U.S. patent application number 14/518469 was filed with the patent office on 2015-04-23 for process for recovery of oil from an oil-bearing formation.
The applicant listed for this patent is SHELL OIL COMPANY. Invention is credited to Dirk Jacob LIGTHELM, Monica M. PINGO-ALAMADA, Julia Frances VAN WINDEN, Esther Christianne Maria VERMOLEN, Leonardus Bartholomeus Maria WASSING.
Application Number | 20150107840 14/518469 |
Document ID | / |
Family ID | 52825158 |
Filed Date | 2015-04-23 |
United States Patent
Application |
20150107840 |
Kind Code |
A1 |
LIGTHELM; Dirk Jacob ; et
al. |
April 23, 2015 |
PROCESS FOR RECOVERY OF OIL FROM AN OIL-BEARING FORMATION
Abstract
The present invention is directed to a process for producing
oil. The mass action ratio (MAR) of divalent cations to monovalent
cations of water from an oil-bearing formation is determined, and
an aqueous displacement fluid having a total dissolved solids
content of from 200 ppm to 5,000 ppm and a MAR of divalent cations
to monovalent cations of from 70% to 130% of the MAR of divalent
cations to monovalent cations of the formation water is introduced
into the formation. Oil is produced from the formation after
introducing the aqueous displacement fluid into the formation.
Inventors: |
LIGTHELM; Dirk Jacob;
(Rijswijk, NL) ; PINGO-ALAMADA; Monica M.;
(Rijswijk, NL) ; VERMOLEN; Esther Christianne Maria;
(Rijswijk, NL) ; VAN WINDEN; Julia Frances;
(Rijswijk, NL) ; WASSING; Leonardus Bartholomeus
Maria; (Rijswijk, NL) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
SHELL OIL COMPANY |
Houston |
TX |
US |
|
|
Family ID: |
52825158 |
Appl. No.: |
14/518469 |
Filed: |
October 20, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61894669 |
Oct 23, 2013 |
|
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|
Current U.S.
Class: |
166/305.1 |
Current CPC
Class: |
C09K 8/588 20130101;
E21B 43/162 20130101 |
Class at
Publication: |
166/305.1 |
International
Class: |
E21B 43/25 20060101
E21B043/25; E21B 47/00 20060101 E21B047/00 |
Claims
1. A process for producing oil from an oil-bearing formation,
comprising: determining the mass action ratio of divalent cations
to monovalent cations of water from the oil-bearing formation;
providing an aqueous displacement fluid comprising water and an
ionically charged polymer, wherein the water of the aqueous
displacement fluid has a total dissolved solids content of from 200
parts per million by weight (ppmw) to 5,000 ppmw and a mass action
ratio of divalent cations to monovalent cations from 70% to 130% of
the mass action ratio of divalent cations to monovalent cations of
the water from the oil-bearing formation; introducing the aqueous
displacement fluid into the oil-bearing formation to displace oil
within the formation; producing oil from the oil-bearing formation
subsequent to introducing the aqueous displacement fluid into the
formation.
2. The process of claim 1 further comprising the steps of:
determining the viscosity of oil of the oil-bearing formation at a
temperature within the range of temperatures in the formation;
providing the aqueous displacement fluid having a viscosity of from
10% to 500% of the viscosity of the oil of the oil-bearing
formation, where the viscosity of the aqueous displacement fluid is
determined at the temperature at which the viscosity of the oil of
the oil-bearing formation is determined.
3. The process of claim 2 wherein the ionic polymer of the aqueous
displacement fluid is mixed with the water of the aqueous
displacement fluid in an amount effective to increase the viscosity
of the water of the aqueous displacement fluid to a viscosity of
from 10% to 500% of the viscosity of the oil of the oil-bearing
formation.
4. The process of claim 1 wherein the ionically-charged polymer is
a water-dispersible polymer.
5. The process of claim 1 wherein the ionically-charged polymer is
a water soluble polymer.
6. The process of claim 1 wherein the ionically-charged polymer is
a selected from the group consisting of a water-soluble
polyacrylamide, a water-soluble polyacrylate, a partially
hydrolyzed water-soluble polyacrylamide, and mixtures thereof.
7. The process of claim 1 wherein the MAR of divalent cations to
monovalent cations of water of the oil-bearing formation is
determined by obtaining a sample of water from the oil-bearing
formation, measuring the concentrations of each divalent cation
species and each monovalent cation species in the water obtained
from the oil-bearing formation, and calculating the MAR of the
water obtained from the oil-bearing formation according to formula
(I) MAR.sub.fw=(C.sup.+.sub.(fw)).sup.2/C.sup.2+.sub.(fw)) (I)
where MAR.sub.fw is the mass action ratio of divalent cations to
monovalent cations of the water from the formation,
C.sup.+.sub.(fw) is the sum of the concentrations of the monovalent
cation species in the water from the formation, and
C.sup.2+.sub.(fw) is the sum of the concentrations of the divalent
cation species in the water from the formation.
8. The process of claim 1 wherein the water of the aqueous
displacement fluid is provided from a natural source water having a
TDS content of from 200 ppm to 5,000 ppm.
9. The process of claim 1 wherein the water of the aqueous
displacement fluid is provided from a saline source water having a
TDS content greater than 10,000 ppm wherein the saline source water
is treated to adjust the TDS content of the saline source water to
within a range of from 200 ppm to 5,000 ppm.
10. The process of claim 1 wherein the water of the aqueous
displacement fluid is provided from a source water having a TDS
content less than 500 ppm wherein the source water is treated to
adjust the TDS content of the source water to within a range of
from 500 ppm to 5,000 ppm.
11. The process of claim 1 wherein the water of the aqueous
displacement fluid is provided from a source water having a MAR of
divalent cations to monovalent cations that is from 70% to 130% of
the MAR of divalent cations to monovalent cations of the water of
the formation, where the MAR of the water of the aqueous
displacement fluid is calculated according to formula (II)
MAR.sub.adf=(C.sup.+.sub.(adf)).sup.2/C.sup.2+.sub.(adf)) (II)
where MAR.sub.adf is the mass action ratio of divalent cations to
monovalent cations of the water of the aqueous displacement fluid,
C.sup.+.sub.(adf) is the sum of concentrations of monovalent cation
species in the water of the aqueous displacement fluid, and
C.sup.2+.sub.(adf) is the sum of concentrations of divalent cation
species in the water of the aqueous displacement fluid.
12. The process of claim 1 wherein the water of the aqueous
displacement fluid is provided from a source water having a MAR of
divalent cations to monovalent cations that is less than 70% or
greater than 130% of the MAR of divalent cations to monovalent
cations of the water of the formation and the MAR of divalent
cations to monovalent cations of the source water is adjusted to a
range of from 70% to 130% of the MAR of divalent cations to
monovalent cations of the water of the formation, where the MAR of
the water of the aqueous displacement fluid is calculated according
to formula (II)
MAR.sub.adf=(C.sup.+.sub.(adf)).sup.2/C.sup.2+.sub.(adf)) (II)
where MAR.sub.adf is the mass action ratio of divalent cations to
monovalent cations of the water of the aqueous displacement fluid,
C.sup.+.sub.(adf) is the sum of concentrations of monovalent cation
species in the water of the aqueous displacement fluid, and
C.sup.2+.sub.(adf) is the sum of concentrations of divalent cation
species in the water of the aqueous displacement fluid.
13. The process of claim 1 further comprising producing water from
the oil-bearing formation along with oil from the oil-bearing
formation and separating the produced oil from the produced water.
Description
RELATED CASES
[0001] This application claims benefit of U.S. Provisional
Application No. 61/894,669, filed on Oct. 23, 2013, which is
incorporated herein by reference.
FIELD OF THE INVENTION
[0002] The present invention is directed to a process for recovery
of oil from an oil-bearing formation. In particular, the present
invention is directed to a process for recovering oil from an
oil-bearing formation with a polymer-containing fluid.
BACKGROUND OF THE INVENTION
[0003] Only a portion of oil present in an oil-bearing formation is
recoverable as a result of the natural pressure of the formation.
The oil recovered from this "primary" recovery typically ranges
from 5% to 35% of the oil in the formation. Enhanced oil recovery
methods have been developed to increase the amount of oil that may
be recovered from an oil-bearing formation above and beyond that
recovered in primary recovery.
[0004] Water-flooding, in which water is injected through an
injection well into an oil-bearing formation to mobilize and drive
oil through the formation for production from a production well, is
a widely used method of secondary recovery used to increase the
amount of oil recovered from a formation beyond primary recovery.
The amount of oil produced by water-flooding may be reduced by
water fingering through the oil in the formation due in part to
viscosity differences between the injected water and oil in the
formation rendering water more mobile than oil in the formation.
Oil by-passed by water fingering is left in place in the formation
and is typically not recovered by further water-flooding since
additional water injected into the formation follows the path of
the initial water through the formation.
[0005] Water-soluble polymer has been added to water injected into
an oil-bearing formation to increase the viscosity of the water and
decrease the viscosity difference between the injected water and
oil in the formation, improving the water-to-oil mobility ratio and
thereby reducing water fingering through the oil. This improves the
sweep efficiency of the water in the formation and increases oil
recovery. The aqueous polymer mixture may drive through the
formation in a plug-like flow to mobilize the oil in the formation
for production with reduced fingering of the aqueous drive solution
through the oil relative to water without polymer.
[0006] Ionically charged water-soluble polymers have been utilized
with low salinity water, where "low salinity" water has a total
dissolved solids ("TDS") content of 15,000 ppm or less, to produce
an aqueous polymer mixture for use in recovering oil from an
oil-bearing formation. Use of an ionically charged water-soluble
polymer with low salinity water provides a substantial viscosity
increase to the water with a minimum quantity of polymer so that a
given polymer concentration will provide a higher aqueous phase
viscosity as the salinity of the aqueous phase is reduced.
