U.S. patent application number 13/835030 was filed with the patent office on 2014-09-18 for alkali polymer surfactant sandwich.
This patent application is currently assigned to Chevron U.S.A. Inc.. The applicant listed for this patent is Robert Matthew Dean, Varadarajan Dwarakanath, Taimur Malik, Will S. Slaughter, Dustin L. Walker. Invention is credited to Robert Matthew Dean, Varadarajan Dwarakanath, Taimur Malik, Will S. Slaughter, Dustin L. Walker.
Application Number | 20140262275 13/835030 |
Document ID | / |
Family ID | 50391435 |
Filed Date | 2014-09-18 |
United States Patent
Application |
20140262275 |
Kind Code |
A1 |
Dean; Robert Matthew ; et
al. |
September 18, 2014 |
ALKALI POLYMER SURFACTANT SANDWICH
Abstract
Aspects of the invention relate to methods for enhancing the
amount of oil recovered from subterranean reservoirs or reducing
the amount of surfactant needed. The method includes injecting a
first alkali-polymer slug through a wellbore into a reservoir,
followed by injecting a alkali-polymer-surfactant slug through the
wellbore into the reservoir, and then injecting a second
alkali-polymer slug through the wellbore into the reservoir.
Inventors: |
Dean; Robert Matthew;
(Houston, TX) ; Walker; Dustin L.; (Katy, TX)
; Slaughter; Will S.; (Houston, TX) ; Malik;
Taimur; (Houston, TX) ; Dwarakanath; Varadarajan;
(Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Dean; Robert Matthew
Walker; Dustin L.
Slaughter; Will S.
Malik; Taimur
Dwarakanath; Varadarajan |
Houston
Katy
Houston
Houston
Houston |
TX
TX
TX
TX
TX |
US
US
US
US
US |
|
|
Assignee: |
Chevron U.S.A. Inc.
San Ramon
CA
|
Family ID: |
50391435 |
Appl. No.: |
13/835030 |
Filed: |
March 15, 2013 |
Current U.S.
Class: |
166/300 |
Current CPC
Class: |
C09K 8/58 20130101; E21B
43/16 20130101 |
Class at
Publication: |
166/300 |
International
Class: |
E21B 43/16 20060101
E21B043/16 |
Claims
1. A method for enhancing oil recovery in a subsurface reservoir in
fluid communication with a wellbore comprising, in order: injecting
a first alkali-polymer slug through the wellbore into the
reservoir; injecting an alkali-polymer-surfactant slug through the
wellbore into the reservoir; and injecting a second alkali-polymer
slug through the wellbore into the reservoir.
2. The method of claim 1, further comprising injecting a polymer
slug through the wellbore into the reservoir following the second
alkali-polymer slug.
3. The method of claim 1, wherein the alkali-polymer-surfactant
slug comprises less surfactant mass than a predetermined optimal
surfactant amount.
4. The method of claim 3, wherein the alkali-polymer-surfactant
slug comprises the alkali-polymer-surfactant slug may comprise
greater than 95%, greater than 90%, greater than 80%, greater than
70%, greater than 60%, or greater than 50%, of the predetermined
optimal surfactant amount.
5. The method of claim 1, wherein the alkali-polymer-surfactant
slug comprises one or more of the group consisting of internal
olefin sulfonates, isomerized olefin sulfonates, alkyl aryl
sulfonates, medium alcohol (C10 to C17) alkoxy sulfates, alcohol
ether [alkoxy]carboxylates, alcohol ether [alkoxy]sulfates, primary
amines, secondary amines, tertiary amines, quaternary ammonium
cations, cationic surfactants that are linked to a terminal
sulfonate or carboxylate group, alkylaryl alkoxy alcohols, alkyl
alkoxy alcohols, alkyl alkoxylated esters, and alkyl
polyglycosides.
6. The method of claim 1, wherein the alkali-polymer-surfactant
slug, the first alkali-polymer slug, and/or the second alkali
polymer slug comprises one or more of the group consisting of
sodium carbonate, sodium bicarbonate, sodium hydroxide, potassium
hydroxide, sodium silicate, tetrasodium EDTA, sodium metaborate,
sodium citrate, and sodium tetraborate.
7. The method of claim 1, wherein the alkali-polymer-surfactant
slug, the first alkali-polymer slug, and/or the second alkali
polymer slug comprises one or more of the group consisting of
xanthan gum, scleroglucan, partially hydrolyzed polyacrylamides,
hydrophobically-modified associative polymers, co-polymers of
polyacrylamide (PAM), 2-acrylamido 2-methylpropane sulfonic acid,
and N-vinyl pyrrolidone (NVP).
8. The method of claim 1, wherein the alkali-polymer-surfactant
slug, the first alkali-polymer slug, and/or the second alkali
polymer slug comprises 0.1 to 10 percent by weight alkali.
9. The method of claim 1, wherein the alkali-polymer-surfactant
slug, the first alkali-polymer slug, and/or the second alkali
polymer slug comprises 250 ppm to 5,000 ppm polymer.
10. The method of claim 1, wherein the alkali-polymer-surfactant
slug comprises 0.1 to 5 weight percent surfactant.
11. The method of claim 1, further comprising receiving production
fluid from the reservoir.
12. The method of claim 13, wherein greater than 90% of residual
oil is recovered from the reservoir.
13. The method of claim 1, wherein the first alkali-polymer slug is
optimized for the subsurface reservoir by adjusting the
concentration of alkali and polymer in the alkali-polymer slug to
at least about 50%, at least about 60%, at least about 70%, at
least about 80%, or at least about 90% of optimal salinity for the
reservoir.
14. The method of claim 1, wherein the second alkali-polymer slug
is optimized for the subsurface reservoir by adjusting the
concentration of alkali and polymer to at least about 50%, at least
about 60%, at least about 70%, at least about 80%, or at least
about 90% of optimal salinity for the reservoir.
15. The method of claim 1, wherein the alkali-surfactant-polymer
slug is optimized for the subsurface reservoir by adjusting one or
more of the concentration of alkali, polymer and surfactant to
about at least 50%, at least about 60%, at least about 70%, at
least about 80%, or at least about 90% of optimal salinity for the
reservoir.
16. The method of claim 1, further comprising, prior to injection
of the first alkali-polymer slug, softening seawater or brine
water; and adding alkali and polymer to the softened seawater to
form the first alkali-polymer slug.
