U.S. patent application number 14/626362 was filed with the patent office on 2015-08-20 for enhanced oil recovery process to inject low salinity water and gas in carbonate reservoirs.
The applicant listed for this patent is Waleed Salem AlAmeri, Ali M. AlSumaiti, Ramona M. Graves, Hossein Kazemi, Tadesse Weldu Teklu. Invention is credited to Waleed Salem AlAmeri, Ali M. AlSumaiti, Ramona M. Graves, Hossein Kazemi, Tadesse Weldu Teklu.
Application Number | 20150233222 14/626362 |
Document ID | / |
Family ID | 53797668 |
Filed Date | 2015-08-20 |
United States Patent
Application |
20150233222 |
Kind Code |
A1 |
Teklu; Tadesse Weldu ; et
al. |
August 20, 2015 |
ENHANCED OIL RECOVERY PROCESS TO INJECT LOW SALINITY WATER AND GAS
IN CARBONATE RESERVOIRS
Abstract
The present invention relates to a method to enhance oil
recovery from a hydrocarbon reservoir. One aspect of the invention
includes injecting high salinity water into the reservoir followed
by alternating the injection of low salinity water and gas.
Inventors: |
Teklu; Tadesse Weldu;
(Golden, CO) ; AlAmeri; Waleed Salem; (Abu Dhabi,
AE) ; Graves; Ramona M.; (Evergreen, CO) ;
Kazemi; Hossein; (Castle Rock, CO) ; AlSumaiti; Ali
M.; (Abu Dhabi, AE) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Teklu; Tadesse Weldu
AlAmeri; Waleed Salem
Graves; Ramona M.
Kazemi; Hossein
AlSumaiti; Ali M. |
Golden
Abu Dhabi
Evergreen
Castle Rock
Abu Dhabi |
CO
CO
CO |
US
AE
US
US
AE |
|
|
Family ID: |
53797668 |
Appl. No.: |
14/626362 |
Filed: |
February 19, 2015 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61941869 |
Feb 19, 2014 |
|
|
|
Current U.S.
Class: |
166/305.1 |
Current CPC
Class: |
E21B 43/166 20130101;
C09K 8/594 20130101; E21B 43/164 20130101 |
International
Class: |
E21B 43/16 20060101
E21B043/16 |
Claims
1. A method to enhance recovery of oil in a hydrocarbon reservoir,
comprising: injecting a low salinity water into the reservoir; and
injecting a gas into the reservoir after the injection of the low
salinity water into the reservoir.
2. The method of claim 1, further comprising alternating injecting
the low salinity water into the reservoir, and injecting the gas
into the reservoir.
3. The method of claim 1, wherein the gas is at least one of a
carbon dioxide, a natural gas liquid, a nitrogen, a liquid
petroleum gas and combinations thereof.
4. The method of claim 1, wherein the gas is produced from the
reservoir.
5. The method of claim 1, further comprising injecting a high
salinity water into the reservoir prior to injecting the low
salinity water into the reservoir.
6. The method of claim 5, wherein the high salinity water is at
least one of seawater, produced hydrocarbon reservoir water, and
combinations thereof.
7. The method of claim 1, wherein the low salinity water is at
least one of a desalinated seawater, a diluted seawater, a
desalinated hydrocarbon reservoir formation water, a diluted
hydrocarbon reservoir water, a river water, a lake water, or a
produced hydrocarbon reservoir water.
8. The method of claim 1, wherein the reservoir is an oil-wet
carbonate reservoir, a shale reservoir or a sandstone
reservoir.
9. A method to enhance oil recovery from a hydrocarbon reservoir,
comprising: injecting high salinity water into the reservoir;
injecting a low salinity water into the reservoir following the
injection of the high salinity water, wherein a salinity level of
the low salinity water is less than a salinity level of the high
salinity water; injecting a gas into the reservoir following the
injection of the low salinity water; and alternating the injection
of the low salinity water and the gas into the reservoir.
10. The method of claim 9, wherein the gas is at least one of a
carbon dioxide, a natural gas liquid, a nitrogen, a liquefied
petroleum gas and combinations thereof.
11. The method of claim 10, wherein the high salinity water is at
least one of a seawater, a reservoir formation water and
combinations thereof.
12. The method of claim 9, wherein the low salinity water is at
least one of a desalinated seawater, a diluted seawater, a
desalinated hydrocarbon reservoir formation water, a diluted
hydrocarbon reservoir water, a river water, a lake water, or a
produced hydrocarbon reservoir water.
13. The method of claim 9, wherein the reservoir is an oil-wet
carbonate reservoir, a shale reservoir or a sandstone
reservoir.
14. The method of claim 9, wherein the alternating injection of the
low salinity water and the gas is repeated until a water cut is
greater than about 80%.
15. The method of claim 10, wherein the gas is the carbon
dioxide.
16. The method of claim 10, wherein the gas is the natural gas
liquid.
17. A method to enhance recovery of a hydrocarbon in a reservoir,
comprising: waterflooding the reservoir with a high salinity water;
injecting a first injection of a low salinity water into the
reservoir, wherein at least about 0.2 of a pore volume of the
reservoir is occupied by the low salinity water; injecting a first
injection of a gas into the reservoir, wherein at least about 0.2
of the pore volume of the reservoir is occupied by the gas;
alternating at least one additional injection of the low salinity
water into the reservoir and at least one additional injection of
the gas into the reservoir.
18. The method of claim 17, further comprising injecting an initial
injection of the gas into the reservoir prior to the first
injection of the low salinity water into the reservoir.
19. The method of claim 17, wherein the hydrocarbon is at least one
of crude oil or natural gas.
20. The method of claim 17, wherein the gas is at least one of a
carbon dioxide, a natural gas liquid, a nitrogen, or a liquid
petroleum gas.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority under 35 U.S.C.
.sctn.119(e) to U.S. Provisional Patent Application Ser. No.
61/941,869 filed Feb. 19, 2014, which is incorporated herein in its
entirety by reference.
FIELD OF THE INVENTION
[0002] The invention relates to a method to enhance the recovery of
oil in a hydrocarbon reservoir with the injection of low salinity
water and gas, such as carbon dioxide, natural gas liquids,
liquefied petroleum gas or a gas mixture.