[0007] The viscosity of an aqueous polymer mixture, however, may be
changed upon introduction of the mixture into an oil-bearing
formation as a result of ion exchange, particularly divalent ion
exchange, between the aqueous polymer mixture, the rock (minerals
and clays) of the formation, and formation water due to differences
in ion concentration, particularly divalent cation concentration,
between the aqueous polymer mixture, the rock of the formation, and
the formation water. Ion exchange between the formation water and
the aqueous polymer mixture occurs upon mixing as the ionic
concentration of the mixture of formation water and aqueous polymer
mixture equilibrates--and may result in an increase in total cation
and divalent cation concentration in the aqueous environment of the
polymer as the aqueous polymer mixture is mixed with formation
water having a higher TDS content than the low salinity water of
the aqueous polymer mixture. Ion exchange between the aqueous
polymer mixture and the rock of the formation may result in
divalent cations being stripped from the aqueous polymer mixture
when the water of the aqueous polymer mixture has a lower TDS
content than the formation water.
[0008] The viscosity of the aqueous polymer mixture may be reduced
upon mixing with the formation water if the formation water has a
divalent cation concentration that is greater than the divalent
cation concentration of the aqueous polymer mixture, thereby
altering the mobility ratio of the aqueous polymer mixture to oil
in the formation and potentially reducing the effectiveness of the
aqueous polymer mixture to inhibit fingering of the mixture through
oil in the formation. Furthermore, formation water having a greater
divalent cation content relative to the aqueous polymer mixture may
precipitate polymer from the mixture due to the affinity of the
polymer for divalent cations, potentially reducing permeability of
the formation. The viscosity of the aqueous polymer mixture may be
increased if the formation water has a divalent cation content less
than that of the aqueous polymer mixture and/or if a significant
amount of divalent cations are stripped from the aqueous polymer
mixture by ion exchange with the formation rock, potentially
inhibiting flow of the mixture through the formation. Furthermore,
formation damage and clay swelling may be induced by contact of the
aqueous polymer mixture with formation water having a higher
divalent cation content relative to the aqueous polymer mixture
since the aqueous polymer mixture may strip divalent cations from
the formation and formation water due to the affinity of the
polymer for divalent cations, inducing clay deflocculation.
Improved processes are desirable for maintaining the viscosity of
aqueous polymer mixtures introduced into an oil-bearing formation
to produce oil from the formation.
SUMMARY OF THE INVENTION
[0009] The present invention is directed to a process for producing
oil from an oil-bearing formation comprising: [0010] determining
the mass action ratio of divalent cations relative to monovalent
cations of water from the oil-bearing formation, where the mass
action ratio of divalent cations relative to monovalent cations of
the water from the oil-bearing formation is defined by formula
(I)
[0010] MAR.sub.fw=[C.sup.+.sub.(fw)].sup.2/C.sup.2+.sub.(fw) (I)
[0011] where MAR.sub.fw is the mass action ratio of divalent cation
to monovalent cations of the [0012] formation water,
C.sup.+.sub.(fw) is the concentration of monovalent ions in the
formation water, [0013] and C.sup.2+.sub.(fw) is the concentration
of divalent cations in the formation water; [0014] providing an
aqueous displacement fluid comprising water and an ionically
charged polymer, wherein the water of the aqueous displacement
fluid has a total dissolved solids content of from 200 parts per
million by weight (ppmw) to 5,000 ppmw and a mass action ratio of
divalent cations relative to monovalent cations from 70% to 130% of
the MAR.sub.fw, where the mass action ratio of the divalent cations
to monovalent cations of the water of the aqueous displacement
fluid is defined by formula (II)
[0014] MAR.sub.adf=[C.sup.+.sub.(adf)].sup.2/C.sup.2+.sub.(adf)
(II) [0015] where MAR.sub.adf is the mass action ratio of divalent
cation to monovalent cations of the [0016] aqueous displacement
fluid, C.sup.+.sub.(adf) is the concentration of monovalent ions in
the aqueous displacement fluid, and C.sup.2+.sub.(adf) is the
concentration of divalent cations in the aqueous displacement
fluid; [0017] introducing the aqueous displacement fluid into the
oil-bearing formation to displace oil within the formation; [0018]
producing oil from the oil-bearing formation subsequent to
introducing the aqueous displacement fluid into the formation.
BRIEF DESCRIPTION OF THE DRAWINGS
[0019] FIG. 1 is a diagram of an ionic filter that may be used in
the process of the present invention.
[0020] FIG. 2 is a diagram of an ionic filter that may be used in
the process of the present invention.
[0021] FIG. 3 is a diagram of an ionic filter that may be used in
the process of the present invention.
[0022] FIG. 4 is a diagram of an oil-production and separation
system that may be used in the process of the present
invention.
[0023] FIG. 5 is a diagram of a well pattern for production of oil
than may be used in the process of the present invention.
[0024] FIG. 6 is a graph showing the sodium and calcium
concentrations in effluents of a synthetic formation brine, a
designed low salinity water solution, a high salinity polymer
solution, and a designed low salinity water solution injected into
an oil-bearing core.
[0025] FIG. 7 is a graph showing the magnesium and potassium
concentrations in effluents of a synthetic formation brine, a
designed low salinity water solution, a high salinity polymer
solution, and a designed low salinity water solution injected into
an oil-bearing core.
[0026] FIG. 8 is a graph showing the viscosity of effluents of a
high salinity polymer solution and a designed low salinity polymer
solution injected into an oil-bearing core.
DETAILED DESCRIPTION OF THE INVENTION
[0027] The present invention is directed to a process in which an
aqueous displacement fluid comprising water having a total
dissolved solids ("TDS") content of from 200 ppm to 5,000 ppm and
an ionically charged water-dispersable polymer is introduced into
an oil-bearing formation comprising oil and water, and the
viscosity of the aqueous displacement fluid is maintained upon
contact with the formation and the water in the formation. The
viscosity of the aqueous displacement fluid may be selected or
designed to be compatible in terms of mobility with the oil in the
formation at formation temperature conditions so that the aqueous
displacement fluid may drive mobilized oil through the formation in
substantially plug-like flow without substantial fingering of the
aqueous displacement fluid through the oil or oil through the
aqueous displacement fluid. The viscosity of the aqueous
displacement fluid may be a function of the type and concentration
of polymer in the aqueous displacement fluid and the divalent
cation concentration of the aqueous displacement fluid--where the
divalent cation concentration may affect the viscosity of the
aqueous displacement fluid by its effect on the ionically charged
polymer. Prior to introducing the aqueous displacement fluid into
the formation, the ionic polymer species and the divalent cationic
content of the aqueous displacement fluid may be selected or
designed to provide the aqueous displacement fluid with a viscosity
effective to provide the aqueous displacement fluid with a mobility
effective to enable the aqueous displacement fluid to drive
mobilized oil in the formation in a substantially plug-like flow at
formation temperature conditions.
[0028] In the process of the present invention, the viscosity and
relative mobility of the aqueous displacement fluid may be
maintained upon introduction of the aqueous displacement fluid into
the oil-bearing formation and contact with formation water and
formation clays, rocks, and/or minerals by selecting or designing
the ionic content of the aqueous displacement fluid such that the
mass action ratio ("MAR") of divalent cations to monovalent cations
of the aqueous displacement fluid is comparable to, or
insubstantially different from, the MAR of divalent cations to
monovalent cations of the formation water and the formation rock.
As used herein, the MAR of divalent cations to monovalent cations
of the aqueous displacement fluid or the water in the formation or
the formation rock is defined as the ratio of the sum of the
concentrations of monovalent cations squared to the sum of the
concentrations of divalent cations in the aqueous displacement
fluid or the formation water or the formation rock, or
MAR=(C.sup.+).sup.2/(C.sup.2+), where C.sup.+ is the sum of the
concentration of all monovalent cation species in milliequivalents
per liter, and C.sup.2+ is the sum of the concentration of all
divalent cation species in milliequivalents per liter--the
definition utilizes a sum of concentrations rather than a
conventional product of concentrations to simplify the calculation
on the assumption that monovalent cations will react similarly (e.g
as a species, compared to divalent cations) and divalent cations
will react similarly (e.g. as a species, compared to monovalent
cations). When used herein "MAR" refers to the MAR of divalent
cations to monovalent cations. When the aqueous displacement fluid
has a MAR that is comparable to the formation water MAR and the
formation rock MAR (which are similar since the cation exchange
between the formation water and formation rock is in a state of
equilibrium), little change in the divalent cation to monovalent
cation ratio occurs within the aqueous displacement fluid, the
formation water, and the formation rock when the aqueous
displacement fluid is contacted with the formation water and the
formation rock. As a result, the viscosity of the aqueous
displacement fluid is not increased or reduced as a result of a
change in the divalent cation to monovalent cation ratio as the
aqueous displacement fluid is contacted with the formation and the
formation water, and the viscosity of the aqueous displacement
fluid may be maintained at or near an optimal viscosity for
inhibiting fingering of the aqueous displacement fluid through oil
in the formation or vice versa as the aqueous displacement fluid is
utilized to mobilize and force oil through the formation for
production from the formation.
