Note: Descriptions are shown in the official language in which they were submitted.
CA 02910988 2015-10-29
WO 2014/194031
PCT/US2014/039923
PROCESS FOR ENHANCING OIL RECOVERY FROM AN OIL-BEARING
FORMATION
Field of the Invention
The present invention is directed to process for enhancing oil recovery from
an oil-
bearing formation.
Background of the Invention
In the recovery of oil from a subterranean oil-bearing formation, it is
possible to
recover only a portion of the oil in the formation using primary recovery
methods that
utilize the natural formation pressure to produce the oil. A portion of the
oil that cannot be
produced from the formation using primary recovery methods may be produced by
improved or enhanced oil recovery (FOR) methods.
In a secondary oil recovery process, water or brine is injected into an
injection well
extending into the oil-bearing formation after primary recovery is complete.
The water or
brine mobilizes oil in the formation, pushing the mobilized oil from the
injection well to a
production well located at a distance from the injection well. The mobilized
oil, along with
formation water, and the water injected into the formation may be produced at
the
production well.
Secondary oil recovery, while effective to produce some of the oil left in the
formation after primary recovery is complete, often leaves a significant
portion of residual
oil in the formation. Oil may be trapped in pores in the rock of the formation
or oil may
adhere to rock surfaces in the formation rather than being pushed through the
formation by
the injected water. The residual oil may be left trapped in the formation
after the injected
water has passed through the formation¨potentially significantly reducing the
quantity of
oil produced from the formation if only primary and secondary recovery
processes are
utilized to recover oil from the formation.
A portion of the residual oil in place in the formation after a secondary oil
recovery
waterflood may be produced by injecting an oil recovery formulation into the
formation
that is different from the water or brine injected into the formation in the
secondary oil
recovery waterflood¨which is known as tertiary oil recovery. The tertiary oil
recovery
formulation may mobilize the oil, for example, by liberating oil trapped in
the pores of the
rock of the formation, or by changing the adherence of the oil to rock
surfaces in the
1
CA 02910988 2015-10-29
WO 2014/194031
PCT/US2014/039923
formation, or by lowering interfacial tension between the residual oil and
water in the
formation, or by changing the physical characteristics, for example viscosity,
of the
residual oil. Examples of such tertiary oil recovery formulations include low
ionic strength
water, water soluble polymer formulations, alkaline-surfactant-polymer
formulations, oil
miscible solvents such as dimethyl ether, and oil miscible gases such as
carbon dioxide and
low molecular weight hydrocarbons.
Secondary and tertiary oil recovery may be conducted using conventional
injector-
producer well configurations. Some conventional injector-producer well
configurations
utilized for secondary and tertiary oil recovery are selected so that the
injected water or oil
recovery formulation pushes oil in the formation across the formation from the
injection
well to the producer well. Large arrays of such injector-producer wells may be
utilized to
produce oil from a single formation. For example, from 10 to 1000 injector-
producer well
pairs arranged in a direct fluid path from the injection well to the producer
well may be
utilized to produce oil from a single formation.
Application of tertiary oil recovery processes, however, may be limited when
using
certain conventional injector-producer well configurations. In certain
conventional
injector-producer well configurations, for example in offshore applications,
the injection
wells and the production wells are placed apart at large distances, for
example 1 km or
more due to the large capital expense outlays required for well drilling. The
oil is
mobilized and driven across the formation in a pattern or line drive geometry
in a
secondary oil recovery process. The distance between the injection wells and
the
production wells may render tertiary oil recovery technically and commercially
impractical
due to the long waiting time required for oil mobilized by the tertiary oil
recovery
formulation to arrive in the production well after a long waiting time for oil
mobilized by
secondary oil recovery to arrive in the production well. Furthermore, some of
these
injector-producer well configurations have been developed with peripheral
water injectors
that inject water below the oil/water contact in the formation, where the
injected water may
inhibit or prevent contact of the tertiary oil recovery formulation with the
oil, causing the
loss of the tertiary oil recovery formulation.
What is needed is a tertiary enhanced oil recovery process for recovering
residual
oil in an oil-bearing formation where injection wells and production wells are
placed apart
at a substantial distance.
2
CA 02910988 2015-10-29
WO 2014/194031
PCT/US2014/039923
Summary of the invention
The present invention is directed to a process for recovering oil from an oil-
bearing
formation, comprising:
for a first time period, injecting a first oil recovery fluid into the oil-
bearing
formation through a first well extending into the formation and producing oil
from the
formation through a second well extending into the formation;
for a second time period, injecting the first oil recovery fluid into the
formation
through the first well, injecting a second oil recovery formulation into the
formation
through the second well, and producing oil from the formation through a third
well
extending into the formation, where the second well is located on a fluid flow
path within
the formation between the first well and the third well, where the second oil
recovery fluid
is different than the first oil recovery fluid, and wherein the second time
period is after the
first time period, and the second time period commences, at the earliest, upon
initial
production of a mixture comprising oil and the first oil recovery fluid from
the formation
through the second well.
Additional advantages and other features of the present disclosure will be set
forth
in part in the description which follows and in part will become apparent to
those having
ordinary skill in the art upon examination of the following or may be learned
from the
practice of the disclosure. The advantages of the disclosure may be realized
and obtained
as particularly pointed out in the appended claims.
As will be realized, the present disclosure is capable of other and different
embodiments, and its several details are capable of modifications in various
obvious
respects, all without departing from the disclosure. Accordingly, the drawings
and
description are to be regarded as illustrative in nature, and not as
restrictive.
Brief Description of the Drawings
The drawing figures depict one or more implementations in accordance with the
present teachings, by way of example only, not by way of limitation. In the
figures, like
reference numerals refer to the same or similar elements.
Fig. 1 is an illustration of a step of a process of the present invention in a
first time period
of the process in a petroleum production system with vertically disposed
wells.
3
CA 02910988 2015-10-29
WO 2014/194031
PCT/US2014/039923
Fig. 2 is an illustration of a step of a process of the present invention in a
first time period
of the process in a petroleum production system with wells having horizontally
disposed
sections.
Fig. 3. is a diagram of a well pattern for production of petroleum in
accordance with a
process of the present invention.
Fig. 4 is an illustration of a step of a process of the present invention in a
second time
period of the process in a petroleum production system with vertically
disposed wells.
