Note: Descriptions are shown in the official language in which they were submitted.
CA 02599553 2010-01-28
METHOD AND APPARATUS TO ENHANCE HYDROCARBON PRODUCTION
FROM WELLS
BACKGROUND OF THE INVENTION
Microemulsions are a broad class of micro- and nano- sized fluid particles.
They can achieve very low surface tension, can simultaneously have oil, water,
surfactant phases,
and can be designed to transport a wide variety of chemicals in different
thermodynamically stable
phases. Specifically, in some supercritical fluids like CO2 used for Enhanced
Oil Recover (EOR)
projects in the oil and gas industry, the addition of certain microemulsions
enhance the supercritical
fluids' ability to dissolve highly polar, ionic, high molecular weight
species. These high molecular
weight species are often found in oil and gas FOR reservoirs.
A microemulsion is a mixture of water, water insoluble and water soluble
components forming a visually homogeneous, transparent liquid. One or more
active ingredients
may be present in the aqueous phase, the non-aqueous phase, or in both phases.
A variety of
microemulsion formulations may be prepared in which the aqueous phase can be
considered the
dispersed phase, the continuous phase or, alternatively, where the two phases
are considered to be
bi-continuous. In all cases microemulsions will disperse into water to form
either conventional
emulsions or dilute microemulsions. Microemulsion solutions form a unique
class of emulsions
normally consisting of an aqueous phase, and oil phase and a surfactant phase.
This class of
emulsion is very small, in the nano- to micro- meter range, is usually
optically clear and
thermodynamically stable, as opposed to other emulsions that are kinetically
stable; and
microemulsions normally have low viscosities and ultra low interfacial tension
properties. The
formation of a microemulsion requires the appropriate blending of an oil
phase, a water phase, and
at least one surfactant. It is often necessary to add salts to enhance the
thermodynamic stability of
the emulsion depending on the specific blend of the solution. Non-limiting
examples of
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compositional blends that can be used to form a microemulsion include
solutions consisting of 13%-
55% of fluids from the turpene group (examples include limonene and others),
0%-30%
isopropanol, 0-50% water, 0%-50% triethylene glycol, and 0%-15% salts.
The fact that these are very small particles with reduced surface tension
allows
them to get into low permeability and low porosity subterranean reservoirs.
When injecting fluids
into subterranean reservoirs during secondary and tertiary recovery to sweep
out the hydrocarbons it
is useful to be able to get the injection fluid into all areas if the
reservoir, including the low
permeability and porosity areas of the subterranean reservoir as the higher
permeability and porosity
structures are most easily recovered and likely have their hydrocarbons
significantly or substantially
exhausted during the primary recovery phase of the reservoir.
Presently, the use of microemulsions in oil and gas production has been
limited
to fracturing and acid stimulation operations. Fracturing operations involve
the pumping of
hydraulic fluids at high pressure (i.e., pressures above the hydraulic
fracturing pressure of the
reservoir) into the subterranean reservoir formations of the subterranean zone
to crack the
subterranean reservoir and enhance the subterranean reservoir permeability.
This causes hydraulic
fracturing of the subterranean formations, and the release of hydrocarbons
through the resulting
enhanced permeability, thereby improving hydrocarbon recovery. Microemulsions
then allow for
and enhance the recovery of fracturing fluids used in the operation to be
produced back out of the
production well reducing fluid damage in the reservoir and thereby increasing
the ability of a well to
produce from the fracture system made by these fluids.
Blends of microemulsions and supercritical fluids have not been used for the
recovery of oil and gas outside of the context of fracturing and stimulation
injection operations. For
example they have not been used in secondary and tertiary hydrocarbon recovery
where supercritical
fluids are often used. In fracturing and stimulation operations, the
microemulsion is blended in a
fracturing or stimulation fluid at low concentrations, typically on the order
of 0.2% of the blend.
Additionally, microemulsions have not been used as the actual fracturing or
stimulation fluid, but
only as an additive to a fracturing fluid. Furthermore, the separation and
recycling of the
microemulsion from a fracture or stimulation fluid has never been performed.
Additionally, fluid
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compositions comprising microemulsions and supercritical fluids have not been
used for the
enhanced recovery of oil and gas. The present invention permits enhanced
recovery of
hydrocarbons using microemulsions with supercritical fluids and further
provides a method to
reduce the cost of the microemulsion application by providing for the
separation and recycling of the
microemulsion once it is produced back to surface with the well fluids.
