U.S. patent application number 12/023499 was filed with the patent office on 2009-08-06 for determination of an actual optimum salinity and an actual optimum type of microemulsion for surfactant/polymer flooding.
This patent application is currently assigned to Total E&P USA, Inc.. Invention is credited to James J. Sheng.
Application Number | 20090194276 12/023499 |
Document ID | / |
Family ID | 40930533 |
Filed Date | 2009-08-06 |
United States Patent
Application |
20090194276 |
Kind Code |
A1 |
Sheng; James J. |
August 6, 2009 |
DETERMINATION OF AN ACTUAL OPTIMUM SALINITY AND AN ACTUAL OPTIMUM
TYPE OF MICROEMULSION FOR SURFACTANT/POLYMER FLOODING
Abstract
Systems and methods for the determination of an optimum salinity
type and an optimum salinity of a surfactant microemulsion system
are shown. Optimum salinity type and optimum salinity in
surfactant/polymer flooding is determined, according to
embodiments, by core-flood experiments so that a variety of
multiphase flow parameters such as relative permeability and phase
trapping that affects oil recovery factor, influences the
determination of the optimum salinity type and optimum salinity.
The optimum salinity determined from this approach preferably
corresponds to the highest oil recovery factor.
Inventors: |
Sheng; James J.; (Katy,
TX) |
Correspondence
Address: |
FULBRIGHT & JAWORSKI L.L.P
2200 ROSS AVENUE, SUITE 2800
DALLAS
TX
75201-2784
US
|
Assignee: |
Total E&P USA, Inc.
Houston
TX
|
Family ID: |
40930533 |
Appl. No.: |
12/023499 |
Filed: |
January 31, 2008 |
Current U.S.
Class: |
166/252.3 |
Current CPC
Class: |
E21B 43/16 20130101;
C09K 8/584 20130101 |
Class at
Publication: |
166/252.3 |
International
Class: |
E21B 43/22 20060101
E21B043/22 |
Claims
1. A method of determining an actual optimum salinity of a
surfactant system that produces an optimal recovery factor of an
oil from a reservoir, said method comprising: conducting core flood
experiments for said reservoir; determining from said core flood
experiments, said actual optimum salinity, wherein said determined
actual optimum salinity is a function of IFT and parameters other
than IFT and wherein said core flood experiments comprises a first
set of core flood experiments that are run to determine the actual
optimum system type and then a second set of core flood experiments
run to determine the actual optimum salinity in said actual optimum
system type.
2. The method of claim 1 wherein said other parameters is selected
from the list consisting of: relative permeability, phase trapping
and adsorption.
3. (canceled)
4. (canceled)
5. The method of claim 1 wherein said core flood experiments, to
determine the actual optimum system type, are run in each of
surfactant system types, Type II(-), Type III, and Type II(+).
6. A method of determining an optimum salinity of a surfactant
system that produces an optimal recovery factor of an oil, said
method comprising: determining a surfactant salinity range for each
of system types Type II(-), Type III, and Type II(+) system;
selecting a plurality of salinities from each of at least two of
said determined ranges of system types, wherein said determining of
said salinity ranges of system types includes: experiments that
measure the interfacial tension between a microemulsion and a water
solution and said microemulsion and said oil; running core flood
experiments for said selected surfactant salinities to determine a
highest oil recovery factor of said plurality of selected
salinities; selecting a series of surfactant system salinities from
the salinity range of said system type that includes the surfactant
salinity with said highest oil recovery factor; and running core
flood experiments on said series of surfactant salinities to
determine an oil recovery factor for each of said selected series
of surfactant salinities.
7. (canceled)
8. The method of claim 6 wherein said determining of said
surfactant salinity ranges of system types includes: experiments
that equilibrate a mixture of said oil and a surfactant system and
measuring the volumes of phases formed by said equilibration.
9. The method of claim 6 wherein said selecting includes: selecting
combinations from the list consisting of: a salinity about midpoint
of said Type III system, a salinity about a predetermined
percentage below the lowest Type III salinity, a salinity about
said predetermined percentage above the highest Type III
salinity.
