Note: Descriptions are shown in the official language in which they were submitted.
CA 027966632012-10-16
WO 2011/140180 PCT/US2011/035122
SYSTEMS AND METHODS FOR PRODUCING OIL AND/OR GAS
Field of the Invention
The present disclosure relates to systems and methods for producing oil
and/or gas.
Background of the Invention
Enhanced Oil Recovery (EOR) may be used to increase oil recovery in
fields worldwide. There are three main types of EOR, thermal, chemical/polymer
and gas injection, which may be used to increase oil recovery from a
reservoir,
beyond what can be achieved by conventional means ¨ possibly extending the
life
of a field and boosting the oil recovery factor.
Thermal enhanced recovery works by adding heat to the reservoir. The
most widely practiced form is a steam drive, which reduces oil viscosity so
that it
can flow to the producing wells. Chemical flooding increases recovery by
reducing
the capillary forces that trap residual oil. Polymer flooding improves the
sweep
efficiency of injected water. Miscible injection works in a similar way to
chemical
flooding. By injecting a fluid that is miscible with the oil, trapped residual
oil can be
recovered.
Referring to Figure 1, there is illustrated prior art system 100. System 100
includes underground formation 102, underground formation 104, underground
formation 106, and underground formation 108. Production facility 110 is
provided
at the surface. Well 112 traverses formations 102 and 104, and terminates in
formation 106. The portion of formation 106 is shown at 114. Oil and gas are
produced from formation 106 through well 112, to production facility 110. Gas
and
liquid are separated from each other, gas is stored in gas storage 116 and
liquid is
stored in liquid storage 118.
U.S. Patent Number 5,826,656 discloses a method for recovering
waterflood residual oil from a waterflooded oil-bearing subterranean formation
penetrated from an earth surface by at least one well by injecting an oil
miscible
solvent into a waterflood residual oil-bearing lower portion of the oil-
bearing
subterranean formation through a well completed for injection of the oil
miscible
solvent into the lower portion of the oil-bearing formation; continuing the
injection
of the oil miscible solvent into the lower portion of the oil-bearing
formation for a
1
:A 027966632012-10-16
WO 2011/140180 PCT/US2011/035122
period of time equal to at least one week; recompleting the well for
production of
quantities of the oil miscible solvent and quantities of waterflood residual
oil from
an upper portion of the oil-bearing formation; and producing quantities of the
oil
miscible solvent and waterflood residual oil from the upper portion of the oil-
bearing formation. The formation may have previously been both waterflooded
and oil miscible solvent flooded. The solvent may be injected through a
horizontal
well and solvent and oil may be recovered through a plurality of wells
completed to
produce oil and solvent from the upper portion of the oil-bearing formation.
PCT Patent Application Publication WO 2010/02693 discloses a method
comprising recovering a carbon source from a formation; converting at least a
portion of the carbon source to a synthesis gas; converting at least a portion
of the
synthesis gas to an ether; and injecting at least a portion of the ether into
the
formation.
PCT Patent Application Publication WO 2008/141051 discloses a system
for producing oil and/or gas from an underground formation including a well
above
the formation; a mechanism to inject an enhanced oil recovery formulation into
the
formation, the enhanced oil recovery formulation including dimethyl ether; and
a
mechanism to produce oil and/or gas from the formation.
There is a need in the art for improved systems and methods for enhanced
oil recovery. There is a further need in the art for improved systems and
methods
for enhanced oil recovery using a water flood. There is a further need in the
art for
improved systems and methods for improving the operation and recovery factor
from a water flood.
Summary of the Invention
In one aspect, the invention provides a system for producing oil and/or gas
from an underground formation comprising a well above the formation; a
mechanism to inject an enhanced oil recovery formulation into the formation,
the
enhanced oil recovery formulation comprising water and an additive; and a
mechanism to produce oil and/or gas from the formation.
In another aspect, the invention provides a method for producing oil and/or
gas comprising injecting water and an additive into a formation from a first
well;
and producing oil and/or gas from the formation from a second well.
2
81656554
Advantages of the invention include one or more of the following:
Improved systems and methods for enhanced recovery of hydrocarbons
from a formation with an improved waterflood.
Improved systems and methods for enhanced recovery of hydrocarbons
from a formation with a water injectant containing an oil soluble or miscible
additive.
Improved compositions and/or techniques for secondary recovery of
hydrocarbons.
Improved systems and methods for enhanced oil recovery.
Improved systems and methods for enhanced oil recovery using a miscible
additive in a waterflood.
Improved systems and methods for enhanced oil recovery using water with a
compound which is miscible with oil in place.
Improved systems and methods for maintaining formation pressure.
Improved systems and methods for maintaining production rates.
Improved systems and methods for increasing the life of a reservoir.
Improved systems and methods for boosting the oil recovery factor.
According to one aspect of the present invention, there is provided a
method for producing oil and/or gas comprising: injecting water and an
additive
chosen from the group consisting of dimethyl ether, diethyl ether, and methyl
ethyl
ether into a formation from a first well wherein the mixture of the water and
the
additive comprises from about 50% to about 99% water (by moles); producing oil
and/or gas from the formation from a second well stopping injecting the
mixture of
3
CA 2796663 2017-09-21
81656554
water and additive; injecting water without additive into the formation; and
producing
a water additive mixture to the surface.
Brief Description of the Drawings
Figure 1 illustrates an oil and/or gas production system.
Figure 2a illustrates a well pattern.
Figures 2b and 2c illustrate the well pattern of Figure 2a during enhanced oil
recovery processes.
Figures 3a-3c illustrate oil and/or gas production systems.
Figure 4 illustrates an oil and/or gas production method.
Figure 5 illustrates a list of suitable waterflood additives.
Figure 6 illustrates a list of suitable waterflood additives.
Figure 7 illustrates the incremental recovery with the use of a waterflood
additive.
Figure 8 illustrates the incremental recovery with the use of waterflood
additives of different concentrations.
3a
CA 2796663 2017-09-21
20 02796663 2012-10-16
WO 2011/140180
PCT/US2011/035122
Detailed Description of the Invention
Figures 2a, 2b, & 2c:
Referring now to Figure 2a, in some embodiments, an array of wells 200 is
illustrated. Array 200 includes well group 202 (denoted by horizontal lines)
and
well group 204 (denoted by diagonal lines).
Each well in well group 202 has horizontal distance 230 from the adjacent
well in well group 202. Each well in well group 202 has vertical distance 232
from
the adjacent well in well group 202.
Each well in well group 204 has horizontal distance 236 from the adjacent
well in well group 204. Each well in well group 204 has vertical distance 238
from
the adjacent well in well group 204.
