U.S. patent application number 12/023738 was filed with the patent office on 2009-08-06 for optimum salinity profile in surfactant/polymer flooding.
This patent application is currently assigned to Total E&P USA, Inc.. Invention is credited to James J. Sheng.
Application Number | 20090194281 12/023738 |
Document ID | / |
Family ID | 40930536 |
Filed Date | 2009-08-06 |
United States Patent
Application |
20090194281 |
Kind Code |
A1 |
Sheng; James J. |
August 6, 2009 |
OPTIMUM SALINITY PROFILE IN SURFACTANT/POLYMER FLOODING
Abstract
An optimum salinity profile in surfactant/polymer flooding from
formation water to post-flush drive that leads to the highest oil
recovery factor is shown. The optimum salinity determined from
core-flooding experiments is preferably used in the surfactant
slug. The surfactant slug is protected from deterioration by the
injection of cushion slugs immediately before and after the
injection of the surfactant slug in a reservoir wherein the cushion
slugs have the same salinity or about the same salinity as the
surfactant slug. According to embodiments, a salinity lower than
the lowest salinity of Type III, C.sub.sel, is used in the
post-flush drive, while formation water could be of any
salinity.
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: |
40930536 |
Appl. No.: |
12/023738 |
Filed: |
January 31, 2008 |
Current U.S.
Class: |
166/270.1 |
Current CPC
Class: |
C09K 8/584 20130101 |
Class at
Publication: |
166/270.1 |
International
Class: |
E21B 43/22 20060101
E21B043/22 |
Claims
1. A method of recovering oil from a reservoir using surfactant
flooding, said method comprising: injecting a fluid slug in said
reservoir; injecting, after said first injection, a first cushion
slug in said reservoir, injecting a surfactant slug following said
first cushion slug; injecting a second cushion slug following said
surfactant slug, wherein said first and second cushion slugs have
salinities selected from the list consisting of: the salinity of
said surfactant slug and about the salinity of said surfactant
slug; and injecting a fluid slug of lower salinity than said
surfactant slug, after said second cushion slug, wherein said
injected fluid slug, of lower salinity than said surfactant slug,
has a salinity lower than the lowest salinity at which a three
phase microemulsion system exists at equilibrium.
2. The method of claim 1 wherein said salinities of said first and
second cushion slugs are the same as said surfactant slug.
3. The method of claim 1 wherein said surfactant slug contains a
co-surfactant.
4. The method of claim 1 wherein said surfactant slug includes a
polymer.
5. The method of claim 1 wherein said first and second cushion
slugs are selected from the list consisting of: water, brine and
mobility control agents.
6. (canceled)
7. The method of claim 1 wherein said first injected fluid slug is
selected from the list consisting of: water, brine and mobility
control agents.
8. The method of claim 1 wherein said first injected fluid slug has
a salinity different from said surfactant slug.
9. (canceled)
10. (canceled)
11. The method of claim 1 further comprising: injecting a fluid
slug of lower salinity than said surfactant slug, after said second
cushion slug.
12. The method of claim 11 wherein said fluid slug is selected from
the list comprising: water, brine and surfactant solution mobility
control agents.
13. The method of claim 1 wherein the salinity of said surfactant
slug is an actual optimum salinity determined by running
experiments, wherein said actual optimum salinity determined from
said experiments is a function of IFT and parameters other than
IFT.
14. The method of claim 13 wherein said experiments include running
core flood experiments.
15. The method of claim 14 wherein said core flood experiments are
run first to determine the actual optimum system type and then to
determine an actual optimum salinity in said actual optimum system
type.
16. The method of claim 14 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.
17. A method of recovering oil from a reservoir, said method
comprising: selecting an optimum salinity by running at least one
core flood experiment to measure oil recovery applicable to each of
at least two surfactant system types, said surfactant system types
selected from the list consisting of: Type II(-), Type III, and
Type II(+) system; injecting a first cushion slug in said
reservoir, then injecting a surfactant slug; and then injecting a
second cushion slug, wherein said first and second cushion slugs
and said surfactant slug is or about at the optimum salinity.
18. The method of claim 17 further comprising: injecting a fluid
slug prior to said first cushion slug.
19. The method of claim 17 further comprising: injecting a fluid
slug of lower salinity than said optimum salinity, after said
second cushion slug.