10. The method of claim 9 wherein said predetermined percentage is
5-30%.
11. The method of claim 6 further comprising: identifying the
optimum oil recovery factor obtained from said core flood
experiments for said selected surfactant salinities.
12. The method of claim 6 further comprising: selecting a new
surfactant system salinity from each of at least two of said ranges
of system types if said highest oil recovery factor of said
selected salinities is within a predetermined percentage of a core
flood oil recovery factor of said other selected salinities; and
running core flood experiments for said new system surfactant
salinities.
13. The method of claim 12 wherein the predetermined percentage is
selected from the range of 5 to 15.
14. (canceled)
15. The method of claim 6 further comprising: identifying the
surfactant system salinity of said series of salinities having the
highest oil recovery as the optimum salinity.
16. A method of recovering oil from a reservoir, said method
comprising: conducting core flood experiments for said reservoir;
determining from said core flood experiments, said actual optimum
salinity, wherein said determined actual optimum salinity is a
function of IFT and parameters other than IFT; and flooding said
reservoir with a surfactant system of said optimum salinity,
wherein said core flood experiments are run first to determine the
actual optimum system type and then to determine the actual optimum
salinity in said actual optimum system type.
17. The method of claim 16 wherein said other parameters is
selected from the list consisting of: relative permeability, phase
trapping, and adsorption.
18. (canceled)
19. (canceled)
20. The method of claim 16 wherein said core flood experiments are
run in at least two surfactant system types, said surfactant system
types selected from the list consisting of: Type II(-), Type III,
and Type II(+) system.
21. A method of recovering oil from a reservoir, said method
comprising: flooding said reservoir with a surfactant system, the
salinity of said surfactant system determined by: determining a
surfactant salinity range for each of system types Type II(-), Type
III, and Type II(+) system; selecting a plurality of salinities
from each of at least two of said determined ranges of system
types; and running core flood experiments for said selected
plurality of surfactant salinities to determine a highest oil
recovery factor of said selected salinities; selecting a series of
surfactant salinities from the salinity range of said system type
that includes the surfactant salinity with said highest oil
recovery factor; and running core flood experiments on said series
of surfactant salinities to determine an oil recovery factor for
each of said selected series of surfactant salinities.
22. The method of claim 21 wherein said determining of said
salinity ranges of system types includes: experiments that measure
the interfacial tensions between a microemulsion and a water
solution, and between said microemulsion and said oil.
23. The method of claim 21 wherein said determining of said
salinity ranges of system types includes: experiments that
equilibrate a mixture of said oil and a surfactant system and
measuring the volumes of phases formed by said equilibration.
24. The method of claim 21 wherein said selecting includes:
selecting combinations from the list consisting of: a salinity
about midpoint of said Type III system, a salinity about 5-30%
below the lowest Type III salinity, a salinity about 5-30% above
the highest Type III salinity.
25. The method of claim 21 wherein said surfactant system salinity
determination further comprises: identifying the highest oil
recovery factor obtained from said core flood experiments for said
selected surfactant salinities.
26. The method of claim 25 wherein said surfactant system salinity
determination further comprises: selecting a new surfactant system
salinity from each of at least two of said ranges of system types
if said highest oil recovery factor of said selected salinities is
within a predetermined percentage higher than that of a core flood
oil recovery factor of said other selected salinities; and running
core flood experiments for said new surfactant salinities.
27. The method of claim 26 wherein the predetermined percentage is
selected from the range of about 5 to 15.
28. (canceled)
29. The method of claim 21 wherein said surfactant system salinity
determination further comprises: identifying the salinity of said
series of salinities having the highest oil recovery as the optimum
salinity.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is related to co-pending application, U.S.
Pat. Ser. No. XX/XXX,XXX, Attorney Docket No.
55805/P004US/10800390, filed ______, entitled "DESIGN OF OPTIMUM
SALINITY PROFILE IN SURFACTANT/POLYMER FLOODING," concurrently
filed herewith, the disclosure of which is incorporated herein by
reference.