BRIEF SUMMARY OF THE INVENTION
In one embodiment of the present invention, there is a method of improving
hydrocarbon recovery from a subterranean hydrocarbon reservoir comprising the
step of. injecting a
composition comprising a microemulsion fluid into an injection well and then
into the subterranean
reservoir, the microemulsion fluid comprising: (i) an oil phase, (ii) an
aqueous phase; and, (iii) a
surfactant; the step of injecting a composition comprises injecting the
composition at a pressure
below the hydraulic fracturing pressure of the reservoir.
In some embodiments, the method further comprises heating the fluid prior to
said step of injecting.
In some embodiments, the composition further comprises a supercritical fluid.
In some embodiments, the supercritical fluid comprises supercritical carbon
dioxide.
In some embodiments, the aqueous phase is distributed in the oil phase in the
form of droplets having a diameter in the range 1 to 1000 rim or in the form
of micro domains
having at least one dimension of length, breadth or thickness in the range 1
to 1000 nm.
In some embodiments, the method further comprises the step of blending the
microemulsion fluid with other fluids.
In some embodiments, the method further comprises the step of injecting the
composition into a production well.
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In some embodiments, the method further comprises heating the fluid prior to
the step of injecting.
In some embodiments, the method further comprises blending the
microemulsion fluid with a component selected from the group consisting of
carbon dioxide,
methane, ethane, propane, nitrogen, air, water, and any combination thereof.
In some embodiments, the method further comprises the step of recovering at
least a portion of the microemulsion fluid from produced fluids.
In some embodiments, the method further comprises the step of re-injecting
said recovered microemulsion into said injection well.
In some embodiments, the step of injecting comprises continual injection.
In some embodiments, the step of injection comprises sequentially injecting
more than one microemulsion fluid blend.
In another embodiment of the present invention, there is method of improving
hydrocarbon recovery from a subterranean hydrocarbon reservoir comprising the
step of: injecting a
composition comprising a microemulsion fluid and a supercritical fluid into an
injection well and
then into the subterranean reservoir, the microemulsion fluid comprising: (i)
an oil phase, (ii) an
aqueous phase; and, (iii) at least one surfactant; the step of injecting a
composition comprises
injecting the composition at a pressure below the hydraulic fracturing
pressure of the reservoir.
In some embodiments, the aqueous phase is distributed in the oil phase in the
form of droplets having a diameter in the range 1 to 1000 nm or in the form of
micro domains
having at least one dimension of length, breadth or thickness in the range 1
to 1000 nm.
In some embodiments, the method further comprises heating the fluid prior to
the step of injecting.
In some embodiments, the supercritical fluid comprises supercritical carbon
dioxide.
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In some embodiments, the method further comprises blending the
microemulsion fluid with a component selected from the group consisting of
carbon dioxide,
methane, ethane, propane, nitrogen, air, water, and any combination thereof.
In some embodiments, the method further comprises the step of recovering at
least a portion of the microemulsion fluid from produced fluids.
In some embodiments, the method further comprises the step of re-injecting
recovered microemulsion into the injection well.
In some embodiments, the step of injecting comprises continual injection.
In some embodiments, the step of injection comprises sequentially injecting
more than one microemulsion fluid blend.
In another embodiment of the present invention, there is a method of improving
hydrocarbon recovery from a subterranean hydrocarbon reservoir comprising the
step of injecting a
composition comprising a microemulsion fluid and a supercritical fluid into a
production well and
then into the subterranean reservoir, the microemulsion fluid comprising: (i)
an oil phase, (ii) an
aqueous phase; and, (iii) at least one surfactant; the step of injecting a
composition comprises
injecting the composition at a pressure below the hydraulic fracturing
pressure of the reservoir.
In some embodiments, the aqueous phase is distributed in the oil phase in the
form of droplets having a diameter in the range I to 1000 nm or in the form of
micro domains
having at least one dimension of length, breadth or thickness in the range 1
to 1000 nm.
In some embodiments, the injected supercritical fluid and microemulsion are
flowed back to surface through the production well.