BACKGROUND OF INVENTION
[0003] Conventional waterflooding is widely used globally in
carbonate oil reservoirs. The ultimate oil recovery from primary
production and waterflooding is significantly less than 50%. To
recover additional residual oil after waterflooding, gas flooding
(such as CO.sub.2), low salinity waterflooding, or other enhanced
oil recovery (EOR) methods can be implemented. However, low
salinity waterflooding is not economical because it has to displace
previously injected higher salinity water to mobilize some of the
residual oil (especially when the waterflooding uses seawater in an
offshore operation).
SUMMARY OF INVENTION
[0004] The present invention relates to a process to enhance oil
recovery using low salinity water injection and a gas injection,
into oil-wet carbonate reservoirs, which have undergone primary
production and waterflooding. This low salinity water injection can
be optimized by injecting low salinity water and alternating with a
gas or gas mixture (LS-WAG) injection scheme. The gas can be
CO.sub.2, nitrogen gas, natural gas liquids (NGL), liquefied
petroleum gas (LPG), CO.sub.2+NGL mixture, CO.sub.2+N.sub.2+NGL
mixture, and/or N.sub.2+NGL mixture, or any other combination.
[0005] Low salinity waterflood after a high salinity waterflood
significantly increases the recovery of oil. Following the low
salinity flood with CO.sub.2 injection further improved recovery of
oil. The EOR process can be implemented as a continuous gas
flooding following low salinity waterflood, or as low salinity
water-alternating-gas (LS-WAG) process. The LS-WAG EOR process can
be effective in mobilizing additional oil from reservoirs,
including oil-wet carbonate reservoirs, shale and sandstone, for
the following reasons: [0006] i. Reduces time--Full field low
salinity water injection is expensive because it has to displace
the already injected high salinity water to be beneficial. This
takes a long time to reach the beneficial effects. [0007] ii. Time
and cost efficiency--Alternating injection of the low salinity
water with miscible solvents (such as, CO.sub.2, Natural Gas
Liquids (NGLs), CO.sub.2+NGL mixture, N.sub.2+NGL mixture) greatly
mobilizes more oil and the already-mobilized oil more effectively.
This also reduces the cost of preparing low salinity water
(desalination) because less low salinity water will be used. [0008]
iii. Miscibility achieved--If N.sub.2 is used as injection gas, the
minimum miscibility pressure (MMP) is usually high in most
reservoirs, and miscibility may not be achieved. Whereas, if the
injection streams are, for instance, 50% N.sub.2 plus 50% NGLs, or
20% N.sub.2 and 80% NGLs, or other combinations is injected the
miscibility can be achieved. [0009] iv. Minimum miscibility reached
quickly--The LS-WAG process achieves minimum miscibility rather
quickly to mobilize more of the by-passed oil. For instance, pure
CO.sub.2 has a MMP of 2470 psia with a 32 API oil from Middle East
carbonate reservoir, but a 50% mixture of CO.sub.2 and 50% NGL
would lower MMP to 1615 psia for the same reservoir oil.
[0010] By applying low salinity water-alternating-gas (LS-WAG)
approach the enhanced oil recovery process is effective in
mobilizing residual oil from oil-wet carbonate reservoirs. This EOR
process, for example, can be applied to one of the largest
carbonate reservoirs, Upper Zakkum, located offshore Abu Dhabi.
This Upper Zakkum reservoir is currently undergoing conventional
seawater flooding at injection rate of 800 MBW/day. The average
daily oil production is 560 MSTB. This LS-WAG EOR process can be
beneficial to this field to produce significant amount of
additional oil.
[0011] The present invention takes advantage of the synergistic
effect of mobilizing residual oil due to both low salinity water
and gas solvents (CO.sub.2, NGL, LPG, nitrogen gas, CO.sub.2+NGL
mixture, CO.sub.2+N.sub.2+NGL mixture, N.sub.2+NGL mixture and
mixtures thereof). Though not wanting to be bound by theory, the
low salinity water is believed to alter the wettability state of
the reservoir towards water-wet and lower interfacial tension (IFT)
between brine and oil. The solubility of carbon dioxide is higher
in low salinity water as compared to the solubility of carbon
dioxide in higher salinity water, which means higher carbonic acid
concentration when applied with low salinity water, and this leads
to improved wettability alteration towards water-wet state and
further reduction in IFT. In addition, there is a decrease in oil
viscosity and further increase in oil swelling can be achieved
compared to a conventional WAG process, resulting in improved oil
mobility. Thus, the method results in enhanced oil recovery from
the reservoir.
[0012] An aspect of the invention is a method to enhance recovery
of oil in a hydrocarbon reservoir. The method includes injecting
low salinity water into the reservoir, then injecting a gas into
the reservoir after the injection of the low salinity water into
the reservoir.
[0013] Another aspect of the invention is a method to enhance oil
recovery from a hydrocarbon reservoir, where high salinity water is
injected into a reservoir. Low salinity water is then injected into
the reservoir following the injection of the high salinity water.
The salinity level of the low salinity water is less than a
salinity level of the high salinity water. After the low salinity
injection, a gas is injected into the reservoir following a
subsequent injection of the low salinity water into the reservoir.
Subsequently, the low salinity water and the gas are injected in
alternation manner.
[0014] An aspect of the present invention is a method to enhance
recovery of a hydrocarbon in a reservoir, where the reservoir is
flooded with high salinity water. Then a first injection of low
salinity water is injected into the reservoir, where at least about
0.2 of a pore volume of the reservoir is occupied by the low
salinity water. Following the first injection of the low salinity
water, a first injection of a gas is injected into the reservoir,
where at least about 0.2 of the pore volume of the reservoir is
occupied by the gas. Subsequently, the low salinity water and the
gas are injected in an alternating manner.