Each well in well group 202 is distance 234 from the adjacent wells in well
group 204. Each well in well group 204 is distance 234 from the adjacent wells
in
well group 202.
In some embodiments, each well in well group 202 is surrounded by four
wells in well group 204. In some embodiments, each well in well group 204 is
surrounded by four wells in well group 202.
In some embodiments, horizontal distance 230 is from about 5 to about
1000 meters, or from about 10 to about 500 meters, or from about 20 to about
250
meters, or from about 30 to about 200 meters, or from about 50 to about 150
meters, or from about 90 to about 120 meters, or about 100 meters.
In some embodiments, vertical distance 232 is from about 5 to about 1000
meters, or from about 10 to about 500 meters, or from about 20 to about 250
meters, or from about 30 to about 200 meters, or from about 50 to about 150
meters, or from about 90 to about 120 meters, or about 100 meters.
In some embodiments, horizontal distance 236 is from about 5 to about
1000 meters, or from about 10 to about 500 meters, or from about 20 to about
250
meters, or from about 30 to about 200 meters, or from about 50 to about 150
meters, or from about 90 to about 120 meters, or about 100 meters.
In some embodiments, vertical distance 238 is from about 5 to about 1000
meters, or from about 10 to about 500 meters, or from about 20 to about 250
meters, or from about 30 to about 200 meters, or from about 50 to about 150
meters, or from about 90 to about 120 meters, or about 100 meters.
4
20 02796663 2012-10-16
WO 2011/140180
PCT/US2011/035122
In some embodiments, distance 234 is from about 5 to about 1000 meters,
or from about 10 to about 500 meters, or from about 20 to about 250 meters, or
from about 30 to about 200 meters, or from about 50 to about 150 meters, or
from
about 90 to about 120 meters, or about 100 meters.
In some embodiments, array of wells 200 may have from about 10 to about
1000 wells, for example from about 5 to about 500 wells in well group 202, and
from about 5 to about 500 wells in well group 204.
In some embodiments, array of wells 200 is seen as a top view with well
group 202 and well group 204 being vertical wells spaced on a piece of land.
In
some embodiments, array of wells 200 is seen as a cross-sectional side view
with
well group 202 and well group 204 being horizontal wells spaced within a
formation.
Referring now to Figure 2b, in some embodiments, array of wells 200 is
illustrated. Array 200 includes well group 202 (denoted by horizontal lines)
and
well group 204 (denoted by diagonal lines).
In some embodiments, a water flooding mixture is injected into well group
204, and oil is recovered from well group 202. As illustrated, the water
flooding
mixture has injection profile 208, and oil recovery profile 206 is being
produced to
well group 202.
In some embodiments, a water flooding mixture is injected into well group
202, and oil is recovered from well group 204. As illustrated, the water
flooding
mixture has injection profile 206, and oil recovery profile 208 is being
produced to
well group 204.
In some embodiments, well group 202 may be used for injecting a water
flooding mixture, and well group 204 may be used for producing oil and/or gas
from the formation for a first time period; then well group 204 may be used
for
injecting a water flooding mixture, and well group 202 may be used for
producing
oil and/or gas from the formation for a second time period, where the first
and
second time periods comprise a cycle.
In some embodiments, multiple cycles may be conducted which include
alternating well groups 202 and 204 between injecting a water flooding
mixture,
and producing oil and/or gas from the formation, where one well group is
injecting
5
20 02796663 2012-10-16
WO 2011/140180 PCT/US2011/035122
and the other is producing for a first time period, and then they are switched
for a
second time period.
In some embodiments, a cycle may be from about 12 hours to about 1 year,
or from about 3 days to about 6 months, or from about 5 days to about 3
months.
In some embodiments, each cycle may increase in time, for example each cycle
may be from about 5% to about 10% longer than the previous cycle, for example
about 8% longer.
In some embodiments, a water flooding mixture may be injected at the
beginning of a cycle, and an immiscible enhanced oil recovery agent or a
mixture
including an immiscible enhanced oil recovery agent may be injected at the end
of
the cycle. In some embodiments, the beginning of a cycle may be the first 10%
to
about 80% of a cycle, or the first 20% to about 60% of a cycle, the first 25%
to
about 40% of a cycle, and the end may be the remainder of the cycle.
Referring now to Figure 2c, in some embodiments, array of wells 200 is
illustrated. Array 200 includes well group 202 (denoted by horizontal lines)
and
well group 204 (denoted by diagonal lines).
In some embodiments, a water flooding mixture is injected into well group
204, and oil is recovered from well group 202. As illustrated, the water
flooding
mixture has injection profile 208 with overlap 210 with oil recovery profile
206,
which is being produced to well group 202.
In some embodiments, a water flooding mixture is injected into well group
202, and oil is recovered from well group 204. As illustrated, the water
flooding
mixture has injection profile 206 with overlap 210 with oil recovery profile
208,
which is being produced to well group 204.
Enhanced Oil Recovery Methods
The recovery of oil and/or gas with array of wells 200 from an underground
formation may be accomplished by any known method. Suitable methods include
subsea production, surface production, primary, secondary, or tertiary
production.
The selection of the method used to recover the oil and/or gas from the
underground formation is not critical.
In some embodiments, oil and/or gas may be recovered from a formation
into a well, and flow through the well and flowline to a facility. In some
embodiments, enhanced oil recovery, water with the use of an added agent for
6
20 02796663 2012-10-16
WO 2011/140180 PCT/US2011/035122
example a surfactant, a polymer, and/or a miscible agent such as a dimethyl
ether
formulation or carbon dioxide, may be used to increase the flow of oil and/or
gas
from the formation.
Releasing at least a portion of the water flooding mixture and/or other
.. liquids and/or gases may be accomplished by any known method. One suitable
method is injecting the water flooding mixture into a single conduit in a
single well,
allowing the water flooding mixture to soak, and then pumping out at least a
portion of the water flooding mixture with gas and/or liquids. Another
suitable
method is injecting the water flooding mixture into a first well, and pumping
out at
.. least a portion of the water flooding mixture with gas and/or liquids
through a
second well. The selection of the method used to inject at least a portion of
the
water flooding mixture and/or other liquids and/or gases is not critical.
In some embodiments, the water flooding mixture and/or other liquids
and/or gases may be pumped into a formation at a pressure up to the fracture
.. pressure of the formation.
In some embodiments, the water flooding mixture may be mixed in with oil
and/or gas in a formation to form a mixture which may be recovered from a
well.