In another embodiment of the present invention, there is a method of improving
the sequestering of gases in a subterranean reservoir comprising the step of.
injecting a fluid
composition comprising a microemulsion fluid and a supercritical fluid into a
well and then into the
subterranean reservoir, the microemulsion fluid comprising: (i) an oil phase,
(ii) an aqueous phase;
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and, (iii) at least one surfactant; the step of injecting a composition
comprises injecting the
composition at a pressure below the hydraulic fracturing pressure of the
reservoir.
In some embodiments, the aqueous phase is distributed in the oil phase in the
form of droplets having a diameter in the range 1 to 1000 nm or in the form of
micro domains
having at least one dimension of length, breadth or thickness in the range 1
to 1000 nm.
BRIEF DESCRIPTION OF THE DRAWINGS
For a more complete understanding of the present invention, reference is now
made to the following descriptions taken in conjunction with the accompanying
drawing, in which:
FIG. 1 illustrates that anatomy of a water/oil/surfactant microemulsion,
showing the domains of each component and the borders between them.
DETAILED DESCRIPTION OF THE INVENTION
As used herein, "a" or "an" means one or more. Unless otherwise indicated,
the singular contains the plural and the plural contains the singular. In this
way, "a microemulsion"
means one ore more than one microemulsion; "a supercritical fluid" means one
or more than one
supercritical fluid; "a surfactant" means one or more than one surfactant, "at
a pressure below the
hydraulic fracturing pressure of the reservoir" means at one or more than one
pressure below the
hydraulic fracturing pressure of the reservoir, etc.
It is well known to those skilled in the art of fluid injection that one can
determine the pressure required to hydraulically fracture a rock (the
"hydraulic fracturing pressure"
or "hydraulic fracture pressure"). There exists ample literature describing
the various methods used
to determine the fracture pressure of a given subterranean reservoir. One
example is a fluid
injection test, often referred to as a "mini-frac" or "step-rate injection
test" wherein a fluid of known
characteristics of density and friction factors, for example water, is pumped
from the surface of a
well down the well tubular and into a subterranean interval. This can be
performed in any
subterranean interval including sandstone, limestone, shale, and coal beds,
where the injection
pressure is monitored and recorded at a given injection rate and the injection
pressure is monitored
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and recorded on a graph, and where the ordinate axis is the injection pressure
at the given injection
rate, and the abscissa axis is the injection rate. Starting from a low
injection rate, and incrementally
increasing the rate for a time interval (typically five minutes), a given
injection pressure is obtained
with the injection fluid, usually water, and plotted on a graph. While the
injection pressure into the
subterranean reservoir is below the fracture pressure, the line on the graph
formed by the data points
of pressure and rate will have a constant slope, until the injection pressure
exceeds the subterranean
injection intervals fracture pressure. This inflection point on the graph is
the hydraulic fracture
pressure. One embodiment of the present invention involves the injection of
fluids below the
fracture pressure. Therefore, the determination of the hydraulic fracturing
pressure of a
subterranean interval is well-known to those of ordinary skill in the art. Any
method of determining
the hydraulic fracturing pressure is applicable in the present invention.
A microemulsion fluid particle can move into subterranean reservoir that is
water saturated, oil saturated, water wet, or oil wet due to its external
phase behavior best shown in
FIG. 1. In the microemulsion shown, it can be seen that there are micro-
domains dominated by
surfactant, by water, and by oil. The micro-domains may comprise droplets.
Droplets have a
substantially spherical form, while micro-domains can have other, less
symmetric, geometries. A
microemulsion is herein defined to be a stable biphasic mixture of two
immiscible liquids stabilized
by a surfactant and usually a co-surfactant. Microemulsions are
thermodynamically stable,
isotropically clear, form without excessive mixing, and have dispersed
droplets usually in the range
of 5 nm to 100 nm diameter.
When a hydrocarbon-bearing, subterranean reservoir formation does not have
enough energy for the hydrocarbons to be produced to the surface in economic
quantities or at
optimum rates, reservoir pressure enhancement and enhanced hydrocarbon
recovery techniques are
employed to increase the recovery of the hydrocarbon reserves. A well bore
penetrating a
subterranean formation typically consists of a metal pipe (casing) cemented
into the original bore
hole. Holes (perforations) are placed to penetrate through the casing and the
cement sheath
surrounding the casing to allow hydrocarbon flow into the well bore and, if
necessary, to allow
treatment fluids to flow from the well bore into the formation.