BRIEF DESCRIPTION OF THE DRAWINGS
[0015] FIG. 1 illustrates three cores using the Huppler technique
for sample 1 discussed in Table 1 at the end of the experiment;
[0016] FIG. 2 illustrates a schematic of the three phase core
flooding experiment;
[0017] FIG. 3 illustrates the overall experimental procedure;
[0018] FIG. 4 illustrates the oil recovery factor (RF) and pressure
difference between injections and production end as a function of
the pore volume injected for protocol discussed in Example 1;
[0019] FIG. 5 illustrates the oil recovery factor (RF) and pressure
difference between injections and production end as a function of
the pore volume injected for protocol discussed in Example 2;
[0020] FIG. 6 illustrates core discs corresponding to measurement
condition A, measurement condition B, measurement condition C, and
measurement condition D;
[0021] FIG. 7 illustrates the contact angle measurements of
carbonate/sandstone/Three Forks discs at corresponding to
measurement condition A, measurement condition B, measurement
condition C, and measurement condition D; and
[0022] FIG. 8 illustrates the contact angle between
carbonate/sandstone/Three Forks discs and oil-droplet at
measurement conditions A, B, and C.
DETAILED DESCRIPTION
[0023] The present invention relates to methods to recover oil from
a reservoir. An aspect of the invention relates to a method to
recover oil from a reservoir, which includes injecting high
salinity water into the reservoir followed by alternating the
injection of low salinity water and gas. Another aspect of the
invention includes a method for the enhanced recovery of oil from a
reservoir where oil had previously been recovered.
[0024] As provided herein, the abbreviations as used within this
patent application has the following meanings:
"High salinity water" means a higher salinity level in water
compared to a salinity level in low salinity water. By way of
example only, high salinity water may be seawater, formation water,
produced water and combinations thereof. High salinity water also
includes within its definition the term waterflooding as it is
generally known in the art as in typical operations. "Low salinity
water" means water with a lower salinity level compared to the
salinity level in a high salinity water. By way of example only,
high salinity water may be seawater, while low salinity water may
be desalinated seawater. Other examples of low salinity water may
include, but are not limited to, at least one of desalinated
seawater, diluted seawater, desalinated hydrocarbon reservoir
formation water, diluted hydrocarbon reservoir water, river water,
lake water, or formation water. Alternatively, low salinity water
may be seawater, while high salinity water may be water with a
higher salinity than the seawater. Thus, high salinity water is
defined by the comparison to the low salinity water, and vice
versa. "LS.sub.2" means low salinity where the salinity level is
lower than the high salinity water (for example the seawater) by a
factor of about 2. This low-salinity water can be prepared by a
dilution or desalination processes. "LS.sub.4" means low salinity
where the salinity level is lower than the high salinity water (for
example the seawater) by a factor of about 4. This low-salinity
water can be prepared by a dilution or desalination processes.
"LS.sub.50" means low salinity where the salinity level is lower
than the high salinity water (for example the seawater) by a factor
of about 50. This low-salinity water can be prepared by a dilution
or desalination processes. "LS.sub.x" means low salinity where the
salinity level is lower than the high salinity water (for example
the seawater) by a factor of about "x". This low-salinity water can
be prepared by a dilution or desalination processes. "S.sub.or,"
means residual oil saturation. "S.sub.wi" means initial water
saturation. "SW" means seawater. "MMP" means minimum miscibility
pressure. "RF" means recovery factor. "WAG" means
water-alternating-gas. "LS-WAG" or "LSWAG" means low salinity
water-alternating-gas. "LS-WACO.sub.2" means low salinity
water-alternating-CO.sub.2 gas. "LSWAG ratio" means the ratio of
the low salinity water to the gas. By way of example only, if the
WAG ratio is 1:1, the same amount by pore volume of water is
injected as gas. "Slug size" relates to the pore volume of the low
salinity water and the pore volume of the gas.
[0025] One skilled in the art would understand that the operating
conditions of the reservoir will depend upon the characteristics of
the reservoir. Thus, the temperature, flow rate of the high
salinity water, flow rate of the low salinity water, flow rate of
the gas, duration of the high salinity waterflood, duration of the
low salinity waterflood, duration of the gas injection (which may
be measured by the pore volume injected), the water cut at
completion of the operation and other operating parameters may not
be discussed. However, one skilled in the art would understand how
to determine the operating parameters for the reservoir.
[0026] An aspect of the present invention is a method to recover
oil from a reservoir by injecting high salinity water into the
reservoir, followed by injecting low salinity water into the
reservoir followed by injecting a gas into the reservoir. The low
salinity water and the gas injections can be alternated into the
reservoir.
[0027] As described in the definitions, the salinity level of the
low salinity water is less than the salinity level of the high
salinity water. The low salinity water may be formed by decreasing
the salinity level of the high salinity water to form the low
salinity water. By way of example the high salinity water may be
decreased by desalinating the high salinity water. In some
embodiments, the salinity level of the low salinity water can be
half the salinity level of the high salinity water. In some
embodiments, the salinity level of the low salinity water can be a
quarter the salinity level of the high salinity water. In some
embodiments, the low salinity water can be "x" times the salinity
level of the high salinity water, where x is the amount the
salinity is decreased compared to the high salinity water. The
benefits of the present invention may be increased when the
salinity in the low salinity water is decreased. Thus, in a
preferred embodiment, the low salinity water may be fresh water,
though it is understood that the use of fresh water may be
constricted by economic factors. Furthermore, the salinity of the
low salinity water may be the same or altered with each subsequent
injection. Thus, by way of example only, the salinity level of the
first low salinity water injection may be about LS.sub.2, which the
salinity level of the second low salinity water injection may be
LS.sub.3, then the salinity of the third low salinity water
injection may be LS.sub.4.
[0028] The pore volume of the reservoir may be occupied by the low
salinity water injected into the reservoir, which may be dependent
upon the reservoir. In some embodiments, the pore volume of the
reservoir occupied by the low salinity water injected into the
reservoir may be about 1 (i.e. about 100%). In some embodiments,
the pore volume of the reservoir occupied by the low salinity water
may be greater than about 0.1, about 0.2, about 0.3, about 0.4,
about 0.5, about 0.6, about 0.7, about 0.8, about 0.9 or about 1.
In some embodiments, the pore volume of the first low salinity
water injection may be less than or equal to the pore volume of
subsequent low salinity water injections. In some embodiments where
the high salinity water was injected first, the pore volume of the
reservoir of the low salinity water may be about 1, such that the
majority or all of the high salinity water that was injected into
the reservoir may be displaced by the low salinity water.