TECHNICAL FIELD
[0002] The present disclosure relates to the field of Enhanced Oil
Recovery (EOR) from reservoirs using a surfactant system.
Specifically, the disclosure relates to the determination of an
actual optimum type of microemulsion. Additionally, the
determination of an actual optimum salinity in surfactant/polymer
flooding is disclosed.
BACKGROUND OF THE INVENTION
[0003] Petroleum (crude oil) is a finite resource that naturally
occurs as a liquid in formations in the earth. Usually, crude oil
is extracted by drilling wells into underground reservoirs. If the
pressure of the crude oil underground is sufficient, then that
pressure will cause the oil to rise to the surface. When pressure
of the crude oil is sufficiently high, recovery simply involves
constructing pipelines to carry the crude oil to storage facilities
(e.g. tank batteries). This is known as primary recovery. If the
pressure of the crude oil in the reservoir is insufficient to cause
it to rise to the surface, then secondary means of recovery have to
be used to recover the oil. Secondary oil recovery includes:
pumping, water injection, natural gas reinjection, air injection,
carbon dioxide injection or injection of some other gas into the
reservoir.
[0004] The extraction of crude oil from a reservoir by conventional
(primary/secondary oil) recovery technology, however, leaves behind
a significant portion of the total amount of oil in that reservoir.
Traditionally, the oil recovered from a reservoir, using
conventional technology as compared to the total amount of oil in
the reservoir, is about 33%. Thus, on average, when only
conventional methods are used, approximately 67% of the oil in a
reservoir is "stranded" in that reservoir. Consequently, EOR
processes are used to increase crude oil recovery from
reservoirs.
[0005] One method of EOR involves the use of surfactants. A
surfactant is a wetting agent that lowers the interfacial tension
between fluids or substances. Applied in oil recovery, surfactants
reduce the interfacial tension that may prevent oil droplets from
moving easily through a reservoir. The use of surfactants in aiding
oil to move easily through the reservoir involves the creation of
microemulsions. Microemulsions are generally clear, stable,
mixtures of oil, water and surfactant, sometimes in combination
with a cosurfactant. By themselves, oil and water are immiscible
but when oil and water are mixed with the appropriate surfactant,
the oil water and surfactant are brought into a single
microemulsion phase. The microemulsion's salinity affects the
microemulsion's effectiveness in enhancing the recovery of oil from
a reservoir. Salinity is a measure of salt content. There are three
different types of microemulsion systems used in oil recovery--Type
II(-), Type III and Type II(+). The type of microemulsion system
depends on the salinity in the systems.
[0006] Salinity values C.sub.set and C.sub.seu define the range of
each microemulsion system type. C.sub.sel is the lowest salinity at
which a three phase microemulsion system exists at equilibrium and
C.sub.seu is the highest salinity at which a three phase
microemulsion system exists at equilibrium. Below C.sub.sel, the
system is defined as Type II(-). Above C.sub.seu the system is
defined as Type II(+). Between C.sub.sel and C.sub.seu, the system
is defined as Type III. In a Type III system, the interfacial
tensions (IFTs) between microemulsion and water, and microemulsion
and oil are both low. The point of lowest interfacial tension is
the midpoint between C.sub.sel and C.sub.seu. Currently, this
midpoint between C.sub.sel and C.sub.seu is defined as the optimum
salinity. Because the IFTs of microemulsion and water and
microemulsion and oil are at their lowest point at this defined
optimum salinity, conventional theory dictates that this salinity
will be most effective in oil recovery. It is currently believed
that the lower the values of the IFTs of microemulsion and water
and microemulsion and oil, in a surfactant/polymer flooding system,
the higher the oil recovery. Therefore, in conventional methods,
the optimum salinity is determined by laboratory experiments that
identify the Type III microemulsion salinity that has the lowest
interfacial tension between the microemulsion and the water and oil
phases, that is, the midpoint between C.sub.sel and C.sub.seu.