17. The method of claim 1, further comprising, prior to injection
of the first alkali-polymer slug, softening seawater or brine
water; and adding alkali, polymer, and surfactant to the softened
seawater to form alkali-polymer-surfactant slug.
18. The method of claim 1, further comprising, prior to injection
of the first alkali-polymer slug, softening seawater or brine
water; and adding alkali and polymer to the softened seawater to
form the second alkali-polymer slug.
19. The method of claim 1, wherein the first alkali-polymer slug,
the second alkali-polymer slug, and/or the
alkali-polymer-surfactant slug comprises from about 100 to 150,000
ppm total dissolved solids.
Description
TECHNICAL FIELD
[0001] The present disclosure generally relates to a method for
chemically enhanced oil recovery. In particular cases, the present
disclosure concerns a method of injecting an alkali-polymer (AP)
mixture into a reservoir before and after injecting an
alkali-surfactant-polymer (ASP) mixture in order to control loss of
surfactant performance due to cation exchange, increase polymer
stability at high temperatures, enhance recovery of oil and/or to
reduce the amount of surfactant needed.
BACKGROUND
[0002] Reservoir systems, such as petroleum reservoirs, typically
contain fluids such as water and a mixture of hydrocarbons such as
oil and gas. To remove ("produce") the hydrocarbons from the
reservoir, different mechanisms can be utilized such as primary,
secondary or tertiary recovery processes.
[0003] In a primary recovery process, hydrocarbons are displaced
from a reservoir through the high natural differential pressure
between the reservoir and the bottomhole pressure within a
wellbore. The reservoir's energy and natural forces drive the
hydrocarbons contained in the reservoir into the production well
and up to the surface. Artificial lift systems, such as sucker rod
pumps, electrical submersible pumps or gas-lift systems, are often
implemented in the primary production stage to reduce the
bottomhole pressure within the well. Such systems increase the
differential pressure between the reservoir and the wellbore
intake; thus, increasing hydrocarbon production. However, even with
use of such artificial lift systems only a small fraction of the
original-oil-in-place (OOIP) is typically recovered using primary
recovery processes as the reservoir pressure, and the differential
pressure between the reservoir and the wellbore intake declines
overtime due to production. For example, typically only about
10-20% of the OOIP can be produced before primary recovery reaches
its limit, either when the reservoir pressure is so low that the
production rates are not economical or when the proportions of gas
or water in the production stream are too high.
[0004] In order to increase the production life of the reservoir,
secondary or tertiary recovery processes can be used. Secondary
recovery processes include water or gas well injection, while
tertiary methods are based on injecting additional chemical
compounds into the well. Typically in these processes, fluids are
injected into the reservoir to maintain reservoir pressure and
drive the hydrocarbons to producing wells. An additional 10-50% of
OOIP can be produced in addition to the oil produced during primary
recovery. While secondary and tertiary methods of oil recovery can
further enhance oil production from a reservoir, care must be taken
in choosing the right processes and injection fluid for each
reservoir, as some methods may cause formation damage or
plugging.
[0005] A well-known tertiary recovery process is
alkali-surfactant-polymer (ASP) flooding. Polymers are used to
increase the viscosity of a fluid, thereby leading to a reduced
mobility ratio and to improved sweep efficiency. The most commonly
used polymer for surfactant-polymer flooding is polyacrylamide
(PAM) in its anionic form, hydrolyzed polyacrylamide (HPAM).
Surfactants are used to lower the interfacial properties of the
reservoir, thereby reducing capillary forces and increasing the
efficiency of the displacement of oil. A wide variety of
surfactants exist, but the most widely used in prior literature are
petroleum sulfonates. Recent work has focused on use of synthetic
surfactants, which are typically higher cost, thereby requiring
means to reduce adsorption and retention. Alkali is used to raise
the pH of the flood, minimizing the amount of surfactant adsorbed.
The compositions of chemicals used in enhanced oil recovery (EOR)
processes may vary depending on the type, environment, and
composition of the reservoir formation.
[0006] Many factors affect the choice of surfactant for use in a
specific reservoir. For example, the salinity of the water in
subterranean hydrocarbon reservoirs can vary a great deal, as can
the pH. For example, one oil field has total dissolved salts of
between 0.2 and 0.3 weight percent. Other reservoirs may have
salinities as high as 20 percent total dissolved solids and over
0.5 percent divalent in the form of calcium and magnesium ions (or
higher). Currently, it is desirable to optimize the surfactant used
in an ASP flood by evaluating tailored versions of the surfactants
with native reservoir brine and reservoir oil under subterranean
reservoir conditions via phase behavior experiments.
[0007] In the enhanced oil recovery process, the addition of
surfactants, polymers, co-solvents and electrolytes improve the oil
recovery significantly. However, surfactant adsorption is one of
the main causes of high chemical cost during chemical flood. If the
surfactant mass required to propagate through a reservoir can be
reduced, then the cost associated with the surfactant is also
reduced. Alkali is one such means to ensure low surfactant
adsorption/retention.
SUMMARY
[0008] A general embodiment of the disclosure is a method for
enhancing oil recovery in a subsurface reservoir in fluid
communication with a wellbore comprising injecting a first
alkali-polymer slug through the wellbore into the reservoir;
injecting an alkali-polymer-surfactant slug through the wellbore
into the reservoir; and injecting a second alkali-polymer slug
through the wellbore into the reservoir. The method may further
comprise injecting a polymer slug through the wellbore into the
reservoir following the second alkali-polymer slug. In specific
embodiments, the first and second alkali-polymer slugs comprise
about the same amounts of alkali and/or polymer or different
amounts of polymer and/or alkali. The alkali-polymer-surfactant
slug may comprise less surfactant mass than a predetermined optimal
surfactant amount. For example, the alkali-polymer-surfactant slug
may comprise greater than 95%, greater than 90%, greater than 80%,
greater than 70%, greater than 60%, or greater than 50%, of the
predetermined optimal surfactant amount. In some embodiment, the
alkali-polymer-surfactant slug comprises between 50-80% of the
predetermined optimal surfactant amount, or between 40-60% of the
optimal surfactant amount while still achieving greater than 90%
residual oil recovery.