[0029] The gas can be any suitable gas, including but not limited
to, carbon dioxide, natural gas liquids, liquid petroleum gas,
nitrogen gas, and combinations thereof. The natural gas liquids can
be intermediate hydrocarbons, such as C.sub.2-C.sub.5 gas, and
combinations thereof. Liquefied petroleum gas (LPG) can be C.sub.3
(propane) or C.sub.4 (butane) or combinations thereof. Preferably,
the gas may be carbon dioxide or NGLs. More preferably, the gas may
be carbon dioxide. In some embodiments, at least some of the
natural gas liquid or at least some of the LPG may be recycled from
the reservoir. One skilled in the art would understand that the
recycled natural gas may need to be scrubbed to remove any
condensate or water within the gas prior to injection into the
reservoir.
[0030] In some embodiments, the pore volume of the reservoir may be
occupied by the gas, such that the gas may occupy greater than
about 0, about 0.1, about 0.2, about 0.3, about 0.4, about 0.5,
about 0.6, about 0.7, about 0.8, about 0.9 or about 1. In some
embodiments, the pore volume of the first gas injection may be
higher than the pore volume of subsequent gas injections. In some
embodiments, the pore volume of the first gas injection may be the
same or less than the pore volume of subsequent gas injections.
[0031] A slug size may be used to characterize the relationship
between the low salinity water injection and gas injection can be
alternated in a slug size of about 0.5 pore volume. In some
embodiments, the low salinity water injection may be alternated in
a slug size of about 0.1 to about 1 pore volume.
[0032] The method may be used to recover oil from an oil reservoir.
In some embodiments, the oil reservoir may be an oil-wet carbonate
reservoir, a shale reservoir or a sandstone reservoir. One skilled
in the art would understand that the reservoir may comprise a
single reservoir or multiple reservoirs, or a single well or
multiple wells. The reservoir may be offshore or onshore. The low
salinity water and the gas can be injected into the reservoir by
alternating the injection of the low salinity water and gas. The
alternating injections may be continued for any duration, for
example, until the water cut is at least about 80 mass %. In some
embodiments, the water cut can be about 85 mass %, about 90 mass %,
and about 95 mass %. In some embodiments, the operation cost may
permit or prevent feasibility of the project.
[0033] Another aspect of the present invention is a method to
enhance recovery of oil in a reservoir. The method includes
waterflooding the reservoir with low salinity water then injecting
a gas into the reservoir. The method may further include a high
salinity waterflood prior to waterflooding the reservoir with the
low salinity water. The method can further include alternating
injecting the low salinity water into the reservoir, and injecting
the gas into the reservoir.
[0034] As described in the definitions, the salinity level of the
low salinity water is less than the salinity level of the high
salinity water. The low salinity water may be formed by decreasing
the salinity level of the high salinity water to form the low
salinity water. By way of example the high salinity water may be
decreased by desalinating the high salinity water. In some
embodiments, the salinity level of the low salinity water can be
half the salinity level of the high salinity water. In some
embodiments, the salinity level of the low salinity water can be a
quarter the salinity level of the high salinity water. In some
embodiments, the low salinity water can be "x" times the salinity
level of the high salinity water, where x is the amount the
salinity is decreased compared to the high salinity water. The
benefits of the present invention may be increased when the
salinity in the low salinity water is decreased. Thus, in a
preferred embodiment, the low salinity water may be fresh water,
though it is understood that the use of fresh water may be
constricted by economic factors. Furthermore, the salinity of the
low salinity water may be the same or altered with each subsequent
injection. Thus, by way of example only, the salinity level of the
first low salinity water injection may be about LS.sub.2, which the
salinity level of the second low salinity water injection may be
LS.sub.3, then the salinity of the third low salinity water
injection may be LS.sub.2.
[0035] The pore volume of the reservoir may be occupied by the low
salinity water injected into the reservoir, which may be dependent
upon the reservoir. In some embodiments, the pore volume of the
reservoir occupied by the low salinity water injected into the
reservoir may be about 1. In some embodiments, the pore volume of
the reservoir occupied by the low salinity water may be greater
than about 0.1, about 0.2, about 0.3, about 0.4, about 0.5, about
0.6, about 0.7, about 0.8, about 0.9 or about 1. In some
embodiments, the pore volume of the first low salinity water
injection may be less than or equal to the pore volume of
subsequent low salinity water injections. In some embodiments where
the high salinity water was injected first, the pore volume of the
reservoir of the low salinity water may be about 1, such that the
majority or all of the high salinity water that was injected into
the reservoir may be displaced by the low salinity water
[0036] The gas can be any suitable gas, including but not limited
to, carbon dioxide, natural gas liquids, liquid petroleum gas,
nitrogen gas, and combinations thereof. The natural gas liquids can
be intermediate hydrocarbons, such as C.sub.2-C.sub.5 gas, and
combinations thereof. Liquefied petroleum gas (LPG) can be C.sub.3
(propane) or C.sub.4 (butane) or combinations thereof. Preferably,
the gas may be carbon dioxide or NGLs. More preferably, the gas may
be carbon dioxide. In some embodiments, at least some of the
natural gas liquid or at least some of the LPG may be recycled from
the reservoir. One skilled in the art would understand that the
recycled natural gas may need to be scrubbed to remove any
condensate or water within the gas prior to injection into the
reservoir.
[0037] In some embodiments, the pore volume of the reservoir may be
occupied by the gas, such that the gas may occupy greater than
about 0, about 0.1, about 0.2, about 0.3, about 0.4, about 0.5,
about 0.6, about 0.7, about 0.8, about 0.9 or about 1. In some
embodiments, the pore volume of the first gas injection may be
higher than the pore volume of subsequent gas injections. In some
embodiments, the pore volume of the first gas injection may the
same or less than the pore volume of subsequent gas injections.
[0038] A slug size may be used to characterize the relationship
between the low salinity water injection and gas injection can be
alternated in a slug size of about 0.5 pore volume. In some
embodiments, the low salinity water injection may be alternated in
a slug size of about 0.1 to about 1 pore volume.
[0039] The method may be used to recover oil from an oil reservoir.
