U.S. patent application number 13/826827 was filed with the patent office on 2013-09-26 for ultra low concentration surfactant flooding.
This patent application is currently assigned to Glori Energy Inc.. The applicant listed for this patent is GLORI ENERGY INC.. Invention is credited to Egil Sunde.
Application Number | 20130248176 13/826827 |
Document ID | / |
Family ID | 49210702 |
Filed Date | 2013-09-26 |
United States Patent
Application |
20130248176 |
Kind Code |
A1 |
Sunde; Egil |
September 26, 2013 |
ULTRA LOW CONCENTRATION SURFACTANT FLOODING
Abstract
A method of recovering oil from a formation that includes the
use of surfactants at low concentrations. The surfactant may be an
oleophilic surfactant. The method may include conditioning an oil
recovery system to inhibit microbes that could consume the
oleophilic surfactant. A method that determines the concentration
of a surfactant that is sufficient to change the interfacial
tension between oil and water in a near well bore area of an
injection well in a formation but does not require changing the
interfacial tension between oil and water outside the near well
bore area.
Inventors: |
Sunde; Egil; (Sandnes,
NO) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
GLORI ENERGY INC. |
Houston |
TX |
US |
|
|
Assignee: |
Glori Energy Inc.
Houston
TX
|
Family ID: |
49210702 |
Appl. No.: |
13/826827 |
Filed: |
March 14, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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61614882 |
Mar 23, 2012 |
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Current U.S.
Class: |
166/270.1 |
Current CPC
Class: |
C09K 8/584 20130101;
E21B 43/16 20130101; E21B 43/20 20130101 |
Class at
Publication: |
166/270.1 |
International
Class: |
E21B 43/16 20060101
E21B043/16 |
Claims
1. A method of recovering oil from a formation, said method
comprising: injecting a drive fluid into said formation; injecting
an oleophilic surfactant into said formation at a concentration of
0.1 to 100 mg/l of said injected fluid; and recovering said oil
from said formation.
2. The method of claim 1 further comprising: reducing a microbe
population in said formation.
3. The method of claim 2 wherein said reduction of microbe
population comprises injecting, into said formation, a selection
from the list consisting of: a biocide, a biostat and combinations
thereof.
4. The method of claim 2 wherein said reduction of microbe
population comprises adjusting the pH of the injection fluid to
inhibit microbial growth.
5. The method of claim 2 wherein said reduction of microbe
population comprises exposing said microbe population to a
predetermined temperature to inhibit microbial growth.
6. The method of claim 1 wherein said injection of drive fluid and
said injection of oleophilic surfactant includes preparing a
mixture of said drive fluid and said oleophilic surfactant and
injecting said mixture via an injection well in said formation.
7. The method of claim 1 wherein said injection of fluid is done
via an injection well in said formation and said injection of said
oleophilic surfactant is done via a capillary tube leading from a
surfactant source to the near well bore area of said injection
well.
8. The method of claim 1 wherein said oleophilic surfactant is
injected in batches to achieve said concentration of 0.1 to 100
mg/l over a predetermined period.
9. The method of claim 1 wherein said oleophilic surfactant is
injected continuously to achieve said concentration of 0.1 to 100
mg/l.
10. The method of claim 1 wherein said oleophilic surfactant is
selected from the list consisting of: sorbitan trioleate, sorbitan
tristearate, sorbitan monooleate, sorbitan monolaurate, compounds
comprising: amyl alcohols, hexyl alcohols, decyl alcohols, cresols
and p-nonyl phenol and combinations thereof.
11. The method of claim 1 wherein said fluid comprises material
selected from the list consisting of: water, brine, produced water
and combinations thereof.
12. The method of claim 1 wherein said recovering does not include
the use of a mobility control slug.
13. The method of claim 1 wherein said recovering does not include
the use of a preflush slug.
14. The method of claim 1 wherein said formation has been water
flooded to a residual oil saturation.