Fig. 5 is an illustration of a step of a process of the present invention in a
second time
period of the process in a petroleum production system with wells having
horizontally
disposed sections.
Fig. 6 is an illustration of a step of a process of the present invention in a
second time
period of the process in a petroleum production system with vertically
disposed wells.
Fig. 7 is an illustration of a step of a process of the present invention in a
second time
period of the process in a petroleum production system with wells having
horizontally
disposed sections.
Fig. 8 is an illustration of a step of a process of the present invention in a
second time
period of the process in a petroleum production system with vertically
disposed wells
wherein oil is produced from a first well and a third well.
Fig. 9 is an illustration of a step of a process of the present invention in a
second time
period of the process in a petroleum production system with vertically
disposed wells.
Fig. 10 is an illustration of a step of a process of the present invention in
a second time
period of the process in a petroleum production system with wells having
horizontally
disposed sections.
Detailed Description of the Invention
The present invention is directed to an enhanced oil recovery process in which
an
enhanced oil recovery formulation¨the second oil recovery fluid¨is injected
into an oil-
bearing formation through a second well located between a first well and a
third well
during a second time period after an improved oil recovery formulation¨the
first oil
recovery fluid¨is initially injected into the formation through the first well
during a first
time period. The second oil recovery fluid is different than the first oil
recovery fluid. Oil
is produced from the second well during at least a portion of the first time
period, and oil is
produced from the third well during a least a portion of the second time
period, and,
4
CA 02910988 2015-10-29
WO 2014/194031
PCT/US2014/039923
optionally, during at least a portion of the first time period. The second
time period
commences, at the earliest, upon initial production of a mixture comprising
oil and the first
oil recovery fluid from the formation through the second well. When the first
well and the
third well are located at a substantial distance from each other, injection of
the second oil
recovery fluid through the second well after the first time period enables the
second oil
recovery fluid to mobilize residual oil for recovery that was not mobilized by
the first oil
recovery fluid. The time period for production from the third well of the oil
mobilized by
injection of the second oil recovery fluid through the second well is reduced
substantially
relative to the time period for production of such oil from the third well
that would be
required if the second oil recovery fluid were injected only through the first
well, for
example, the time period for production may be reduced by years to decades.
When
peripheral water injectors are utilized to enhance production of oil by
injecting water below
an oil/water contact in the formation, injection of the second oil recovery
fluid into a
formation through the second well rather than the first initial injection well
reduces the risk
of losing the second oil recovery fluid without mobilizing residual oil for
recovery.
Referring now to Fig. 1, a first well 101, a second well 103, and a third well
105 are
shown extending from surfaces 107 through an overburden 109 into an oil-
bearing
formation 111. The surfaces 107 may be a platforms located on the sea 113 if
the oil-
bearing formation 111 is located offshore, or may be the earth's surface (not
shown) if the
oil-bearing formation 111 is located onshore.
The first well 101 may be a conventional well for injecting a fluid into an
oil-
bearing formation; the second well 103 may be a conventional well for
injecting a fluid
into an oil-bearing formation and for producing fluids including oil from the
formation, and
the third well 105 may be a conventional well for producing a fluids including
oil from an
oil-bearing formation. In some embodiments of the process of the present
invention the
first well 101 may be a conventional well for producing fluids including oil
from the
formation as well as a conventional well for injecting fluids into an oil-
bearing formation.
The second well 103 is located on a fluid flow path within the formation
between the first
well 101 and the third well 105. In an embodiment of the process of the
present invention,
the process may be conducted offshore, and the second well 103 may be a
sidetrack well
moved into position between the first well 101 and the third well 105, where
the second,
sidetrack, well 103 is positioned within the formation 111 on a fluid flow
path between the
first and third wells.
5
CA 02910988 2015-10-29
WO 2014/194031
PCT/US2014/039923
As shown in Fig. 1, the first well 101, the second well 103, and the third
well 105
may be primarily vertically or transversely oriented wells within the
formation relative to
the surface of the sea 113 or the earth's surface, where each of the
vertically or transversely
oriented wells 101, 103, and 105 are located a horizontal distance from each
other within
the formation 111. In another embodiment, as shown in Fig. 2, a portion 201 of
the
injection well 101, a portion 203 of the intermediate well 103, and a portion
205 of the
production well 105 are substantially horizontally oriented within the
formation relative to
the surface of the sea (not shown) or the earth's surface 114, where each of
the
substantially horizontally oriented portions 201, 203, and 205 of the wells
101, 103, and
105 are located a vertical distance from each other within the formation 111.
Referring now to Figure 3 an array of wells 300 is illustrated. Array 300
includes a
first well group 301 (denoted by vertical lines), a second well group 303
(denoted by
horizontal lines), and a third well group 305 (denoted by diagonal lines). The
first well
described above may include multiple first wells depicted as the first well
group 301 in the
array 300, the second well described above may include multiple second wells
depicted as
the second well group 303 in the array 300, and the third well described above
may include
multiple third wells depicted as the third well group 305 in the array 300.
In some embodiments, the array of wells 300 may be seen as a top view with the
first well group 301, the second well group 305, and the third well group 307
being
vertically disposed wells spaced on a piece of land. In some embodiments, the
array of
wells 300 may be seen as a cross-sectional side view of the formation showing
horizontally
disposed portions of the first wells of the first well group 301, the second
wells of the
second well group 30, and the third wells of the third well group 305,
respectively, spaced
within the formation.
Each first well in the first well group 301 may be a distance 311 from an
adjacent
first well in the first well group where the distance 311 may be from about
100 to about
10000 meters, or from about 250 to about 5000 meters, or from about 500 to
about 1000
meters. Each first well in the first well group 301 may be a distance 313 from
an adjacent
first well in the first well group. The distance 313 may be from about 5 to
about 10000
meters, or from about 10 to about 2500 meters, or from about 15 to about 1000
meters.
Each second well in the second well group 303 may be a distance 315 from an
adjacent second well in the second well group. The distance 315 may be from
about 100 to
about 10000 meters, or from about 250 to about 5000 meters, or from about 500
to about
6
CA 02910988 2015-10-29
WO 2014/194031
PCT/US2014/039923
1000 meters. Each second well in the second well group 303 may be a distance
317 from
an adjacent second well in the second well group. The distance 317 may be from
about 5
to about 10000 meters, or from about 10 to about 2500 meters, or from about 15
to about
1000 meters.