In some embodiments, a quantity of the water flooding mixture may be injected
into a well, followed by another component to force the formulation across the
.. formation. For example air, water in liquid or vapor form, carbon dioxide,
other
gases, other liquids, and/or mixtures thereof may be used to force the water
flooding mixture across the formation.
In some embodiments, the water flooding mixture may be heated prior to
being injected into the formation to lower the viscosity of fluids in the
formation, for
example heavy oils, paraffins, asphaltenes, etc.
In some embodiments, the water flooding mixture may be heated and/or
boiled while within the formation, with the use of a heated fluid or a heater,
to lower
the viscosity of fluids in the formation. In some embodiments, heated water
and/or
steam may be used to heat and/or vaporize the water flooding mixture in the
formation.
In some embodiments, the water flooding mixture may be heated and/or
boiled while within the formation, with the use of a heater. One suitable
heater is
disclosed in copending United States Patent Application having serial number
7
81656554
10/693,816, filed on October 24, 2003.
Figures 3a & 3b:
Referring now to Figures 3a and 3b, in some embodiments of the invention,
system 300 is illustrated. System 300 includes underground formation 302,
underground formation 304, underground formation 306, and underground
formation 308. Facility 310 is provided at the surface. Well 312 traverses
formations 302 and 304, and has openings in formation 306. Portions 314 of
formation 306 may be optionally fractured and/or perforated. During primary
production, oil and gas from formation 306 is produced into portions 314, into
well
312, and travels up to facility 310. Facility 310 then separates gas, which is
sent
to gas processing 316, and liquid, which is sent to liquid storage 318.
Facility 310
also includes water flooding mixture storage 330. As shown in Figure 3a, water
flooding mixture may be pumped down well 312 that is shown by the down arrow
and pumped into formation 306. Water flooding mixture may be left to soak in
formation for a period of time from about 1 hour to about 15 days, for example
from about 5 to about 50 hours.
After the soaking period, as shown in Figure 3b, water flooding mixture and
oil and/or gas is then produced back up well 312 to facility 310. Facility 310
is
adapted to separate and/or recycle water flooding mixture, for example by a
gravity separation, centrifugal separation, chemical absorption, and/or by
boiling
the formulation, condensing it or filtering or reacting it, then storing or
transporting
desirable liquids and gases, and re-injecting and/or disposing of undesirable
liquids and gases, for example by repeating the soaking cycle shown in Figures
3a
and 3b from about 2 to about 5 times.
In some embodiments, water flooding mixture may be pumped into
formation 306 below the fracture pressure of the formation, for example from
about
40% to about 90% of the fracture pressure.
In some embodiments, well 312, as shown in Figure 3a, injecting into
formation 306 may be representative of a well in well group 202, and well 312
as
shown in Figure 3b, producing from formation 306, may be representative of a
well
in well group 204.
8
CA 2796663 2017-09-21
20 02796663 2012-10-16
WO 2011/140180 PCT/US2011/035122
In some embodiments, well 312 as shown in Figure 3a, injecting into
formation 306, may be representative of a well in well group 204, and well
312, as
shown in Figure 3b, producing from formation 306 may be representative of a
well
in well group 202.
Figure 3c:
Referring now to Figure 3c, in some embodiments of the invention, system
400 is illustrated. System 400 includes underground formation 402, formation
404,
formation 406, and formation 408. Production facility 410 is provided at the
surface. Well 412 traverses formation 402 and 404 has openings at formation
406. Portions of formation 414 may be optionally fractured and/or perforated.
As
oil and gas is produced from formation 406 it enters portions 414, and travels
up
well 412 to production facility 410. Gas and liquid may be separated, and gas
may
be sent to gas storage 416, and liquid may be sent to liquid storage 418.
Production facility 410 is able to produce and separate water flooding
mixture,
which may be produced and stored in production / storage 430. Water flooding
mixture is pumped down well 432, to portions 434 of formation 406. Water
flooding mixture traverses formation 406 to aid in the production of oil and
gas,
and then the water flooding mixture, oil and/or gas may all be produced to
well
412, to production facility 410. Water flooding mixture may then be recycled,
for
example by separating the water flooding mixture from the rest of the
production
stream, then re-injecting the formulation into well 432.
In some embodiments, a quantity of water flooding mixture or water flooding
mixture mixed with other components may be injected into well 432, followed by
another component to force water flooding mixture or water flooding mixture
mixed
with other components across formation 406, for example a liquid, such as
water
in gas or liquid form; water mixed with one or more salts, polymers, and/or
surfactants; or a gas, such as air; carbon dioxide; other gases; other
liquids; and/or
mixtures thereof.
In some embodiments, well 412 which is producing oil and/or gas is
representative of a well in well group 202, and well 432 which is being used
to
inject water flooding mixture is representative of a well in well group 204.
9
20 02796663 2012-10-16
WO 2011/140180 PCT/US2011/035122
In some embodiments, well 412 which is producing oil and/or gas is
representative of a well in well group 204, and well 432 which is being used
to
inject water flooding mixture is representative of a well in well group 202.
Figure 4:
Referring now to Figure 4, in some embodiments of the invention, method
500 is illustrated. Method 500 includes injecting a water flooding mixture
indicated
by a checkerboard pattern on the figure; injecting an immiscible enhanced oil
recovery formulation indicated by diagonal pattern on the figure; and
producing oil
and/or gas from a formation indicated by white pattern on the figure.
Injection and production timing for well group 202 is shown by the top
timeline, while injection and production timing for well group 204 is shown by
the
bottom timeline.
In some embodiments, at time 520, water flooding mixture is injected into
well group 202 for time period 502, while oil and/or gas is produced from well
group 204 for time period 503. Then, water flooding mixture is injected into
well
group 204 for time period 505, while oil and/or gas is produced from well
group
202 for time period 504. This injection / production cycling for well groups
202 and
204 may be continued for a number of cycles, for example from about 5 to about
cycles.
20 In some embodiments, at time 530, there may be a cavity in the formation
due to oil and/or gas that has been produced during time 520. During time 530,
only the leading edge of cavity may be filled with a water flooding mixture,
which is
then pushed through the formation with an immiscible enhanced oil recovery
formulation. Water flooding mixture may be injected into well group 202 for
time
25 .. period 506, then immiscible enhanced oil recovery formulation may be
injected into
well group 202 for time period 508, while oil and/or gas may be produced from
well
group 204 for time period 507. Then, water flooding mixture may be injected
into
well group 204 for time period 509, then immiscible enhanced oil recovery
formulation may be injected into well group 204 for time period 511, while oil
and/or gas may be produced from well group 202 for time period 510. This
injection / production cycling for well groups 202 and 204 may be continued
for a
number of cycles, for example from about 5 to about 25 cycles.