15. A method of recovering oil from a formation, said method
comprising: injecting a drive fluid into said formation; injecting
an oleophilic surfactant into said formation at a concentration
that allows said surfactant to change interfacial tension between
oil and water in a near well bore area of an injection well in a
formation, but does not change interfacial tension between oil and
water outside said near well bore area; and recovering said oil
from said formation.
16. The method of claim 15 wherein said oleophilic surfactant is
selected from the list consisting of: sorbitan trioleate, sorbitan
tristearate, sorbitan monooleate, sorbitan monolaurate, compounds
comprising: amyl alcohols, hexyl alcohols, decyl alcohols, cresols
and p-nonyl phenol and combinations thereof.
17. The method of claim 15 wherein said near well bore area is 50
meters or less from said well.
18. A method of recovering oil from a formation, said method
comprising: injecting an oleophilic surfactant into said formation,
injecting flood water into said formation, wherein said oleophilic
surfactant is injected at a concentration of 0.1 to 100 mg/l of
said injected flood water and wherein said injection of fluid is
done via an injection well in said formation and said injection of
surfactant is done via a capillary tube leading from a surfactant
source to the near well bore area of said injection well;
injecting, into said formation, a selection from the list
consisting of: a biocide, a biostat and combinations thereof;
recovering said oil from said formation.
19. The method of claim 18 wherein said injection of said flood
water and said injection of oleophilic surfactant is done via an
injection well in said formation and said recovery is via a
production well in said formation.
20. The method of claim 18 wherein said oleophilic surfactant is
selected from the list consisting of: sorbitan trioleate, sorbitan
tristearate, sorbitan monooleate, sorbitan monolaurate, compounds
comprising: amyl alcohols, hexyl alcohols, decyl alcohols, cresols
and p-nonyl phenol and combinations thereof.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] The present application claims priority to co-pending U.S.
Provisional Patent Application No. 61/614,882, entitled "ULTRA LOW
CONCENTRATION SURFACTANT FLOODING", filed Mar. 23, 2012, the
disclosure of which is hereby incorporated herein by reference.
BACKGROUND OF THE INVENTION
[0002] Crude oil remains an important energy source. Crude oil
producers typically produce oil by drilling wells into underground
oil reservoirs in a formation. For some wells, the natural pressure
of the oil is sufficient to bring the oil to the surface. This is
known as primary recovery. Over time, as oil is recovered by
primary recovery for these wells, the natural pressure drops and
becomes insufficient to bring the oil to the surface. When this
happens, a large amount of crude oil may still be left in the
formation. Consequently, various secondary and tertiary recovery
processes may be employed to recover more oil. Secondary and
tertiary recovery processes may include: pumping, water injection,
natural gas reinjection, air injection, carbon dioxide injection or
injection of some other gas into the reservoir.
[0003] The injection of fluids in the well is a common enhanced oil
recovery method. Water is the most economical and widely used.
Water flooding involves the injection of water into an oil-bearing
reservoir. The injected water displaces the oil from the reservoir
to a production system of one or more production wells from which
the oil is recovered. Water, however, does not displace oil
efficiently because water and oil are immiscible due to high
interfacial tension between these two liquids.
[0004] As discussed in U.S. Pat. No. 6,828,281, entitled
"Surfactant Blends for Aqueous Solutions Useful for Improving Oil
Recovery," it is generally accepted that this high interfacial
tension between injected water and reservoir oil and the
wettability characteristics of rock surfaces within the reservoir
are factors which can negatively influence the amount of oil
recovered by water flooding. One technique for increasing the oil
recovery of waterflooding has been to add surfactants to the
injected water so as to lower the oil/water interfacial tension
and/or alter the reservoir rock's wettability characteristics.
Reducing the interfacial tension in this way allows the water
pressure to act on the residual oil more effectively and thereby
improve the movement of the oil through channels of the reservoir.