Each third well in the third well group 305 may be a distance 319 from an
adjacent
third well in the third well group. The distance 319 may be from about 100 to
about 10000
meters, or from about 250 to about 5000 meters, or from about 500 to about
1000 meters.
Each third well in the third well group 305 may be a distance 321 from an
adjacent
production well in the third well group. The distance 321 may be from about 5
to about
10000 meters, or from about 10 to about 2500 meters, or from about 15 to about
1000
meters.
Each first well in the first well group 301 may be a distance 323 from an
adjacent
second well in the second well group 303. Each second well in the second well
group 303
may be a distance 323 from an adjacent first well in the first well group 301.
The distance
323 may be from about 3 to about 5000 meters, or from about 5 to about 2500
meters, or
from about 10 to about 1000 meters, where the distance 323 may be less than
the distance
311 and/or distance 313.
Each second well in the second well group 303 may be a distance 325 from an
adjacent third well in the third well group 305. Each third well in the third
well group 305
may be a distance 325 from an adjacent second well in the second well group
303. The
distance 325 may be from about 3 to about 5000 meters, or from about 5 to
about 2500
meters, or from about 10 to about 1000 meters.
Each first well in the first well group 301 may be a distance 327 from the
nearest
third well in the third well group 305. Each third well in the third well
group 305 may be a
distance 327 from the nearest first well in the first well group 301. The
distance 327 may
be from about 4 to about 7500 meters, or from about 5 to about 5000 meters, or
from about
10 to about 2500 meters, where the distance 327 is greater than the distance
323.
In some embodiments, the array of wells 300 may have from 15 to 1500 wells,
for
example from 5 to 500 first wells in the first well group 301, from 5 to 500
second wells in
the second well group 303, and from 5 to 500 third wells in the third well
group 305.
The oil-bearing formation may be comprised of a porous matrix material, oil,
and
water. The oil-bearing formation comprises oil that may be separated and
produced from
the formation after introduction of the first oil recovery fluid, and after
introduction of the
7
CA 02910988 2015-10-29
WO 2014/194031
PCT/US2014/039923
second oil recovery fluid into the formation following introduction of the
first oil recovery
fluid into the formation. The formation preferably contains a substantial
amount of oil-in-
place, a significant portion of which may be recovered from the formation by
mobilization
using the first oil recovery fluid and the second oil recovery fluid and
subsequent
production of the mobilized oil.
The oil-bearing formation may also be comprised of water, which may be located
in
pores within the porous matrix material. The water in the formation may be
connate
water.
The porous matrix material of the formation may be comprised of one or more
porous matrix materials selected from the group consisting of a porous mineral
matrix, a
porous rock matrix, and a combination of a porous mineral matrix and a porous
rock
matrix. The rock and/or mineral porous matrix material of the formation may be
comprised
of sandstone, shale, and/or a carbonate selected from dolomite, limestone, and
mixtures
thereof¨where the limestone may be microcrystalline or crystalline limestone.
The
formation may have a permeability of from 0.0001 to 15 Darcies, or from 0.001
to 1 Darcy.
Oil in the oil-bearing formation may be located in pores within the porous
matrix
material of the formation. The oil in the oil-bearing formation may be
immobilized in the
pores within the porous matrix material of the formation, for example, by
capillary forces,
by interaction of the oil with the pore surfaces, by the viscosity of the oil,
or by interfacial
tension between the oil and water in the formation.
The oil-bearing formation should be a formation susceptible to production of
oil by
injection of the first oil recovery fluid and the second oil recovery fluid
into the formation
and subsequent production and recovery of oil from the formation.
Determination of the
suitability of a formation for oil recovery may be made by conducting
conventional core
flow studies on core plugs extracted from the formation utilizing the first
and second oil
recovery fluids in sequence as injectants, where the core plugs are saturated
with oil from
the formation and with connate water or water having a salinity matched to the
formation
connate water salinity at a comparable initial water saturation prior to
injecting the first
and second oil recovery fluids.
Referring again to Fig. 1, in the process of the present invention a first oil
recovery
fluid is introduced into the oil-bearing formation 111 for a first time
period, for example
by injecting the first oil recovery fluid into the formation through the first
well 101 by
pumping the first oil recovery fluid through the first well and into the
formation. The first
8
CA 02910988 2015-10-29
WO 2014/194031
PCT/US2014/039923
time period and injection of the first oil recovery fluid into the formation
111 may
commence after primary recovery of oil from the formation is complete, e.g.,
after little or
no further oil may be recovered from the formation due to the natural pressure
of the
formation.
The pressure at which the first oil recovery fluid is introduced into the
formation
111 through the first well 101 may range from the instantaneous pressure in
the formation
up to the fracture pressure of the formation or exceeding the fracture
pressure of the
formation. The pressure at which the first oil recovery fluid may be injected
into the
formation may range from 20% to 95%, or from 40% to 90%, of the fracture
pressure of
the formation. Alternatively, the first oil recovery fluid may be injected
into the formation
at a pressure of at least the fracture pressure of the formation, where the
first oil recovery
fluid may be injected under formation fracturing conditions.
The volume of the first oil recovery fluid introduced into the formation 111
via the
first well 101 may range from 0.5 to 20 pore volumes between the first well
101 and the
third well 105, or from 1 to 10 pore volumes between the first well and the
third well, or
from 2 to 5 pore volumes between the first well and the third well, where the
term "pore
volume between the first well and the third well" refers to the volume of the
formation that
may be swept by the first oil recovery fluid between the first well 101 and
the third well
105. The pore volume between the first well and the third well may be readily
be
determined by methods known to a person skilled in the art, for example by
modelling
studies or by injecting water having a tracer contained therein through the
formation 111
from the first well 101 to the third well 105.