20 02796663 2012-10-16
WO 2011/140180 PCT/US2011/035122
In some embodiments, at time 540, there may be a significant hydraulic
communication between well group 202 and well group 204. Water flooding
mixture may be injected into well group 202 for time period 512, then
immiscible
enhanced oil recovery formulation may be injected into well group 202 for time
period 514 while oil and/or gas may be produced from well group 204 for time
period 515. The injection cycling of miscible and immiscible enhanced oil
recovery
formulations into well group 202 while producing oil and/or gas from well
group
204 may be continued as long as desired, for example as long as oil and/or gas
is
produced from well group 204.
In some embodiments, oil and/or gas produced may be transported to a
refinery and/or a treatment facility. The oil and/or gas may be processed to
produced to produce commercial products such as transportation fuels such as
gasoline and diesel, heating fuel, lubricants, chemicals, and/or polymers.
Processing may include distilling and/or fractionally distilling the oil
and/or gas to
produce one or more distillate fractions. In some embodiments, the oil and/or
gas,
and/or the one or more distillate fractions may be subjected to a process of
one or
more of the following: catalytic cracking, hydrocracking, hydrotreating,
coking,
thermal cracking, distilling, reforming, polymerization, isomerization,
alkylation,
blending, and dewaxing.
Waterflooding Mixture
In some embodiments, oil and/or gas may be recovered from a formation
with a waterflooding mixture.
In some embodiments, the waterflooding mixture may include from about
50% to about 99% water, for example from about 60% to about 98%, from about
70% to about 97%, from about 80% to about 96%, or from about 90% to about
95%.
The selection of water used in the waterflooding mixture is not critical.
Suitable water to be used in the mixture could be salt water or fresh water,
for
example water from a body of water off such as a sea, an ocean, a lake, or a
river,
from a water well, connate water produced from a subsurface formation,
processed water from a city water supply, gray water from a city sewage
treatment
plant, or another water supply. In some embodiments, water used in the
waterflooding mixture may be subjected to one or more processing steps, such
as
11
81656554
those disclosed in United States Patent Application Publication Number US
2009/0308609, for example if water with a high salinity content will be used.
The waterflooding mixture may include one or more additives to increase its
effectiveness, for example by boosting the oil recovery factor, by swelling
the oil,
by lowering the viscosity of the oil, by increasing the mobility of the oil,
and/or by
increasing the subsurface pressure in the formation.
In some embodiments, the waterflooding mixture may include from about
1% to about 50% additives, for example from about 2% to about 40%, from about
3% to about'30%, from about 4% to about 20%, or from about 5% to about 10%.
Suitable additives to be used with the waterflooding mixture include
chemicals having a molar solubility in water of at least about 1%, for example
at
least about 2% or at least about 3%, up too fully miscible with water, and
having =
an octanol ¨ water partition coefficient of at least about 1, for example
greater than
about 1.3, greater than about 2, or greater than about 3.
In some embodiments, suitable waterflooding mixture additives are listed in
the attached Table 1.
In some embodiments, suitable waterflooding mixture additives include
alcohols, amines, pyridines, ethers, carboxylic acids, aldehydes, ketones,
phosphates, guinones, and mixtures thereof, where the chemical has a molar
solubility in water of at least about 1% and an octane! ¨ water partition
coefficient
of at least about 1.
In some embodiments, suitable waterflooding mixture additiv.es include
ethers such as dimethyl ether, diethyl ether, and methyl-ethyl ether.
There are a number of chemicals that have a high solubility in water, which
are in fact fully miscible in water, but which would not be suitable as a
waterflooding mixture additive that because of their very low partitioning
coefficient. In operation, it would be easy to mix these chemicals with water
and
inject them into a subsurface formation, but a negligible amount of the
chemical
would then be transferred to the=crude oil. In practice, one of these
chemicals with
a high solubility and a low partitioning coefficient would barely boost the
recovery
factor as compared to a waterflood by itself.
12
CA 2796663 2017-09-21
20 02796663 2012-10-16
WO 2011/140180 PCT/US2011/035122
Some examples of chemicals with a high solubility in water, and a low
partitioning coefficient include amines, glycols, and alcohols such as:
tetraethylenepentamine
triethylene tetramine
sorbitol
diethylene triamine
ethylenediamine
tetraethylene glycol
triethylene glycol
glycerol
formamide
diethylene glycol
diethanolamine
ethylene glycol
monoethanolamine
pyruvic acid
There are also a number of chemicals that have a high partitioning
coefficient, but which would not be suitable as a waterflooding mixture
additive that
because of their very low solubility in water. In operation, only a very small
amount of these chemicals could be mixed with water and injected into a
subsurface formation, so that only a negligible amount of the chemical would
be
transferred to the crude oil. In order to achieve a large amount of the
chemical
been transferred to the crude oil, a huge volume of water would have to be
injected. In practice, one of these chemicals with a low solubility and a high
partitioning coefficient would barely boost the recovery factor as compared to
a
waterflood by itself.
Some examples of chemicals with a low solubility in water, and a high
partitioning coefficient include alkanes, alkenes, and aromatic hydrocarbons,
such
as:
n-hexadecane
n-pentadecane
n-heptadecane
n-eicosane
n-nonadecane
n-octadecane
n-tridecane
n-tetradecane
hexachlorobenzene
1-hexadecene
n-dodecane
1-pentadecene
1-tetradecene
13
81656554
1-heetadecanol
Immiscible Enhanced Oil Recovery Agents:
In some embodiments, suitable immiscible enhanced oil recovery agents
include liquids or gases, such as water in gas or liquid form, air, nitrogen,
mixtures
of two or more of the preceding, or other immiscible enhanced oil recovery
agents
as are known in the art. In some embodiments, suitable immiscible enhanced oil
recovery agents are not first contact miscible or multiple contact miscible
with oil in
the formation.
In some embodiments, a suitable immiscible enhanced oil recovery
agents includes water. The selection of water used as the immiscible agent is
not
critical. Suitable water to be used could be salt water or fresh water, for
example
water from a body of water off such as a sea, an ocean, a lake, or a river,
from a
water well, connate water produced from a subsurface formation, processed
water
from a city water supply, gray water from a city sewage treatment plant, or
another
water supply. In some embodiments, water used as the immiscible agent may be
subjected to one or more processing steps, such as those disclosed in United
States Patent Application Publication Number US 2009/0308609, for example
if water with a high salinity content will be used,
in some embodiments, immiscible agents and/or water flooding mixtures
injected into the formation may he recovered from the produced oil and/or gas
and
re-injected into the formation.