[0029] The process of the present invention involves determining
the MAR of water from an oil-bearing formation, providing an
aqueous displacement fluid comprising water and an ionically
charged polymer, where the water of the aqueous displacement fluid
has a total dissolved solids ("TDS") content of from 200 parts per
million by weight (ppmw) to 5,000 ppmw and a MAR from 70% to 130%
of the MAR of the water from the formation; introducing the aqueous
displacement fluid into the oil-bearing formation to displace oil
within the formation; and producing oil from the formation
subsequent to introducing the aqueous displacement fluid into the
formation. The MAR of the formation water is defined herein by
formula (I):
MAR.sub.fw=(C.sup.+.sub.(fw)).sup.2/C.sup.2+.sub.(fw)) (I)
where MAR.sub.fw is the mass action ratio of divalent cation to
monovalent cations of the formation water, C.sub.(fw) is the sum of
the concentrations of monovalent cations in milliequivalents per
liter in the formation water and C.sup.2+.sub.(fw) is the sum of
the concentrations of divalent cations in milliequivalents per
liter in the formation water. The MAR of the aqueous displacement
fluid is defined herein by formula (II):
MAR.sub.adf=(C.sup.+.sub.(adf)).sup.2/C.sup.2+.sub.(adf)) (II)
where MAR.sub.adf is the mass action ratio of divalent cations to
monovalent cations of the water of the aqueous displacement fluid,
C.sup.+.sub.(adf) is the sum of the concentrations of monovalent
cations in milliequivalents per liter in the aqueous displacement
fluid, and C.sup.2+.sub.(adf) is the sum of the concentrations of
divalent cations in milliequivalent per liter in the aqueous
displacement fluid. The process of the present invention may
further involve determining the viscosity of oil in the formation
and providing an aqueous displacement fluid having a viscosity of
from 10% to 500% of the viscosity of the oil in the formation,
where the viscosity of the aqueous displacement fluid and the oil
may be determined at a temperature within a range of temperatures
in the formation.
[0030] The MAR of divalent cations to monovalent cations of water
from the oil-bearing formation may be determined by obtaining a
sample of water from the oil bearing formation, measuring the
concentrations of each divalent cation species and each monovalent
cation species in the formation water, and calculating the
formation water MAR.sub.(fw) according to formula (I) above.
Samples of water from the oil-bearing formation may be obtained in
accordance with conventional methods known to those skilled in the
art of producing oil. For example, formation water may be obtained
by drawing fluids from a formation through a well and separating
the formation water from other produced fluids such as oil. The
divalent cation concentration of divalent cation species and the
monovalent ion concentration of monovalent cation species in the
formation water sample may be determined in accordance with
conventional methods known to those in the art of analytical
chemistry.
[0031] After determining the MAR of the formation water, an aqueous
displacement fluid comprised of water and a water dispersable ionic
polymer is provided having a TDS content of 200 ppm to 5,000 ppm
and a MAR from 70% to 130% of the MAR of the formation water. The
water of the aqueous displacement fluid may be provided from
natural source water having a TDS content of from 200 ppm to 5,000
ppm and a MAR of from 70% to 130% of the MAR of the formation
water. Alternatively, the water of the aqueous displacement fluid
may be provided from a source water having a TDS content outside of
the range of from 200 ppm to 5,000 ppm and/or having a MAR of less
than 70% or greater than 130% of the MAR of the formation water,
wherein the source water is treated to adjust the TDS content to
within a range of from 200 ppm to 5,000 ppm, or is treated to
adjust the MAR to a MAR of from 70% to 130% of the MAR of the
formation water, or is treated to adjust the TDS content to within
a range of 200 ppm to 5,000 ppm and to adjust the MAR to a MAR of
from 70% to 130% of the MAR of the formation water.
[0032] The water of the aqueous displacement fluid may be provided
from a source water having a TDS content of from 200 ppm to 5,000
ppm, or may be provided from a source water having a TDS content of
less than 200 ppm or greater than 5,000 ppm that is treated to
condition the water to have a TDS content of from 200 ppm to 5,000
ppm. The water of the aqueous displacement fluid may be provided
from a low salinity natural source water such as an aquifer, a
lake, water produced from the oil-bearing formation, or a river
comprising water containing from 200 ppm to 5,000 ppm total
dissolved solids, where the source water may be utilized as the
water of the aqueous displacement fluid without processing to
adjust the TDS content of the source water.
[0033] In another embodiment, the water of the aqueous displacement
fluid may be provided by processing water from a low salinity
natural source water such as an aquifer, a lake, or a river or from
water produced from an oil-bearing formation wherein the water from
the natural source or the oil-bearing formation has a TDS content
of from 0 ppm to less than 200 ppm. The TDS content of the water
having a TDS content of from 0 ppm to less than 200 ppm may be
adjusted to 200 ppm to 5,000 ppm by adding one or more water
soluble salts, for example NaCl and/or CaCl.sub.2, to the water.
The one or more water soluble salts may be added to the source
water as an aqueous solution of the salt(s), or may be added to the
source water in solid form.
[0034] In another embodiment, the water of the aqueous displacement
fluid, or at least a portion thereof, may be provided by processing
a saline source water. The saline source water to be processed may
have a TDS content of greater than 10,000 ppm, or at least 20,000
ppm, or at least 25,000 ppm, or at least 30,000 ppm, or at least
35,000 ppm, or at least 40,000 ppm, or at least 50,000 ppm, or from
15,000 ppm to 250,000 ppm, or from 20,000 ppm to 200,000 ppm, or
from 25,000 ppm to 150,000 ppm, or from 30,000 ppm to 100,000 ppm,
or from 35,000 ppm to 50,000 ppm. The saline source water to be
processed to provide the water of the aqueous displacement fluid
may be selected from the group consisting of aquifer water,
seawater, brackish water, estuarine water, water produced from the
oil-bearing formation, and mixtures thereof.
[0035] Referring now to FIG. 1, a saline source water having a TDS
content of greater than 10,000 ppm as described above may be
processed to produce at least a portion of the water of the aqueous
displacement fluid by contacting the saline source water 111 with
an ionic filter 113, where the mechanism for processing the saline
source water may comprise the ionic filter. A portion of the source
water 111 may be passed through the ionic filter 113 to form
treated water 115 having reduced salinity relative to the source
water 111, wherein the treated water may have a TDS content of up
to 5,000 ppm, and more preferably of from 200 ppm to 5,000 ppm, and
most preferably from 500 ppm to 4,000 ppm. At least a portion of
the treated water 115 may be utilized as at least a portion of the
water of the aqueous displacement fluid.
[0036] A portion of the source water 111 may be excluded from
passing through the ionic filter 113 to form a brine retentate 117
having increased salinity relative to the source water. The brine
retentate may have a TDS content of at least 20,000 ppm, or from
25,000 ppm to 300,000 ppm. At least a portion of the brine
retentate may be utilized as described in further detail below.
[0037] If the treated water has a MAR that is greater than 130% or
less than 70% of the MAR of the formation water, the treated water
may be adjusted so the treated water has a MAR that is from 70% to
130% of the MAR of the formation water. Monovalent
cation-containing salts, or aqueous solutions thereof, or divalent
cation-containing salts, or aqueous solutions thereof, may be
utilized to adjust the MAR of the treated water upwards or
downwards to adjust the MAR of the treated water to within 70% to
130% of the MAR of the formation water. If necessary, at least a
portion of the brine retentate 117 may be added to the treated
water 115 to adjust the MAR of the treated water to within 70% to
130% of the MAR of the formation water. At least a portion of the
MAR adjusted treated water may be utilized as the water of the
aqueous displacement fluid.
[0038] The ionic filter 113 may be a membrane based system
utilizing ionic separation membrane units selected from the group
consisting of a nanofiltration membrane unit, a reverse osmosis
membrane unit, and combinations thereof. A nanofiltration membrane
unit may be comprised of one or more nanofiltration membranes
effective for preferentially or selectively removing multivalent
ions, including divalent cations, from the source water so the
treated water may contain less than 80%, or less the 90%, or less
than 95% multivalent ions and/or divalent cations than the source
water fed to the nanofiltration membrane(s), and the retentate may
contain a corresponding increase of multivalent ions and/or
divalent cations relative to the source water. The one or more
nanofiltration membranes of a nanofiltration membrane unit may also
moderately reduce the monovalent ion content of source water fed to
the nanofiltration membrane(s), where the treated water may contain
less than 20%, or less than 30%, or less than 50%, or less than 70%
of monovalent ions than the source water fed to the nanofiltration
membrane(s), and the brine retentate may contain a corresponding
increase of monovalent ions relative to the source water.
Nanofiltration membranes may be formed of charged polymeric
materials (e.g. having carboxylic acid, sulfonic acid, amine, or
amide functional groups) including polyamides, cellulose acetate,
piperazine, or substituted piperazine membranes in which a thin ion
discriminating layer of membrane is supported on a thicker porous
material, which is sandwiched between the discriminating layer and
a backing material. Suitable commercially available nanofiltration
membranes in sheet form or in spirally wound form that may be
utilized in a nanofiltration membrane unit in the ionic filter 13
include, but are not limited to, SEASOFT 8040DK, 8040DL, and SEASAL
DS-5 available from GE Osmonics, Inc., 5951 Clearwater Drive,
Minnetonka, Minn. 55343, United States; NF200 Series, and NF-55,
NF-70, and NF-90 available from Dow FilmTec Corp., 5239 W.
73.sup.rd St., Minneapolis, Minn., 55345, United States; DS-5 and
DS-51 available from Desalination Systems, Inc., 760 Shadowridge
Dr., Vista, Calif., 92083, United States; ESNA-400 available from
Hydranautics, 401 Jones Road, Oceanside, Calif. 92508, United
States; and TFCS available from Fluid Systems, Inc., 16619 Aldine
Westfield Road, Houston, Tex. 77032, United States.