The first oil recovery fluid may be water or brine. The first oil recovery
fluid may
be water or brine such as used in water flooding in conventional secondary oil
recovery
processes, where injection of the first oil recovery fluid may be a water
flood for improved
oil recovery from the formation. The water or brine used as the first oil
recovery fluid may
be provided from seawater, brackish water, an aquifer, a lake, a river, or
water produced
from the formation. The water or brine used as the first oil recovery fluid
may contain, or
may be conditioned to contain, less than 100 mg/1 sulfate anion (S042) to
inhibit souring of
the formation by sulfate-consuming bacteria. The first oil recovery fluid
water or brine
may be conditioned to contain less than 100 mg/1 sulfate by conventional
methods for
removing sulfate anions from water, for example, by nanofilitration, by
reverse osmosis, by
forward osmosis, or by ion exchange. The water or brine used as the first oil
recovery fluid
9
CA 02910988 2015-10-29
WO 2014/194031
PCT/US2014/039923
may contain, or may be conditioned to contain, a total dissolved solids (TDS)
content of at
least 200 parts per million (ppm) to avoid destabilization of the formation
induced by
swelling of clays within the formation. Fresh water having a TDS content of
less than 200
ppm may be conditioned to contain a TDS of at least 200 ppm by adding sodium
chloride
or calcium chloride to the water. Brine used as the first oil recovery fluid
preferably
contains, or may be conditioned to contain, a TDS content of less than 50,000
ppm. Brine
having a TDS content of more than 50,000 ppm may be conditioned to contain a
TDS
content of less than 50,000 ppm by conventional desalination methods, for
example,
thermal desalination, nanofiltration, reverse osmosis, forward osmosis, and
ion exchange.
As the first oil recovery fluid is introduced into the formation 111 during
the first
time period, the first oil recovery fluid spreads into the formation as shown
by arrow 115.
Upon introduction to the formation 111 and during the first time period, the
first oil
recovery fluid contacts oil within the formation, mobilizes at least a portion
of the
contacted oil, and pushes at least a portion of the mobilized oil 117 across
the formation to
the second well 103. At least a portion of the mobilized oil 117 is then
produced from the
formation through the second well 103. A portion 119 of the mobilized oil may
be pushed
across the formation to the third well by introduction of the first oil
recovery fluid into the
formation, and the mobilized portion of oil 119 may be produced through the
third well
105 during the first time period.
Referring to Fig. 2, when the wells are horizontally disposed in the
formation, the
first oil recovery fluid may be introduced into the formation through the
horizontally
disposed portion 201 of the first well 101, and the first oil recovery fluid
may spread into
the formation 111 as shown by arrows 215. The first oil recovery fluid
contacts oil within
the formation, mobilizes at least a portion of the contacted oil, and pushes
at least a portion
of the mobilized oil 217 downward to the horizontally disposed portion 203 of
the second
well 103. At least a portion of the mobilized oil 217 is then produced from
the formation
through the second well 103. A portion 219 of the mobilized oil also may be
pushed
downward to the horizontally disposed portion 205 of the third well 105 by
introduction of
the first oil recovery fluid into the formation. The mobilized portion of the
oil 219 may be
produced through the horizontally disposed portion 205 of the third well 105
during the
first time period.
Referring now to Figs. 1 and 2, the first time period extends until, at the
earliest, a
portion of the first oil recovery fluid is produced through the second well
103 along with
CA 02910988 2015-10-29
WO 2014/194031
PCT/US2014/039923
oil from the formation. The first recovery fluid may be produced through the
second well
103 in a mixture comprised of oil, formation water, and first oil recovery
fluid. The first
time period may extend until, at the earliest, the mixture comprising oil,
formation water,
and the first oil recovery fluid produced through the second well 103 has a
weight ratio of
first oil recovery fluid plus formation water to oil of at least 1:1, or at
least 2:1.
Referring now to Figs. 4 and 5, after the first time period, a second oil
recovery
fluid is injected into the formation 111 through the second well 103 and oil
is produced
from the formation through the third well 105 for a second time period. The
first oil
recovery fluid may injected into the first well 101 for at least a portion, or
all, of the second
time period.
The second time period commences after the first time period. The second time
period may commence immediately upon completion of the first time period, or
may
commence some time after the completion of the first time period. The second
time period
commences, at the earliest, upon initial production of a mixture comprising
oil and the first
oil recovery fluid through the second well 103. The second time period may
commence, at
the earliest, upon production of a mixture comprising oil, formation water,
and the first oil
recovery formulation where the mixture has a weight ratio of the first oil
recovery fluid
plus the formation water to oil of at least 1:1, or at least 2:1. The second
time period may
end upon cessation of injection of the second oil recovery fluid into the
formation 111
through the second well 103.
The second oil recovery fluid may be a fluid effective to mobilize residual
oil left in
the formation after introduction of the first oil recovery fluid into the
formation and contact
of oil with the first oil recovery fluid in the formation. The second oil
recovery fluid may
be effective to enable mobilization and production of a significant amount of
residual oil in
addition to oil mobilized and produced by introducing the first oil recovery
fluid into the
formation. After passage of the first oil recovery fluid through the
formation, the second
oil recovery fluid may mobilize the residual oil by liberating residual oil
trapped in the
pores of the rock of the formation, or by changing the adherence of the
residual oil to rock
surfaces in the formation, or by lowering interfacial tension between the
residual oil and
water in the formation, or by changing the physical characteristics of the
residual oil, for
example viscosity. The second oil recovery fluid is different from the first
oil recovery
fluid, and may be selected from the group consisting of a low salinity aqueous
fluid having
an ionic strength of at most 0.15M and a TDS content of from 200 ppm to 10000
ppm, an
11
CA 02910988 2015-10-29
WO 2014/194031
PCT/US2014/039923
aqueous solution of a surfactant or combination of surfactants, an alkaline-
surfactant-
polymer formulation, an aqueous solution of water soluble polymer, dimethyl
ether, and
mixtures thereof.
The second oil recovery fluid may be a low salinity aqueous fluid having an
ionic
strength of at most 0.15M and a TDS content of from 200 ppm to 10000 ppm. The
low
salinity aqueous fluid may have a TDS content of from 500 ppm to 7000 ppm, or
from
1000 ppm to 5000 ppm, or from 1500 ppm to 4500 ppm. The low salinity aqueous
fluid
may have an ionic strength of at most 0.1M or at most 0.05M, or at most 0.01M,
and may
have an ionic strength of from 0.01M to 0.15M, or from 0.02M to 0.125M, or
from 0.03M
to 0.1M. Ionic strength, as used herein, is defined by the equation
/ = - * E1.2 t1t c. z?
2 = t
where I is the ionic strength, c is the molar concentration of ion i, z is the
valency of ion i,
and n is the number of ions in the measured solution.