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These wells are then allowed to flow hydrocarbons and other reservoir fluids
to
the surface. Eventually, the reservoir pressure will diminish such that fluids
will not erupt or flow
naturally to the surface, and pumps and other types of artificial lift devices
will need to be employed
to lift the fluids from the bore to surface. However, at some point the
reservoir will not produce
sufficient hydrocarbons to the well bore, at which time the so called primary
recovery phase is over.
The amount of hydrocarbon remaining in the reservoir at the end of this
primary recovery may, in
some cases, exceed 70% of the original hydrocarbon in place. Hence it is of
interest to attempt to
recover the remaining hydrocarbon reserves with enhanced methods.
After primary recovery methods are used, enhanced hydrocarbon recovery
techniques are sometimes applied to push or mobilize the hydrocarbons from the
reservoir. These
enhanced techniques are well developed and known to those in the industry and
include, among
others, water floods, steam floods, CO2 floods, Water Alternative Gas floods
(WAG), surfactant
floods, VAPEX, Steam Assisted Gravity Drainage (SADG), and even fire floods.
Enhanced hydrocarbon recovery requires that the injected fluid mobilize the
hydrocarbon from the subterranean reservoir structure. The voids in the
subterranean reservoir may
be quite small and the capillary forces required to allow the injection fluid
to contact and "sweep"
and displace the remaining hydrocarbon from the subterranean reservoir may be
quite high.
Moreover, it is normally required that fluids injected for enhanced recovery
methods be injected
below the hydraulic fracture pressure of the reservoir. Hence the injection
fluids in enhanced oil
recovery processes often bypass significant volumes of un-mobilized
hydrocarbon and in certain
reservoirs injection fluids cannot be injected below hydraulic fracture
pressure. The present
invention allows for injections using microemulsions to lower the injection
pressure of enhanced
hydrocarbon recovery projects and improve the sweep efficiency and solvency,
or cleaning of the
reservoir, with supercritical fluids and microemulsions.
Application of enhanced recovery methods as described above is a routine part
of petroleum industry operations as applied to mature oil reservoirs. This
invention further provides
a method to use microemulsions to enhance not only oil recovery but also to
enhance gas recovery
from reservoirs as diverse as shales, micro-dacy sandstone and limestones as
well as coal bed
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methane subterranean reservoirs. Furthermore, the methods of the invention are
used to lower
injection pressures in enhanced recovery methods, as well as for disposal by
subterranean
sequestering of CO2. The methods for improving enhanced hydrocarbon recovery
projects for
reservoir sweep efficiency is a field of active interest as said primary
recovery processes can still
leave considerable hydrocarbon reserves un-recovered from the reservoir.
Carbon dioxide is a good injection fluid to mobilize hydrocarbons from
reservoirs. This fluid has been shown to reduce the in-situ viscosity of
hydrocarbons, likely because
at commonly-used injection pressures and temperatures, the injected CO2
injected is soluble in many
hydrocarbons. This energizes the remaining hydrocarbon fluids and helps to
mobilize them out of
the reservoir. CO2 and other fluids have a solvency affinity with
hydrocarbons. This affinity along
with their ability to reduce hydrocarbon viscosity, and their supercritical
phase fluid behavior make
them attractive FOR fluids. It is also known that the addition of certain
microemulsion solvents
with these supercritical fluids can enhance the polarity and solvency ability
of the fluids. Although
CO2 is preferred, other species may also be used as will be apparent to those
of skill in the art upon
an understanding of the present invention.
However, CO2 and other injected gases and fluids used in enhanced
hydrocarbon recovery processes have a tendency to seek out the highest
permeability subterranean
reservoir in the formation and flow from the injection wells to the production
wells via the path of
least resistance. The results is that hydrocarbons in a situation wherein the
lower permeability and
lower porosity subterranean reservoir are poorly swept by the injected gases
and fluids. The oil and
gas industry has developed a method to address this issue by alternating the
injection of the fluids
from liquids like water followed by a cycle of injection of gas. This method
is known in the
industry as Water Alternate Gas (WAG). The water injected in the water cycle
phase of the WAG
often follows a fluid path in the reservoir different from the path the CO2
follows during the C02
injection phase. The water often follows to the higher permeability, and
because of a higher surface
tension and density, it tends to fill the more permeable flow paths with water
thereby not allowing
the CO2 from rapidly passing through this lower permeability paths from
injection well to
production well on the next cycle. The water often encapsulates the residual
oil in the reservoir in
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both the high permeability and low permeability sections making it difficult
for the CO2 on the next
injection cycle to contact the oil still remaining.