[0009] In specific embodiments, the alkali-polymer-surfactant slug
comprises one or more of the group consisting of internal olefin
sulfonates, isomerized olefin sulfonates, alkyl aryl sulfonates,
medium alcohol (C10 to C17) alkoxy sulfates, alcohol ether
[alkoxy]carboxylates, alcohol ether [alkoxy]sulfates, primary
amines, secondary amines, tertiary amines, quaternary ammonium
cations, cationic surfactants that are linked to a terminal
sulfonate or carboxylate group, alkylaryl alkoxy alcohols, alkyl
alkoxy alcohols, alkyl alkoxylated esters, and alkyl
polyglycosides. In some embodiments, the alkali-polymer-surfactant
slug, the first alkali-polymer slug, and/or the second alkali
polymer slug comprises one or more of the group consisting of
sodium carbonate, sodium bicarbonate, sodium hydroxide, potassium
hydroxide, sodium silicate, tetrasodium EDTA, sodium metaborate,
sodium citrate, and sodium tetraborate. In specific embodiments,
the alkali-polymer-surfactant slug, the first alkali-polymer slug,
and/or the second alkali polymer slug comprises one or more of the
group consisting of xanthan gum, scleroglucan, partially hydrolyzed
polyacrylamides, hydrophobically-modified associative polymers,
co-polymers of polyacrylamide (PAM), 2-acrylamido 2-methylpropane
sulfonic acid, and N-vinyl pyrrolidone (NVP). The
alkali-polymer-surfactant slug, the first alkali-polymer slug,
and/or the second alkali polymer slug can comprise 0.1 to 5 weight
percent alkali, for example, 0.3 to 3 weight percent, 0.4 to 2.5
weight percent, or 0.6 to 1.5 weight percent alkali. The
alkali-polymer-surfactant slug, the first alkali-polymer slug,
and/or the second alkali polymer slug can comprise at least 500 ppm
polymer, at least 1000 ppm polymer, at least 2000 ppm polymer, at
least 3000 ppm polymer or at least 5000 ppm polymer. The
alkali-polymer-surfactant slug may comprise 0.1 to 5 weight percent
surfactant, for example, the slug can comprise 0.3 to 3 weight
percent, or 0.5 to 2 weight percent surfactant.
[0010] The method may further comprise receiving production fluid
from the reservoir. Additionally, the first and/or the second
alkali-polymer slug can be optimized for the subsurface reservoir
by adjusting the concentration of alkali and polymer to at least
about 50%, at least about 60%, at least about 70%, at least about
80%, or at least about 90% of optimal salinity for the reservoir.
In some embodiments, the alkali-surfactant-polymer slug is
optimized for the subsurface reservoir by adjusting one or more of
the concentration of alkali, polymer and surfactant to at least
about 50%, at least about 60%, at least about 70%, at least about
80%, or at least about 90% of optimal salinity for the
reservoir.
[0011] In specific embodiments, the method further comprises
softening seawater or waste brine prior to injection of the first
alkali-polymer, and adding alkali and polymer to the softened
seawater to form the first alkali-polymer slug. In additional
embodiments, seawater or waste brine is softened prior to injection
of the first alkali-polymer; and alkali, polymer, and surfactant
are added to the softened seawater to form the
alkali-polymer-surfactant slug. The method may also comprise,
softening seawater or waste brine prior to injection of the first
alkali-polymer, and adding alkali and polymer to the softened
seawater to form the second alkali-polymer slug.
[0012] The foregoing has outlined rather broadly the features and
technical advantages of the present invention in order that the
detailed description of the invention that follows may be better
understood. Additional features and advantages of the invention
will be described hereinafter. It should be appreciated by those
skilled in the art that the conception and specific embodiments
disclosed may be readily utilized as a basis for modifying or
designing other structures for carrying out the same purposes of
the present invention. It should also be realized by those skilled
in the art that such equivalent constructions do not depart from
the scope of the invention as set forth in the appended claims. The
novel features which are believed to be characteristic of the
invention, both as to its organization and method of operation,
together with further objects and advantages will be better
understood from the following description when considered in
connection with the accompanying figures. It is to be expressly
understood, however, that each of the figures is provided for the
purpose of illustration and description only and is not intended as
a definition of the limits of the present invention.
BRIEF DESCRIPTION OF THE DRAWINGS
[0013] For a more complete understanding of the present invention,
reference is now made to the following descriptions taken in
conjunction with the accompanying drawing, in which:
[0014] FIG. 1 is an illustration of a pre-ASP AP slug entering a
subterranean reservoir.
[0015] FIG. 2 is an illustration of an ASP slug entering a
subterranean reservoir after a pre-ASP AP slug.
[0016] FIG. 3 is an illustration of a post-ASP AP slug entering a
subterranean reservoir after a ASP slug and a pre-ASP AP slug.
[0017] FIG. 4 is a graph of oil recovered, oil cut per pore volume
for an example core flood using an ASP slug and a post-ASP AP
slug.
[0018] FIG. 5 is a graph of oil recovered, oil cut per pore volume
for an example core flood using a pre-ASP AP slug, an ASP slug and
a post-ASP AP slug.
[0019] FIG. 6 is a graph of oil recovered, oil cut per pore volume
for an example core flood using a pre-ASP AP slug, an ASP slug and
a post-ASP AP slug, where the ASP slug had a reduced mass of
surfactant when compared to the composition used in FIG. 5.
[0020] FIG. 7 is a graph of oil recovered, oil cut per pore volume
for an example core flood in a control core flood.
[0021] FIG. 8 is a graph of oil recovered, oil cut per pore volume
for an example core flood with a pre-ASP AP and post-ASP AP
slug.
[0022] FIG. 9 is a graph of oil recovered, oil cut per pore volume
for an example core flood with no pre-ASP AP or post-ASP AP
slug.
[0023] FIG. 10 is a graph of oil recovered, oil cut per pore volume
for an example core flood with half the surfactant used in the core
of FIG. 9 but including a pre-ASP AP slug and a post-ASP AP
slug.
DETAILED DESCRIPTION
[0024] Aspects of the present invention describe a method for
enhancing the oil recovery from surfactant polymer floods or for
reducing the mass of surfactant needed during a surfactant polymer
flood. Specifically, an embodiment comprises injecting an AP
mixture before and after injecting an ASP mixture into a
reservoir.