In one embodiment, after the injection of the water flooding mixture is
stopped, there is a quantity of oil in the formation which has absorbed a
quantity of
waterflooding mixture additives. The oil is immobile and can not be recovered.
In
order to recover the waterflooding mixture additives, a quantity of water
without
any additives is injected into the formation of and exposed to the oil, which
water
will absorb the additives, and then the water additive mixture will be
produced to
the surface.
In some embodiments, oil as present in the formation prior to the injection of
any enhanced oil recovery agents has a viscosity of at least about 0.01
centipoise,
or at least about 0.1 centipoise, or at least about 0.5 centipoiso, or at
least about 1
14
CA 2796663 2017-09-21
20 02796663 2012-10-16
WO 2011/140180 PCT/US2011/035122
centipoise, or at least about 2 centipoise, or at least about 5 centipoise. In
some
embodiments, oil as present in the formation prior to the injection of any
enhanced
oil recovery agents has a viscosity of up to about 500 centipoise, or up to
about
100 centipoise, or up to about 50 centipoise, or up to about 25 centipoise.
Surface Processes:
In some embodiments, oil and/or gas may be recovered from a formation
with a waterflooding mixture. In order to separate the production fluids, the
liquids
may be separated from the gases, for example using gravity based and/or
centrifugal separators as are known in the art. Then, the liquids may be
separated, where the water may be separated from the oil for example using
gravity based and/or centrifugal separators as are known in the art. The gas,
the
oil and the water may still contain some waterflooding mixture additives. The
oil
made undergo a distillation process to flash the waterflooding mixture
additives
and light hydrocarbons. This mixture of the waterflooding mixture additives
and
light hydrocarbons may be added to the gas phase. The gas phase will then be
exposed to the water which will preferentially pull out the waterflooding
mixture
additives and leave behind the light hydrocarbons. At the end of the process,
most
of the waterflooding mixture additives will have been removed from the oil and
gas
so that they can be exported, while the water mixed with the waterflooding
mixture
additives will be ready to be recycled into the same field or stored and used
in
another field.
Illustrative Embodiments:
In one embodiment of the invention, there is disclosed a system for
producing oil and/or gas from an underground formation comprising a well above
the formation; a mechanism to inject an enhanced oil recovery formulation into
the
formation, the enhanced oil recovery formulation comprising water and an
additive;
and a mechanism to produce oil and/or gas from the formation. In some
embodiments, the system also includes a second well a distance from the first
well, wherein the mechanism to produce oil and/or gas from the formation is
located at the second well. In some embodiments, the mechanism to inject is
located at the well, and wherein the mechanism to produce oil and/or gas from
the
formation is located at the well. In some embodiments, the underground
formation
is beneath a body of water. In some embodiments, the system also includes a
:A 027966632012-10-16
WO 2011/140180 PCT/US2011/035122
mechanism for injecting an immiscible enhanced oil recovery formulation into
the
formation, after the water and an additive has been released into the
formation. In
some embodiments, the additive comprises a chemical having a solubility in
water
of at least 1% (at atmospheric conditions) and a octanol-water partitioning
coefficient of at least 1 (at atmospheric conditions). In some embodiments,
the
system also includes an immiscible enhanced oil recovery formulation selected
from the group consisting of water in gas or liquid form, and mixtures
thereof. In
some embodiments, the well comprises an array of wells from 5 to 500 wells. In
some embodiments, the mechanism to produce oil and/or gas from the formation
is located at the well. In some embodiments, the additive comprises a chemical
having a solubility in water of at least 2% at a pressure of 50 bars and a
temperature of 25 degrees centigrade. In some embodiments, the additive
comprises a chemical having a crude oil ¨ water partitioning coefficient of at
least
2 at a pressure of 50 bars and a temperature of 25 degrees centigrade.
In one embodiment of the invention, there is disclosed a method for
producing oil and/or gas comprising injecting water and an additive into a
formation from a first well; and producing oil and/or gas from the formation
from a
second well. In some embodiments, a mixture of the water and the additive
comprises from about 50% to about 99% water (by moles). In some
embodiments, the water and the additive is injected at a pressure from 0 to
37,000
kilopascals above the initial reservoir pressure, measured prior to when
injection
begins. In some embodiments, the method also includes converting at least a
portion of the recovered oil and/or gas into a material selected from the
group
consisting of transportation fuels such as gasoline and diesel, heating fuel,
lubricants, chemicals, and/or polymers. In some embodiments, the underground
formation comprises an oil having an API from 10 to 100. In some embodiments,
the water further comprises a water soluble polymer adapted to increase a
viscosity of the mixture. In some embodiments, the method also includes
reducing
a bubble point of the oil in the formation with the additive. In some
embodiments,
the method also includes increasing a swelling factor of the oil in the
formation with
the additive. In some embodiments, the method also includes reducing a
viscosity
of the oil in the formation with the additive. In some embodiments, the water
and
the additive is injected into a reservoir having a reservoir temperature of at
least
16
20 02796663 2012-10-16
WO 2011/140180 PCT/US2011/035122
100 degrees centigrade, for example at least 250 degrees centigrade, measured
prior to when injection begins. In some embodiments, the underground formation
comprises a permeability from 0.0001 to 15 Darcies, for example a permeability
from 0.001 to 1 Darcy.
Those of skill in the art will appreciate that many modifications and
variations are possible in terms of the disclosed embodiments of the
invention,
configurations, materials and methods without departing from their spirit and
scope. Accordingly, the scope of the claims appended hereafter and their
functional equivalents should not be limited by particular embodiments
described
and illustrated herein, as these are merely exemplary in nature.
Examples:
Example 1: (Report 090130)
The comprehensive functionality of this setup was verified through three
sets of coreflood experiments which were performed on Crude Sample A live
crude oil saturated Berea cores at 5600 psi, 175 F. In the first coreflood,
43.8 % oil
recovery was accomplished by waterflood and 49.1 % incremental oil recovery
was achieved by following 3.8 pore volume 9.35 %m (mole percentage)
DME/watermixture flood. In the second and third corefloods, the impact of DME
concentration in water on ultimate oil recovery was studied preliminarily.
Specifically designed for 1-1.5 inch diameter, 24 inch long core to minimize
the end effect, the coreflood system can be applied both horizontally and
vertically
with maximum operating pressure of 7500 psi and maximum operating
temperature of 300 F. The comprehensive functionality of this setup was
verified
through three sets of coreflood experiments:
# 1. Waterflood followed by tertiary 9.35 %m DME/waterflood
# 2. 2 %m secondary DME/waterflood
# 3. 5 %m secondary DME/waterflood
These corefloods were performed on Crude Sample A live crude oil
saturated Berea core vertically under reservoir condition (5600 psi, 175 F).