[0039] A reverse osmosis membrane unit useful in the ionic filter
113 may be comprised of one or more reverse osmosis membranes
effective for removing substantially all ions, including monovalent
ions, from the source water so the treated water may contain less
than 85%, or less than 90%, or less than 95%, or less than 98% ions
than the source water fed to the reverse osmosis membrane(s), and
the brine retentate may contain a corresponding increase of ions
relative to the source water. Reverse osmosis membranes may be
spirally wound or hollow fiber modules, and may be asymmetric
membranes prepared from a single polymeric material, such as
asymmetric cellulose acetate membranes, or thin-film composite
membranes prepared from a first and a second polymeric material,
such as cross-linked aromatic polyamides in combination with a
polysulfone. Suitable commercially available reverse osmosis
membranes that may be utilized in a reverse osmosis membrane unit
in the ionic filter 113 include, but are not limited to, AG8040F
and AG8040-400 available from GE Osmonics; SW30 Series and LF
available from Dow FilmTec Corp.; DESAL-11 available from
Desalination Systems, Inc.; ESPA available from Hydranautics; ULP
available from Fluid Systems, Inc.; and ACM available from TriSep
Corp., 93 S. La Patera Lane, Goleta, Calif. 93117, United
States.
[0040] Typically, pressure must be applied across the ionic filter
113 to overcome osmotic pressure across the membrane when saline
source water 111 is filtered to reduce the TDS content of the
source water and produce the treated water 115. The pressure
applied across the ionic filter 113 may be at least 2.0 MPa, or at
least 3.0 MPa, or at least 4.0 MPa, and may be at most 10.0 MPa, or
at most 9.0 MPa, or at most 8.0 MPa, and may range from 2.0 MPa to
10.0 MPa, or from 3.0 MPa to 9.0 MPa. The pressure applied across a
nanofiltration membrane in the ionic filter 113 may be in the lower
portion of the pressure range relative to the pressure applied
across a reverse osmosis membrane. The pressure applied across a
nanofiltration membrane unit of the ionic filter 113 may range from
2.0 MPa to 6.0 MPa, and the pressure applied across a reverse
osmosis membrane unit of the ionic filter 113 may range from 4.0
MPa to 10.0 MPa. If the ionic filter 113 is comprised of membrane
units either nanofiltration, reverse osmosis, or both combined in a
series, the pressure applied across each membrane of the membrane
unit may be less than the previous membrane unit by at least 0.5
MPa as less pressure is required to overcome the osmotic pressure
of the permeate of a preceding membrane unit.
[0041] Referring now to FIG. 2, the ionic filter 113 may be
comprised of a first ionic membrane unit 119 and one or more second
ionic membrane units 121 arranged in series, wherein each ionic
membrane unit may be a nanofiltration membrane unit or a reverse
osmosis membrane unit. The saline source water 111 having a TDS
content of greater than greater than 10,000 ppm as described above
may be contacted with the first ionic membrane unit 119 to pass at
least a portion of the saline source water through the first ionic
membrane unit to form a permeate 123 having a reduced TDS content
relative to the saline source water, wherein the permeate may have
a TDS content of at least 1,000 ppm, or at least 2,500 ppm, or at
least 5,000 ppm, or at least 7,000 ppm, or at least 10,000 ppm, or
at least 15,000 ppm. A portion of the saline source water may be
excluded from passing through the first ionic membrane unit 119 to
form a primary brine retentate 125 having increased salinity
relative to the source water. The permeate 123 may be contacted
with each of the second ionic membrane units 121 in sequence to
pass at least a portion of the permeate through each of the second
ionic membrane units to form treated water 115 having reduced
salinity relative to the permeate 123 and the saline source water
111, wherein the treated water may have a TDS content of from 200
ppm to 5,000 ppm. At least a portion of the treated water 115 may
be utilized as at least a portion of the water of the aqueous
displacement fluid.
[0042] A portion of the permeate 123 may be excluded from passing
through each of the one or more second ionic membrane units 121 to
form one or more secondary brine retentates 127. The primary brine
retentate 125, one or more of the secondary brine retentates 127,
or a combination of the primary brine retentate 125 and one or more
of the secondary brine retentates 127 may form the brine retentate
117 from the ionic filter 113, where the brine retentate 117 has an
increased salinity relative to the source water 111 and may have a
TDS content of at least 20,000 ppm, or from 25,000 ppm to 300,000
ppm. At least a portion of the brine retentate 117 formed of the
primary brine retentate 125, one or more of the secondary brine
retentates 127, or a combination thereof may be utilized as
described in further detail below.
[0043] Referring now to FIG. 3, the ionic filter 113 may be
comprised of a first ionic membrane unit 129 and a second ionic
membrane unit 131 arranged in parallel, wherein the first ionic
membrane unit may be comprised of one or more nanofiltration
membranes or one or more reverse osmosis membranes, or a
combination thereof, and the second ionic membrane unit may be
comprised of one or more nanofiltration membranes, one or more
reverse osmosis membranes, or a combination thereof. A first
portion 133 of the saline source water 111 as described above may
be contacted with the first ionic membrane unit 129 and a portion
of the first portion of the saline source water 133 may be passed
through the first ionic membrane unit 129 to form a first permeate
135 having reduced TDS content relative to the saline source water
111. The first permeate 135 may have a TDS content of less than
10,000 ppm, or less than 7,500 ppm, or less than 6,000 ppm, or less
than 5,000 ppm, or from 200 ppm to 5,000 ppm. A portion of the
first portion of the saline source water 133 may be excluded from
passing through the first ionic membrane unit 129 to form a first
brine retentate 137 having a TDS content greater than the saline
source water 111. The first brine retentate 137 may have a TDS
content of at least 20,000 ppm, or at least 25,000 ppm, or at least
30,000 ppm, or at least 35,000 ppm, or at least 40,000 ppm, or at
least 50,000 ppm. A second portion 139 of the saline source water
111 may be contacted with the second ionic membrane unit 131, and a
portion of the second portion of the saline source water 139 may be
passed through the second ionic membrane unit 131 to form a second
permeate 141 having reduced TDS content relative to the saline
source water 111. The second permeate may have a TDS content of
less than 10,000 ppm, or less than 7,500 ppm, or less than 5,000
ppm, or from 200 ppm to 5,000 ppm. A portion of the second portion
of the saline source water 139 may be excluded from passing through
the second ionic membrane unit 131 to form a second brine retentate
143 having a TDS content of at least 20,000 ppm, or at least 25,000
ppm, or at least 30,000 ppm, or at least 25,000 ppm, or at least
40,000 ppm, or at least 50,000 ppm. At least a portion of the first
and second permeates 135 and 141 may be combined to form the
treated water 115 having a TDS content of up to 5,000 ppm, or less
than 40,000 ppm, or from 200 ppm to 5,000 ppm, where at least a
portion of the treated water 115 may be used as the water of the
aqueous displacement fluid. The first brine retentate 137, a
portion thereof, the second brine retentate 143, a portion thereof,
a combination of the first brine retentate 137 and the second brine
retentate 143, or a combination of portions thereof, may form the
brine retentate 117 which may be utilized as described in further
detail below.
[0044] In an embodiment, the first ionic membrane unit 129 may
consist of one or more nanofiltration membranes and the second
ionic membrane unit 131 may consist of one or more reverse osmosis
membranes. The second permeate 141 passed through the second ionic
membrane unit 131 may have a TDS content of less than 200 ppm
provided the one or more reverse osmosis membranes of the second
ionic membrane unit 131 remove substantially all of the total
dissolved solids from the saline source water 111. The first
permeate 135 passed through nanofiltration membranes may have
sufficient monovalent ions therein to have a TDS content of at
least 200 ppm, or at least 1,000 ppm, or at least 2,000 ppm, so
that the combined first and second permeates form the treated water
115 having a TDS content of from 200 ppm to 5,000 ppm.
[0045] Referring now to FIGS. 1, 2, and 3, if the treated water 115
has a TDS content of less than 200 ppm, the TDS content of the
treated water may be adjusted so the treated water has a TDS
content to a range of from 200 ppm to 5,000 ppm. A portion of the
brine retentate 117 may be added to the treated water 115 to adjust
the TDS content from below 200 ppm to a range of from 200 ppm to
5,000 ppm. Alternatively, one or more salts or aqueous salt
solutions, for example NaCl and/or CaCl.sub.2 salts or aqueous salt
solutions, may be added to the treated water 115 to adjust the TDS
content of the treated water to a range of from 200 ppm to 5,000
ppm. At least a portion of the resulting TDS adjusted treated water
may be utilized as the water of the aqueous displacement fluid.
[0046] The water of the aqueous displacement fluid also has a MAR
of from 70% to 130% of MAR of the formation water. The water of the
aqueous displacement fluid may be selected from a water source
having a MAR of from 70% to 130% of the MAR of the formation water
or water from a water source may be treated so the water has a MAR
of from 70% to 130% of the MAR of the formation water. The water
source may be treated water from a source water that has been
treated to adjust the TDS content of the water to a range from 200
ppm to 5,000 ppm as described above. In one embodiment of the
process of the present invention, water from a low salinity natural
source water or from a saline source water as described above is
treated to adjust the TDS content of the water to a range of from
200 ppm to 5,000 ppm, then the TDS adjusted treated water is
treated to adjust the MAR of the TDS adjusted treated water to
within 70% to 130% of the MAR of the formation water while
maintaining the TDS content of the MAR adjusted water in a range of
from 200 ppm to 5,000 ppm. In another embodiment, the MAR of water
from a low salinity natural source water or a saline source water
as described above is treated to adjust the MAR of the water to a
range of from 70% to 130% of the formation water, then the MAR
adjusted water is treated to adjust the TDS content of the MAR
adjusted water to a range of from 200 ppm to 5,000 ppm as described
above while maintaining the MAR of the water within 70% to 130% of
the MAR of the formation water. In another embodiment, the MAR of
water from a low salinity natural source water having a TDS content
of from 200 ppm to 5,000 ppm as described above is treated to
adjust the MAR of the water to within 70% to 130% of the MAR of the
formation water while maintaining the TDS content of the water in a
range of from 200 ppm to 5,000 ppm. In another embodiment, the TDS
content of water from a low salinity natural source water or a
saline source water having a MAR of from 70% to 130% of the MAR of
the formation water is treated to adjust the TDS content to a range
of from 200 ppm to 5,000 ppm while maintaining the MAR ratio of the
water in a range of from 70% to 130% of the formation water. In
another embodiment, the water of the aqueous displacement fluid may
be selected from a source water having a TDS content of from 200
ppm to 5,000 ppm and a MAR in a range of from 70% to 130% of the
MAR of the formation water.