[0025] Not to be limited by theory, it is thought that alkaline
environments reduce anionic surfactant absorption. In embodiments,
the AP mixture injected prior to a surfactant slug successfully
raises the pH and increases or maintains the effective salinity in
front of the surfactant slug while protecting surfactant from
hardness and limiting surfactant mobility. The AP mixture injected
behind the surfactant slug maintains the effective salinity and
high pH and allows the surfactant slug to stay in an optimum
environment, i.e. Winsor type III region, throughout the entire
flood. This process minimizes surfactant adsorption because the
surfactant is always in a high pH environment, while the polymer
provides mobility control. The minimized surfactant absorption and
small surfactant slug size reduces the surfactant mass needed and,
thus, the costs of the process. That is, the pre-ASP AP slug 1)
provides mobility control of the following ASP slug 2) raises pH to
lower surfactant absorption, and 3) precipitates multivalent
cations that are in the mixing zone, thus further protecting the
ASP slug. The post-ASP AP slug 1) provides mobility control behind
the ASP slug and 2) keeps the ASP slug at optimal salinity (lowest
oil-water interfacial tension) and high pH (optimal phase behavior;
protects some anionic surfactants (sulfates) at high temperature)
and 3) protects the polymer in a softened water environment with
high pH
[0026] As used herein, the term "equal" refers to equal values or
values within the standard of error of measuring such values. The
term "substantially equal" or "about" refers to an amount that is
within 3% of the value recited.
[0027] As used herein, "a" or "an" means "at least one" or "one or
more" unless otherwise indicated.
[0028] As used herein, a "polymer sandwich" refers to a sequence of
injected slugs, first starting with an AP composition that does not
comprise an effective amount of surfactant, followed by an ASP
composition, and followed by an AP composition that does not
comprise an effective amount of surfactant.
[0029] "Optimal salinity" is the salinity which recovers the
highest amount of oil. Optimal salinity can be measured by
performing a salinity scan (phase behavior test) with alkali on a
mixture of an injection water, crude oil, and surfactant; where the
point at which equal volumes of crude oil and water are solubilized
is defined as the optimal salinity. Alkali concentration at optimal
salinity is different for every crude/surfactant combination (see
examples in FIGS. 4 to 6). In embodiments, the alkali in the AP or
ASP slugs provides, contributes, or maintains the salinity. For
highest oil recovery, it is desirable to maintain optimal salinity
over the longest duration in the subsurface.
[0030] "High pH" is a pH which successfully reduces the amount of
surfactant adsorbed by a reservoir and maintains the surfactant in
an environment which results in low interfacial tension. In some
embodiments, "High pH" is between about 8 to 14, between about 9 to
12, or >8 pH.
[0031] "Effective amount," when used in reference to surfactant,
refers to an amount sufficient to affect an increase in oil
recovery over not including the component. For example, an
effective amount of surfactant in an ASP slug would increase oil
recovery over only using the equivalent AP slug without
surfactant.
[0032] "Pore volume" or "PV" fraction as used herein refers to the
total volume of pore space in the oil reservoir that is
contemplated in a sweep (contacted pore space at ASP, AP, PD
mobility ratio).
[0033] FIG. 1 is an example oil recovery system which includes
injection well 11 which extends to a portion of a subsurface
reservoir 13 containing hydrocarbons for production, such that
injection well 11 is in fluid communication with subsurface
reservoir 13 and the hydrocarbons. Production well 15 is also in
fluid communication with reservoir 13 in order to receive the
hydrocarbons. Production well 15 is positioned a lateral distance
away from injection well 11. For example, production well 15 can be
positioned between 50 feet to 10,000 feet away from injection well
11. There can be additional production wells (not shown) at
predetermined locations to optimally receive the hydrocarbons being
pushed through reservoir 13 due to injections from additional
injection wells (not shown).
[0034] In an embodiment, as illustrated in FIG. 1, a first AP slug
17 is injected through the injection well 11 into reservoir 13. The
first AP slug 17 may be preceded by a pre-flush, such as a
pre-flush of softened water at any desired salinity. As described
further below, the AP slug comprises alkali and polymer. The first
AP slug 17 disperses through reservoir 13, with at least a portion
thereof proceeding toward production well 15.
[0035] Following the injection of the first AP slug 17, an ASP slug
21 is injected in to the reservoir, as shown in FIG. 2. The
trailing edge of the first AP slug 17 keeps the leading edge of the
ASP slug 21 around optimal salinity and around optimal pH. The ASP
slug 21 is then followed by the second AP slug 31, as shown in FIG.
3. The leading edge of the second AP slug 31 keeps the trailing
edge of the ASP slug 21 at around optimal salinity and around
optimal pH.
[0036] A driver or chaser slug, "polymer drive" may be injected
through the injection well into the reservoir after the second AP
slug 31 or the second AP slug 31 may function as the polymer drive
where desired. The polymer used in the chaser slug can be the same
polymer used in slugs 17, 21, or 31, or may be different. In one
embodiment, multiple chaser slugs can be injected. For example, a
first chaser slug containing a small amount of polymer can be
injected and the followed by a second chaser slug containing a
larger amount of polymer.
[0037] The methods of the disclosure may be performed on-shore or
off-shore, and may be adjusted to make the most efficient use of
the location. As an example, seawater may be used as an aqueous
base for any of the slugs described here, since off-shore
production facilities tend to have an abundance of seawater
available, limited storage space, and transportation costs to and
from off-shore site are typically high. If seawater is used as the
aqueous base, it is usually softened prior to the addition of the
alkali, polymer and/or surfactant, thereby removing any multivalent
ions, specifically Mg and Ca, as they can precipitate and cause
injection problems. Additionally, the alkali, polymer, and
surfactants may be added to an aqueous base fluid in a solid form
or in a solution. Solid forms may be put into solution prior to
addition to the production fluid or the solid form may be directly
added to the production fluid.
[0038] Embodiments of the disclosure are practiced in high
temperature reservoirs, for example, greater than 50.degree. C.,
greater than 55.degree. C., greater than 60.degree. C., greater
than 65.degree. C., greater than 70.degree. C., greater than
80.degree. C., or greater than 90.degree. C. In some embodiments,
the temperature of the reservoir is 15.degree. C. to over
100.degree. C.