It is generally accepted that the interfacial tension between the
surfactant treated water and the reservoir oil should be reduced to
less than 0.1 dyne/cm for low-tension water flooding to provide
effective recovery. Generally, it is assumed that adding one or
more surface active agents or surfactants to the injected water
forms a solution or emulsion of surfactants that sweeps through the
formation and displace oil.
[0005] Currently, surfactants are designed to be miscible with
water and have relatively low affinity for oil so that the
surfactants can be transported deep into the reservoir and interact
with the surface of the residual oil and reduce the interfacial
tension over a large volume of the residual oil. To cover this
large volume of residual oil requires the application of a large
volume of surfactant, which makes the surfactant flooding process
expensive. Further, when large volumes of surfactants are added to
flood water, breakthrough may occur and cause emulsion problems in
the produced oil. Breakthrough occurs when the flood water makes
its way to the producing well and the residual oil is recovered in
a state of emulsion with the flood water. It is difficult to
separate emulsified oil into its constituent components (i.e. oil
and flood water).
BRIEF SUMMARY OF THE INVENTION
[0006] One aspect of arriving at the present disclosure involved a
new theory that the oil in the reservoir exists primarily as long
continuous strands as opposed to the prevailing theory in the art
that the oil exists in the reservoir primarily as droplets during
and after water flooding. According to the new theory, long strands
of oil extend from an injector well to a producer well. Further to
this theory, embodiments of the invention involve changing the flow
properties of the oil strands near the injector well, thereby
causing this oil to be displaced, which in turn displaces oil from
the affected strands towards the producer well. In other words,
changing the interfacial tension between oil and flood water near
the injection well area causes a chain reaction of oil flow towards
the production well, though the interfacial tension between oil and
flood water at locations that are not near the injection well need
not be changed and in embodiments are not changed.
[0007] Embodiments of the invention include a method of recovering
oil from a reservoir in a formation that includes injecting a fluid
into the reservoir and injecting a surfactant into the reservoir at
a predetermined concentration range of the injected fluid. In
embodiments, the predetermined concentration range is based on
providing sufficient surfactant to lower the interfacial tension
between flood water and oil in the near well bore area but there is
no requirement that the predetermined concentration range affects
the interfacial tension between flood water and oil outside the
near well bore area. In some embodiments, the interfacial tension
between flood water and oil outside the near well bore area is not
affected by the surfactant. Because only the near well bore area is
effectively being treated by the surfactant, the amount of
surfactant required is small compared with existing surfactant
water flooding methods. In some instances, when lower
concentrations of surfactant are used in the formation, the
surfactant may be susceptible to premature depletion as a result of
microbes within the formation consuming the surfactant. As such,
embodiments of the invention involve preventing the microbes from
consuming the surfactants. In embodiments of the invention, the
surfactants used in the flooding process are oleophilic
surfactants.
[0008] 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 which form the subject of the claims
of the invention. It should be appreciated by those skilled in the
art that the conception and specific embodiment 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 spirit
and 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
[0009] 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:
[0010] FIG. 1 shows a diagram of a system for implementing methods
according to embodiments of the invention;
[0011] FIG. 2 shows a flow chart illustrating steps according to
embodiments of the invention;
[0012] FIG. 3 illustrates equipment that may be used to carry out
core flood experiments according to embodiments of the invention;
and
[0013] FIG. 4 shows a graph of results achieved from experiment;
according to embodiments of the invention.
DETAILED DESCRIPTION OF THE INVENTION
[0014] FIG. 1 shows a diagram of a system for implementing methods
according to embodiments of the invention. System 10 includes an
injection well 100 and a production well 101. Oil 102 resides in
oil-bearing formation 105. Oil-bearing formation 105 may be any
type of geological formation and may be situated under overburden
104. Although formation 105 is shown as being onshore in FIG. 1, it
should be appreciated that formation 105 may be located onshore or
offshore. According to the new theory, previously mentioned, oil
102 primarily exists as strands 102-1 to 102-n within formation
105. The strands are of various lengths and may extend from
injection well 100 to production well 101 as shown. In addition,
the strands are 3-dimensional in nature and may cross link to other
strands throughout formation 105. See E. Sunde, B.-L. Lillebo, T.