Crude Sample A Live Crude Oil Preparation
Crude Sample A live crude oil was prepared: it was first filtered and then
recombined with natural gas to reach the desired GOR of 1435.6 scf/STB (at 60
F) and bubble point pressure of 5157 psi. Potentially, the live crude oil
sample in
17
20 02796663 2012-10-16
WO 2011/140180 PCT/US2011/035122
the transfer vessel may undergo phase separation during transportation.
Therefore, the received live crude transfer cylinder was mounted on rocker and
shaken at 175 F, 5600 psi continuously for 48 hours to ensure that the live
crude
sample was homogenous. Once finished, the transfer cylinder was installed in
the
coreood system.
DME/Water mixture preparation
Experimental study carried out indicates the solubility of DME in water is
around 18 %m at 100:11 C ( 212:20 F) and 5600 psi [6]. The result suggests we
can target 10%m DME in brine in the first experiment.
30950 ppm nanofiltered brine was applied to prepare DME/water mixture.
To prepare 10 %m DME/water mixture, 142 cc brine was mixed with 57.5 cc DME
under 1000 psi at room temperature. Therefore, actually 9.35 %m DME/water
mixture was prepared in a transfer vessel and the mixture was maintained under
5600 psi during lifetime to prevent phase separation. In the second and third
corefloods, to study the impact of DME concentration in water on ultimate oil
recovery, 2%m DME/water mixture was prepared by mixing 9.7 cc DME with 120
cc brine and 5%m DME/water mixture was synthesized by mixing 25 cc DME with
120 cc brine with same process.
Coreflood apparatus
A comprehensive coreflood system was built to investigate the incremental
oil recovery under real reservoir condition. The main components of the system
are list below:
1. One coreflood cell. The cell is wrapped by insulating ceramic fiber and
can be heated by silicone heater on top, middle and bottom section. The
overburden fluid is water. This cell can be rotated to conduct both vertical
and
horizontal flood.
2. Three lsco Series D pumps. These lsco pumps have 100 cc capacity and
10,000 psi upper pressure limit, they are used to control confining stress,
injection
pressure and maintaining back pressure respectively.
3. Three transfer vessels. The inlet transfer vessels are filled with fluids
to
be injected into the core. Here, the injectants can be either live crude oil,
brine or
DME/brine mixture in our case. The outlet of coreflood cell is connected to a
18
20 02796663 2012-10-16
WO 2011/140180 PCT/US2011/035122
Temco 10,000 psi Back Pressure Regulator(BPR) and using a transfer vessel
filled
with argon gas for back pressure maintenance.
4. Effluent collection device. A stepping-valve controlled device(VICI
EMHMA-CE) was installed to collect effluents in test tubes. The outlet was
switched to different test tube automatically after every 0.1 pore volume
brine or
DME/brine mixture was injected. The produced gas was released from fluid and
collected in the gas sampling bags. Totally 20 fluid samples and 20 gas
samples
can be collected in one cycle.
5. A computer-controlled data acquisition system. It is used to monitor and
control the experiments and record the data files including pressure, volume
and
temperature etc.
Coreflood procedure
Here, we chose Crude Sample A crude oil saturated Berea sandstone core
(porosity 18%, permeability 100 mD) for coreflood experiments to prove the
concept. As mentioned, three corefloods(# 1-3) were carried out vertically in
this
study. These corefloods are:
# 1. Waterflood followed by tertiary 9.35 %m DME/waterflood
# 2. 2 %m secondary DME/waterflood
# 3. 5 %m secondary DME/waterflood
The sequence followed during core experiments are described below:
1. Berea cores, 1 inch diameter by 24 inch long, were cleaned by flushing
with chloroform to remove any hydrocarbons followed by methanol to remove any
salts present. The solvent in core slug was then removed by drying the core in
oven at 100 C for 24 hours. Mass of dried pristine cores was measured.
2. Core was then sleeved using Teflon heat-shrink tubing, and loaded in a
desaturation cell for brine saturation to determine pore volume (PV).
Temperature
of desatu ration cell was first set at 75 F and 1150 psi overburden pressure
was
applied. Then, core was vacuumed and then saturated with synthesized Crude
Sample A formation brine (116,382 ppm). In the laboratory condition, only
divalent
and monovalent salts are selected to make synthetic brine. The salts were
purchased from Sigma-Aldrich Co. The brine was filtered through a 0.2 m PTFE
filter and degassed prior to use. Accurate pore volume was measured during the
brine saturation process.
19
20 02796663 2012-10-16
WO 2011/140180 PCT/US2011/035122
3. Subsequently, brine in the core slug was displaced by Crude Sample A
dead crude oil to achieve initial oil saturation condition using a 15 bar
ceramic
membrane. This step was carried out at a maximum rate of 1 cc/hour with 175
psi
injection pressure applied for experiment #1 and #3 and 150 psi injection
pressure
applied for experiment #2. 25 psi back pressure was applied for all these
experiments. The injection rate selection was based on the total pore volume
and
was kept low to allow the completion of flow experiments within reasonable
time
constraints. The process was conducted until there is no obvious increase in
hydrocarbon pore volume. Accurate hydrocarbon pore volume and irreducible
.. water saturation can be measured during the process. Following the
drainage,
temperature was increased to 175 F. The dead crude saturated core was aged for
4 weeks to achieve the restored state.
4. Afterwards, the dead oil saturated cores were transferred into the
coreflood cell. Before transferring, dead crude oil saturated cores were
further
wrapped by Teflon tape followed by aluminium foil. The end piece pistons were
designed with o-ring grooves. Then, both pistons and aluminium foil wrapped
cores were packed by thick heat-shrink Teflon tubing. The force on o-ring
exerted
by heat shrink tubing provided seal around end-pieces.
5. Then, dead crude in the core slug was displaced with 2 pore volume
synthesized Crude Sample A live crude oil at a flow rate of 1 cc/hr. During
this
process, temperature of coreflood cell and live crude oil cylinder was set at
175 F,
confining pressure was set to 6600 psi with the pore pressure set at 5600 psi
giving an effective stress of 1000 psi. The effluents passed through BPR and
multi-position actuator controlled device and finally collected in the test
tubes.
6. After live crude displacement, the inlet was connected to the transfer
vessel filled with coreflood injectants(Water or DME/Water mixture). The core
floods were carried out at a flow rate of 1 cc/hr. The produced fluids were
collected
in the test tubes. Most of gas was released from produced fluids at ambient
condition, then collected in the sample bags for composition analysis to
.. understand the recovery process. As mentioned above, totally 20 liquid
samples
and 20 gas samples were collected in one cycle.