[0007] One type of laboratory experiment used to determine the Type
III microemulsion salinity with the lowest interfacial tension
between the microemulsion and the water and oil phases is described
in U.S. Pat. No. 4,125,156, entitled "AQUEOUS SURFACTANT SYSTEMS
FOR IN SITU MULTIPHASE MICROEMULSION FORMATION," the disclosure of
which is incorporated herein by reference. Apart from identifying
the salinity of lowest interfacial tension, this laboratory
experiment may also be used to determine the salinity ranges for
the three different types of microemulsion systems. As disclosed in
U.S. Pat. No. 4,125,156, aqueous surfactant systems of a wide range
of salinities are equilibrated with the oil in question.
Equilibrations are carried out in glass-stoppered graduated
cylinders, which are shaken and then allowed to sit at a constant
temperature until volumetric readings remain constant with time
(for example, a 24 hour period). Alternatively, equilibration may
be done in pipettes or other similar laboratory equipment.
[0008] The number of phases and the volumes of these phases at
equilibrium, for each salinity tested, are then recorded. Graphs of
volume versus salinity are plotted. From these graphs, three
regions are identified. The first region is that of intermediate
salinities where three phases exist at equilibrium--(1) a
micremulsion phase between (2) an oil phase and (3) a water phase.
This is the region of a Type III microemulsion system with a lower
boundary of C.sub.sel and an upper boundary of C.sub.seu. Also, the
midpoint between C.sub.sel and C.sub.seu, can be identified from
the graph. This midpoint, as mentioned before, is defined as the
optimum salinity by conventional methods.
[0009] When the salinities are lower than C.sub.sel (the lowest
Type III salinity), the microemulsion system is known as a Type
II(-) system. At these lower salinities, two phases will exist--(1)
a microemulsion phase below (2) an oil phase. When the salinities
are higher than C.sub.seu (the highest Type III salinity) the
microemulsion system is known as a Type II(+) system. At these
higher salinities, two phases will exist--(1) a microemulsion phase
on top of (2) a water phase.
[0010] Once the Type III and, consequently, the Type II(+) and Type
II(-) system salinity ranges are determined in the laboratory, the
midpoint salinity of the Type III system is used in oil recovery
from reservoirs in current practice of EOR using surfactant
flooding. In other words, current EOR techniques necessarily
requires that oil recovery be done using Type III systems only.
BRIEF SUMMARY OF THE INVENTION
[0011] In arriving at the present invention, it was discovered that
IFT is just one of several parameters that affects the oil recovery
in surfactant flooding. Parameters such as relative permeability,
phase trapping and adsorption, individually or in combination, may
cause an actual optimum salinity of a microemulsion system to occur
in any of Type II(-), Type III or Type II(+) microemulsion systems.
This contrasts with the current state of the art that focuses on
interfacial tension as the determining parameter and consequently
that the optimum salinity is, necessarily a Type III salinity.
[0012] In accordance with embodiments of the invention, therefore,
in determining an actual optimum salinity, experiments are run
where the determined actual optimum salinity is a function of
parameters other than but including IFT. In one embodiment, core
flood experiments are run to determine the actual optimum
salinity.
[0013] 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
[0014] 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:
[0015] FIG. 1 shows recovery factors and water cuts for continuous
injection cases of different microemulsion systems;
[0016] FIG. 2 shows recovery factors and water cuts for continuous
injection cases of different microemulsion systems (k.sub.r2
increased while k.sub.r3 decreased);
[0017] FIG. 3 is a flow chart showing one embodiment of the current
invention; and
[0018] FIG. 4 is a diagram showing one embodiment of the
invention.
DETAILED DESCRIPTION OF THE INVENTION
[0019] The current state of the art of determining an optimum
salinity within a Type III microemulsion system focuses on one
parameter-interfacial tension. In arriving at the present
invention, though it was believed that interfacial tension is an
important factor in the ultimate oil recovery, it was realized that
other potentially important parameters were not being taken into
account in the selection of the optimum salinity type. Accordingly,
it was hypothesized that if the other parameters such as relative
permeability, phase trapping and adsorption, were taken into
account, the actual optimum salinity determined would, often times,
be other than a Type III and/or a different value from the
conventional optimum salinity. Simulations of multiphase flow in
surfactant flooding were conducted to determine the effect of
several parameters on oil recovery factor.