[0039] Pre-ASP and Post-ASP AP Slug
[0040] As discussed in reference to FIGS. 1 and 3, in one
embodiment AP slugs 17 and 31 used in flooding processes for
enhanced oil recovery in reservoirs comprise effective amounts of
alkali and polymer in an aqueous solution and do not compromise an
effective amount of a surfactant. The alkali and polymer used in
the first AP slug 17 and the second AP slug 31 may be the same or
different. Additionally, the alkali and polymers may be
compositions comprising more than one alkali or polymer. The
aqueous solution which comprises the alkali and polymer can be a
softened brine with a lower TDS than necessary for "Optimal
Salinity" (because of the desire to add an alkali to achieve
"Optimal" or near "Optimal Salinity"). For example, the aqueous
solution comprises from about 100 to about 150,000 ppm total
dissolved solids. The experiments in FIGS. 4 to 6 have a softened
water source of 3000 ppm TDS. The dissolved solid may be NaCl, or
KCl, or any combination of other monovalent salts. The optimal
composition of the AP solution will vary based on the nature of the
oil that is being recovered, the nature of reservoir that it is
being recovered from, and the nature of the surfactant composition
used in the ASP slug 21.
[0041] For each reservoir operation, an optimal salinity can be
determined, and the AP slugs 17 and 31 can be mixed in order to
achieve the optimal salinity. Such methods for achieving optimal
salinity are described and taught by "Identification and Evaluation
of High-Performance EOR Surfactants," D. B. Levitt, A. C. Jackson,
C. Heinson, L. N. Britton, T. Malik, V. Dwarakanath, and G. A.
Pope, SPE/DOE Symposium on Improved Oil Recovery (SPE 100089),
22-26 Apr. 2006, Tulsa, Okla., USA, 2006. The formulation of the
first AP slug 17 is typically responsive to the amount of
electrolytes associated with the reservoir and/or the water (mixing
with produced water or fresh). For a low salinity field where a
non-negative salinity gradient ("The Effect of a Non-Negative
Salinity Gradient on ASP Flood Performance" Levitt, D. B;
Chamerois, M.; Bourrel, M., Gauer, P.; Morel, D. SPE 144938,
Presented at the SPE Enhanced Oil Recovery Conference, Kuala
Lumpur, Malaysia, 19-21 Jul. 2011) may be employed, AP slug 17
generally is some optimized proportion of "Optimal Salinity." For
example, in the experiments of FIGS. 5 and 6, background formation
brine salinity was 3000 ppm hard brine, AP slug was injected at
7400 ppm alkali (Na.sub.2CO.sub.3). This alkali concentration is
80% optimal salinity. The extra mass of alkali not only functions
to reduce surfactant adsorption via high pH and remove multivalent
cation interactions with the surfactant, but also aids in
maintaining an optimal salinity environment throughout the entire
flood.
[0042] As used herein, an "alkali-polymer slug," "pre-ASP Aslug,"
"post-ASP Aslug," or "Aslug" refers to a slug which comprises both
alkali and polymer. The AP slug does not comprise an effective
amount of surfactant, but does comprise effective amounts of
alkali, and effective amounts of polymer. Effective amounts of
alkali are concentrations of alkali that help maintain a high pH
and desired salinity of the ASP slug 21. In one example, the
effective amounts of alkali are within 20%, are within 10%, are
within 5%, are within 3% or are equal to the optimal levels of
salinity and pH determined for a specific reservoir operation. For
example, effective amounts of alkali could include, but are not
limited to about 0.5% to 10%, 0.5% to 5%, or greater than the
minimum effective propagation concentration ("Selection and
Evaluation of Surfactants for Field Pilots," Dean, R. M., M. S.
Thesis 2011. University of Texas at Austin, Austin, Tex.).
[0043] Effective amounts of polymer are concentrations that allow
the slug to efficiently sweep the reservoir. The required viscosity
is a function of mobility ratio. Mobility ratio (M) is defined as
water (or ASP) relative permeability divided by oil relative
permeability multiplied by oil viscosity divided by water (or ASP)
viscosity (krw/kro*.mu.o/.mu.w). Generally a unit mobility ratio,
M=1, or lower is desired in an ASP flood. In one example, effective
amounts of polymer are equal to or less than that of each
subsequent slug's viscosity in order obtain favorable mobility
ratio throughout the entire flood process. For example, effective
amounts of polymer include, but are not limited to about 250 ppm to
about 5,000 ppm, such as about 500 to about 2500 ppm concentration,
or about 750 to 3000 ppm in order to achieve a favorable mobility
ratio under the reservoir conditions of temperature. Additionally,
in some embodiments, the pre-ASP AP slug and the post-ASP AP slug
comprise about the same or different amounts of alkali. In other
embodiments, the pre-ASP AP slug and the post-ASP AP slug comprise
the same or different amounts of polymer.
[0044] For each reservoir operation, the optimal slug volume for
either or both AP slugs 17 and 31 may be determined. For example,
the AP slugs may be injected into the reservoir in volumes of
between 0.05 to 0.5 PV, 0.1 to 0.4 PV, or .about.0.1 PV. The
necessary slug size can be determined through core flooding
experiments and simulation. The volume of first AP slug 17 may be
the equal to, or different from the volume of the second AP slug
31. The speed of injection of the slugs may also vary depending on
the reservoir operations.
[0045] ASP Slug
[0046] As discussed in reference to FIG. 2, ASP slug 21 used in
flooding techniques for enhanced oil recovery in reservoirs
comprises an alkali, a surfactant, and a polymer in an aqueous
solution. The alkali and polymer used may be the same or different
from the alkali and polymers used in the first and second AP slugs
17 and 31. Additionally, the alkali, surfactant and polymers may be
compositions comprising more than one alkali, surfactant or
polymer. In one embodiment, the aqueous solution comprises from
about 500 to about 10,000 ppm total dissolved solids, such about
2,000 to about 8,000 ppm, about 1,000 ppm to about 5,000 ppm, or
about 5,000 to about 9,500 ppm. The dissolved solid may be
monovalent cations and their corresponding anions in the softened
brine and additional alkali to achieve the predetermined optimal
salinity. The optimal composition of the ASP solution will vary
based on the nature of the oil that is being recovered and the
nature of reservoir that it is being recovered from.
[0047] As discussed above for the AP slugs, for each reservoir
operation, an optimal salinity and pH can be determined. The ASP
slug 21 can be mixed in order to achieve the optimal salinity and
pH. Such methods for achieving optimal salinity are described and
taught by "Identification and Evaluation of High-Performance EOR
Surfactants," D. B. Levitt, A. C. Jackson, C. Heinson, L. N.