[0047] The MAR of divalent cations to monovalent cations of water
from a source water for use in the aqueous displacement fluid may
be determined by measuring the concentrations of each divalent
cation species and each monovalent cation species in the water, and
calculating the water MAR.sub.(adf) according to formula (II)
above. The divalent cation concentration of divalent cation species
and the monovalent ion concentration of monovalent cation species
in the water may be determined in accordance with conventional
methods known to those in the art of analytical chemistry.
[0048] The MAR of the water for use in the aqueous displacement
fluid may be adjusted, if necessary, by 1) calculating the amount
of monovalent cations and/or divalent cations required to adjust
the MAR of the water to be used in the aqueous displacement fluid
to an MAR in a range of from 70% to 130% of the measured MAR of the
formation water; and 2) adding or removing the calculated amount of
monovalent cations and/or divalent cations to the water to adjust
the MAR of the water to a range of from 70% to 130% of the MAR of
the formation water.
[0049] Monovalent cations and/or divalent cations may be added to
the water to be used in the aqueous displacement fluid to adjust
the MAR of divalent cations to monovalent cations of the water to a
range of from 70% to 130% of the MAR of the formation water.
Monovalent cations and/or divalent cations may be added to the
water by adding a selected amount of one or more selected
monovalent cation salts and/or one or more selected divalent cation
salts, or adding an aqueous solution of a selected amount of one or
more monovalent cation salts and/or one or more selected divalent
cation salts. In one embodiment of the process of the present
invention, one or more brine retentates 117, 125, 127, 137, or 143
produced in the treatment of water to reduce the TDS content of the
water as described above may be added to water to adjust the MAR of
the water to a range of from 70% to 130% of the formation
water.
[0050] Monovalent cations and/or divalent cations may be removed
from the water to be used in the aqueous displacement fluid to
adjust the MAR of divalent cations to monovalent cations of the
water to a range of from 70% to 130% of the formation water.
Divalent cations may be removed from the water preferentially
relative to monovalent cations by passing the water through a
nanofiltration membrane as described above. Monovalent cations may
be removed from the water preferentially relative to divalent
cations by passing the water through an ion exchange column packed
with an ion exchange material selective for adsorbing monovalent
cations.
[0051] The aqueous displacement fluid also comprises a
water-dispersible, preferably water-soluble, ionic polymer that is
dispersed in the water described above. After selection or
production of water having a TDS content of from 200 ppm to 5,000
ppm and a MAR of divalent cations to monovalent cations that is
from 70% to 130% of the MAR of divalent cations to monovalent
cations of the formation water, the ionically charged polymer is
mixed with the water to increase the viscosity thereof and to
produce the aqueous displacement fluid. The ionically charged
polymer may be added in an amount effective to increase the
viscosity of the treated water to within 10% to 500% of the
viscosity of oil within the oil-bearing formation as measured at a
temperature within the temperature range in the oil-bearing
formation. The ionic ally charged polymer may be added in an amount
effective to reduce the mobility of the treated water relative to
the mobility of oil in place in the formation, preferably so that
the mobility ratio of the resulting aqueous displacement fluid
relative to oil in the oil-bearing formation is from 0.2 to 5.
[0052] The polymer that is mixed with the water to form the aqueous
displacement fluid may be any ionically charged polymer usable in
an enhanced oil recovery application, where the polymer is soluble
or uniformly dispersable in the water. The polymer may be a
homopolymer or a heteropolymer comprised of two or more monomeric
units. The ratio of monomeric units of a heteropolymer to be mixed
with the treated water may be selected to provide the aqueous
displacement fluid with a selected viscosity in accordance with
conventional knowledge in the art of mixing water-soluble or
water-dispersable polymers in water. The polymer may be a
water-soluble polyacrylamide or polyacrylate. The polymer may be a
partially hydrolyzed polymer. A partially hydrolyzed polymer for
mixing in the treated water may have a degree of hydrolysis of from
0.1 to 0.4, or from 0.2 to 0.3. A preferred polymer for use in the
aqueous displacement fluid is a partially hydrolyzed polyacrylamide
having a degree of hydrolysis of from 0.15 to 0.4, preferably from
0.2 to 0.35. Preferred polymers for use in the aqueous displacement
fluid are commercially available partially hydrolyzed
polyacrylamides sold under the trade name of FLOPAAM.TM. by SNF
SAS, particularly FLOPAAM.TM. 3330 and FLOPAAM.TM. 3630.
[0053] The polymer and the water of the aqueous displacement fluid
may be mixed by adding the polymer to the water, or adding the
water to the polymer, and mixing utilizing any conventional
mechanism for mixing water and a water-soluble or water-dispersable
polymer. The polymer and the water may be mixed to form the aqueous
displacement fluid by agitating the polymer and the water in a
stirred tank. Excessive shear should be avoided when mixing the
polymer and the water to inhibit mechanical reduction of the size
of the polymer molecules.
[0054] The polymer may be provided for mixing with the water in a
solid powder form or in a concentrated aqueous solution containing
from 5 wt. % to 25 wt. % of the polymer. If the polymer is provided
for mixing in a solid powder form, the water and polymer should be
mixed for a sufficient time to allow for hydration of the
polymer.
[0055] The amount of polymer mixed with the water to form the
aqueous displacement fluid may be selected to provide the aqueous
displacement fluid formed with a selected viscosity relative to oil
in place in the oil-bearing formation in which the aqueous
displacement fluid is to be introduced. The viscosity of a polymer
solution is a function of the polymer, its molecular weight, the
degree of hydrolysis of the polymer, the salinity of the polymer
solution, the pH of the solution, the temperature of the solution,
the shear rate, and the concentration of the polymer in the
solution. The amount of polymer mixed with the water may be
selected to provide the aqueous displacement fluid with a selected
viscosity since the polymer, its molecular weight, its degree of
hydrolysis, the salinity and pH of the water of the aqueous
displacement fluid, and the temperature of the aqueous displacement
fluid (relative to the formation temperature) are fixed and the
shear rate may be held constant by controlling the pressure at
which the aqueous displacement fluid is injected into the
formation. The selected viscosity may be from 10% to 500%, or from
40% to 400% of the viscosity of the oil in place in the oil-bearing
formation as determined at formation temperature conditions. The
viscosity of the oil in place in the formation at formation
temperature conditions may be determined in accordance with
conventional methods within the art. The selected viscosity of the
aqueous displacement fluid may range from 0.5 mPa s (cP) to 250 mPa
s (cP) as measured at a temperature within the range of formation
temperature conditions.
[0056] The amount of polymer provided in the aqueous displacement
fluid may also be selected to provide a selected mobility ratio of
the aqueous displacement fluid relative to oil within the
formation. The selected mobility ratio of the aqueous displacement
fluid to oil in the formation may range from 0.2 to 5, or from 0.5
to 3.
[0057] The amount of polymer in the aqueous displacement fluid may
be from at least 350 ppm up to 10,000 ppm by weight of the aqueous
displacement fluid. The amount of polymer in the aqueous
displacement fluid may range from 500 ppmw to 5,000 ppmw, or from
1,000 ppmw to 2,500 ppmw of the aqueous displacement fluid.
[0058] The aqueous displacement fluid is introduced into the
oil-bearing formation to enhance recovery of oil from the formation
by displacing and mobilizing oil in the formation for production
from the formation. The oil-bearing formation may be comprised of a
porous matrix material, oil, and connate water. The oil-bearing
formation comprises oil that may be separated and produced from the
formation after introduction of the aqueous displacement fluid into
the formation.
[0059] 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.
Formation temperatures may range from 5.degree. C. to 275.degree.
C., or from 50.degree. C. to 250.degree. C.; formation pressures
may range from 1 MPa to 100 MPa; pH of the connate water in the
formation may range from 4 to 9, or from 5 to 8; and salinity of
the connate water may range from a TDS content of 2000 ppm to
300,000 ppm.
[0060] The rock and/or mineral porous matrix material of the
formation may be comprised of sandstone and/or a carbonate selected
from dolomite, limestone, and mixtures thereof--where the limestone
may be microcrystalline or crystalline limestone. Minerals that may
form the mineral porous matrix material may be clays or transition
metal compounds. Clays that may form at least a portion of the
mineral porous matrix material include smectite clays,
smectite/illite clays, montmorillonite clays, illite clays,
illite/mica clays, pyrophyllite clays, glauconite clays, and
kaolinite clays. Transition metal compound minerals that may form
at least a portion of the mineral porous matrix material include
carbonates and oxides, for example, iron oxide, siderite, and
plagioclase feldspars.