In some embodiments, the oil reservoir may be an oil-wet carbonate
reservoir, a shale reservoir or a sandstone reservoir. One skilled
in the art would understand that the reservoir may comprise a
single reservoir or multiple reservoirs, or a single well or
multiple wells. The reservoir may be offshore or onshore. The low
salinity water and the gas can be injected into the reservoir by
alternating the injection of the low salinity water and gas. The
alternating injections may be continued for any duration, for
example, until the water cut is at least about 80 mass %. In some
embodiments, the water cut can be about 85 mass %, about 90 mass %,
and about 95 mass %. In some embodiments, the operation cost may
permit or prevent feasibility of the project.
[0040] Another aspect of the present invention is a method to
enhance recovery of a hydrocarbon in a reservoir. The method
includes waterflooding the reservoir with high salinity water, then
injecting low salinity water into the reservoir, then injecting a
gas into the reservoir. The method can further include alternating
the injection of low salinity water and gas into the reservoir.
[0041] As described in the definitions, the salinity level of the
low salinity water is less than the salinity level of the high
salinity water. The low salinity water may be formed by decreasing
the salinity level of the high salinity water to form the low
salinity water. By way of example the high salinity water may be
decreased by desalinating the high salinity water. In some
embodiments, the salinity level of the low salinity water can be
half the salinity level of the high salinity water. In some
embodiments, the salinity level of the low salinity water can be a
quarter the salinity level of the high salinity water. In some
embodiments, the low salinity water can be "x" times the salinity
level of the high salinity water, where x is the amount the
salinity is decreased compared to the high salinity water. The
benefits of the present invention may be increased when the
salinity in the low salinity water is decreased. Thus, in a
preferred embodiment, the low salinity water may be fresh water,
though it is understood that the use of fresh water may be
constricted by economic factors. Furthermore, the salinity of the
low salinity water may be the same or altered with each subsequent
injection. Thus, by way of example only, the salinity level of the
first low salinity water injection may be about LS.sub.2, which the
salinity level of the second low salinity water injection may be
LS.sub.3, then the salinity of the third low salinity water
injection may be LS.sub.2.
[0042] The pore volume of the reservoir may be occupied by the low
salinity water injected into the reservoir, which may be dependent
upon the reservoir. In some embodiments, the pore volume of the
reservoir occupied by the low salinity water injected into the
reservoir may be about 1. In some embodiments, the pore volume of
the reservoir occupied by the low salinity water may be greater
than about 0.1, about 0.2, about 0.3, about 0.4, about 0.5, about
0.6, about 0.7, about 0.8, about 0.9 or about 1. In some
embodiments, the pore volume of the first low salinity water
injection may be less than or equal to the pore volume of
subsequent low salinity water injections. In some embodiments where
the high salinity water was injected first, the pore volume of the
reservoir of the low salinity water may be about 1, such that the
majority or all of the high salinity water that was injected into
the reservoir may be displaced by the low salinity water
[0043] The gas can be any suitable gas, including but not limited
to, carbon dioxide, natural gas liquids, liquid petroleum gas,
nitrogen gas, and combinations thereof. The natural gas liquids can
be intermediate hydrocarbons, such as C.sub.2-C.sub.5 gas, and
combinations thereof. Liquefied petroleum gas (LPG) can be C.sub.3
(propane) or C.sub.4 (butane) or combinations thereof. Preferably,
the gas may be carbon dioxide or NGLs. More preferably, the gas may
be carbon dioxide. In some embodiments, at least some of the
natural gas liquid or at least some of the LPG may be recycled from
the reservoir. One skilled in the art would understand that the
recycled natural gas may need to be scrubbed to remove any
condensate or water within the gas prior to injection into the
reservoir.
[0044] In some embodiments, the pore volume of the reservoir may be
occupied by the gas, such that the gas may occupy greater than
about 0, about 0.1, about 0.2, about 0.3, about 0.4, about 0.5,
about 0.6, about 0.7, about 0.8, about 0.9 or about 1. In some
embodiments, the pore volume of the first gas injection may be
higher than the pore volume of subsequent gas injections. In some
embodiments, the pore volume of the first gas injection may the
same or less than the pore volume of subsequent gas injections.
[0045] A slug size may be used to characterize the relationship
between the low salinity water injection and gas injection can be
alternated in a slug size of about 0.5 pore volume. In some
embodiments, the low salinity water injection may be alternated in
a slug size of about 0.1 to about 1 pore volume.
[0046] The method may be used to recover oil from an oil reservoir.
In some embodiments, the oil reservoir may be an oil-wet carbonate
reservoir, a shale reservoir or a sandstone reservoir. One skilled
in the art would understand that the reservoir may comprise a
single reservoir or multiple reservoirs, or a single well or
multiple wells. The reservoir may be offshore or onshore. The low
salinity water and the gas can be injected into the reservoir by
alternating the injection of the low salinity water and gas. The
alternating injections may be continued for any duration, for
example, until the water cut is at least about 80 mass %. In some
embodiments, the water cut can be about 85 mass %, about 90 mass %,
and about 95 mass %. In some embodiments, the operation cost may
permit or prevent feasibility of the project.
[0047] Another aspect of the invention is a method to enhance
recovery of a hydrocarbon in a reservoir. The method includes
injecting a gas into the reservoir followed by waterflooding the
reservoir with a low salinity water. The method can further include
alternating the injection of the gas and low salinity water into
the reservoir.
[0048] As described in the definitions, the salinity level of the
low salinity water is less than the salinity level of the high
salinity water. The low salinity water may be formed by decreasing
the salinity level of the high salinity water to form the low
salinity water. By way of example the high salinity water may be
decreased by desalinating the high salinity water. In some
embodiments, the salinity level of the low salinity water can be
half the salinity level of the high salinity water. In some
embodiments, the salinity level of the low salinity water can be a
quarter the salinity level of the high salinity water. In some
embodiments, the low salinity water can be "x" times the salinity
level of the high salinity water, where x is the amount the
salinity is decreased compared to the high salinity water. The
benefits of the present invention may be increased when the
salinity in the low salinity water is decreased. Thus, in a
preferred embodiment, the low salinity water may be fresh water,
though it is understood that the use of fresh water may be
constricted by economic factors. Furthermore, the salinity of the
low salinity water may be the same or altered with each subsequent
injection. Thus, by way of example only, the salinity level of the
first low salinity water injection may be about LS.sub.2, which the
salinity level of the second low salinity water injection may be
LS.sub.3, then the salinity of the third low salinity water
injection may be LS.sub.2.