Britton, T. Malik, V. Dwarakanath, and G. A. Pope, SPE Reservoir
Evaluation & Engineering (SPE 100089-PA-P), April 2009, p.
243-253. In an embodiment, the ASP solution may have a salt
tolerance of at least greater than the optimal salinity at
reservoir temperature while still recovering greater than 90
percent of the residual oil.
[0048] Additionally, an optimal amount of surfactant can be
predetermined. The optimal surfactant amount in a coreflood is the
minimum amount of surfactant that recovers >90% residual oil
additional oil with the lowest mass of surfactant. The
predetermined optimal surfactant formulation (surfactant,
co-surfactant, co-solvent, optimal salinity) is determined by lab
phase behavior measurements (see Levitt 2009 for method). The
predetermined optimal surfactant amount is calculated without
taking into account the additional pre-ASP and post-ASP AP slugs.
This predetermined optimal surfactant amount is considered the
"normal" mass of surfactant one would add to a conventional ASP
slug. In an embodiment, with the use of the pre-ASP and post-ASP AP
slugs, a lower mass of surfactant may be used than the normal
amount.
[0049] As used herein, an "alkali-surfactant-polymer slug" or "ASP
slug" refers to a slug which comprises alkali, polymer and
surfactant. Effective amounts of alkali are concentrations of
alkali that help maintain the pH and salinity of the ASP slug 21.
In one example, the effective amounts of alkali are within 30%,
within 20%, within 10%, within 5%, within 3% or are equal to the
optimal levels of salinity determined for a specific reservoir
operation. For example, effective amounts of alkali could include
any concentration greater than the minimum amount required to
propagate pH through the reservoir, which is dependent upon
salinity, hardness, clay content, CEC, and Temperature (Dean,
2011), all the way to as high as the concentration required in the
ASP slug. Effective amounts of polymer are concentrations that
allow the slug to efficiently sweep the reservoir. Viscosity at a
given concentration is dependent on salinity, therefore viscosity
must be compared when slugs have differing concentrations of
alkali. In one example, effective viscosities of polymer are within
20%, within 10%, within 5%, within 3% or are equal to the optimal
levels of viscosity determined for a specific reservoir operation.
For example, effective amounts of polymer include, but are not
limited to about 250 ppm to about 5,000 ppm, such as about 500 to
about 4000 ppm concentration, or about 1000 to 4000 ppm in order to
match or exceed the reservoir oil viscosity under the reservoir
conditions of temperature and pressure.
[0050] Effective amounts of surfactant are concentrations which can
be propagated at a velocity within 25% to that of the polymer and
alkali and are well above the critical micelle concentration (CMC)
and/or increases the amount of oil recovered from a reservoir. For
example, effective amounts of surfactant could include, but are not
limited to about 0.1 to 5.0% by weight, or about 0.3% to 3% by
weight. In one embodiment, the surfactant mass used is within about
1 wt % *0.30 PV; i.e. 2 wt % *0.15 PV; 0.5 wt %*0.6 PV, or about 1
wt % *0.25 PV. The slug size is dependent upon the concentration
used. Optimized total mass tries to be equal to the total estimated
amount of surfactant that will adsorb or be retained in the
reservoir.
[0051] The volume of the ASP slug 21 may be the equal to, or
different from the volumes of the first and second AP slugs 17 and
31. The speed of injection of the slugs may also vary depending on
the reservoir operations.
[0052] Polymer
[0053] Water soluble polymers, such as those commonly employed for
enhanced oil recovery, are included to control the mobility of the
injection solution. Such polymers include, but are not limited to,
biopolymers such as xanthan gum and scleroglucan and synthetic
polymers such as partially hydrolyzed polyacrylamides (HPAMs or
PHPAs) and hydrophobically-modified associative polymers (APs).
Also included are co-polymers of polyacrylamide (PAM) and one or
both of 2-acrylamido 2-methylpropane sulfonic acid (and/or sodium
salt) commonly referred to as AMPS (also more generally known as
acrylamido tertiobutyl sulfonic acid or ATBS) and N-vinyl
pyrrolidone (NVP). Molecular weights (Mw) of the polymers range
from about 100,000 Daltons to about 30,000,000 Daltons, such as
about 100,000 to about 500,000, or about 1,000,000 to about
20,000,000 Daltons. In specific embodiments of the invention the
polymer is about 2,000,000 Daltons, about 8,000,000 Daltons, or
about 20,000,000 Daltons. The polymer and the size of the polymer
may be tailored to the permeability, temperature and salinity of
the reservoir.
[0054] Surfactant
[0055] Surfactants are included to lower the interfacial tension
between the oil and water phase to less than about 10 -2 dyne/cm
(for example) and thereby recover additional oil by mobilizing and
solubilizing oil trapped by capillary forces. Examples of
surfactants that can be utilized include, but are not limited to,
anionic surfactants, cationic surfactants, amphoteric surfactants,
non-ionic surfactants, or a combination thereof. Anionic
surfactants can include sulfates, sulfonates, phosphates, or
carboxylates. Such anionic surfactants are known and described in
the art in, for example, U.S. Pat. No. 7,770,641, incorporated
herein in full. Examples of specific anionic surfactants include
internal olefin sulfonates, isomerized olefin sulfonates, alkyl
aryl sulfonates, medium alcohol (C10 to C17) alkoxy sulfates,
alcohol ether [alkoxy]carboxylates, and alcohol ether
[alkoxy]sulfates. Example cationic surfactants include primary,
secondary, or tertiary amines, or quaternary ammonium cations.
Example amphoteric surfactants include cationic surfactants that
are linked to a terminal sulfonate or carboxylate group. Example
non-ionic surfactants include alcohol alkoxylates such as alkylaryl
alkoxy alcohols or alkyl alkoxy alcohols. Other non-ionic
surfactants can include alkyl alkoxylated esters and alkyl
polyglycosides. In some embodiments, multiple non-ionic surfactants
such as non-ionic alcohols or non-ionic esters are combined. As a
skilled artisan may appreciate, the surfactant(s) selection may
vary depending upon such factors as salinity, temperature, and clay
content in the reservoir. The surfactants can be injected in any
manner such as continuously or in a batch process.