Torsvik, SPE 154138, Towards a New Theory for Improved Oil Recovery
from Sandstone Reservoirs, the disclosure of which is incorporated
herein by reference in its entirety.
[0015] According to the new theory, oil 102 is trapped within
formation 105, not as unique distinct droplets, but as strands
(e.g. strands 102-1 to 102-n) in portions of formation 105's
network of pores small enough to put up resistance to the
surrounding drag and pressure drop of surrounding water flow. Oil
102 is continuous and present throughout the pore networks between
injection well 100 and production well 101. Between the pore
networks, there may be other parts of formation 105 where water
flow has almost completely cleared out the oil.
[0016] In a three-dimensional system, the oil will self-organize
according to the sum of pressures acting on it and the available
pore network, thereby also redistributing some of its surrounding
film of water. This and the fact that oil and water will seek the
greatest possible separation to minimize friction, will leave the
residual oil in continuous oil strands occupying pore spaces in all
three dimensions. However, the general orientation of the oil
strands will be parallel to the direction of flow due to the effect
of shear forces.
[0017] The branched oil strands, being continuous throughout the
reservoir, will not be produced because they are trapped by
capillary bound water in the pore throat in regions close to the
production well. As a consequence, shallow chemical treatment of
production wells is often successful in releasing this trapped
oil.
[0018] In current methods of surfactant water flooding, oil is
recovered from a formation by pumping surfactant sufficient to
treat, for example, the section of formation 105 shown as section
108. That is, current methods of surfactant water flooding seek to
treat, with a surfactant, all or most areas where there is oil in
the formation. This current method is based on the theory,
mentioned above, that the oil exists in the formation primarily as
droplets.
[0019] To be able to produce oil strands 102-1 to 102-n, the
capillary bound water blocking the pore throat must be removed.
This can be achieved in at least two ways. First, the water may be
removed from the pore throat by reducing the capillary forces in
the pore throat. Second, the water may be removed by increasing the
pressure in the oil strand.
[0020] Provided a blocking pore throat has become oil-filled, the
strand will easily be emptied into production well 101 because of
the existing pressure gradient in the formation. This is similar to
stepping on a tube of toothpaste. The water does not push the oil
strand from the end, but squeeze it from all sides. This implies
that water molecules are displaced on a scale of pore diameters,
while the oil can move hundreds of meters in a short time span,
because it flows as a continuous phase with minimal friction.
[0021] Reduction of the capillary forces around a production well
has been performed using surfactants or bacteria, so-called "huff
and puff". See Lake, L. W. 1989. Enhanced Oil Recovery.
Prentice-Hall Inc., Englewood Cliffs. ISBN 0-13-281601-6. A
relatively small amount of surfactant (or surfactant producing
bacteria) can be injected in the production well and this is then
put back on production. A substantial increase in oil production
can be obtained over a relatively short period using this method.
The amount of oil produced by this method is observed to be much
greater than the amount of residual oil the surfactant could
theoretically influence. Hence the oil must have been drawn in from
deep in the reservoir. This oil is often observed to have lower
viscosity than the oil produced previously. This further suggests
that the oil comes from areas that have not seen much water flow
and consequently, has not had its lighter hydrocarbon components
stripped off.
[0022] Increasing the pressure in the oil strands, (pressure
pulses) can also be created by skilled application of surfactants.
The pressure pulse can be obtained by applying surfactants to
reduce the surface tension of the oil strand at the water injection
well. Surfactants can break down surface tension to a level where
the oil/water interface collapses and the oil flows out.