7. Once the corefloods were finished, the pore pressure was decreased to
ambient condition, whereas part of residual oil was blow down and collected.
Core
20 02796663 2012-10-16
WO 2011/140180 PCT/US2011/035122
slugs were then baked in oven at 100 C for 24 hours to obtain the remaining
oil
mass. The addition of blow-down oil volume to remaining oil volume gave
irreducible oil volume.
Ultimate Recovery Factor
The whole experiments were controlled and monitored by computer.
Pressure, volume, flow rate, and temperature were recorded every 1 minute. The
mass balance was calculated once the experiment was finished. As previously
described, most of the residue oil in the core slug was blow down. The core
slug
was then transferred to oven and dried at 100 C for 24 hours to measure the
remaining oil. The Table is a summary, at the end of the coreflood, the mass
balance was near 100 % as mass balance of oil in each step was performed. In
experiment # 1, totally about 92.9 % oil recovery was achieved through
waterflood
and subsequent 9.35%m DME/waterflood.
No visible residue oil was observed from core slug after 9.35 %m tertiary
DME/Water coreflood. In experiment # 2 and # 3, 52.5 % and 71.5 % ultimate oil
recovery were accomplished respectively.
Since effluents were collected in test tubes, whereas gas samples were
phase separated from the liquid phase and collected in gas sample bags, the
recovery factors at each step were calculated as a function of injected
hydrocarbon pore volume. The graph shows recovery factor curves, produced
GOR and DME concentration in produced gas as a function of injected
Summary of coreflood experiments.
Parameter Corefloods # 1 Corefloods # 2
Corefloods #
3
Pore Volume (cc) 51.35 51.37 53.04
Hydrocarbon Pore Volume (cc) 38.69 33.27 38.62
Formation Volume Factor(FVF) 1.56 1.44 1.50
Initial Oil Saturation (%) 75.35 64.8 72.8
Irreducible Water Saturation ( /0) 24.65 35.2 27.2
Slowdown dead OH Volume (cc) 0.75 6.7 5
Remaining dead Oil Volume (cc) 1.23 4.12 2.55
Produced dead Oil Volume (cc) 23.04 12.14 18.4
Ultimate Oil Recovery 92.9% 52.5% 71.5%
hydrocarbon pore volume from experiment #1. Waterflood achieved about 43.8%
oil recovery (secondary recovery) and water breakthrough was observed after
21
20 02796663 2012-10-16
WO 2011/140180 PCT/US2011/035122
about 0.46 hydrocarbon pore volume brine injection. After 1.1 hydrocarbon pore
volume injection, the inlet was switched to 9.35 %m DME/water mixture cylinder
and 9.35 %m DME/VVaterflood finally achieved 49.1 % incremental oil recovery
with 5 hydrocarbon pore volume injection (tertiary recovery). During tertiary
flood,
collected gas after 1.50, 2.31, 2.85, 4.21, 5.31 and 5.90 hydrocarbon pore
volume
injection were selected for Gas Chromatography (GC) analysis. GC analysis
indicated that the more DMENVater injection, the higher DME concentration in
produced gas, which was consistent with produced GOR data.
Figure 7 shows the results of the 9.35 %m DME/VVaterflood where the
waterflood recovery plateaus at around 45%, then additional recovery is
achieved
with the use of the 9.35 %m DMENVaterflood mixture.
Additionally, experiment # 2 and # 3 were carried out to study the impact of
DME concentration in water on ultimate oil recovery. The graph shows the
recovery curve as a function of injected hydrocarbon pore volume. Obviously,
DME/waterflood kept producing crude oil even after breakthrough. Basically,
the
more DME/water mixture was injected and the higher DME concentration in water,
the higher ultimate oil recovery. Finally, 2.91 hydrocarbon pore volume 2 %m
DME/water injection achieved 52.5 % ultimate oil recovery. 2.5 hydrocarbon
pore
volume 5 %m DME/water injection accomplished 71.5 A ultimate oil recovery
Figure 8 shows the results of the 2%m DME/Waterflood compared to the
results of the 5%m DME/VVaterflood.
Example 2: (Report 020810)
Two long core flooding experiments, were carried out on Berea
sandstone cores restored using Crude Sample C crude oil (viscosity 65
cp). Both experiments use a DME enhanced waterflood in tertiary mode.
The concentration of DME in the injection stream is 9.35 %m. The
experiment #1 is a continuous injection of 7PV DME/Water mixture after
initial waterflood, after DME enriched waterflood, we switched back to pure
waterflood. During the whole process 92% oil recovery is achieved. For
comparison, only 1PV DME/Water mixture was injected after conventional
waterflood in the experiment #2. 28% incremental recovery is achieved
during DME/Water slug injection.
22
20 02796663 2012-10-16
WO 2011/140180 PCT/US2011/035122
Crude Sample Crude Crude
A Sample B Sample C
Bubble Point [psi] 5188 3538 1071
Molecular Weight [kg/kmol] 97.2 145.54 287.58
p [kg/m3] 731.1 840.4 865
[cP] at Bubble Point 0.543 5.744 65
Reservoir Temperature [ F] 175 135 115
Reservoir Pressure [psi] 5500 3500 1350
Gas Oil Ratio [cc/cc] 251.33 91.84 23
Two core floods were carried out on 100mD Berea sandstone cores
restored using Crude Sample C crude oil and synthesized brine. They are:
#1 Water flood followed by 7PV 9.35%m DME/Water flood followed by water flood
#2 Water flood followed by 1PV 9.35%m DME/Water flood followed by water flood
For both experiments, initial water flood can generally produce 45% 00IP.
For experiment #1, after water flood, we kept injecting DME/VVater mixture
until the recovery curve flattens out. 45% incremental oil recovery has been
achieved during this period. Further water flood after DME/Water flood swept
small
amount oil out very slowly ( 2%), which is not a big impact on ultimate oil
recovery.
For experiment #2, only 1PV DMENVater mixture was injected after
conventional waterflood. 28% incremental recovery is achieved during DME/Water
slug injection and following pure waterflood. 11% of these were produced after
switching back to pure waterflood which was used to push the DME slug through
core.
In addition, the comparison between experiments and the simulation shows
that the main aspects of the recovery process are understood and can be
simulated properly.
Crude Sample C live crude was prepared. Crude Sample C dead crude was
first filtered and then recombined with natural gas to reach the desired GOR
of
140.65 scf/STB (at 60 F). The saturation pressure of synthesized live crude is
1071 psia. Since the live crude oil sample may be phase separated during
transportation, same recombination procedure used as described above was
followed to ensure live crude sample is homogeneous before transferring to
live
crude cylinder in coreflood setup. PVT study of recombined Crude Sample C live
crude shows its viscosity is 65 cp at saturation pressure.