[0056] Alkali
[0057] The alkali employed is a basic salt of an alkali metal from
Group IA metals of the Periodic Table. In an embodiment, the alkali
metal salt is a base, such as an alkali metal hydroxide, carbonate
or bicarbonate, including, but not limited to, sodium carbonate,
sodium bicarbonate, sodium hydroxide, potassium hydroxide, sodium
silicate, tetrasodium EDTA, sodium metaborate, sodium citrate, and
sodium tetraborate. The alkali is typically used in amounts ranging
from about 0.3 to about 5.0 weight percent of the solution, such as
about 0.5 to about 3 weight percent. As previously discussed, use
of the alkali maintains surfactant in a high pH environment,
thereby minimizing surfactant adsorption. Alkali also protects the
surfactant from hardness. Using alkali before and after the ASP
slug helps to minimize surfactant adsorption, as a high pH
environment is maintained through any diffusion of the ASP
slug.
[0058] Additional Additives
[0059] The slugs described throughout this disclosure, including
the AP slugs 17 and 31, the ASP slug 21, and any chaser slugs can
also include additional additives. These additives include
chelators, co-solvents, reducing agents/oxygen scavengers, and
biocides. Chelators may be used to complex with multivalent cations
and soften the water in the solution. Examples of chelators include
ethylenediaminetetraacetic acid (EDTA) which can also be used as an
alkali, methylglycinediacetic acid (MGDA). Chelants may be utilized
to handle hard brines. The amount of chelant may be selected based
on the amount of divalent ions in the slug solutions. For example,
chelating agents can be used a 10:1 molar ratio with divalent
cations such as calcium or magnesium. Other chelating agents may
work depending on the brine composition and the desired pH.
[0060] Co-solvents may also be included in the slug compositions.
Suitable co-solvents are alcohols, such as lower carbon chain
alcohols like isopropyl alcohol, ethanol, n-propyl alcohol, n-butyl
alcohol, sec-butyl alcohol, n-amyl alcohol, sec-amyl alcohol,
n-hexyl alcohol, sec-hexyl alcohol and the like; alcohol ethers,
polyalkylene alcohol ethers, polyalkylene glycols,
poly(oxyalkylene)glycols, poly(oxyalkylene)glycols ethers or any
other common organic co-solvent or combinations of any two or more
co-solvents. For example, in an embodiment, an ether, ethylene
glycol butyl ether (EGBE), is used and typically is about 0.75 to
1.5 times the concentration of surfactant of ASP slug 21.
Generally, the co-solvent when used may be present in an amount of
about 0.5 to about 6.0 weight percent of the solution, such as from
about 0.5 to about 4.0 weight percent, or about 0.5 to about 3
weight percent.
[0061] Reducing agents/oxygen scavengers such as sodium dithionite
may be used to remove any oxygen in the mixture and reduce any free
iron into Fe.sup.2+. They are used to protect synthetic polymers
from reactions that cleave the polymer molecule and lower or remove
viscosifying abilities. A reduced environment also lowers
surfactant adsorption.
[0062] Biocides are used to prevent organic (algal) growth in
facilities, stop sulfate reducing bacteria (SRB) growth which
"sour" the reservoir by producing dangerous and deadly H.sub.2S,
and are also used to protect biopolymers from biological life which
feed on their sugar-like structures and therefore remove mobility
control. Biocides include aldehydes and quaternary ammonium
compounds.
EXAMPLES
[0063] The following examples are included to demonstrate specific
embodiments of the disclosure. It should be appreciated by those of
skill in the art that the techniques disclosed in the examples that
follow represent techniques discovered by the inventors to function
well in the practice of the invention, and thus, can be considered
to constitute modes for its practice. However, those skilled in the
art should, in light of the present disclosure, appreciate that
many changes can be made in the specific embodiments disclosed and
still obtain a like or similar result without departing from the
scope of the invention.
Example 1
Core Floods
[0064] Core flood experiments were conducted according to known
laboratory methods for reservoir cores where the reservoir salinity
was less than the optimal salinity for an ASP slug. In this
example, five core floods were run using a brine flood core. The
core was first oil flooded to initial oil saturation levels
(S.sub.oi), after which they were water flooded to residual oil
saturation (S.sub.orw). Note, S.sub.oi and S.sub.orw will be
specific to a particular reservoir. The four core floods proceeded
as follows:
[0065] Flood #1: post-ASP AP slug only in Reservoir Core [0066]
Injected an ASP slug with a normal mass of S. [0067] Injected an AP
slug (post-ASP AP slug). [0068] Injected a P slug (Polymer
Drive).
[0069] Flood #2: pre and post-ASP AP slug in Reservoir Core [0070]
Injected an AP slug (pre-ASP AP slug). [0071] Injected an ASP slug
in core floods with a normal mass of S. [0072] Injected an AP slug
(post-ASP AP slug). [0073] Injected a P slug (Polymer Drive).
[0074] Flood #3: pre and post-ASP AP slugs with lower S in
Reservoir Core [0075] Injected an AP slug (pre-ASP AP slug). [0076]
Injected an ASP slug in core floods with a lower mass of S than
required [0077] Injected an AP slug (post-ASP AP slug). [0078]
Injected a P slug (Polymer Drive).
[0079] Flood #4: control in Surrogate Core [0080] Inject an ASP
slug in core floods with a normal mass of S. [0081] Injected a P
slug (Polymer Drive).
[0082] Flood #5: pre and post-ASP AP slug in Surrogate Core [0083]
Injected an AP slug (pre-ASP AP slug). [0084] Injected an ASP slug
in core floods with a normal mass of S. [0085] Injected an AP slug
(post-ASP AP slug). [0086] Injected a P slug (Polymer Drive).
[0087] A summary of the floods follows in Table 1. The polymer was
an AMPS polymer manufactured by SNF. The brine was a softened
version of the 3000 ppm formation brine. The surfactant blend was a
mixture of anionic sulfonate surfactants. The co-solvent was
EGBE.