[0049] The pore volume of the reservoir may be occupied by the low
salinity water injected into the reservoir, which may be dependent
upon the reservoir. In some embodiments, the pore volume of the
reservoir occupied by the low salinity water injected into the
reservoir may be about 1. In some embodiments, the pore volume of
the reservoir occupied by the low salinity water may be greater
than about 0.1, about 0.2, about 0.3, about 0.4, about 0.5, about
0.6, about 0.7, about 0.8, about 0.9 or about 1. In some
embodiments, the pore volume of the first low salinity water
injection may be less than or equal to the pore volume of
subsequent low salinity water injections. In some embodiments where
the high salinity water was injected first, the pore volume of the
reservoir of the low salinity water may be about 1, such that the
majority or all of the high salinity water that was injected into
the reservoir may be displaced by the low salinity water
[0050] The gas can be any suitable gas, including but not limited
to, carbon dioxide, natural gas liquids, liquid petroleum gas,
nitrogen gas, and combinations thereof. The natural gas liquids can
be intermediate hydrocarbons, such as C.sub.2-C.sub.5 gas, and
combinations thereof. Liquefied petroleum gas (LPG) can be C.sub.3
(propane) or C.sub.4 (butane) or combinations thereof. Preferably,
the gas may be carbon dioxide or NGLs. More preferably, the gas may
be carbon dioxide. In some embodiments, at least some of the
natural gas liquid or at least some of the LPG may be recycled from
the reservoir. One skilled in the art would understand that the
recycled natural gas may need to be scrubbed to remove any
condensate or water within the gas prior to injection into the
reservoir.
[0051] In some embodiments, the pore volume of the reservoir may be
occupied by the gas, such that the gas may occupy greater than
about 0, about 0.1, about 0.2, about 0.3, about 0.4, about 0.5,
about 0.6, about 0.7, about 0.8, about 0.9 or about 1. In some
embodiments, the pore volume of the first gas injection may be
higher than the pore volume of subsequent gas injections. In some
embodiments, the pore volume of the first gas injection may the
same or less than the pore volume of subsequent gas injections.
[0052] A slug size may be used to characterize the relationship
between the low salinity water injection and gas injection can be
alternated in a slug size of about 0.5 pore volume. In some
embodiments, the low salinity water injection may be alternated in
a slug size of about 0.1 to about 1 pore volume.
[0053] The method may be used to recover oil from an oil reservoir.
In some embodiments, the oil reservoir may be an oil-wet carbonate
reservoir, a shale reservoir or a sandstone reservoir. One skilled
in the art would understand that the reservoir may comprise a
single reservoir or multiple reservoirs, or a single well or
multiple wells. The reservoir may be offshore or onshore. The low
salinity water and the gas can be injected into the reservoir by
alternating the injection of the low salinity water and gas. The
alternating injections may be continued for any duration, for
example, until the water cut is at least about 80 mass %. In some
embodiments, the water cut can be about 85 mass %, about 90 mass %,
and about 95 mass %. In some embodiments, the operation cost may
permit or prevent feasibility of the project.
EXAMPLE
Example 1
[0054] Two core-flood experiment of seawater flood, followed by
three sets of low salinity-water flood, flowed by CO.sub.2 flood is
performed on Facies 5 (F5) of Reservoir I core samples from a giant
carbonate oil field in the Middle East. Facies description and
geologic study of the reservoir can be found in Jobe (2013). Cores
were prepared, cleaned using toluene and methanol. The
petrophysical properties such as permeability and porosity are
measured using Core Measurement System (CMS-300). Table 1 lists
rock properties of samples used in the two core-flood experiments.
The core type for all samples was F5 carbonate core (composite
core). The diameter of the samples was about 1.5 inches and the PV
was about 29.98 cc for Example 1 and 34.864 cc for Example 2. The
miscible CO.sub.2 flooding following seawater and low salinity
waterflooding (e.g. LS.sub.2, LS.sub.4, LS.sub.x) on composite
carbonate cores. Eight weeks of aging applied. The miscible
CO.sub.2 flooding following seawater and low salinity waterflooding
(e.g. LS.sub.2, LS.sub.4, LS.sub.x) on composite carbonate cores.
Eight weeks of aging applied.
TABLE-US-00001 TABLE 1 Exp. # L (in) .phi., % k.sub.air (md) 1 a
1.88 26.9 3.38 b 1.82 21.1 1.16 c 1.896 14.5 0.76 2 a 1.7 18.23
1.49 b 1.88 21.35 7.04 c 1.881 26.95 3.81
Tests were performed on a stack with three cores each. Ultra-high
speed centrifuge (ACES 200) is used to saturate the cores with
formation brine. A composite core is formed by combining the three
cores using Huppler technique as illustrated in FIG. 1 for sample 1
discussed in Table 1. The image of the core samples illustrated in
FIG. 1 was taken at the end of the experiment. The total length of
the composite core was about 5.596 inches. The flooding direction
was from left to right. Another set of stacked cores from F5 were
used for core-flood experiment #2. The composite core was placed in
a high-pressure-high-temperature (HPHT) core flooding equipment,
Formation Response Tester (FRT 6100). Three additional pore volumes
(PV) of brine were injected into the composite core inside the
core-flood equipment to ensure full brine saturation and no air in
trapped in the pores. A confining pressure of about 2,300 psia,
back pressure regulator (BPR) of about 1800 psia, and reservoir
temperature of about 195.degree. F. were applied to the hassler
type core holder unit during the flooding and aging processes. The
schematic of the three phase core flooding experiment setup is
illustrated in FIG. 2. Up to the three sets of low salinity
flooding, the production fluids are collected in the fraction
collector. For the case of gas flooding, the separator is used to
collect the production fluid; and the produced gas is measured
using the gas flow meter (GFM); and the oil/water are collected in
a graduated tube and centrifuged and measured.
