drainage of heated bitumen from the inter-well region, in turn allowing steam
to percolate upward from the production well towards the injection well.
[00110] In a further embodiment, the two embodiments above are
carried out sequentially or simultaneously, i.e., a water-soluble surfactant
is
provided to the reservoir via the injection well, and an oil-soluble
surfactant is
provided to the reservoir via the production well optionally with steam.
Injection of surfactant(s) in this manner may lead to faster inter-well
communication compared to either (i) providing a water-soluble surfactant to
the reservoir via the injection well or (ii) providing an oil-soluble
surfactant to
the reservoir via the production well alone.
[00111] Following delivery of the surfactant, a certain period of time
may be allowed to elapse for the surfactant to penetrate at least a near-
wellbore region of the reservoir.
[00112] In one embodiment, during or subsequent to surfactant
delivery, gravity encourages fluid mobility in the inter-well region,
assisting,
facilitating, or accelerating establishment of fluid communication between the
injection well and the production well.
[00113] In one embodiment, a pressure differential is applied
between the injection and the production wells during or subsequent to
surfactant delivery to encourage mobility in the inter-well region,
facilitating
establishment of fluid communication between the wells.
[00114] In some embodiments, a surfactant may be delivered into a
region of the reservoir, such as a near-wellbore region, before injection of
any
other fluid or heating of the reservoir.
26
CA 02886934 2015-03-31
[00115] In some embodiments, a mobile reservoir fluid may be
formed in the reservoir after delivery of the surfactant. The reservoir fluid
may
be formed by heating, by solvent soaking, by injected steam or heated water,
or by the surfactant.
[00116] In some embodiments, a surfactant may be delivered into
the reservoir while the reservoir fluid is formed, such as by co-injecting the
surfactant with steam, heated water, or a solvent.
[00117] In some embodiments, a surfactant may be delivered into
the reservoir after the reservoir fluid has been formed, such as after a
period
of injection of steam, heated water, or a solvent.
[00118] In some embodiments, a surfactant may be delivered into
the reservoir before a fluid pressure is applied to drive the reservoir fluid
from
one well to another well of the well pair. An initial injection pressure may
be
required to deliver the surfactant into the reservoir. In different
embodiments,
the surfactant may be delivered into the reservoir after initial communication
between the wells of the well pair has been established, such as to improve,
accelerate or expand fluid communication between the wells of the well pair.
In the latter case, the fluid pressure may also be applied while injecting the
surfactant.
[00119] In one embodiment, following injection of the surfactant a
chasing fluid can be used to displace the surfactant from the well, forcing
part
or all of the surfactant into the formation. The chasing fluid may be a gas,
for
example nitrogen. Application of a pressure differential can also be used to
promote displacement of the surfactant into the near-wellbore region of the
reservoir.
[00120] In some embodiments, once the surfactant has been
delivered, optionally alone or co-injected with steam or a solvent, a certain
period of time may be allowed to elapse for the surfactant to penetrate part
of
27
the near-wellbore region of the reservoir. The near-wellbore region may for
example
be within an inter-well region between a first well and a second well of a
well pair.
This period of time (i.e., surfactant soak) can take place, for example, prior
to the
application of a pressure differential to establish the fluid communication
between
the wells of the well pair. The surfactant soak can also take place after the
application of a pressure differential or injection of a chasing fluid, which
promote an
initial insertion of the surfactant into the near-wellbore region, the soaking
period
permitting the surfactant to diffuse further from the wellbore into the near-
wellbore
region.
[00121] In various embodiments of the invention, the injection of
surfactant may
comprise an injection pattern. For example, the injection pattern may comprise
simultaneous injection with the steam or staged (e.g., sequential) injection
at
selected time intervals and at selected locations. The injection may be
performed in
various regions to create a target injection pattern to achieve target results
at a
particular location. In various embodiments of the invention, the injection
may be
continuous or periodic. Targeted injection may also be utilized to increase
well
conformance in regions of low mobility.
[00122] In one embodiment, the surfactant is injected at sub-fracturing
pressures of the reservoir formation.