TABLE-US-00001 TABLE 1 Summary of floods 1-5. Composition Flood 1
Flood 2 Flood 3 Flood 4 Flood 5 Slug 1 Polymer -- 2750 ppm 2750 ppm
-- 2750 ppm (pre- Brine -- 3000 ppm 3000 ppm -- 3000 ppm ASP AP)
NaCl NaCl NaCl Na.sub.2CO.sub.3 -- 0.72% (80% 0.72% (80% -- 0.72%
S*) S*) (80% S*) Volume -- 0.10 PV 0.15 PV -- 0.15 PV Viscosity --
10.5 cP 10.5 cP -- 10.5 cP Slug 2 Surfactant 1.50% 1.50% 1.50%
1.50% 1.50% (ASP) Co. 0.50% 0.50% 0.50% 0.50% 0.50% Surfactant Co-
2.80% 2.80% 2.80% 2.80% 2.80% solvent Polymer 3500 ppm 3500 ppm
2750 ppm 3600* ppm 2750 ppm Brine 3000 ppm 3000 ppm 3000 ppm 3000
ppm 3000 ppm NaCl NaCl NaCl NaCl NaCl Na.sub.2CO.sub.3 0.90% 0.90%
0.90% 0.90% 0.90% Volume 0.15 PV 0.15 PV 0.10 PV 0.15 PV 0.10 PV
Viscosity 10.5 cP 10.5 cP 6.5 cP 17 cP 6.5 cP Slug 3 Co- 1.50%
1.50% 1.50% -- 1.50% (post- solvent ASP AP) Polymer 3500 ppm 3200
ppm 2750 ppm -- 2750 ppm Brine 3000 ppm 3000 ppm 3000 ppm -- 3000
ppm NaCl NaCl NaCl NaCl Na.sub.2CO.sub.3 0.72% (85% 0.72% (80%
0.72% (80% -- 0.72% S*) S*) S*) (80% S*) Volume 0.10 PV 0.10 PV
0.10 PV -- 0.10 PV Viscosity 11.5 cP 10.5 cP 8.5 cP -- 8.5 cP Slug
4 Polymer 2000 ppm 2000 ppm 2000 ppm 2000 ppm 2000 ppm (Polymer
Brine 3000 ppm 3000 ppm 3000 ppm 3000 ppm 3000 ppm Drive) NaCl NaCl
NaCl NaCl NaCl Volume 1.75 PV 1.65 PV 1.65 PV 1.75 PV 1.65 PV
Viscosity 13 cP 13 cP 13 cP 18 cP 13 cP Result Residual 84.40% 96%
91.1% 88.2% 94.9% Oil Recovery Core Reservoir Reservoir Reservoir
Bentheimer Bentheimer
[0088] Flood 2 showed the highest oil recovery, while Flood 3
illustrates that equal or better oil recovery can be achieved with
less surfactant by employing an AP sandwich. Graphs of oil
recovered, oil cut per pore volume for Floods 1-5 are shown in
FIGS. 4-8, respectively. This example illustrates that improved oil
recovery is achieved using a pre-ASP AP slug and/or a post-ASP AP
slug.
Example 2
Core Floods in Surrogate Core
[0089] In this example, two core floods were run using a brine
flood core. The core was first oil flooded to initial oil
saturation levels (S.sub.oi), after which they were water flooded
to residual oil saturation (S.sub.orw). Note, S.sub.oi and
S.sub.orw will be specific to a particular reservoir. The two core
floods proceeded as follows:
[0090] Flood #6: control in Surrogate Core [0091] Inject an ASP
slug in core floods with a normal mass of S. [0092] Injected a P
slug (Polymer Drive).
[0093] Flood #7: pre and post-ASP AP slug in Surrogate Core [0094]
Injected an AP slug (pre-ASP AP slug). [0095] Injected an ASP slug
in core floods with half the mass of surfactant than Flood #6.
[0096] Injected an AP slug (post-ASP AP slug). [0097] Injected a P
slug (Polymer Drive).
[0098] A summary Floods 6 and 7 is found in Table 2. The polymer
was an AMPS polymer manufactured by SNF. The brine was a softened
version of the 30,000 ppm formation brine. The surfactant blend was
a mixture of anionic sulfonate surfactants. The co-solvent was
EGBE.
TABLE-US-00002 TABLE 2 Summary of floods 5 and 6. Composition Flood
5 Flood 6 Slug 1 (pre-ASP AP) Polymer -- 3,000 ppm Brine -- 30,000
ppm NaCl Na.sub.2CO.sub.3 -- 2.00% Volume -- 0.19PV Viscosity -- 16
Slug 2 (ASP) Surfactant 2.00% 2.00% Co. Surfactant -- -- Co-solvent
3.00% 3.00% Polymer 3,000 ppm 3,000 ppm Brine 30,000 ppm NaCl
30,000 ppm NaCl 2,000 CaCl.sub.2 Na.sub.2CO.sub.3 1.75% 2.00%
Volume 0.30 PV 0.15 PV Viscosity 16 16 Slug 3 (post-ASP AP)
Co-solvent -- -- Polymer -- 3,200 ppm Brine -- 30,000 ppm NaCl
Na.sub.2CO.sub.3 -- 0.75% Volume -- 0.15 PV Viscosity -- 18.7 Slug
4 (Polymer Drive) Polymer 3,200 ppm 3,200 ppm Brine 30,000 ppm NaCl
30,000 ppm NaCl Volume 1.50 PV 1.30 PV Viscosity 18 18 Result
Residual Oil Recovery 99.3% 91.5% Core Bentheimer Bentheimer
[0099] While Flood 6 showed the highest oil recovery, Flood 7 used
half the surfactant, but still recovered more than 90% of the
residual oil. Graphs of oil recovered, oil cut per pore volume, and
oil saturation per pore volume injected for Floods 6 and 7 are
shown in FIGS. 9 and 10, respectively. This example illustrates
that half the amount of surfactant can be used in conjunction with
pre- and post-AP floods and still recover greater than 90% of
residual oil.
[0100] Although the present invention and its advantages have been
described in detail, it should be understood that various changes,
substitutions and alterations can be made herein without departing
from the scope of the invention as defined by the appended claims.
Moreover, the scope of the present disclosure is not intended to be
limited to the particular embodiments of the process, machine,
manufacture, composition of matter, means, methods and steps
described in the specification. As one of ordinary skill in the art
will readily appreciate from the disclosure of the present
invention, processes, machines, manufacture, compositions of
matter, means, methods or steps, presently existing or later to be
developed that perform substantially the same function or achieve
substantially the same result as the corresponding embodiments
described herein may be utilized according to the present
invention. Accordingly, the appended claims are intended to include
within their scope such processes, machines, manufacture,
compositions of matter, means, methods, or steps.
* * * * *