[0061] The porous matrix material may be a consolidated matrix
material in which at least a majority, and preferably substantially
all, of the rock and/or mineral that forms the matrix material is
consolidated such that the rock and/or mineral forms a mass in
which substantially all of the rock and/or mineral is immobile when
oil, the aqueous displacement fluid, or other fluid is passed
therethrough. Preferably at least 95 wt. % or at least 97 wt. %, or
at least 99 wt. % of the rock and/or mineral is immobile when oil,
the aqueous displacement fluid, or other fluid is passed
therethrough so that any amount of rock or mineral material
dislodged by the passage of the oil, the aqueous displacement
fluid, or other fluid is insufficient to render the formation
impermeable to the flow of the oil, the aqueous displacement fluid,
or other fluid through the formation. Alternatively, the porous
matrix material may be an unconsolidated matrix material in which
at least a majority, or substantially all, of the rock and/or
mineral that forms the matrix material is unconsolidated. The
formation, whether formed of a consolidated mineral matrix, an
unconsolidated mineral matrix, or combination thereof may have a
permeability of from 0.00001 to 15 Darcys, or from 0.001 to 1
Darcy.
[0062] The oil-bearing formation may be a subterranean formation.
The subterranean formation may be comprised of one or more porous
matrix materials described above, where the porous matrix material
may be located beneath an overburden at a depth ranging from 50
meters to 6,000 meters, or from 100 meters to 4,000 meters, or from
200 meters to 2,000 meters under the earth's surface. The
subterranean formation may be a subsea formation.
[0063] The oil contained in the oil-bearing formation may have a
viscosity under formation conditions (in particular, at
temperatures within the temperature range of the formation) of at
least 0.2 mPas (0.2 cP), or at least 1 mPas (1 cP), or at least 5
mPas (10 cP), or at least 10 mPas (100 cP). The oil contained in
the oil-bearing formation may have a viscosity under formation
temperature conditions of from 0.2 to 10,000 mPas (0.2 to 10,000
cP), or from 1 to 1,000 mPas (1 to 1,000 cP) or from 1 to 500 mPas
(1 to 500 cP), or from 1 to 250 mPas (1 to 250 cP). Preferably the
oil in the oil-bearing formation has a viscosity under formation
temperature conditions of from 0.2 to 500 mPas so that the aqueous
displacement fluid may be provided having a mobility ratio relative
to the oil of at most 2 without inclusion of inordinate amounts of
polymer in the aqueous displacement fluid.
[0064] 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.
[0065] 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, water from a
secondary or tertiary oil recovery process water-flood, or a
mixture thereof. Connate water in the oil-bearing formation may
have a TDS content of at least 500 ppm, or at least 1,000 ppm, or
at least 2,500 ppm, or at least 5,000 ppm, or at least 10,000 ppm,
or at least 25,000 ppm, or from 500 ppm to 250,000 ppm, or from
1,000 ppm to 200,000 ppm, or from 2,000 ppm to 100,000 ppm, or from
2,500 ppm to 50,000 ppm, or from 5,000 ppm to 45,000 ppm. Connate
water in the oil-bearing formation may have a multivalent ion
content of at least 50 ppm, or at least 100 ppm, or at least 150
ppm, and may have a multivalent ion content of from 50 ppm to
40,000 ppm, or from 100 ppm to 20,000 ppm, or from 150 ppm to
15,000 ppm. Connate water in the oil-bearing formation may have a
divalent ion content of at least 20 ppm, or at least 40 ppm, or at
least 50 ppm, or at least 100 ppm, or from 20 ppm to 35,000 ppm, or
from 40 ppm to 20,000 ppm, or from 50 ppm to 15,000 ppm. Preferably
the connate water in the formation has at most a moderate amount of
total dissolved solids and a relatively low concentration of
multivalent cations therein, preferably having a TDS content of at
most 30,000 ppm and a total multivalent cation content of at most
250 ppm.
[0066] The water in the oil-bearing formation may be positioned to
immobilize oil within the pores. Introduction of the aqueous
displacement fluid into the formation may mobilize at least a
portion of the oil in the formation for production and recovery
from the formation by freeing at least a portion of the oil from
pores within the formation. Introduction of the aqueous
displacement fluid into the formation may mobilize oil for
production therefrom by driving the oil through the formation in a
plug-like flow.
[0067] The viscosity of the aqueous displacement fluid may be
maintained upon introduction to the formation and contact of the
aqueous displacement fluid with the formation water and with the
clays, minerals, and rock of the formation due to the relative
equivalence of the MAR of divalent cations to monovalent cations of
the aqueous displacement fluid and the formation water. Prior to
introduction of the aqueous displacement fluid to the formation,
the divalent cation and monovalent cation content of the formation
water, the oil, and the clays, minerals, and rock of the formation
is in relative equilibrium so the divalent cation and monovalent
cation concentration of the formation water, of the oil, and of the
formation are relatively constant. Introduction of the aqueous
displacement fluid into the formation to mobilize the oil therein
does not disturb this equilibrium since the MAR of divalent cations
to monovalent cations of the aqueous displacement fluid and the
formation water are similar even though the TDS content of the
aqueous displacement fluid may be significantly different than the
formation water TDS content. As a result, viscosity of the aqueous
displacement fluid is not significantly changed upon contact with
the formation water and the formation rock by ion exchange with the
formation water and formation rock, and the polymer of the aqueous
displacement fluid is not precipitated.
[0068] Referring now to FIG. 4, a system 200 for practicing a
process of the present invention is shown. The system includes a
first well 201 and a second well 203 extending into an oil-bearing
formation 205 such as described above. The oil-bearing formation
205 may be comprised of one or more formation portions 207, 209,
and 211 formed of porous material matrices, such as described
above, located beneath an overburden 213. An aqueous displacement
fluid as described above is provided. The aqueous displacement
fluid may be provided from an aqueous displacement fluid storage
facility 215 fluidly operatively coupled to a first
injection/production facility 217 via conduit 219. First
injection/production facility 217 may be fluidly operatively
coupled to the first well 201, which may be located extending from
the first injection/production facility 217 into the oil-bearing
formation 205. The aqueous displacement fluid may flow from the
first injection/production facility 217 through the first well to
be introduced into the formation 205, for example in formation
portion 209, where the first injection/production facility 217 and
the first well, or the first well itself, include(s) a mechanism
for introducing the aqueous displacement fluid into the formation.
Alternatively, the aqueous displacement fluid may flow from the
aqueous displacement fluid storage facility 215 directly to the
first well 201 for injection into the formation 205, where the
first well comprises a mechanism for introducing the aqueous
displacement fluid into the formation. The mechanism for
introducing the aqueous displacement fluid into the formation 205
via the first well 201--located in the first injection/production
facility 217, the first well 201, or both--may be comprised of a
pump 221 for delivering the aqueous displacement fluid to
perforations or openings in the first well through which the
aqueous displacement fluid may be introduced into the
formation.
[0069] The aqueous displacement fluid may be introduced into the
formation 205, for example by injecting the aqueous displacement
fluid into the formation through the first well 201 by pumping the
aqueous displacement fluid through the first well and into the
formation. The pressure at which the aqueous displacement fluid is
introduced into the formation 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 aqueous displacement fluid may be injected
into the formation may range from 10% to 95%, or from 20% to 90%,
of the fracture pressure of the formation. The pressure at which
the aqueous displacement fluid is injected into the formation may
be selected to limit degradation of polymer in the aqueous
displacement fluid by shear, where lower injection pressures limit
degradation of the polymer by shear. Preferably the aqueous
displacement fluid is injected into the formation at pressures of
from 10% to 50% of the fracture pressure of the formation.
[0070] The volume of the aqueous displacement fluid introduced into
the formation 205 via the first well 201 may range from 0.001 to 5
pore volumes, or from 0.01 to 2 pore volumes, or from 0.1 to 1 pore
volumes, or from 0.2 to 0.9 pore volumes, where the term "pore
volume" refers to the volume of the formation that may be swept by
the aqueous displacement fluid between the first well 201 and the
second well 203. The pore volume may be readily be determined by
methods known to a person skilled in the art, for example by
modeling studies or by injecting water having a tracer contained
therein through the formation 205 from the first well 201 to the
second well 203.
[0071] Introduction of the aqueous displacement fluid to the
formation may mobilize oil in the formation for production from the
formation. As the aqueous displacement fluid is introduced into the
formation 205 through the first well 201, the aqueous displacement
fluid spreads into the formation as shown by arrows 223. The
aqueous displacement fluid contacts the oil in the porous matrix
material of the formation and pushes the oil through the formation
to the second well 203 for production from the formation. Fingering
of the aqueous displacement fluid through the oil or the oil
through the aqueous displacement fluid may be inhibited by the
viscosity of the aqueous displacement fluid relative to the
viscosity of the oil, and in a preferred embodiment the aqueous
displacement fluid mobilizes and drives the oil through the
formation in a substantially plug-like flow.
[0072] The mobilized oil and the aqueous displacement fluid may be
pushed across the formation 205 from the first well 201 to the
second well 203 by further introduction of more aqueous
displacement fluid or by introducing water into the formation
subsequent to introduction of the aqueous displacement fluid into
the formation. The water may be introduced into the formation 205
through the first well 201 after completion of introduction of the
aqueous displacement fluid into the formation to force or otherwise
displace the oil and the aqueous displacement fluid toward the
second well 203 for production.
[0073] The water to be introduced into the formation after
introduction of the aqueous displacement fluid into the formation
may be stored in, and provided for introduction into the formation
205 from, a water storage facility 225 that may be fluidly
operatively coupled to the first injection/production facility 217
via conduit 227. The water to be introduced into the formation
after introduction of the aqueous displacement fluid into the
formation preferably has an MAR of divalent cations to monovalent
cations that is from 70% to 130% of the MAR of divalent cations to
monovalent cations of the aqueous displacement fluid, and
preferably the water is provided from a source utilized to provide
the water for the aqueous displacement fluid. The first
injection/production facility 217 may be fluidly operatively
coupled to the first well 201 to provide the water to the first
well for introduction into the formation 205. Alternatively, the
water storage facility 225 may be fluidly operatively coupled to
the first well 201 directly to provide water to the first well for
introduction into the formation 205. The first injection/production
facility 217 and the first well 201, or the first well itself, may
comprise a mechanism for introducing the water into the formation
205 via the first well 201. The mechanism for introducing the water
into the formation 205 via the first well 201 may be comprised of a
pump or a compressor for delivering the water to perforations or
openings in the first well through which the water may be injected
into the formation. The mechanism for introducing the water into
the formation 205 via the first well 201 may be the pump 221
utilized to inject the aqueous displacement fluid into the
formation via the first well 201.