The low salinity aqueous fluid may have an ionic strength that is less than
the ionic
strength of connate water present in the oil-bearing formation, and/or a
multivalent cation
concentration that is less than the multivalent cation concentration of
connate water present
in the oil-bearing formation, and/or a divalent cation concentration that is
less than the
divalent cation concentration of connate water present in the oil-bearing
formation. The
fraction of the ionic strength of the low salinity aqueous fluid to the ionic
strength of the
connate water may be less than 1, or may be less than 0.9, or may be less than
0.5, or may
be less than 0.1, or may be from 0.01 up to, but not including, 1, or from
0.05 to 0.9, or
from 0.1 to 0.8. The fraction of the multivalent cation content of the low
salinity aqueous
fluid to the multivalent cation content of the connate water may be less than
1, or may be
less than 0.9, or may be less than 0.5, or may be less than 0.1, or may be
from 0.01 up to,
but not including, 1, or from 0.05 to 0.9, or from 0.1 to 0.8. The fraction of
the divalent ion
content of the low salinity aqueous fluid to the divalent ion content of the
connate water
may be less than 1, or less than 0.9, or less than 0.5, or less than 0.1, or
from 0.01 up to, but
not including, 1, or from 0.05 to 0.9, or from 0.1 to 0.8.
The low salinity aqueous fluid may have a relatively low multivalent cation
content
and/or a relatively low divalent cation content. The low salinity aqueous
fluid may have a
multivalent cation concentration of at most 200 ppm, or at most 100 ppm, or at
most 75
ppm, or at most 50 ppm, or at most 25 ppm, or from 1 ppm to 200 ppm, or from 2
ppm to
100 ppm, or from 3 ppm to 75 ppm, or from 4 ppm to 50 ppm, or from 5 ppm to 25
ppm.
12
CA 02910988 2015-10-29
WO 2014/194031
PCT/US2014/039923
The low salinity aqueous fluid may have a divalent cation concentration of at
most 150
ppm, or at most 100 ppm, or at most 75 ppm, or at most 50 ppm, or at most 25
ppm, or
from 1 ppm to 100 ppm, or from 2 ppm to 75 ppm, or from 3 ppm to 50 ppm, or
from 4
ppm to 25 ppm, or from 5 ppm to 20 ppm.
The low salinity aqueous fluid may be provided from a natural source or may be
provided by processing source water having a TDS content of greater than 10000
ppm, or,
if desired to use a low salinity aqueous fluid having a TDS content of 5,000
ppm or less by
processing a source water having a TDS content of greater than 5,000 ppm, to
produce the
aqueous fluid. The aqueous fluid may be provided from a natural source such as
an
aquifer, a lake, or a river comprising water containing from 200 ppm to 10000
ppm total
dissolved solids.
The low salinity aqueous fluid, or at least a portion thereof, may be provided
by
processing a saline source water having a TDS content of greater than 10000
ppm to
produce the aqueous fluid, and the system may further comprise a saline source
water
having a TDS content of greater than 10000 ppm and a mechanism for processing
a saline
source water having a TDS content of greater than 10000 ppm to produce the low
salinity
aqueous fluid. The saline source water may have a TDS content of at least
10000 ppm, or
at least 15000 ppm or at least 17500 ppm, or at least 20000 ppm, or at least
25000 ppm, or
at least 30000 ppm, or at least 40000 ppm, or at least 50000 ppm, or from
10000 ppm to
250000 ppm, or from 15000 ppm to 200000 ppm, or from 17500 ppm to 150000 ppm,
or
from 20000 ppm to 100000 ppm, or from 25000 ppm to 50000 ppm. The saline
source
water to be processed may be selected from the group consisting of aquifer
water,
seawater, brackish water, water produced from the oil-bearing formation, and
mixtures
thereof. The saline source water may be processed according to conventional
desalination
processes to produce the low salinity aqueous fluid to be used as the second
oil recovery
fluid.
Alternatively, the second oil recovery fluid may be an aqueous solution
containing
one or more surfactants. The surfactant(s) may be any surfactant effective to
reduce the
interfacial tension between water and residual oil left in the formation after
passage of the
first oil recovery fluid through the formation and thereby mobilize the
residual oil for
production from the formation. The surfactant may be an anionic surfactant.
The anionic
surfactant may be a sulfonate-containing compound, a sulfate-containing
compound, a
carboxylate compound, a phosphate compound, or a blend thereof. The anionic
surfactant
13
CA 02910988 2015-10-29
WO 2014/194031
PCT/US2014/039923
may be an alpha olefin sulfonate compound, an internal olefin sulfonate
compound, a
branched alkyl benzene sulfonate compound, a propylene oxide sulfate compound,
an
ethylene oxide sulfate compound, a propylene oxide-ethylene oxide sulfate
compound, or a
blend thereof. The anionic surfactant may contain from 12 to 28 carbons, or
from 12 to 20
carbons. The surfactant of the second oil recovery fluid may comprise an
internal olefin
sulfonate compound containing from 15 to 18 carbons or a propylene oxide
sulfate
compound containing from 12 to 15 carbons, or a blend thereof, where the blend
contains a
volume ratio of the propylene oxide sulfate to the internal olefin sulfonate
compound of
from 1:1 to 10:1.
The aqueous surfactant solution of the second oil recovery fluid may contain
an
amount of the surfactant effective to reduce the interfacial tension between
residual oil and
water in the formation and thereby mobilize the residual oil for production
from the
formation. The aqueous surfactant solution of the second oil recovery fluid
may contain
from 0.05 wt.% to 5 wt.% of the surfactant or combination of surfactants, or
may contain
from 0.1 wt.% to 3 wt.% of the surfactant or combination of surfactants.
The aqueous surfactant solution of the second oil recovery fluid may also
contain a
co-solvent, where the co-solvent may be a low molecular weight alcohol
including, but not
limited to, methanol, ethanol, and iso-propanol, isobutyl alcohol, secondary
butyl alcohol,
n-butyl alcohol, t-butyl alcohol, or a glycol including, but not limited to,
ethylene glycol,
1,3-propanediol, 1,2-propandiol, diethylene glycol butyl ether, triethylene
glycol butyl
ether, or a sulfosuccinate including, but not limited to, sodium dihexyl
sulfosuccinate. The
co-solvent may be utilized in the aqueous surfactant solution of the second
oil recovery
fluid for assisting in prevention of formation of a viscous emulsion. If
present, the co-
solvent may comprise from 100 ppm to 50000 ppm, or from 500 ppm to 5000 ppm of
the
aqueous surfactant solution of the second oil recovery fluid. A co-solvent may
be absent
from the aqueous surfactant solution of the second oil recovery fluid.