20. The method of claim 17 wherein said first and second cushion
slugs are selected from the list consisting of: water, brine and
mobility control agents.
21. A method of recovering oil from a reservoir using surfactant
flooding, said method comprising: injecting a fluid slug in said
reservoir; injecting a first cushion slug; injecting a surfactant
slug following said first cushion slug, said surfactant slug
comprising a polymer and a co-surfactant; injecting a second
cushion slug following said surfactant slug, wherein said first and
second cushion slugs comprise brine and a mobility control agent
and said first and second cushion slugs have salinities selected
from the list consisting of: the salinity of said surfactant slug
and about the salinity of said surfactant slug; and injecting a
fluid slug of lower salinity than said surfactant slug, after said
second cushion slug, wherein said injected fluid slug, of lower
salinity than said surfactant slug, has a salinity lower than the
lowest salinity at which a three phase microemulsion system exists
at equilibrium.
22. The method of claim 21 wherein said surfactant salinity is an
actual optimum salinity determined by running experiments and said
actual optimum salinity determined from said experiments is a
function of IFT and parameters other than IFT.
23. The method of claim 22 wherein said experiments include running
core flood experiments.
24. The method of claim 23 wherein said core flood experiments are
run first to determine the actual optimum system type and then to
determine an actual optimum salinity in said actual optimum system
type.
25. The method of claim 14 wherein said core flood experiments are
run in all of the following surfactant system types: Type II(-),
Type III, and Type II(+) system.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is related to co-pending application, U.S.
patent Ser. No. XX/XXX,XXX, [Attorney Docket No.
55805/P003US/10712257], filed ______, entitled "DETERMINATION OF AN
ACTUAL OPTIMUM SALINITY AND AN ACTUAL OPTIMUM TYPE OF MICROEMULSION
FOR 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 design of an optimum
salinity profile for surfactant flooding of a reservoir.
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 factors 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.
[0006] To make the best use of the microemulsion system,
experiments have been developed to determine what is the ideal
salinity of the microemulsion system for surfactant flooding.
Traditionally, these experiments have focused on identifying an
optimum salinity based on interfacial tension (IFT). However,
co-pending application DETERMINATION OF AN ACTUAL OPTIMUM SALINITY
AND AN ACTUAL OPTIMUM TYPE OF MICROEMULSION FOR ENHANCED OIL
RECOVERY discloses a novel method of determining the actual optimum
salinity to be used in surfactant flooding.
[0007] To determine the actual optimum salinity, oil samples are
taken from an oil reservoir. Then, 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.
Accordingly, 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. Also, the midpoint between C.sub.sel and
C.sub.seu, can be identified from the graph. This midpoint 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 (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] After the salinity ranges of each of microemulsion systems
Type II (-), Type III and Type II (+) have been defined, the best
microemulsion system type for oil recovery is determined. 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. A salinity is selected from each of
the salinity ranges Type II (-), Type III and Type II (+). Core
flood experiments are run, with each of these selected salinities
to determine which salinity provides the highest oil recovery
factor. The core flood may be run, in the laboratory, on a sample
of the rock formation containing the oil. In running the core flood
experiments, the microemulsion system type with the highest oil
recovery factor is identified.
[0011] Once the actual optimum system type has been determined, the
next step is to determine the actual optimum salinity within this
optimum system type. This is necessary, 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, further core flood experiments are run on a series of
salinities selected from the actual optimum microemulsion system
type. The salinity with the highest recovery factor, of this series
of salinities, is the actual optimum salinity.
[0012] However, according to the current state of the art, the
optimum salinity is defined as the average of the lower boundary of
C.sub.sel and the upper boundary of C.sub.seu of a Type III
microemulsion system; and this optimum salinity is applied, during
EOR, in a negative salinity gradient. A negative salinity gradient
means that starting from the salinity of the formation water (water
naturally occurring in the rock formation of a reservoir), the
salinity of each slug of the surfactant flooding system injected
into the reservoir, during EOR, is lower than the formation water
or the previously injected slug. For example, if the sequence of
injections in surfactant flooding of a reservoir is first, a
preflush slug, second, a surfactant/polymer slug and third a
polymer/water drive slug, the negative salinity gradient dictates
that the formation water will have a salinity greater than all the
injected slugs. The preflush slug will have the next highest
salinity. The surfactant/polymer slug will have an actual optimum
salinity which is lower than the preflush slug and the
polymer/water drive slug will have the lowest salinity. In other
words, salinity is progressively reduced as fluid is injected into
the reservoir. This negative salinity gradient is widely used.