[0020] The simulations were conducted on a chemical flood simulator
known as the University of Texas Chemical Simulator, UTCHEM. UTCHEM
is a three-dimensional, multiphase, multicomponent, numerical
simulator. From the simulation results, it was discovered that
taking other parameters such as relative permeability, phase
trapping, adsorption, into consideration in determining an optimum
salinity, may result in an optimum salinity of microemulsion system
type other than a Type III system. Essentially, the simulation
results show that the effect of other parameters such as relative
permeability, phase trapping, and adsorption, renders the long
practice of relying solely on interfacial tension as the best
indicator of highest oil recovery, unreliable. The effect of one of
these parameters-relative permeability--is presented in the
simulation example below.
SIMULATION EXAMPLE
Input Data to UTCHEM
[0021] For the UTCHEM simulations, a fine core-scale model was
used. The grid blocks used are 80.times.1.times.1 which is a 1D
model. The length is 0.745 ft. Some of the reservoir and fluid
properties are listed in Table 1. The base case injection scheme is
1.0 pore volume (PV) water, 0.1 PV 3 vol. % surfactant solution,
0.4 PV 0.07 wt % polymer solution, followed by 1.0 PV water
injection. A pore volume is the total volume of a porous medium
minus the material of the medium. In other words a pore volume is
the total volume of a fluid, say oil, required to saturate the
porous medium.
TABLE-US-00001 TABLE 1 Reservoir and Fluid Properties Porosity 0.3
k.sub.H, mD 200 k.sub.V, mD 100 Initial water saturation 0.2 Water
viscosity, cP 1 Oil viscosity, cP 5 Formation water salinity,
meq/ml 0.4 Assumed Surfactant data: Optimum salinity, meq/ml 0.365
lower salinity, meq/ml 0.345 upper salinity, meq/ml 0.385
[0022] The Microemulsion Systems Used in the Simulations
[0023] Simulations to investigate the effect of relative
permeability were conducted on three salinities, each belonging to
a different microemulsion system type as follows:
TABLE-US-00002 TABLE 2 System Salinities Type III 0.365 meq/ml in
all injected fluids Type II(+) 0.415 meq/ml in all injected fluids
Type II(-) 0.335 meq/ml in all injected fluids
[0024] The effect of relative permeability was investigated in two
scenarios: (1) the continuous injection of surfactant and (2) the
injection of a finite slug of surfactant. Each scenario will be
discussed below.
Effect of Relative Permeability (k.sub.r Curves) with Continuous
Injection of Surfactant on Oil Recovery Factor
[0025] The simulations where there was continuous injection of
surfactant solution was conducted without polymer. In this series
of simulations, of a Type II(-), Type III and Type II(+)
microemulsion system, the conventional teachings in the art would
dictate that the Type III microemulsion system, would necessarily
provide the highest oil recovery factor. However, as shown in FIG.
1, the recovery factor with the Type II(+) microemulsion system is
higher than the recovery factor in the Type III system. This
demonstrates that oil will be more effectively displaced from an
oil reservoir with a Type II(+) microemulsion system, under the
above listed conditions and relative permeability k.sub.r. There is
a correlation between relative permeability and multiphase flow
effect. From the foregoing, it is believed that multiphase flow
effect plays an important role in determining which microemulsion
system type gives the highest oil recovery factor. In general, a
three-phase flow is less efficient displacement than a two-phase
flow.
[0026] FIG. 1 shows that with a Type II(+) microemulsion system,
water breaks through later (longer low water-cut period), than the
Type III microemulsion system as illustrated by the water cut (fw).
Water breakthrough occurs when water cut (fw) increases sharply. As
can be seen in FIG. 1, with the Type II(-) microemulsion system, a
high aqueous phase saturation in the two-phase flow system results
in the earliest water breakthrough and the lowest oil recovery at
the same pore volume of injection.