Alternatively, the second oil recovery fluid may be an aqueous mixture
containing
a polymer. The aqueous polymer mixture of the second oil recovery fluid may be
prepared
or conditioned to have a viscosity on the same order of magnitude as the
viscosity of
residual oil in the formation under formation temperature conditions so the
second oil
recovery fluid may mobilize and drive the residual oil across the formation
for production
from the formation with a minimum of fingering of the oil through the second
oil recovery
fluid and/or fingering of the second oil recovery fluid through the oil. The
aqueous
14
CA 02910988 2015-10-29
WO 2014/194031
PCT/US2014/039923
polymer mixture may comprise a polymer selected from the group consisting of
polyacrylamides; partially hydrolyzed polyacrylamides; polyacrylates;
ethylenic co-
polymers; biopolymers; carboxymethylcelloluses; polyvinyl alcohols;
polystyrene
sulfonates; polyvinylpyrrolidones; AMPS (2-acrylamide-methyl propane
sulfonate); co-
polymers of acrylamide, acrylic acid, AMPS, and n-vinylpyrrolidone in any
ratio; and
combinations thereof. Examples of ethylenic co-polymers include co-polymers of
acrylic
acid and acrylamide, acrylic acid and lauryl acrylate, and lauryl acrylate and
acrylamide.
Examples of biopolymers include xanthan gum, guar gum, and scleroglucan.
The quantity of polymer in the aqueous polymer mixture of the second oil
recovery
fluid should be sufficient to provide the second oil recovery fluid with a
viscosity sufficient
to drive mobilized residual oil through the oil-bearing formation with a
minimum of
fingering of the second oil recovery fluid through the mobilized residual oil
and with a
minimum of fingering of the mobilized residual oil through the second oil
recovery fluid.
The quantity of the polymer in the aqueous polymer mixture of the second oil
recovery
fluid may be sufficient to provide the second oil recovery fluid with a
dynamic viscosity at
formation temperatures on the same order of magnitude, or, less preferably a
greater order
of magnitude, as the dynamic viscosity of the residual oil in the oil-bearing
formation at
formation temperatures so the second oil recovery fluid may push mobilized
residual oil
through the formation. The quantity of the polymer in the aqueous polymer
mixture of the
second oil recovery fluid may be sufficient to provide the second oil recovery
fluid with a
dynamic viscosity of at least 1 mPa s (1 cP), or at least 10 mPa s (10 cP), or
at least 100
mPa s (100 cP), or at least 1000 mPa s (1000 cP) at 25 C or at a temperature
within a
formation temperature range. The concentration of polymer in the aqueous
mixture of the
second oil recovery fluid may be from 250 ppm to 10000 ppm, or from 500 ppm to
5000
ppm, or from 1000 to 2000 ppm.
The molecular weight average of the polymer in the aqueous polymer mixture
should be sufficient to provide sufficient viscosity to the second oil
recovery fluid to drive
mobilized residual oil through the formation. The polymer may have a molecular
weight
average of at least 10000 daltons, or at least 50000 daltons, or at least
100000 daltons. The
polymer may have a molecular weight average of from 10000 to 30000000 daltons,
or
from 100000 to 15000000 daltons.
Alternatively, the second oil recovery fluid may be an alkaline-surfactant-
polymer
("ASP") formulation. The ASP formulation may be an aqueous solution containing
one or
CA 02910988 2015-10-29
WO 2014/194031
PCT/US2014/039923
more surfactants as described above, and containing one or more polymers as
described
above, and containing an alkali. The alkali of the second oil recovery fluid
ASP
formulation may be any alkali effective to interact with residual oil in the
formation to
form a soap effective to reduce the interfacial tension between residual oil
and water in the
formation. The second oil recovery fluid ASP formulation may comprise one or
more
alkali compounds. The one or more alkali compounds may be selected from the
group
consisting of lithium hydroxide, sodium hydroxide, potassium hydroxide,
lithium
carbonate, sodium carbonate, potassium carbonate, lithium bicarbonate, sodium
bicarbonate, potassium bicarbonate, lithium silicate, sodium silicate,
potassium silicate,
lithium phosphate, sodium phosphate, potassium phosphate, and mixtures
thereof.
The second oil recovery fluid ASP formulation may contain an amount of
surfactant as described above, an amount of polymer as describe above, and an
amount of
the alkali effective to interact with the residual oil in the formation to
form a soap effective
to reduce the interfacial tension between residual oil and water in the
formation and
thereby mobilize the residual oil for production from the formation. The
second oil
recovery fluid may contain from 0.001 wt.% to 5 wt.% of the alkali, or from
0.005 wt.% to
1 wt.% of the alkali, or from 0.01 wt.% to 0.5 wt.% of the alkali.
Alternatively, the second oil recovery fluid may comprise an ether, preferably
dimethyl ether ("DME") or diethyl ether ("DEE"). The ether of the second oil
recovery
fluid should be soluble in water and soluble in oil, where the ether may be
transported
through formation water and/or the first recovery fluid to residual oil in the
formation by
introduction of the second oil recovery fluid into the formation, and the
ether may mobilize
the residual oil by reducing the viscosity of the residual oil upon contact
with the residual
oil. Preferably the second oil recovery fluid is a dimethyl ether formulation.
The dimethyl
ether formulation may include dimethyl ether and/or dimethyl ether derivatives
and/or
precursors for example, methanol and mixtures thereof.
Referring now to Fig. 4, the second oil recovery fluid is introduced into the
formation 111 for a second time period by injecting the second oil recovery
fluid into the
formation, where, as described above, the second time period commences, at the
earliest,
upon initial production of a mixture comprising oil and the first oil recovery
fluid through
the second well 103. Injection of the first oil recovery fluid through the
first well 101 may
continue throughout the second time period, or for a portion of the second
time period. Oil
121 mobilized by the first oil recovery fluid, or by the first and the second
oil recovery
16
CA 02910988 2015-10-29
WO 2014/194031
PCT/US2014/039923
fluids, is produced from the formation through the third well 105 during the
second time
period, or for a portion of the second time period.