Therefore, the current general recovery factors in EOR, using
surfactant flooding, reflects the recovery factors generally
achieved by a negative salinity gradient system.
BRIEF SUMMARY OF THE INVENTION
[0013] In arriving at the present invention, it was discovered that
a negative salinity gradient, in most scenarios, does not provide
the highest oil recovery factor in EOR. First, apart from providing
relatively low recovery factors, a negative salinity gradient is
not effective in all cases. Negative salinity gradients are only
applicable when the formation water is of high salinity. Indeed,
formation water is usually of high salinity. However, not all
formation water is of higher salinity than the salinity of a chosen
surfactant. Moreover, constant salinity gradient (all injected
slugs having the same salinity equal to the formation water) and
positive salinity gradient (opposite of negative salinity
gradient), are rarely used because they generally provide low oil
recovery factors.
[0014] Second, the negative salinity gradient does not adequately
maintain the designed properties of the surfactant slug as the
surfactant slug proceeds through a reservoir. In other words, the
properties of the surfactant slug, including salinity, deteriorate
significantly once it progresses through the reservoir in a
negative salinity gradient system because of salinity dilution.
This deterioration of the properties of the surfactant flood, is
adverse to achieving good oil recovery factors. For example, there
may be diffusion to or from the surfactant slug depending on the
salinity of the materials, such as formation water, in the
reservoir causing the microemulsion system to become less
desirable.
[0015] Therefore, in accordance with embodiments of the present
invention, a method of recovering oil from a reservoir includes
protecting the surfactant slug from deterioration by injecting
cushion slugs before and after the injection of the surfactant slug
in a reservoir where the cushion slugs have the same salinity or
about the same salinity as the surfactant slug. In one embodiment,
the surfactant salinity that is protected by cushion slugs is
determined by experiments where the determined salinity is a
function of parameters other than, but including IFT.
[0016] 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
[0017] 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:
[0018] FIG. 1 shows a comparison of oil recovery factors with the
use of a negative salinity gradient and oil recovery factors with
the use of the optimum salinity profile; and
[0019] FIG. 2 is a schematic diagram showing one embodiment of the
invention as an optimum salinity profile.
DETAILED DESCRIPTION OF THE INVENTION
[0020] In arriving at the present invention, the hypothesis that
the negative salinity gradient does not always provide the best oil
recovery factors in EOR was tested by conducting simulation studies
to compare oil recovery factors using the negative salinity
gradients with recovery factors when the principles of the present
invention are applied in an optimum salinity profile. The
simulations were conducted on a chemical flood simulator known as
the University of Texas Chemical Compositional Simulator, UTCHEM.
UTCHEM is a three-dimensional, multiphase, multicomponent,
numerical simulator. From the simulation results, it was discovered
that an optimum salinity profile embodying the principles of this
invention, in every simulated case, provided a higher oil recovery
factor than a negative salinity gradient.
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 ID
model. The length is 0.745 ft. Some of the reservoir and fluid
properties are listed in Table 1.
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
The Microemulsion Systems Used in the Simulations
[0022] Simulations to compare oil recovery factors of the negative
salinity gradient with oil recovery factors of an optimum salinity
profile were run using systems with the following salinity
profiles:
TABLE-US-00002 TABLE 2 Salinities (meq/ml) Second Third Slug -
First Slug - Slug - Polymer and System Preflush Water Surfactant
Water Drive Negative Salinity 0.415 0.365 0.335 Gradient
TABLE-US-00003 TABLE 3 Salinities (meq/ml) First Slug- Second Third
Fifth Slug- Preflush Slug- Slug- Fourth Slug- Polymer System water
Cushion Surfactant Cushion Water Drive Optimum 0.415 0.365 0.365
0.365 0.335 Salinity Profile
[0023] The negative salinity gradient system has slugs injected in
the following order, preflush water of 0.415 meq/ml salinity,
surfactant slug of 0.365 meq/ml salinity and then polymer and water
drive of 0.335 meq/ml salinity. The optimum salinity profile has
slugs injected in the following order, preflush water of 0.415
meq/ml salinity, cushion slug of 0.365, surfactant slug 0.365
meq/ml salinity, cushion slug of 0.365 meq/ml salinity, and then
polymer and water drive of 0.335 meq/ml salinity.