Mechanical diversion of CO2 with water, for example, causes the reservoir to
be less mobile to oil movement. This means that although the water may give
some diversion to the
CO2 cycle it also introduces a new set of problems to the mobility of oil in
the reservoir. What is
needed is a method to reduce the water retention in WAG processes, while
improving the injected
ability of CO2 and/or other fluids to mobilize the reservoir fluids to the
production wells. Higher
temperatures and pressures are often associated with deeper wells. What is
further needed is a
method and composition to enhance the ability of injected fluids, including
C02, to solubilize the
remaining hydrocarbons, and to further tailor these secondary solvents to the
in-situ hydrocarbons
and reservoir conditions of temperature and pressure. The tailoring of the
solvents, chemical
constituents, relative percentages, and the changing of these parameters over
time is accomplished
through a process of lab testing cores with hydrocarbons to be produced,
developing blends of
microemulsions with supercritical fluids, injecting these compositions in the
wells, monitoring the
response, and changing the chemical constituents and relative percentages of
the microemulsion in
the injection fluid to enhance volumes of the hydrocarbon produced from
reservoir. Hence this
process is first lab developed, then applied and modified based on well
responses. It is clear to those
of skill in the oil and gas industry that this process is continually
monitored and modified as well
conditions and the nature of the microemulsion and supercritical fluids are
varied. For example, the
current techniques in the FOR industry use CO2 injection phased by water
injection in WAG
projects, but do not blend microemulsion fluids and supercritical CO2 to
tailor the injection fluid
blend to the actual changing reservoir conditions and take advantage of the
synergy between
microemulsions and supercritical fluids. This invention improves the FOR
methods by using
microemulsions with supercritical fluids thereby improving the sweep
efficiency.
It is well known that microemulsions are able to penetrate substrates with low
porosity much better than the current class of macro-surfactant blends. The
microemulsions special
surface tri-phase behavior further enhances its ability to penetrate either
water wet areas in a
reservoir or water wet areas with extremely low surface tension
characteristics. Microemulsion(s),
when combined with supercritical fluids, posses significant synergetic solvent
properties which can
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significantly improve an FOR process. A supercritical fluid is defined as a
substance above its
critical temperature (To) and critical pressure (P.). The critical point
represents the highest
temperature and pressure at which the substance can exist as a vapor and
liquid in equilibrium.
Common supercritical fluids include, carbon dioxide, water, methane, ethane,
propane, ethylene,
propylene, methanol, and ethanol. There are others as well.
A method of enhancing hydrocarbon production in FOR projects is herein
provided, the method comprising: (a) injecting a microemulsion with the
injected flood fluid into
production wells and their subterranean formations; (b) producing hydrocarbons
from the FOR
projects production wells from one or more subterranean formations; (c)
separating gases from the
liquids produced from the production wells; (d) separating the hydrocarbon
fluids from other
produced fluids, with one or more of, centrifugal devices, de-emulsion
chemicals, settling tanks,
membranes, filter media, and heat; (e) recovering some portion of the
injection fluids to recycle into
the injection wells; (f) recovering some portion of the microemulsion
surfactant fluid system; and
(g) repeating steps (a) through (f) for as long as economical hydrocarbons can
be recovered from the
reservoir.
The microemulsions of the present invention preferably comprise (i) an oil
phase, (ii) an aqueous phase, and (iii) at least one surfactant. Some non-
limiting examples of the oil
phase are hydrocarbon oils, fatty acid esters, mineral oils, animal oils,
plant oils, synthetic oils, and
silicone oils. Some non-limiting examples of the aqueous phase are sodium
chloride, hydrogen
peroxide, potassium chloride, fresh water, de-ionized water. Some non-limiting
examples of
surfactants are zwitterionic surfactant, anionic surfactants, cationic
surfactants, ethoxylated nonionic
surfactant, non-ionic surfactants like, alpha-olefin sulfonate, alcohol ether
sulfate, and alcohol
sulfate carboxylated alkylphenol alkoxylates, carboxylated linear alcohol
alkoxylates, carboxylated
branched alcohol alkoxylate, quaternary ammonium halides,
cetyltrimethylammonium chloride,
secondary or tertiary fatty amine salts. Other examples of the various
components known to those
of ordinary skill in the art are also applicable in the present invention.