The pressure at which the second oil recovery fluid is introduced into the
formation
111 through the second well 103 may range from the instantaneous pressure in
the
formation at the second well 103 up to the fracture pressure of the formation
or exceeding
the fracture pressure of the formation. The pressure at which the second oil
recovery fluid
may be injected into the formation may range from 20% to 95%, or from 40% to
90%, of
the fracture pressure of the formation. Alternatively, the second oil recovery
fluid may be
injected into the formation at a pressure of at least the fracture pressure of
the formation,
where the second oil recovery fluid may be injected under formation fracturing
conditions.
The volume of the second oil recovery fluid introduced into the formation 111
via
the second well 103 may range from 0.05 to 20 pore volumes between the second
well 103
and the third well 105, or from 0.1 to 10 pore volumes between the second well
and the
third well, or from 0.2 to 5 pore volumes between the second well and the
third well, where
the term "pore volume between the second well and the third well" refers to
the volume of
the formation that may be swept by the second oil recovery fluid between the
second well
101 and the third well 105. The pore volume between the second well and the
third well
may be readily be determined by methods known to a person skilled in the art,
for example
by modelling studies or by injecting water having a tracer contained therein
through the
formation 111 from the second well 101 to the third well 105. In one
embodiment of the
process of the present invention, as described in further detail below, a slug
of limited
volume of the second oil recovery fluid, for example a volume of from 0.1 to 1
pore
volume between the second and third well, is injected into the formation 111
through the
second well 103 in the second time period while continuing injection of the
first oil
recovery fluid through the first well 101 and producing mobilized oil from the
formation
through the third well 105. In another embodiment of the process of the
present invention,
as described in further detail below, a large volume of the second oil
recovery fluid, for
example a volume of greater than 1 pore volume between the second and third
wells, is
injected into the formation through the second well 103 in the second time
period while
producing mobilized oil from the formation through the third well 105, and,
optionally,
continuing injection of the first oil recovery fluid into the formation
through the first well
for a portion, or all, of the second time period.
17
CA 02910988 2015-10-29
WO 2014/194031
PCT/US2014/039923
As the second oil recovery fluid is introduced into the formation 111 during
the
second time period, the second oil recovery fluid spreads into the formation
as shown by
arrow 415. Upon introduction to the formation 111 and during the second time
period, the
second oil recovery fluid contacts residual oil within the formation,
mobilizes at least a
portion of the contacted residual oil, and pushes at least a portion of the
mobilized residual
oil 121 across the formation to the third well 105. The second oil recovery
fluid contacts at
least a portion of the formation from which a portion of oil has been
mobilized and
removed by contact with the first oil recovery fluid. The second oil recovery
fluid may act
as a tertiary oil recovery fluid and mobilize at least a portion of residual
oil left behind in
the portion of the formation from which oil has been mobilized and removed by
contact
with the first oil recovery fluid. A portion of the first oil recovery fluid
injected into the
formation through the first well 101 may precede the second oil recovery fluid
through the
formation to the third well, mobilizing and moving oil for production from the
third well
105. The second oil recovery fluid may follow a portion of the first oil
recovery fluid from
the second well to the third well, and may mix with a portion of the first oil
recovery fluid.
The injected second oil recovery fluid may push at least a portion of the
first oil recovery
fluid through the formation from the second well to the third well, where the
first and
second oil recovery fluids mobilize oil 121 for production from the third
well.
Referring now to Fig. 5, when the wells are horizontally disposed in the
formation,
the second oil recovery fluid is introduced into the formation 111 during the
second time
period through the horizontally disposed portion 203 of the second well 103,
and the
second oil recovery fluid spreads into the formation as shown by arrows 515.
Upon
introduction to the formation 111 and during the second time period, the
second oil
recovery fluid contacts oil within the formation, mobilizes at least a portion
of the
contacted oil, and pushes at least a portion of the mobilized oil downwards to
the
horizontally disposed portion 205 of the third well 105. At least a portion of
the mobilized
oil 221 then may be produced from the formation through the third well 105.
The second
oil recovery fluid contacts at least a portion of the formation 111 from which
a portion of
oil has been mobilized and removed by contact with the first oil recovery
fluid. The
second oil recovery fluid may act as a tertiary oil recovery fluid and
mobilize at least a
portion of residual oil left behind in the portion of the formation from which
oil has been
mobilized and removed by contact with the first oil recovery fluid. A portion
of the first
oil recovery fluid injected into the formation through horizontally disposed
portion 201 of
18
CA 02910988 2015-10-29
WO 2014/194031
PCT/US2014/039923
the first well 101 may precede the second oil recovery fluid downward through
the
formation to the horizontally disposed portion 205 of the third well 105,
mobilizing and
moving oil for production from the third well 105. The second oil recovery
fluid may
follow a portion of the first oil recovery fluid from the horizontally
disposed portion 203 of
the second well 103 to the horizontally disposed portion 205 of the third well
105 and may
mix with a portion of the first oil recovery fluid. The injected second oil
recovery fluid
may push at least a portion of the first oil recovery fluid downward through
the formation
from the horizontally disposed portion 203 of the second well 103 to the
horizontally
disposed portion 205 of the third well 105, where the first and second oil
recovery fluids
mobilize oil for production from the third well.
The first oil recovery fluid may be injected through the first well 101 for a
portion,
or all, of the second time period. Injection of the first oil recovery fluid
through the first
well 101 during at least a portion of the second time period may continue to
push the first
oil recovery fluid within the formation and oil mobilized by the first oil
recovery fluid
through the formation to the third well 105 for production therefrom.
Injection of the first
oil recovery fluid through the first well during at least a portion of the
second time period
may also serve to drive the second oil recovery fluid and residual oil
mobilized by the
second oil recovery fluid to the third well for production therefrom,
particularly if the first
oil recovery fluid is more dense than the second oil recovery fluid and the
residual oil
mobilized by the second oil recovery fluid. In an embodiment of the process of
the present
invention, the first oil recovery fluid is injected through the first well 101
into the
formation 111 for at least 25% of the time of the second time period, or for
at least 50% of
the time of the second time period, or for the entire second time period. In
another
embodiment, the first oil recovery fluid is not injected into the formation
during the second
time period.