[0024] FIG. 1 is a graphical summary of the results of the
simulations with a negative salinity gradient as compared with an
optimum salinity profile. Comparing the recovery factors of the
negative salinity gradient system with the recovery factors for the
optimum salinity profile system, as shown in FIG. 1, in every
simulation, the optimum salinity profile provides a higher oil
recovery factor. On average, there is a 12.3% higher recovery
factor with the optimum salinity profile system as compared to the
negative salinity gradient system.
[0025] FIG. 2 is a schematic detailing one embodiment of an optimum
salinity profile. On the x-axis is the injection pore volume. A
pore volume is the total volume of a porous medium minus the
material of the rock. In other words, a pore volume is the total
volume of a fluid, say oil, required to saturate the porous medium.
The y-axis reflects the salinity of the different slugs injected
into the reservoir.
[0026] Slug 201, such as preflush water, is the first slug that is
injected into the reservoir. It should be noted that, according to
embodiments, an important concept of this optimum salinity profile
includes the salinity from formation water to post-flush water.
Thus, after determining the optimum salinity of the surfactant slug
203, this optimum salinity of the surfactant slug is used to set
the salinity of each salinity cushion slug which provides cushions
for the surfactant slug 203. This novel approach in setting
salinities of all the slugs to provide a cushion for the surfactant
slug 203 is disclosed herein, as an optimum salinity profile. The
salinity of slug 201 may be of any salinity. In some instances, the
salinity selected for slug 201 will be determined with reference to
the salinity of the formation water. Following the injection of the
preflush water, the first slug cushion 202 is injected. It should
be noted that a cushion slug may be fluids such as water, brine or
polymer mobility-control solution. Cushion 202 will have the same
salinity as the surfactant slug 203. It should be noted that the
surfactant slug 203 may be a surfactant/polymer slug or a
surfactant slug without polymer. In some embodiments, the polymer
is a mobility control agent. Surfactant slug 203 preferably has an
actual optimum salinity as determined by a method as disclosed in
co-pending application Ser. No. ______ DETERMINATION OF AN ACTUAL
OPTIMUM SALINITY AND AN ACTUAL OPTIMUM TYPE OF MICROEMULSION FOR
ENHANCED OIL RECOVERY. Surfactant slug 203 of the actual optimum
salinity is then injected.
[0027] After the injection of surfactant slug 203, a second cushion
slug 204 is injected. The second salinity cushion slug has the same
salinity as the surfactant slug 203. As can be seen in FIG. 2,
surfactant slug 203 is "sandwiched" between cushion slugs 202 and
204. The salinity cushions help to maintain the properties of
surfactant slug 203 as slug 203 proceeds through the reservoir. It
should be noted that varying the cushion slugs' salinity slightly
so that the salinity of the cushion slugs are not exactly the same
as the surfactant slug salinity would not take such a system
variation outside the scope of this invention. Accordingly, when
reference is made to about the surfactant slug salinity or about
the optimum salinity, this means salinities close to the respective
surfactant slug salinity or the optimum salinity that would not
significantly affect the oil recovery factor.
[0028] With cushion slugs of the same or about the same as the
surfactant slug, there will not be diffusion from or to slug 203,
as it progresses through the reservoir, to cause slug 203's
salinity to change from what it was when it was first injected.
Rather, if there is diffusion, that diffusion occurs on the outer
bounds of the cushion slug (front of cushion slug 202 and at the
rear of cushion slug 204). Because the salinity of slug 203 is
maintained at an optimum level, the performance of the slug is
always at its best. After cushion slug 204 has been injected in the
reservoir, slug 205 is injected in the reservoir. Slug 205 has a
salinity that is lower than the salinity of slug 203. Preferably,
slug 205 would have a salinity that is lower than C.sub.sel (the
lowest Type III salinity). Using this optimum salinity profile, as
mentioned above, should increase oil recovery factors by about
12.3% over the widely used negative salinity gradient method. It
should be noted that depending on the reservoir, one embodiment of
the invention may not include slugs 201 and/or 205.
[0029] 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.
* * * * *