Mathematical modeling indicates that the oil that flows out moves
towards the water flow and the pressure gradient. Sk.ae
butted.laaen, I. 2010, Mathematical Modelling of Microbial Induced
Processes in Oil Reservoirs. PhD thesis, University of Bergen,
Bergen, Norway (2010). A consequence of this will be the creation
of a sinusoidal pressure pulse in the opposite direction into the
strand. This pulse travels at the speed of sound in oil and its
amplitude is increased as the strand diameter becomes smaller. At
the end of the oil strand the pulse hits the water filled pore
throat and the kinetic energy is converted to pressure. Although
this is a relatively small force, it will add to the external
pressure gradient, so that the water in the pore throat is expelled
by the oil and the strand will be quickly emptied.
[0023] Consistent with the theory that oil 102 exists in formation
105 primarily as strands, embodiments of the invention change the
interfacial tension between oil and water only in the near well
bore area 103 of injection well 100. In embodiments of the
invention, the near well bore area 103 can extend up to 50 meters
from wellbore 100. FIG. 2 shows a flow chart illustrating steps
according to embodiments of the invention. Method 20 includes step
201, which involves determining a specific surfactant and
determining the concentration range of a surfactant that allows the
surfactant to change the interfacial tension between oil and water
in near well bore area 103 of injection well 100 but does not
require the surfactant to affect the interfacial tension between
oil and water outside near well bore area 103. In embodiments, the
surfactant does not affect the interfacial tension between oil and
water outside near well bore area 103. Because the surfactant is
directed to changing interfacial tension in the near well bore area
103 and not to other areas, the concentration of surfactant used is
low compared to traditional methods. In embodiments of the
invention, the concentration of surfactant to injected water is 100
mg/L or less. In embodiments, the concentrations may be in the
range of 0.1 to 100 mg/L of injected water. In embodiments, the
concentrations may be in the range of 0.1 to 75 mg/L of injected
water. In embodiments, the concentrations may be in the range of
0.1 to 50 mg/L of injected water. In embodiments, the
concentrations may be in the range of 0.1 to 25 mg/L of injected
water. Further, the traditional use of surfactants with low
affinity for oil in order to treat a large area (e.g. section 107)
is not necessary for the embodiments described herein. In
embodiments of the invention, oleophilic surfactants that may be
used as the active surfactant in the water flooding process include
commercially available surfactants such as sorbitan trioleate
(commercial name Span 85), sorbitan tristearate (commercial name
Span 65), sorbitan monooleate (commercial name Span 80), and
sorbitan monolaurate (commercial name Span 20); compounds
comprising amyl alcohols, hexyl alcohols, decyl alcohols, cresols
and p-nonyl phenol, and combinations thereof. The oleophilic
surfactants or the concentration ranges of the oleophilic
surfactants or both that may be used for water flooding may be
determined by methods such as core flood experiments, simulation
experiments etc. It should be noted that the core flood experiments
may include experiments on core samples from the formation being
considered.
[0024] The following method may be used to carry out core flood
experiments. To begin, prepare a cylindrical sandstone core to
resemble a reservoir in the residual situation having water and oil
in representative positions. Embed a sandstone core in epoxy,
evacuated to 9 torr and make water wet by saturating with brine.
Determine the physical properties of the core. For example,
determine the core's length, diameter, pore volume and absolute
permeability. Fill the core with crude oil and then flood with
brine until residual oil concentration is reached. Introduce an oil
soluble surfactant such as those described herein to the core at
concentrations in the range of 0.1-100 mg/L. Following surfactant
introduction, set the injection pump rate to 0.1 ml/min and
produced oil and water may be collected at the rate of one fraction
per hour.