[0027] To verify the hypothesis, above, regarding the multiphase
effect, and to test the effect of relative permeability, the
simulations for each of types Type II(-), Type III and Type II(+)
microemulsion systems was repeated with the same input data except
that the relative permeability of oleic (k.sub.r2), was increased
and the relative permeability of Type III microemulsion (k.sub.r3)
reduced. With a change in the relative permeability, the oil
recovery factor of Type III and Type II(-) microemulsion systems
increased dramatically to about the same level as the recovery for
the Type II(+) microemulsion system. The new oil recovery factor as
a result of a change in the relative permeabilities is shown in
FIG. 2. Comparing FIGS. 1 with 2, it is seen that with the same
phase behavior, by simply changing relative permeabilities,
surfactant system performance is changed significantly.
Effect of Relative Permeabiliteis (k.sub.r Curves) in a Finite
Slug
[0028] In the simulations involving a finite slug, a 0.1 pore
volume (PV) of surfactant slug is injected. The detailed injection
scheme is: 1 PV water, 0.1 PV 3 vol. % surfactant, 0.4 PV 0.07 wt %
polymer solution, 1.0 PV water. A constant salinity is used in all
the injection fluids for a specific type of system. When the same
relative permeability curves were used, the same observations as
those of continuous injection were obtained regarding which type of
microemulsion system would give the highest oil recovery factor. In
other words, the highest oil recovery factor was observed with Type
II(+) microemulsion system as shown in Table 3 below.
TABLE-US-00003 TABLE 3 Type RF, % III 84.86 II(+) 96.98 II(-)
73.4
[0029] The above set of simulations with a finite slug were
repeated with the same input data except that k.sub.r2 is increased
and k.sub.r3 reduced. The recovery factor for the Type III and Type
II(-) microemulsion systems were increased, while the oil recovery
factor for the Type II(+) microemulsion system was reduced. These
simulations, therefore, illustrate that by changing the relative
permeability curves, there is a change in the type of microemulsion
system that gives the highest oil recovery. The oil recovery
factors after reducing k.sub.r3 by half are shown in Table 4.
TABLE-US-00004 TABLE 4 Type RF, % III 94.49 II(+) 76.55 II(-)
90.19
Conclusion Regarding Simulations
[0030] The discovery of the effect of relative permability on the
actual optimum salinity that provides the highest oil recovery in
both a continuous injection scenario and a finite slug scenario led
to similar simulations regarding other parameters. From these
simulations, it was discovered that parameters such as relative
permeability, phase trapping and adsorption, when varied, can
change the actual optimum salinity and actual optimum salinity
type. In arriving at the present invention, it has been proven,
therefore, that the oil recovery factor, using surfactant flooding
EOR, is not only a function of IFT, but also a function of many
other parameters.
[0031] These parameters such as relative permeability, phase
trapping, adsorption, are parameters not considered in the
conventional methods of determining optimum salinity. Instead of
relying solely on IFT in the identification of a Type III
microemulsion system, the current invention solves this problem by
running core flood experiments in each system type, preferably, in
each of the three microemulsion system types or in at least two of
the three microemulsion system types. A core flood experiment
involves the flooding of a portion of the rock formation containing
oil with a surfactant system and measuring the oil recovery factor.
Core flood experiments take into account all parameters such as
interfacial tension, relative permeability, phase trapping etc.
because core flood experiments are essentially a replication of the
flooding process that would occur during the EOR process in the
field.
Running Core Flood Experiments to Determine Actual Optimum
Salinity
[0032] FIG. 3 is a flow chart showing an example of how the
concepts of the present invention may be used to improve oil
recovery factor from a reservoir using core flood experiments. Oil
samples are taken from an oil reservoir in process 300. In process
301, laboratory tests using pipettes, are conducted to determine
the salinity ranges of each type of Type II(-), Type II(+) and Type
III microemulsion systems for the surfactant to be used in recovery
of oil from the reservoir. Equipment 401 may be used to do these
tests. The tests are done by preparing mixtures of the oil, water
and surfactant at different salinities. These mixtures are agitated
and then allowed to "sit" and equilibrate. The amount of phases
that exist after allowing the mixture to come to equilibrium is
recorded. Additionally, the volume of each phase is recorded.