The present invention preferably also uses the injection of microemulsions in
wells in oil and gas fields under reservoir pressure maintenance, RPM, or FOR
projects.
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The preferred embodiment for an FOR project is to first test the hydrocarbon
from the reservoir with a variety of surfactants/solvents, water, oils,
alcohols, and salts in a
microemulsion blend in a core flow test. This flow test is accomplished by
placing a subterranean
reservoir core, or a simulated core of a subterranean reservoir (often a Bera
Sandstone core is used)
into a core sleeve, and passing reservoir oil through the core from one end to
the other thereby
saturating the core of subterranean reservoir or simulated core with reservoir
oil. Then the core is
flushed with water, followed by CO2 above its critical point, and the
resulting oil recovered from
this core flow test is recorded where this recorded result becomes the base
case from which the
following core flow tests using the microemulsion are evaluated, ergo one
designs the subsequent
microemulsion blend to give the best oil recovery above the base case core
flow test. On can
iteratively determine an optimum composition.
This test is repeated for a new core, and this time the microemulsion blend
developed for this particular oil is added to the CO2 injection cycle, wherein
the CO2 and the
microemulsion are pumped together through the core and the recovered oil is
recorded and
compared to the test wherein no microemulsion was added to the CO2 cycle.
This test is then repeated again as before, flushing a core subterranean
reservoir
with the hydrocarbon oil, then pumping a water phase, this time with the
microemulsion in the water
phase, followed by the CO2 phase without the microemulsion. The recovered oil
from this core test
is then recorded and compared to the previous test runs. One then selects an
optimal injection
method for a given reservoir oil and subterranean reservoir.
An optimal method is defined to be a method and blend(s) that yield the
largest
volume increase of oil over the core flow test base case. It is well known to
those of skill in the art
of oil and gas core testing, that the above test is performed in a test cell
that can be subjected to
reservoir temperatures and pressures while the core is tested with the
different methods. Likewise,
the above series of test is repeated for a variety of microemulsion blends,
allowing an optimum
blend of microemulsion to be developed for different hydrocarbons and
subterranean reservoir
properties. Once the blend for the microemulsion system for a given
hydrocarbon, flooding fluid,
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and in-situ reservoir conditions is selected from the above discussed testing
phase, a microemulsion
blend is made and delivered to the well sites.
The flooding fluid can be C02, CH4, C3H8, H2O and combinations of these in a
WAG method. Special attention should be given to the selection and core
testing of the component
parts of the microemulsion blend for any reservoir and to the flooding fluids
to be used. Once the
first microemulsion blend is then selected based on the empirical results of
the core testing, it is
stored in tanks near the injection fluid pumping plant. The microemulsion is
then injected
downstream of the injection fluid pumps at the appropriate concentration for
the reservoir as
discerned from the core testing. During the injection cycle, the microemulsion
may be injected in
the water phase, the super-critical fluid phase, or in both, depending on the
results of the core testing
and field experience, and the blended product of microemulsion and the
injection fluid are then
injected into an injection well. Field experience is used after performing the
injection cycle with
microemulsions and monitoring in the field the actual results of the injection
cycle after the
microemulsion was used.
It is clear that the core testing is the initial starting place but that field
experience may lead to modifications of the quantities, chemical constituents,
and the cycle phase
where the chemical is used. This combination of injection fluid and
microemulsion fluid is then
produced from a different well, typically designated a production well, where
the results of a given
cycle are based on the increase in oil production from a previous cycle that
did not contain the
microemulsion. In some embodiments of the present invention, the microemulsion
can be injected
without other injection fluids, such as water or CO2. In any case, the volume
and cost of the
microemulsion can be optimized by separating the microemulsion from the
produced hydrocarbons
at the surface and recovering at least a portion of the microemulsion for
recycling back into the
injection process.
After some time, and it can be years, the effectiveness of the microemulsion
and any combined injection fluid may be reduced by light hydrocarbons being
easily swept from the
reservoir leaving behind heavy hydrocarbons. The present invention also
includes the ability to
change the microemulsion blends with time to adapt to the changing needs of
the project. For
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example the chemical constituents and their relative concentrations may be
modified to
accommodate the change in reservoir conditions. Some embodiments of the
present invention also
provide that the microemulsion may be switched from down injection wells to
being injected down
previous production wells and then produced up the previous injection wells.