[0055] FIG. 3 illustrates the overall experimental procedure. First
the core was prepared and cleaned, the petrophysical properties
were measured and the fluid was prepared and measured. The brine
was saturated with brine, then flooded with oil. The core was aged,
then flooded again with oil. Next the samples were flooded with
water, followed by a series of low salinity waterflooding. Finally,
the samples were flooded with gas, specifically CO.sub.2.
[0056] Following the overall experimental procedure set forth in
FIG. 3, fifteen pore volume of crude oil was then injected at about
0.1 cc/min flow rate to achieve the residual water saturation
(S.sub.wi), and also to determine the oil relative permeability end
point. The oil composition and oil properties are listed in Table 2
and Table 3, respectively. Oil/brine viscosities at reservoir
temperature of about 195.degree. F. are given in Table 4.
TABLE-US-00002 TABLE 2 Components Mole % CO.sub.2 1.047879 N.sub.2
0.000000 C.sub.1 13.782727 C.sub.2 5.455455 C.sub.3 6.584545
C.sub.4* 5.722424 C.sub.5* 5.267273 C.sub.9* 33.632886 C.sub.21*
21.938239 C.sub.47* 6.568572 *Lumped components
TABLE-US-00003 TABLE 3 Fluid Type API .degree. SG Crude Oil 32
0.865
TABLE-US-00004 TABLE 4 Fluid Type Viscosity (cP) crude oil 3.0
Brine/seawater/ 0.535 low salinity water
[0057] The composite core was aged for 8 weeks to restore
wettability. Four PV of crude oil was injected to saturate the
composite core with crude oil after wettability restoration and
determine relative permeability to oil. Seven PV of sea water was
then injected at about 0.1 cc/min to displace the oil and determine
the residual oil saturation to seawater. This step also was used to
determine the seawater relative permeability end point. Pressure
and temperature conditions of the core flooding unit were kept the
same as in the previous situation. A recovery factor (RF) of about
61.2% was obtained during seawater flooding.
[0058] Three sets of low salinity waterflooding were performed
following the seawater flooding. The first low salinity flood
(LS.sub.2) is obtained by diluting the seawater twice, and LS.sub.4
is five times diluted seawater and LS.sub.50 is fifty times diluted
seawater. Table 5 is composition of the seawater (SW) and three
sets of low salinity water (LS.sub.2, LS.sub.4 and LS.sub.50).
TABLE-US-00005 TABLE 5 Brine/ Compound (kppm) Na.sub.2SO.sub.4
CaCl.sub.2*2H.sub.2O MaCl.sub.2*6H.sub.2O NaCl TDS SW 4.891 1.915
13.550 30.99 51.346 LS.sub.2 2.446 0.958 6.775 15.50 25.679
LS.sub.4 1.223 0.479 3.388 7.75 12.840 LS.sub.50 0.098 0.038 0.271
0.620 1.027
[0059] The incremental oil recovery of the first two low salinity
waterflooding EOR process are about 6% and about 1.1% respectively.
No additional oil was recovered during the third low salinity
waterflood. A constant about 0.1 cc/min injection rate of 5 PV was
applied in each of the three low salinity waterflood EOR processes.
An increase of injectivity as witnessed by the reduction in
pressure drop is observed during the low salinity waterflood as
compared to seawater flooding as illustrated in FIG. 4. Pressure
and temperature conditions of the core flooding unit were kept the
same as in the previous situation.
[0060] FIG. 4 illustrates the oil RF and pressure difference
between injection and production end (.DELTA.P) as a function pore
volume injected (PV inj). During seawater flooding (SW), about
61.2% oil was recovered. During the three sets of low salinity
waterflood (LS.sub.2, LS.sub.4 and LS.sub.50) EOR process, about
additional 7.1% oil was recovered. And finally during the CO.sub.2
miscible flood, about additional 14.2% oil was recovered.
[0061] Finally, fourteen PV continuous CO.sub.2 gas flooding was
performed at about 0.3 cc/min following the three sets of low
salinity waterflooding. During the CO.sub.2 flooding, the confining
pressure and back-pressure regulator (BPR) of the core older unit
were raised about 2700 psia and about 2500 psia respectively to
achieve miscibility. An incremental oil recovery of about 14.2% has
been obtained during the miscible CO.sub.2 flooding. The
injectivity to CO.sub.2 flood is observed to increase as witnessed
by the reduction of pressure drop during the CO.sub.2 flooding
period as illustrated in FIG. 4.
[0062] The MMP of crude oil and CO.sub.2 gas is measured using the
rising-bubble apparatus (RBA) as about 2500 psia. The MMP crude oil
and CO.sub.2 gas also calculated using the Multiple Mixing Cell
(MMC) approach (Ahmadi and Johns, 2011; Teklu et al., 2012) and
good match has been achieved with the experimental data. The MMP of
crude oil with CO.sub.2 gas is determined using MMC approach as
about 2470 psia. The MMP of rich gas, nitrogen, mixture of rich gas
and CO.sub.2, and mixture of rich gas and nitrogen gas with the
crude oil is also determined using MMC approach. Table 6 is the MMP
of the crude oil with different injection gas scenarios.
TABLE-US-00006 TABLE 6 Gas injection cases MMP, psia 100% CO.sub.2
2470 100% NGLs* 830 50% CO.sub.2 and 50% NGLs* 1615 100% N.sub.2
14,000 50% N.sub.2 and 50% NGLs* 4860 20% N.sub.2 and 80% NGLs*
1400 *[0.61 C.sub.2, 0.22 C.sub.3, 0.095 C.sub.4, 0.065 C.sub.5 and
0.01 C.sub.6] is the composition of NGLs used in this study.
Example 2
[0063] The core-flood protocol applied to the second core-flood on
a second F5 sample from Reservoir I was similar to the first
core-flood protocol. About 52.8% oil was recovered during
waterflooding, about 5.2% additional oil was recovered during
LS.sub.2 flooding, and about 0.4% and no additional oil was
recovered during LS.sub.4 and LS.sub.50 flooding cycles,
respectively. Finally, about 25% additional oil was recovery during
about 10 PV continuous miscible CO.sub.2 flooding. FIG. 5
illustrates the oil recovery factor and pressure drop as a function
pore volume injected.