Graphs of volume versus salinity are then plotted, for example by
using computer 402, to determine the lowest salinity, C.sub.sel, a
three phase microemulsion system exists and the highest salinity,
C.sub.seu, a three phase microemulsion system exists. The salinity
range of the Type III microemulsion system exists between these two
points, inclusively. The Type II(-) system is the range of
salinities below the Type III system and the Type II(+) system are
the salinities above the Type III system.
[0033] At this point, in the overall process, it is not known which
of these microemulsion system types is best for recovering oil from
the reservoir in question. Therefore, to determine which
microemulsion system is best for recovering oil from the reservoir,
core flood experiments are run on at least one salinity of each
system type. Thus, in process 302, a salinity is selected from each
of the salinity ranges of Type II (-), Type III and Type II (+).
Any system for selecting a salinity from each range type may be
used according to embodiments of the invention and may be done by
computer 402. For example, a salinity of 5%-30% below C.sub.sel for
Type II(-) or above C.sub.seu for Type II(+). For Type III, the
selected salinity is generally close to the average of C.sub.sel
and C.sub.seu. It should be noted that the selected salinities are
based on phase behavior data or experience. Then, core flood
experiments are run, in process 303 using equipment 403, with each
of these selected salinities to determine which salinity provides
the highest oil recovery factor. The core flood may be run on a
sample of the rock formation containing the oil in the laboratory.
The microemulsion system type with the highest oil recovery factor
is identified.
[0034] In some instances, the difference in recovery factors
amongst the three microemulsion system types may be so small that
it remains unclear whether the microemulsion system giving the
highest oil recovery factor from a single set of core flood
experiments, does in fact identify the actual optimum system.
Therefore, process 304 determines whether the highest recovery
factors are close enough to create this uncertainty. Computer 402
can be used to make this determination. Alternatively, the
determination may be made by an individual with experience. In the
current example, process 304 determines whether the highest oil
recovery factor of the selected salinities is higher than the oil
recovery factor of any other salinity by 10% or less. In one
embodiment, a predetermined percentage of 5-15% is preferred. It
should be noted that instead of 10% used in process 304, another
percentage could be used, according to embodiments of the
invention, to ensure the actual optimum system has been identified.
If there is uncertainty that the actual optimum system has been
identified, new salinities are selected from each microemulsion
system type and the core flood experiments repeated. In a minority
of cases, the oil recovery factors from different microemulsion
systems are in fact close and thus, it would be pointless in
continuing to reselect new salinities. Therefore, process 305
determines whether the selection of salinities have been done more
than "x" number of times before a new selection process is started.
Computer 402 may make this determination. Alternatively, the
determination may be made by an individual with experience. The
value of "x" may be set based on experience showing how many times
on average it is necessary to reselect salinities to ensure a
reliable determination of optimum system type.
[0035] When the selection process has been run at least "x" times
or when it is clear that the highest recovery factor is a reliable
indication of the actual optimum system type, the microemulsion
system type with this highest recovery factor is identified as the
actual optimum system type in process 306. Computer 402 may make
this identification. Alternatively, the identification may be made
by an individual with experience. Once the actual optimum system
type has been determined, the next step is to determine the actual
optimum salinity within this system. This is preferable, because
although at least one core flood experiment would have been done
for the actual optimum microemulsion system type, the salinity
tested in that experiment may not be the salinity that provides the
highest oil recovery in the actual optimum microemulsion system
type. Accordingly, in process 307, further core flood experiments
are run on a series of salinities selected from the actual optimum
microemulsion system type.
[0036] The salinity with the highest recovery factor from the
series of selected salinities is the actual optimum salinity and
identified as such in process 308. Once identified, this actual
optimum salinity is used in the EOR of crude oil from the reservoir
in process 309 using equipment 404.
[0037] 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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