[00123] The surfactant or mixture of surfactants may be utilized in
combination
with other processes such as a solvent aided process (SAP) or a similar
process in
which small amounts of chemicals or solvents such as light hydrocarbons are
utilized to further reduce the oil viscosity. The solvent may include one, or
a
combination, of alkanes, benzenes, toluenes, diesels, butane, suitable C3-C15
hydrocarbons, or the like. Further solvents that can be used for co-injection
are
disclosed in CA 2,698,898.
28
Date Re9ue/Date Received 2021-06-28
CA 02886934 2015-03-31
[00124] It should be mentioned that the conditions and objectives of
the principal oil recovery and start-up stages are different, which can affect
the selection of suitable surfactants. For example, in a typical SAGD
production stage, it may be desirable to deliver a surfactant in the vapour
form to the peripheral region of the steam chamber and it may be desirable
for the surfactant to form an oil-in-water emulsion in the reservoir fluid
that is
drained downward to improve fluid mobility. At this stage, the surfactant may
need to travel a long distance away from the well from which it is injected.
So
a surfactant with a shorter chain length, and thus, higher vapour pressure
may be desirable during the SAGD production stage. It may also be desirable
to use surfactants that can mix well with steam or water for this stage. In
comparison, during the start-up stage, it is not necessary for the surfactant
to
be delivered in a vapour form, and it is not necessary for the surfactant to
travel a long distance in the reservoir. The surfactant can move relatively
faster near the wellbore, and does not need to mix well with water for
delivery
to a region near the wellbore. It is also expected that substantial shear
mixing
can occur in the inter-well region between the two wells of a well pair, which
can help fluid movement in the region. In comparison, it is expected that
there
is much less shear mixing at the edges of the steam chamber far away from
the wells. At the start-up stage, it is desirable to pool more oil from the
formation with water for faster flow and faster communication. When a
pressure differential is established between the wells, it can not only assist
movement of the reservoir fluid, but can also assist delivery of the
surfactant
and mixing of the surfactant with the reservoir fluid.
[00125] Despite the differences between the SAGD production and
start-up stages described herein, surfactant selection for start-up may also
be
based on a number of factors related to the ease or speed with which the
operation can be switched or transitioned from the start-up phase (during
which fluid communication between an injection well and a production well, or
between an injection component and a production component of a single well,
is sought) to a principal recovery process, such as SAGD (during which the
29
CA 02886934 2015-03-31
focus is on hydrocarbon recovery). For example, a surfactant may be co-
injected via the injection well, the production well, or both, into the
reservoir
as a vapour with steam, to establish fluid communication between the wells.
The same surfactant may also be used, under the same or optionally under
different operating conditions, once fluid communication is achieved to
improve the rate of oil recovery. Or, for example, a surfactant may be
delivered to the reservoir in liquid phase to accelerate fluid communication
between the wells and then a different surfactant may be used once fluid
communication is achieved to improve the rate of oil recovery.
[00126] A person skilled in the art will appreciate that the choice of
surfactant(s) for accelerating start-up versus improving hydrocarbon recovery
may depend on factors such as, but not limited to, the type of well
configuration (e.g., well pair or single well) or the type of reservoir
containing
the hydrocarbons (e.g., reservoir depth, thickness, or extent of water
saturation).
[00127] The surfactant or mixture of surfactants may optionally be
utilized during or subsequent to a dilation process, solvent soak,
microorganism injection, or another process that modifies the porous
characteristics of the reservoir.
[00128] In one embodiment, injection of the surfactant into the
reservoir, and the resulting acceleration in fluid communication between the
wells in the well pair, is achieved without simultaneous production of
hydrocarbons from the wells.
[00129] In one embodiment, E-190 (defined above) may be used as the
surfactant. In another embodiment, a mixture of 50% S-82 and 50% IPA
(volume/volume) may be injected into the reservoir. E-190 or the mixture of
50% S-82 and 50% IPA may be co-injected with steam. The concentration of
E-190 or of the mixture of 50% S-82 and 50% IPA in the injected fluid can be
e.g., up to 3,000 ppm by weight. For example, the injection fluid may contain
CA 02886934 2015-03-31
about 2,500 ppm or up to about 2,800 ppm of the mixture of 50% S-82 and
50% IPA; or about 1,500 ppm or up to about 1,750 ppm of E-190.