[0074] The water may be introduced into the formation 205, for
example, by injecting the water into the formation through the
first well 201 by pumping the water through the first well and into
the formation. The pressure at which the water may be injected into
the formation 205 through the first well 201 may be up to or
exceeding the fracture pressure of the formation, or from 20% to
99%, or from 30% to 95%, or from 40% to 90% of the fracture
pressure of the formation, or greater than the fracture pressure of
the formation, and preferably is substantially the same pressure
utilized to inject the aqueous displacement fluid into the
formation.
[0075] The amount of water introduced into the formation 205 via
the first well 201 following introduction of the aqueous
displacement fluid into the formation through the first well may
range from 0.001 to 5 pore volumes, or from 0.01 to 2 pore volumes,
or from 0.1 to 1 pore volumes, or from 0.2 to 0.6 pore volumes,
where the term "pore volume" refers to the volume of the formation
that may be swept by the water between the first well and the
second well. The amount of water introduced into the formation 205
should be sufficient to drive the mobilized oil and the aqueous
displacement fluid across at least a portion of the formation.
[0076] Oil may be mobilized for production from the formation 205
via the second well 203 by introduction of the aqueous displacement
fluid and, optionally, water into the formation through the first
well 201, where the mobilized oil is driven through the formation
from the first well 201 for production from the second well 203 as
indicated by arrows 229. At least a portion of the aqueous
displacement fluid may pass through the formation 205 from the
first well 201 to the second well 203 for production from the
formation along with the mobilized oil.
[0077] After introduction of the aqueous displacement fluid and,
optionally, water into the formation 205 via the first well 201,
oil may be recovered and produced from the formation via the second
well 203. A mechanism may be located at the second well for
recovering and producing oil from the formation 205 subsequent to
introduction of the aqueous displacement fluid into the formation.
The mechanism for recovering and producing oil from the formation
may also recover and produce at least a portion of the aqueous
displacement fluid, other water, and/or gas from the formation
subsequent to introduction of the aqueous displacement fluid into
the formation. The mechanism located at the second well 203 for
recovering and producing the oil, the aqueous displacement fluid,
other water, and/or gas may be comprised of a pump 233, which may
be located in a second injection/production facility 231 and/or
within the second well 203. The pump 233 may draw the oil, at least
a portion of the aqueous displacement fluid, other water, and/or
gas from the formation 205 through perforations in the second well
203 to deliver the oil, at least a portion of the aqueous
displacement fluid, other water, and/or gas, to the second
injection/production facility 231.
[0078] Alternatively, the mechanism for recovering and producing
the oil, at least a portion of the aqueous displacement fluid,
other water, and/or gas from the formation 205 may be comprised of
a compressor 234 that may be located in the second
injection/production facility 231. The compressor 234 may be
fluidly operatively coupled to a gas storage tank 241 via conduit
236, and may compress gas from the gas storage tank for injection
into the formation 205 through the second well 203. The compressor
may compress the gas to a pressure sufficient to drive production
of oil, the aqueous displacement fluid, other water, and/or gas
from the formation via the second well 203, where the appropriate
pressure may be determined by conventional methods known to those
skilled in the art. The compressed gas may be injected into the
formation from a different position on the second well 203 than the
well position at which the oil, aqueous displacement fluid, other
water, and/or gas are produced from the formation, for example, the
compressed gas may be injected into the formation at formation
portion 211 while oil, aqueous displacement fluid, other water,
and/or gas are produced from the formation at formation portion
209.
[0079] Oil, at least a portion of the aqueous displacement fluid,
other water, and/or gas may be drawn from the formation 205 as
shown by arrows 229 and produced up the second well 203 to the
second injection/production facility 231. The oil may be separated
from gas and an aqueous mixture comprised of the produced portion
of aqueous displacement fluid and other formation water produced
from the formation, for example connate water, mobile water, or
water from a oil recovery waterflood. The produced oil may be
separated from the produced aqueous mixture and produced gas in a
separation unit 235 located in the second injection/production
facility 231 and, in an embodiment, operatively fluidly coupled to
the mechanism 233 for recovering and producing oil, the components
of the aqueous mixture, and/or gas from the formation.
[0080] A brine solution having a TDS content of greater than 20,000
ppm, or from 25,000 ppm to 250,000 ppm may be provided from a brine
solution storage facility 247 to the separation unit 235 via
conduit 273 for mixing with the produced oil and the produced
aqueous mixture, and optionally with produced gas. The brine
solution may have a TDS content of at least 20,000 ppm, or at least
25,000 ppm, or at least 30,000 ppm, or at least 40,000 ppm, or at
least 50,000 ppm, or from 20,000 ppm to 250,000 ppm, or from 25,000
ppm to 200,000 ppm, or from 30,000 ppm to 150,000 ppm, or from
40,000 ppm to 100,000 ppm. The brine solution may be selected from
seawater, brackish water, estuarine water, or production water
produced from the formation and separated from oil and/or gas
produced from the formation. Alternatively, the brine solution may
be comprised of at least a portion of a brine retentate 117, a
primary brine retentate 125 and/or a secondary brine retentate 127,
or a first brine retentate 137 and/or a second brine retentate 143
(as shown in FIGS. 1-3) produced by contact of a saline source
water with an ionic filter as described above.
[0081] A demulsifier may also be provided to the separation
facility 235 from a demulsifier storage facility 271 which may be
fluidly operatively connected to the separation unit via conduit
240. The demulsifier may be provided to the separation facility 235
for mixing with the produced oil, the produced water, and the brine
solution, and optionally with produced gas, to facilitate
separation of the produced oil and the produced water.
[0082] The demulsifier may be selected from the group consisting of
amylresins; butylresins; nonylresins; acid- or base-catalyzed
phenol-formaldehyde resins; phenol-acrylate anhydride polyglycol
resins; urethanes; polyamines; polyesteramines; sulfonates;
di-epoxides; polyols; esters and polyol esters including triol
fatty acid esters, triol adipate esters, and triol fumarate esters;
ethoxylated and/or propoxylated compounds of amyl resins,
butylresins, nonylresins, acid- or base-catalyzed
phenol-formaldehyde resins, fatty acids, polyamines, di-epoxides,
and polyols; and combinations thereof which may be dispersed in a
carrier solvent selected from the group consisting of xylene,
toluene, heavy aromatic naphtha, isopropanol, methanol,
2-ethoxyhexanol, diesel, and combinations thereof. A suitable
demulsifier for separating the oil and water produced from the
formation 205 may be selected by conducting a bottle test, a
conventional test known to those skilled in the art for selecting a
demulsifier effective to separate crude oil and water. Commercially
available demulsifiers include the EB-Series from National Chemical
Supply, 4151 SW 47.sup.th Ave., Davie, Fla., 33314, United States,
and Tretolite demulsifiers from Baker Petrolite Corporation, 12645
W. Airport Blvd., Sugar Land, Tex. 77478, United States.
[0083] In an embodiment of a method of the present invention the
first well 201 may be used for injecting the aqueous displacement
fluid and, optionally, water into the formation 205 and the second
well 203 may be used to produce and separate oil, water, and
optionally gas from the formation as described above for a first
time period, and the second well 203 may be used for injecting the
aqueous displacement fluid and, optionally, water into the
formation 205 to mobilize the oil in the formation and drive the
mobilized oil across the formation to the first well and the first
well 201 may be used to produce and separate oil, water, and gas
from the formation for a second time period, where the second time
period is subsequent to the first time period. The second
injection/production facility 231 may comprise a mechanism such as
pump 251 that is fluidly operatively coupled the aqueous
displacement fluid storage facility 215 by conduit 253 and that is
fluidly operatively coupled to the second well 203 to introduce the
aqueous displacement fluid into the formation 205 via the second
well. The pump 251 may also be fluidly operatively coupled to the
water storage facility 225 by conduit 255 to introduce water into
the formation 205 via the second well 203 subsequent to
introduction of the aqueous displacement fluid into the formation
via the second well. The first injection/production facility 217
may comprise a mechanism such as pump 257 or compressor 258 for
production of oil, water, and gas from the formation 205 via the
first well 201. The first injection/production facility 217 may
also include a separation unit 259 for separating produced oil,
produced water, and produced gas fluidly operatively connected to
the mechanism 257 by conduit 260, where the separation unit 259 may
be similar to separation unit 235 as described above. The brine
solution storage facility 247 may be fluidly operatively connected
to the separation unit 259 by conduit 272 to provide brine solution
to the separation unit 259, and the demulsifier storage facility
271 may be fluidly operatively connected to the separation unit 259
by conduit 262 to provide demulsifier to the separation unit 259.
The separation unit 259 may be fluidly operatively coupled to the
liquid storage tank 237 by conduit 261 for storage of produced and
separated oil in the liquid storage tank and to the gas storage
tank 241 by conduit 265 for storage of produced gas in the gas
storage tank.