Alternatively, the
invention teaches the injection of the microemulsion into a well for a given
period of time and the
well is allowed to produce back the microemulsion fluid in what is known as a
cyclic injection
method where the injection well is also the production well. These methods
allow for the active
microemulsion to reach out into reservoir areas near the injection wells that
previously were not
contacted by (or were only minimally contacted by) injected microemulsion(s)
thereby leaving
immobile hydrocarbons. It is also clear that this method can be practiced in
any subterranean
reservoir, not limited to sandstone or limestone, but also in shales, and not
only in oil and
condensate reservoirs but also in gas reservoirs.
In another embodiment of the present invention, there is the injection of
microemulsions blended with fluids into reservoirs under pressure maintenance
programs. In this
case, a hydrocarbon fluid is being produced from wells and, in order to
prevent the reservoir
pressure from dropping below a critical pressure, often the bubble point of
the hydrocarbon, it is
necessary to inject fluids into injection wells while extracting hydrocarbons
from production wells.
The fluids most often used are water, carbon dioxide, propane, nitrogen, air,
and natural gas. The
present invention teaches the blending of microemulsions into the injected
fluids, based on lab
testing of various microemulsion blends that can be made by varying the
relative proportions of the
chemical constituents. The blend is then injected into an injection well and
producing hydrocarbons
(and blend components) up production wells. The produced hydrocarbon and well
fluids are
separated into gas and liquid streams through conventional industrial
separators, settling tanks,
centrifuges, membrane, and filer media to allow for the recovery of the
microemulsion from the
hydrocarbons and other well and injection fluids. Other separation methods,
known to those or
ordinary skill in the art, are also applicable. Supercritical fluids with the
enhanced microemulsion
properties can be used to aid in the improved mobility and removal of
hydrocarbons like
condensates, oil, natural gas, and methane.
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A still further embodiment of the present invention is the stimulation of
hydrocarbon reservoirs by injecting a blend of microemulsions with
supercritical fluids. This
embodiment is performed by having a supercritical fluid delivered to the well
site in a tanker truck,
for example a CO2 transport trailer. The CO2 is first flowed and/or pumped
from the CO2 transport
truck to a high pressure tri-plex pump, and microemulsion is pumped into the
same tri-plex pumping
units, the combined fluid of microemulsion and CO2 is then pressurized through
the tri-plex pump,
transported to the well via a high pressure line connected to the well head
and injected down the
well tubulars and into the reservoir. The supercritical fluid, in this case
CO2, and the microemulsion
blend(s) are then flowed back to the surface through the well along with well
fluids thereby
improving the wells' flowing capacity by the cleaning and solvent mechanism of
the microemulsion
supercritical fluid blend of the present invention.
In a further embodiment, the supercritical fluid is heated after the
pressurization of the fluid through a pump and the microemulsion is then
injected into this
pressurized and heated supercritical fluid prior to the injection into the
well of the combined fluid
blend of microemulsion and supercritical fluid. In either case, these flow
back fluids are separated
into liquid and gas streams and a portion of the microemulsion stimulation
fluid is recovered and
can be reused in subsequent subterranean injections.
The above methods may be used to sequester gases in a subterranean reservoir.
The compositions are injected into a well and then into the subterranean
reservoir. Gases to be
sequestered into the reservoir are then injected. Alternatively the gases to
be sequestered may be
injected simultaneously along with the compositions. There is interest in
sequestering gases such as
CO2 to prevent it from entering the atmosphere and resulting in adverse
environmental
consequences.
Although the present invention and its advantages have been described in
detail, it should be understood that various changes, substitutions and
alterations can be made herein
without departing from the spirit and scope of the invention as defined by the
appended claims.
Moreover, the scope of the present application is not intended to be limited
to the particular
embodiments of the process, machine, manufacture, composition of matter,
means, methods and
CA 02599553 2007-08-30
steps described in the specification. As one of ordinary skill in the art will
readily appreciate from
the disclosure of the present invention, processes, machines, manufacture,
compositions of matter,
means, methods, or steps, presently existing or later to be developed that
perform substantially the
same function or achieve substantially the same result as the corresponding
embodiments described
herein may be utilized according to the present invention. Accordingly, the
appended claims are
intended to include within their scope such processes, machines, manufacture,
compositions of
matter, means, methods, or steps.
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