Conveniently, these surfactants or mixtures can be stored as liquids at about
C under atmosphere pressure, and can be pre-mixed with hot water or
steam at surface before injection. Injection of the surfactant can take place
e.g., into a steam line immediately upstream of the wellhead through an
injection quill or other suitable methods. During injection of the surfactant,
the
BHP (bottom hole pressure) can be up to e.g., 2,600 kPa, 3,000-3,800 kPa,
4,000 kPa, or 5,500 kPa. If surfactant injection is combined with a dilation
process then the BHP can be as high as 8,500 kPa or as high as the
formation fracture pressure, whichever is greater.
Reservoir
[00130] In various
embodiments of the invention, the term "reservoir"
refers to a subterranean or underground formation comprising recoverable
hydrocarbons; and the term "reservoir of bituminous sands" refers to such a
formation wherein at least some of the hydrocarbons are viscous and
immobile and are disposed between or attached to sands. In various
embodiments of the invention, the terms "hydrocarbons" or "hydrocarbon"
relate to mixtures of varying compositions comprising hydrocarbons in the
gaseous, liquid or solid states, which may be in combination with other fluids
(liquids and gases) that are not hydrocarbons. For example, "heavy oil",
"extra
heavy oil", and "bitumen" refer to hydrocarbons occurring in semi-solid or
solid form and having a viscosity in the range of about 1,000 to over
1,000,000 centipoise (mPa.$) measured at original in-situ reservoir
temperature. In this specification, the terms "hydrocarbons", "heavy oil",
"oil"
and "bitumen" are used interchangeably. Depending on the in-situ density and
viscosity of the hydrocarbons, the hydrocarbons may comprise, for example,
a combination of heavy oil, extra heavy oil and bitumen. Heavy crude oil, for
example, may be defined as any liquid petroleum hydrocarbon having an
American Petroleum Institute (API) Gravity of less than about 20 and a
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CA 02886934 2015-03-31
viscosity greater than 1,000 mPa-s. Oil may be defined, for example, as
hydrocarbons mobile at typical reservoir conditions. Extra heavy oil, for
example, may be defined as having a viscosity of over 10,000 mPa.s and
about 10 API Gravity. The API Gravity of bitumen ranges from about 12 to
about 7 and the viscosity is greater than about 1,000,000 mPa.s. Bitumen is
generally non-mobile at typical native reservoir conditions.
[00131] In one embodiment, the present invention relates to the
establishment of fluid communication between wells in well pairs in a SAGD
system wherein the reservoir in the vicinity of one or more of the wells has
not
been subjected to fracture or otherwise altered so that a preferential path or
channel has been created in the reservoir.
[00132] A person skilled in the art will appreciate that an immobile
formation or reservoir at initial (or original) conditions (e.g., temperature
or
viscosity) means that the reservoir has not been treated with heat or other
means. Instead, it is in its original condition, prior to the recovery of
hydrocarbons. Immobile formation means that the formation has not been
mobilized through the addition of heat or other means.
[00133] It will be understood that any range of values herein is
intended to specifically include any intermediate value or sub-range within
the
given range, and all such intermediate values and sub-ranges are individually
and specifically disclosed.
[00134] It will also be understood that the word "a" or "an" is intended
to mean "one or more" or "at least one", and any singular form is intended to
include plurals herein.
[00135] It will be further understood that the term "comprise",
including any variation thereof, is intended to be open-ended and means
"include, but not limited to," unless otherwise specifically indicated to the
contrary.
32
CA 02886934 2015-03-31
[00136] When a list of items is given herein with an "or" before the
last item, any one of the listed items or any suitable combination of two or
more of the listed items may be selected and used.
[00137] Of course, the above described embodiments of the
invention are intended to be illustrative only and in no way limiting. The
described embodiments of the invention are susceptible to many
modifications of form, arrangement of parts, details and order of operation.
The invention, rather, is intended to encompass all such modification within
its
scope, as defined by the claims.
33