Example 3
[0064] The interfacial tension (IFT) between brine and oil as well
as wettability of core discs with oil was measured at ambient
conditions. Drop Shape Analyzer, DSA 100, was used to measure
contact angles between solids and fluids and IFT between different
fluids. For both IFT and wettability measurements, the effect of
salinity of brine was investigated. About 32.degree. API gravity
crude oil from Reservoir I was used in both IFT and wettability
measurement. Also the Reservoir I formation brine (FB) was used in
the IFT and wettability measurements. Pendant drop method was used
to determine the IFT, whereas, captive oil droplet contact angle
measurement method was applied during the contact angle
measurements. Detailed discussion on the IFT and contact angle
measurement and additional results can be found in Teklu et al.
(2014), Teklu et al., (2015), and Alameri et al. (2014).
[0065] Wettability measurements were performed on crude-aged F5
carbonate, Berea sandstone, and Three Forks core discs at
measurement conations A, B, C and D. The measurement condition A is
the base case contact angle measurement, where the core discs were
crude-aged for three weeks at reservoir temperature and the
surrounding brine during contact angle measurements between the
disc and oil-drop late was seawater (SW). The measurement condition
B is where the crude-aged discs were kept for two days in a piston
at about 2,500 psi inside a mixture of about 300 ml seawater (SW)
and about 200 ml CO.sub.2. The core disc and SW--CO.sub.2 mixture
were then extracted from the piston after slowly releasing the
pressure. The contact angle measurements were performed at room
conditions between oil-droplets and the core discs where the
surrounding fluid was the SW--CO.sub.2 mixture extracted from the
cylinder hence has less CO.sub.2 concentration as the pressure was
atmospheric. This was to mimic the reservoir condition of seawater
alternated CO.sub.2 EOR process. Measurement condition C occurred
when the core discs that underwent measurement condition B were
kept for additional about two days in a piston at about 2,500 psi
inside a mixture of about 300 ml LS.sub.2 and about 200 ml
CO.sub.2. The core discs and LS.sub.2--CO.sub.2 mixture were then
extracted from the piston after slowly releasing the pressure. The
contact angle measurements were then performed at room conditions
between oil-droplets and the core discs where the surrounding fluid
was the LS.sub.2--CO.sub.2 mixture extracted from the cylinder
hence has less CO.sub.2 concentration as the pressure was
atmospheric. This measurement condition was to mimic the reservoir
condition of low salinity water alternated with CO.sub.2 EOR
process. About 2,500 psi in both measurement conditions B and C
were chosen to mimic miscible CO.sub.2 situation. Measurement
condition D occurred when the core discs were cleaned and un-aged
and the surrounding fluid was seawater (SW). This measurement
condition was reported here for comparison reason to show how
reservoirs wettability was altered in secondary and tertiary
recovery mechanisms where condition D is the extreme possible
situation when the reservoir pore is `cleaned` during many pore
volume CO.sub.2 injection. In the cleaning process of the core
discs, toluene was applied in Soxhlet extractor until no oil trace
was seen from the discs and methanol was used to remove if any salt
was present and then toluene was again used to make sure the core
discs are clean.
[0066] FIG. 6 illustrates the core discs corresponding to
measurement conditions A, B, C, and D. Pictures of the carbonate,
Berea sandstone, and Three Forks discs used for contact angle
measurement at measurement conditions A, B, C and D. Note that
measurement conditions A, B and C were performed on the same discs
whereas D was performed on adjacent discs (scale: about 0.5 cm by
about 0.5 cm square paper).
[0067] FIGS. 7 and 8, and Table 7 illustrate the contact angle
measurement conditions A, B, and C for carbonate, Berea sandstone
and Three Forks core discs. As illustrated in FIG. 7, the
wettability of carbonate, Berea sandstone, and Three Forks
constantly changed towards water wet wettability state as
measurements progressed from measurement condition "A" to "D." This
implies that wettability alteration was one of the main mechanisms
in mobilizing residual oil in hybrid low salinity and CO.sub.2
flooding EOR process. FIG. 8 illustrates the contact angle between
carbonate/sandstone/Three Forks discs and oil-droplet at
measurement conditions A, B, and C. The first, second, and third
row of FIG. 8 corresponds to carbonate, Berea sandstone, and The
Three Forks core disc cases respectively. And the first, second,
and third columns of FIG. 8 correspond to measurement condition A,
B, and C respectively. The volume of the oil droplets ranged from
about 4 to 15.mu. liters.
[0068] Brine pH and oil-brine IFT measurements were also performed
where the brine was the SW--CO.sub.2 and LS.sub.2--CO.sub.2
mixtures after the pressure was released to atmospheric pressure
and most of the CO.sub.2 were escaped from the solution. Table 8
illustrates the IFT between oil and brine over varying pHs of the
brine. As illustrated in Table 8, at atmospheric pressure and room
temperature, a moderate IFT and pH reduction due to CO.sub.2
solution in the mixture was observed as compared to the SW and
LS.sub.2 brines without CO.sub.2. Atmospheric conditions were used
for the SW--CO.sub.2 mixture and the LS.sub.2--CO.sub.2 mixture.
Further IFT and brine pH reduction is anticipated at reservoir
pressure.
TABLE-US-00007 TABLE 7 Measurement Contact Angle, .theta., in
degrees condition Carbonate Berea Sandstone Three Forks A 133.6
94.6 116.6 B 36.1 60.0 40.8 C 31.2 46.5 36.6 D 21.0 20.4 27.0
TABLE-US-00008 TABLE 8 IFT between oil and Brine brine, dynes/cm pH
SW 16.62 6.60 SW-CO.sub.2 mixture 11.96 5.50 LS.sub.2 18.85 6.53
LS.sub.2-CO2 mixture 12.34 5.29
[0069] The foregoing description of the present invention has been
presented for purposes of illustration and description.
Furthermore, the description is not intended to limit the invention
to the form disclosed herein. Consequently, variations and
modifications commensurate with the above teachings, and the skill
or knowledge of the relevant art, are within the scope of the
present invention. The embodiment described hereinabove is further
intended to explain the best mode known for practicing the
invention and to enable others skilled in the art to utilize the
invention in such, or other, embodiments and with various
modifications required by the particular applications or uses of
the present invention. It is intended that the appended claims be
construed to include alternative embodiments to the extent
permitted by the prior art.
* * * * *