[0084] The first well 201 may be used for introducing the aqueous
displacement fluid and, optionally, subsequently water into the
formation 205 and the second well 203 may be used for producing and
separating oil, water, and gas from the formation for a first time
period; then the second well 203 may be used for introducing the
aqueous displacement fluid and, optionally, subsequently water into
the formation 205 and the first well 201 may be used for producing
and separating oil, water, and gas from the formation for a second
time period; where the first and second time periods comprise a
cycle. Multiple cycles may be conducted which include alternating
the first well 201 and the second well 203 between introducing the
aqueous displacement fluid and, optionally, subsequently water into
the formation 205, and producing and separating oil, water, and gas
from the formation, where one well is introducing and the other is
producing and separating for the first time period, and then they
are switched for a second time period. A cycle may be from about 12
hours to about 1 year, or from about 3 days to about 6 months, or
from about 5 days to about 3 months. The aqueous displacement fluid
may be introduced into the formation at the beginning of a cycle
and water may be introduced at the end of the cycle. In some
embodiments, the beginning of a cycle may be the first 10% to about
80% of a cycle, or the first 20% to about 60% of a cycle, the first
25% to about 40% of a cycle, and the end may be the remainder of
the cycle.
[0085] Referring now to FIG. 5 an array of wells 500 is
illustrated. Array 500 includes a first well group 502 (denoted by
horizontal lines) and a second well group 504 (denoted by diagonal
lines). In some embodiments of the method of the present invention,
the first well of the method described above may include multiple
first wells depicted as the first well group 502 in the array 500,
and the second well of the method described above may include
multiple second wells depicted as the second well group 504 in the
array 500.
[0086] Each well in the first well group 502 may be a horizontal
distance 530 from an adjacent well in the first well group 502. The
horizontal distance 530 may be from about 5 to about 5,000 meters,
or from about 7 to about 1,000 meters, or from about 10 to about
500 meters, or from about 20 to about 250 meters, or from about 30
to about 200 meters, or from about 50 to about 150 meters, or from
about 90 to about 120 meters, or about 100 meters. Each well in the
first well group 502 may be a vertical distance 532 from an
adjacent well in the first well group 502. The vertical distance
532 may be from about 5 to about 5,000 meters, or from about 7 to
about 1,000 meters, or from about 10 to about 500 meters, or from
about 20 to about 250 meters, or from about 30 to about 200 meters,
or from about 50 to about 150 meters, or from about 90 to about 120
meters, or about 100 meters.
[0087] Each well in the second well group 504 may be a horizontal
distance 536 from an adjacent well in the second well group 504.
The horizontal distance 536 may be from about 5 to about 5,000
meters, or from about 7 to about 1,000 meters, or from about 10 to
about 500 meters, or from about 20 to about 250 meters, or from
about 30 to about 200 meters, or from about 50 to about 150 meters,
or from about 90 to about 120 meters, or about 100 meters. Each
well in the second well group 504 may be a vertical distance 538
from an adjacent well in the second well group 504. The vertical
distance 538 may be from about 5 to about 5,000 meters, or from
about 7 to about 1,000 meters, or from about 10 to about 500
meters, or from about 20 to about 250 meters, or from about 30 to
about 200 meters, or from about 50 to about 150 meters, or from
about 90 to about 120 meters, or about 100 meters.
[0088] Each well in the first well group 502 may be a distance 534
from the adjacent wells in the second well group 504. Each well in
the second well group 504 may be a distance 534 from the adjacent
wells in first well group 502. The distance 534 may be from about 5
to about 5,000 meters, or from about 7 to about 1000 meters, or
from about 10 to about 500 meters, or from about 20 to about 250
meters, or from about 30 to about 200 meters, or from about 50 to
about 150 meters, or from about 90 to about 120 meters, or about
100 meters.
[0089] Each well in the first well group 502 may be surrounded by
four wells in the second well group 504. Each well in the second
well group 504 may be surrounded by four wells in the first well
group 502.
[0090] In some embodiments, the array of wells 500 may have from
about 10 to about 1,000 wells, for example from about 5 to about
500 wells in the first well group 502, and from about 5 to about
500 wells in the second well group 504.
[0091] In some embodiments, the array of wells 500 may be seen as a
top view with first well group 502 and the second well group 504
being vertical wells spaced on a piece of land. In some
embodiments, the array of wells 500 may be seen as a
cross-sectional side view of the formation with the first well
group 502 and the second well group 504 being horizontal wells
spaced within the formation.
[0092] To facilitate a better understanding of the present
invention, the following example of certain aspects of some
embodiments is given. In no way should the following example be
read to limit, or define, the scope of the invention.
EXAMPLE
[0093] An experiment was conducted to determine the effect of using
a low salinity aqueous displacement fluid containing a polymer and
having a TDS content of less than 5,000 ppm and less than half the
TDS content of a formation water and having a MAR within 70% to
130% of the MAR of the formation water on viscosity and divalent
cation exchange in an oil-bearing formation relative to an aqueous
displacement fluid formed by combining a polymer with formation
water. The amount of polymer required to provide the same viscosity
was measured for the low salinity aqueous displacement fluid and
the aqueous displacement fluid formed by combining a polymer with
formation water.
[0094] A sandstone core was aged with crude oil for 4 weeks at a
temperature of 50.degree. C. (corresponding to the formation
temperature of the formation from which the crude oil was
obtained). Diffraction analysis showed that the core material was
composed of 95% quartz with the remaining 5% containing
illite-smectite, kaolinite, and illite-mica clays, K-feldspar, and
traces of chlorite, anhydrite, calcite, and pyrite. The core was
then saturated with synthetic formation water having the
composition shown in Table 1.
[0095] A designed low salinity water solution was prepared having a
TDS content of 2170 ppm (2.5.times. dilution relative to the TDS of
the formation water) and a MAR of divalent cations to monovalent
cations equal to the MAR of divalent cations to monovalent cations
of the synthetic formation water (MAR of the designed low salinity
water solution=99% of the MAR of the synthetic formation water).
The composition of the low salinity water solution is shown in
Table 1.
[0096] A high salinity polymer solution (HSP) and a low salinity
polymer solution (LSP) were formed from the synthetic formation
water and the designed low salinity water solution, respectively.
Sufficient hydrolyzed polyacrylamide polymer FLOPAAM 3630S was
added to the synthetic formation water and to the designed low
salinity water solution to produce an HSP solution and an LSP
solution each having a viscosity of 125 cP at 50.degree. C. The HSP
solution contained 2483 ppm of the polymer and the LSP solution
contained 1761 ppm of the polymer.
TABLE-US-00001 TABLE 1 Synthetic formation water Designed LS water
NaCl 4.517 g/L NaCl 1.807 g/L KCl 0.000 g/L KCl 0.000 g/L
CaCl.sub.2.cndot.2H.sub.2O 0.359 g/L CaCl.sub.2.cndot.2H.sub.2O
0.058 g/L Na2SO4 0.497 g/L Na2SO4 0.199 g/L NaHCO3 0.293 g/L NaHCO3
0.117 g/L MgCl.sub.2.cndot.6H.sub.2O 0.059 g/L
MgCl.sub.2.cndot.6H.sub.2O 0.009 g/L Na.sup.+ 2.018 g/L Na.sup.+
0.807 g/L K.sup.+ 0.000 g/L K.sup.+ 0.000 g/L Ca.sup.2+ 0.098 g/L
Ca.sup.2+ 0.016 g/L Mg.sup.2+ 0.007 g/L Mg.sup.2+ 0.001 g/L SO4
0.336 g/L SO4 0.134 HCO3 0.213 g/L HCO3 0.085 Cl.sup.- 2.9339 g/L
Cl.sup.- 1.127 g/L MAR 38.8 MAR 38.3 meq/l ppm meq/l TDS 5605.745
ppm TDS 2170.604 TDS
[0097] The core saturated with synthetic formation water was then
treated sequentially with 30 PV of the synthetic formation water,
then 30 PV of the designed low salinity water, then 80 PV of the
HSP solution, then 30 PV of the designed LSP solution. The effluent
from each of these steps was collected in 3 ml fractions. The
concentration of sodium, potassium, calcium, and magnesium cations
of the effluent fractions from each step was measured by inductive
coupled plasma elemental analysis to determine the stripping effect
of the injected water and polymer solutions. FIGS. 10 and 11 show
the measured concentrations of Na.sup.+, Ca.sup.2+, Mg.sup.2+, and
K.sup.+ in the effluents of the injected synthetic formation brine,
the designed low salinity water, the HSP solution, and the LSP
solution. The concentration of Ca.sup.2+ and Mg.sup.2+ in the HSP
solution effluent and the LSP solution effluent is slightly higher
than the concentration of these cations in the HSP and LSP
solutions at the beginning of the injection of each of these
solutions, which may be an effect of the affinity of the polymer
for calcium and magnesium. Over the course of the injections of the
HSP and LSP solutions, however, the calcium and magnesium
concentrations in the effluent quickly revert to the baseline of
the concentrations of these cations in the injected solutions
Importantly, the LSP solution does not show a significant stripping
of Ca.sup.2+ and Mg.sup.2+ relative to the HSP solution, indicating
that the low salinity of the LSP solution does not induce any
significant amount of stripping of the calcium and magnesium
cations from the core.
[0098] The viscosity of the effluent from the HSP solution
injection and the LSP solution injection effluents was measured by
a rheometer. FIG. 12 shows the viscosity of the HSP solution
effluent and the LSP solution effluent. Each effluent shows a
viscosity drop of about 10% occurring at the beginning of the
injection, then the viscosity levels out. Significantly, the
viscosity drop of the LSP solution is substantially similar to the
viscosity drop of the HSP solution, indicating that the viscosity
of the LSP solution is not significantly affected by the low
salinity of the LSP solution. This may correlate to the LSP
solution not stripping substantial quantities of Ca.sup.2+ and
Mg.sup.2+ from the core, which may be attributable to the MAR of
the LSP solution being equivalent to the MAR of the HSP
solution.
[0099] The present invention is well adapted to attain the ends and
advantages mentioned above 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 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 may include 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.
* * * * *