[0025] Once the surfactant and its concentration range have been
determined at step 201, oleophilic surfactant is injected, at step
202, at the determined concentration range. At step 203, a drive
fluid, such as flood water, is injected into formation 105 via
injection well 100 to displace oil towards production well 101. In
embodiments, formation 105 has been waterflooded to a residual oil
saturation. It should be noted that the flood water, in
embodiments, may be produced water. In embodiments of the
invention, steps 202 and 203 may be carried out together. That is,
the oleophilic surfactant may be mixed with the fluid, such as
water, at the determined concentration. Alternatively or
additionally, oleophilic surfactant may be injected separately from
the injection of the fluid at step 203. For example, oleophilic
surfactant may be injected into formation 105 via a capillary tube
directly to well bore area 103 at a rate that achieves the
determined concentration range, taking into account the volume of
fluid injected via injection well 100. Capillary tubes for
injecting oxygen, among other things, are disclosed in U.S. patent
application Ser. No. 13/166,382 entitled Microbial Enhanced Oil
Recovery Delivery Systems and Methods, filed Jun. 22, 2011, the
disclosure of which is hereby incorporated by reference in its
entirety. Similar to some of the methods in that disclosure,
capillary tubes may be used to introduce oleophilic surfactants
into formation 105. The capillary tubes may be made from any
suitable material such as stainless steel, other metals, polymers
and the like. The capillary tube can have the cross sectional area
with the shape of a circle. However, the cross sectional area of
the capillary tube may include any shape such as ellipse, polygon
the like and combinations thereof. It should be noted that
whichever method is used to inject the oleophilic surfactant, the
injection may be done continuously or intermittently (i.e. in
batches).
[0026] The injection of surfactant sufficient to reduce the
interfacial tension between oil and water in near well bore area
103 without necessarily changing the interfacial tension within
section 107, facilitates the production of oil strands 102-1 to
102-n through section 107 to production well 101. Specifically,
reduction of interfacial tension between flood water and the
portion of the oil strands 102-1 to 102-n in near well bore area
103 causes a pulse that is propagated within oil strands 102-1 to
102-n through the formation and moves oil strands 102-1 to 102-n
through formation 105 to production well 101, from which the oil is
recovered.
[0027] Under the conditions of the present invention there is no
need for the use of a preflush slug nor a mobility control slug.
This represents a clear advantage over existing surfactant
application technologies.
[0028] Because, in embodiments of the invention, the concentration
of surfactant is low, the surfactant may be consumed as substrate
by microbes in the formation. Thus, it is desirable to condition
the injection system and water in the near well bore area to
inhibit microbes that may consume the surfactants. In embodiments,
this conditioning may include reducing the microbe population in
near well bore area 103. This can be accomplished either before,
simultaneously with, or after step 202 and/or step 203. Various
methods may be used to achieve this. These methods may be performed
by exposing the microbes to biocides and biostats, either high or
low pH, a particular temperature and combinations thereof. For
example, a biocide may be injected into formation 105 at near well
bore area 103 to kill the microbes. The capillary tubes described
above for injecting the surfactant may be used to introduce the
biocide into the near well bore area. Further, an initial high
concentration of oleophilic surfactant may be used, which is toxic
to microbes. Further yet, reducing the microbe population may
include exposing the microbes to a temperature or pH that is known
or predetermined to inhibit growth of the microbes or to kill the
microbes.
[0029] In embodiments of the invention, injecting the surfactant
directly into formation 105 allows the initial concentration of the
surfactant to be high. Ultimately, however, the overall
concentration of the oleophilic surfactant will be reduced as the
relatively large volume of flood water is injected. In embodiments
of the invention, any combination of biocide treatment, initial
high concentration of oleophilic surfactant, temperature control
and pH control may be used to prevent the microbes from consuming
the oleophilic surfactant.