23
:A 027966632012-10-16
WO 2011/140180 PCT/US2011/035122
Restored State Core Preparation
Restored state Berea sandstone cores (1" diameter, 24" long) were
prepared using a 15 bar porous plate. Cores were first saturated with 116381
ppm
synthesized brine under 1000 psi confining stress. Afterwards, brine was
displaced
with Crude Sample C dead crude to irreducible water saturation at a capillary
pressure of 150 psi. Then, cores were aged at 115 F under stress for 28 days
to
achieve restored state.
DME/VVater Mixture Preparation
30950 ppm nanofiltered brine was used to prepare DME/water mixture. To
prepare 9.35 %m DME/water mixture, 141.1 cc brine was mixed with 58.9 cc DME
under 1350 psi at room temperature in a transfer vessel.
The coreflood set up has also been described in detail in earlier report, The
system was designed with a maximum operating pressure of 7500 psi and
maximum operating temperature of 300 F. In this study, we set the pore
pressure
at 1350 psi (reservoir pressure, above bubble point) and effective confining
stress
at 1000psi. The temperature of both core holder and live crude cylinder was
maintained at 115 F (reservoir temperature).
Once loaded into core holder, dead crude in the core plug was displaced
with Crude Sample C live crude at a flow rate of 0.018 cc/min under reservoir
conditions. During this process, effluent was collected in a graduate cylinder
through a Temco backpressure regulator.
The pressure difierence between inlet and outlet of core build up
continuously until breakthrough, the system achieved equilibrium after around
1
PV live crude injection. P slightly goes up after 50 hours injection, which
may be
caused by temperature fluctuations.
The whole experiments were controlled and monitored by computer.
Pressure, volume, flow rate, and temperature were recorded every 1 minute. The
mass balance was calculated once the experiment was finished. Previously
results
on Crude Sample A live crude shows most of the residue oil in the core slug
can
be blown down. The formation factor of Crude Sample C live crude (1.08) is
much
less than the formation factor of Crude Sample A live crude (1.66). Therefore,
no
blowdown oil was observed during these two experiments. The core slug was then
transferred to oven and dried at 100 C to measure the remaining oil.
24
20 02796663 2012-10-16
WO 2011/140180
PCT/US2011/035122
Su' n wary of co-Jr-pod experiments.
Parameter Coreoods # 1 Coreoods # 2
Pore Vol II me (cc) 53.04 51.35
Hydrocarbon Pore Volume (cc) 41.57 38.18
Formation Volume Factoi(FVF) 1.06 1.06
Initial Oil Saturation (%) 78.37 74.35
Irreducible Water Saturation (%) 21.63 25.65
Blowdown dead Oil Volume (cc) 0 0
Remaining dead Oil Volume (cc) 4.64 10.90
Produced dead Oil Volume (cc) 36.35 25.99
Ultimate Oil Recovery 92% 73%
The mass balance should be close to 100%. The reality is, at the end, the
mass balance was close to but slightly higher than 100% as mass balance of oil
in
each step was performed, especially for experiment # 1. The obvious emulsion
in
some effluents is expected to be root cause of this slight overestimation.
In experiment # 1, 45% oil recovery was achieved through initial waterflood,
subsequent 9.35%m DME/water flood can give additional 45% incremental oil
recovery. The following waterflood swept some additional oil out very slowly
(2 /0),
which is not a big impact on ultimate oil recovery.
In experiment # 2, initial waterflood consistently achieved 45% oil recovery.
To study the slug size sensitivity, only 1PV of 9.35% DME/Water mixture was
injected subsequently, 28% incremental recovery is achieved during DME/VVater
slug injection and following pure waterflood. 11 A of these were produced
after
switching back to pure waterflood which was used to push the DME slug through
core.
Continuous Injection Experiment #1
Since effluents were collected in test tubes, whereas gas samples were
phase separated from the liquid phase and collected in gas sample bags, the
recovery factors at each step were calculated as a function of injected
hydrocarbon pore volume.
In the beginning the characteristic behavior for a conventional waterflood
can be observed. The initial oil production is followed by some afterdrainage
after
water breakthrough. Water flood achieved about 45% oil recovery(secondary
recovery) and water breakthrough was observed after about 0.4 hydrocarbon pore
volume brine injection. For a rather viscous oil like Crude Sample C it is not
:A 027966632012-10-16
WO 2011/140180 PCT/US2011/035122
surprising that a significant amount of oil is produced after water
breakthrough
during the afterdrainage.
After 4.2 hydrocarbon pore volume injection, the inlet was switched to 9.35
%m DME/water mixture cylinder and this step finally achieved 45 % incremental
oil
recovery after 9 hydrocarbon pore volume injection(tertiary recovery).
During tertiary flood, collected gas after 4.74, 6.33, 5.91, 7.60, 8.39 and
10.71 hydrocarbon pore volume injection were selected for Gas Chromatography
(GC) analysis. GC analysis indicated that the more DME/VVater injection, the
higher DME concentration in produced gas, which was consistent with the trend
of
produced GIWR data.
After we switched back to pure water flood, GIWR decreased very quickly
and further waterflood did not have big impact on improving oil recovery.
Slug Injection Experiment #2
The slug injection process will limit the total amount of DME used. The slug
injection experiment shows similar behavior as experiment #1 before switching
back to pure water flood. Initial waterflood consistently achieved 45% oil
recovery.
The tertiary slug injection ( 1 PV) and subsequent pure waterflood give 28%
incremental oil recovery. 11% were produced after switching back to pure
waterflood which was used to push the DME slug through core.
The oil production restarted after around 0.4 PV DME/water mixture
injection. This is also consistent with the observation in experiment #1. The
critical
discovery here is the further waterflood can still recovery additional 11%
00IP.
After a steep initial pressure drop the curve levels out as the flow
approaches a steady state. The initial pressure drop is caused by the fact
that the
viscous pressure drop is significantly lower than the initial viscous pressure
drop
needed to move the Crude Sample C oil through the core. The pressure drop
during the afterdrainage is controlled by both the viscous and the capillary
pressure. Even though for a viscous oil like Crude Sample C the capillary
forces
are less significant than for lighter oils, they cannot be completely
neglected. After
we switched to 9.35 %m DME/water flood, P built up when DME started to diffuse
from water phase to oil phase, during which these residue oil was swelled and
oil
saturation increases. This reduces the water mobility and increase the oil
mobility.
26