Referring now to Figs. 6 and 7, a large volume of the second oil recovery
fluid
may be introduced into the formation 111 through the second well 103 during
the second
time period, where the volume of the second oil recovery fluid introduced into
the
formation may be greater than 1 pore volume, or greater than 2 pore volumes,
or greater
than 3 pore volumes, or from 1 pore volume and 20 pore volumes, or from 2 pore
volumes
to 10 pore volumes between the second well 103 and the third well 105, or
respective
horizontally disposed portions 203 and 205 thereof. At the end of the second
time period
after injection of a volume of the second oil recovery fluid into the
formation of greater
19
CA 02910988 2015-10-29
WO 2014/194031
PCT/US2014/039923
than 1 pore volume between the second well and the third well or their
respective
horizontally disposed portions thereof, the injected second oil recovery fluid
415 or 515
may extend in a fluid path within the formation from the second well 103 to
the third well
105, or from their respective horizontally disposed portions 203 and 205
thereof. The oil
121 or 221 mobilized by the relatively large volume of second oil recovery
fluid and at
least a portion of oil mobilized by the first oil recovery fluid remaining in
the formation
may be produced from the formation through the third well 105.
In an embodiment of the process of the present invention, as shown in Fig. 8,
when
a relatively large volume of the second oil recovery formulation is introduced
into the
formation as described above through the second well 103, oil 122 may be
produced from
the formation through the first well 101 and oil 121 may be produced from the
formation
through the third well 105. Injection of the first oil recovery fluid into the
formation
through the first well may be halted at the beginning of the second time
period, or in a first
portion of the second time period, and oil may be produced from the first well
101 after
injection of the first oil recovery fluid through the first well is halted. A
portion 815 of the
second oil recovery fluid injected into the formation may mobilize and drive
at least a
portion of oil 122 not mobilized by contact of the first oil recovery fluid
with oil in the
formation to the first well 101 for production therefrom. As described above,
another
portion 415 of the second oil recovery fluid may mobilize and drive at least a
portion of oil
121 to the third well for production therefrom. The first oil recovery fluid
115 and oil
mobilized thereby located in a fluid path between the first and second wells
101 and 103
also may be mobilized and driven for production from the first well by
injection of the
second oil recovery fluid into the formation through the second well.
Alternatively, referring now to Figs. 9 and 10, a small volume slug 915 or
1015 of
the second oil recovery fluid, relative to the pore volume within the
formation between the
second and third wells 103 and 105, or their respective horizontally disposed
portions 203
and 205 thereof, may be introduced into the formation through the second well
during the
second time period. The volume of the second oil recovery fluid 915 or 1015
introduced
into the formation in this embodiment of the process may be from 0.05 to 1
pore volumes
between the second well 103 and the third well 105 or their respective
horizontally
disposed portions 203 and 205 thereof. The relatively small volume slug of the
second oil
recovery fluid 915 or 1015 may be sufficient to mobilize a substantial portion
of the
residual oil not mobilized by contact of the first oil recovery fluid with oil
in the formation,
CA 02910988 2015-10-29
WO 2014/194031
PCT/US2014/039923
for example at least 10 wt.%, or at least 20 wt.%, or at least 50 wt.% of the
residual oil may
be mobilized by contact with the second oil recovery fluid slug. In this
embodiment, the
slug of the second oil recovery fluid 915 or 1015 is injected into the
formation through the
second well 103, or a horizontally disposed portion 203 thereof, while
continuing injection
of the first oil recovery fluid through the first well 101 or a horizontally
disposed portion
201 thereof. The injected second oil recovery fluid slug 915 or 1015 may
contact and
mobilize at least a portion of the oil in the formation not mobilized by
contact with the first
oil recovery fluid. The second oil recovery fluid slug and mobilized oil 121
or 221 may be
driven across the formation to the third well 105 for production therefrom
initially by the
continued injection of the second oil recovery fluid slug.
After injection of the second oil recovery fluid slug 915 or 1015 is complete
and the
second time period is over, injection of the first oil recovery fluid 115 or
215 through the
first well 101 or horizontal portion 201 thereof is continued for a third time
period, where
the third time period commences upon the end of the second time period. The
second oil
recovery fluid slug 915 or 1015 and mobilized oil 121 or 221 may be driven
across the
formation to the third well 105 or horizontal portion thereof 205 for
production therefrom
during the third time period by the continued injection of the first oil
recovery fluid
through the first well. Optionally, the first oil recovery fluid may be
injected into the
formation through the second well 103 or horizontal portion thereof 203 during
the third
period, either while continuing injection of the first oil recovery fluid into
the formation
through the first well 101 or horizontal portion 201 thereof, or after
stopping injection of
the first oil recovery fluid into the formation through the first well.
Oil 121 or 221, including oil mobilized by contact with the first oil recovery
fluid
and residual oil mobilized by contact with the second oil recovery fluid may
be produced
from the formation through the third well 105. A portion of the first oil
recovery fluid, a
portion of the second oil recovery fluid, and formation water may also be
produced from
the formation 111 through the third well 105. Production of oil from the
formation 111
through the third well 105 may be continued for the first, second, and third
time periods,
where production may be halted when insufficient oil is produced to render the
process
economical.
The present invention is well adapted to attain the ends and advantages
mentioned
as well as those that are inherent therein. The particular embodiments
disclosed above are
illustrative only, as the present invention may be modified and practiced in
different but
21
CA 02910988 2015-10-29
WO 2014/194031
PCT/US2014/039923
equivalent manners apparent to those skilled in the art having the benefit of
the teachings
herein. Furthermore, no limitations are intended to the details of
construction or design
herein shown, other than as described in the claims below. While systems and
methods are
described in terms of "comprising," "containing," or "including" various
components or
steps, the compositions and methods can also "consist essentially of' or
"consist of' the
various components and steps. Whenever a numerical range with a lower limit
and an
upper limit is disclosed, any number and any included range falling within the
range is
specifically disclosed. In particular, every range of values (of the form,
"from a to b," or,
equivalently, "from a-b") disclosed herein is to be understood to set forth
every number
and range encompassed within the broader range of values. Whenever a numerical
range
having a specific lower limit only, a specific upper limit only, or a specific
upper limit and
a specific lower limit is disclosed, the range also includes any numerical
value "about" the
specified lower limit and/or the specified upper limit. Also, the terms in the
claims have
their plain, ordinary meaning unless otherwise explicitly and clearly defined
by the
patentee. Moreover, the indefinite articles "a" or "an", as used in the
claims, are defined
herein to mean one or more than one of the element that it introduces.
22