[0030] Although a method according to embodiments of the present
invention has been described with reference to the steps of FIG. 2,
it should be appreciated that operation of the present invention is
not limited to the particular steps and/or the particular order of
the steps illustrated in FIG. 2. Accordingly, alternative
embodiments may provide functionality as described herein using
some or all the steps shown in FIG. 2 in a sequence different than
that shown. For example, in embodiments of the invention, step 204
may be eliminated because there is no issue with respect to the
microbes consuming the surfactant in a particular formation. Other
steps may be eliminated for other reasons. Further, in embodiments
of the invention, step 203 can be performed before or
simultaneously with step 202.
EXAMPLE OF CORE FLOOD EXPERIMENT THAT SUPPORTS THE PRESENT
DISCLOSURE
[0031] The following core flood experiment was conducted to show
the effect of low concentration surfactant flooding. FIG. 3
illustrates the equipment that was used to carry out this
experiment. A rock core plug was cleaned by solvent extraction,
dried to constant weight and encased in epoxy. The encased rock
core plug 301 was tested with pressure and vacuum cycles to assure
integrity. Encased rock core plug 301 was then saturated with a
2.5% (w/v) synthetic salt water solution under vacuum (20 g/L NaCl,
4 g/L Na.sub.2SO.sub.4, Sodium Bicarbonate at 1M (1:100
concentration), 1M HCl pH to 7.42, Autoclaved, Gassed with
N.sub.2). The saturation of encased rock core plug 301 is done by
using pump 303 to pump synthetic salt water solution from fluid
reservoir 302 into encased rock core plug 301. Digital sensor 304
measures differential pressure and back pressure valve 305 helps to
maintain pressure in encased rock core plug 301. The volume
required for saturation determined the pore volume within encased
rock core plug 301. Additional synthetic salt water solution was
injected through encased rock core plug 301 for a period greater
than 24 hours, after which crude oil was injected into the core
until no additional water was displaced. The oil volume and
saturation in encased rock core plug 301 were calculated by mass
balance of injected and recovered fluids. The rock core plug was
then flooded with synthetic salt water solution and the volumes of
oil and water recovered from encased rock core plug 301 were
tracked. Once no additional oil had been recovered for at least one
pore volume, encased rock core plug 301 was considered to be at
residual oil saturation after water flood.
[0032] Encased rock core plug 301 used for this experiment was a
berea sandstone with the following characteristics: 100 mD
permeability, 19.8% porosity, 17.2 ml pore volume, 3.8 cm
(diameter), 7.6 cm (length).
[0033] Once residual oil saturation after water flood has been
achieved, a 100 mg/l solution of Span 85 (Sorbitane trioleate, CAS
Number: 26266-58-0, Sigma-Aldrich) in isopropyl alcohol was
prepared and a volume equal to 1 percent of the pore volume was
injected into encased rock core plug 301. The outlet of encased
rock core plug 301 was then monitored and additional oil production
amounting to 0.37% of the original oil in place was produced from
the rock core plug. FIG. 4 shows a graph of the results achieved by
this experiment. The x-axis shows pore volumes after surfactant
injection. The y-axis shows the percentage of original oil in place
that is recovered.
[0034] It should be noted that if the concentration of the
surfactant is 100 mg/l in a near well bore area then the
concentration outside the near well bore area would be much lower
as a result of dilution. Consequently, this low concentration of
surfactant lowers the interfacial tension between flood water and
oil in the near well bore area but does not affect the interfacial
tension between flood water and oil outside the near well bore
area.
[0035] One of the benefits of using surfactants, such as oleophilic
surfactants, at low concentration is that breakthrough instances in
the recovery process are avoided. That is, there is minimal
surfactant present in the produced fluid to cause emulsification of
oil and water emanating from the production well. Furthermore,
surfactants are chemicals that can affect the properties of the oil
being produced. At the low levels of concentration of surfactants
used in embodiments of the invention, this chemical effect on the
produced oil can be significantly minimized if not completely
eliminated.
[0036] 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 spirit and scope of the invention as defined by the
appended claims. Moreover, the scope of the present application 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.
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