U.S. patent application number 11/641991 was filed with the patent office on 2008-06-19 for enzyme enhanced oil recovery (eeor) for water alternating gas (wag) systems.
Invention is credited to John L. Gray, Philip Y. Lau.
Application Number | 20080142230 11/641991 |
Document ID | / |
Family ID | 39525763 |
Filed Date | 2008-06-19 |
United States Patent
Application |
20080142230 |
Kind Code |
A1 |
Lau; Philip Y. ; et
al. |
June 19, 2008 |
Enzyme enhanced oil recovery (EEOR) for water alternating gas (WAG)
systems
Abstract
The present disclosure relates to the release or recovery of
subterranean hydrocarbon deposits and, more specifically, to a
system and method for enhanced oil recovery (EOR), by utilizing
enzyme compositions and water-alternating-gas (WAG) methods for
injecting water compositions, followed by miscible, near miscible
or immiscible gas into subterranean formations for oil recovery
operations.
Inventors: |
Lau; Philip Y.; (Houston,
TX) ; Gray; John L.; (Houston, TX) |
Correspondence
Address: |
GUERRY LEONARD GRUNE
784 S VILLIER CT.
VIRGINIA BEACH
VA
23452
US
|
Family ID: |
39525763 |
Appl. No.: |
11/641991 |
Filed: |
December 19, 2006 |
Current U.S.
Class: |
166/401 ;
507/201 |
Current CPC
Class: |
C09K 8/594 20130101;
C09K 8/582 20130101 |
Class at
Publication: |
166/401 ;
507/201 |
International
Class: |
E21B 43/22 20060101
E21B043/22 |
Claims
1. An enzymatic fluid for enhanced recovery of oil or other
hydrocarbon deposits in a subterranean formation, wherein said
deposits are releasable by initially adding said enzymatic fluid
directly to a pump for pumping said fluid, combined with water
forming a water composition, into said oil formation through an
injection well followed by an additional period of time allowing
said fluid and said water composition to soak said formation by
said composition moving from said injection well to one or more
producing wells followed by injection of gas into said formation,
followed by recovery of said deposits by pumping or other
means.
2. The enzymatic fluid of claim 1, wherein said pumping of said
fluid independently or as said water composition injection followed
by soak time moving from injection well to one or more producing
wells, followed by injection of gas and subsequent recovery of said
deposits, is known as a water-alternating-gas (WAG) and enzyme
system and may be sequential and repeated as required.
3. The enzymatic fluid of claim 1, wherein said water composition
may contain any substance or combination of substances useful for
enhanced oil recovery.
4. The enzymatic fluid of claim 1, wherein said gas is miscible,
partially miscible, or fully immiscible with either said enzymatic
fluid, said hydrocarbon deposits, and/or said subterranean
formation.
5. The enzymatic fluid of claim 1, wherein said fluid is
GREENZYME.RTM. and wherein said deposits include crude oil.
6. The enzymatic fluid of claim 1, wherein said fluid is used for
treatment of the subterranean formation during water injection
wherein said enzymatic fluid is injected as a cold, heated or
ambient liquid in any combination into said formation.
7. The enzymatic fluid of claim 1, wherein said enzymatic fluid can
be heated to at least 80 degrees Celsius before injection into an
injection well thereby minimizing problems associated with pour
point and maximized penetration of gas injected.
8. The enzymatic fluid of claim 1, wherein said fluid is diluted
with water in a range of 0.01 to 99 percent and more specifically
is diluted within a working range of 3 to 10 percent of enzymatic
fluid in water.
9. The enzymatic fluid of claim 1, wherein said fluid is
incrementally diluted to stimulate wells that are at an
unacceptable level of production prior to restarting a
water-alternating-gas (WAG) and enzyme injection process.
10. The enzymatic fluid of claim 1, wherein said fluid is used for
pre-treatment or treatment of said formation during enhanced oil
recovery such that said fluid is injected and intermixed with water
which is sent into said formation and wherein said formation is a
well that is subsequently not used for a period of time allowing
for soaking of said well prior to another phase of enhanced oil
recovery including, but not limited to pumping and use of water and
gas for one or more cycles during said recovery.
11. The enzymatic fluid of claim 1, wherein said fluid is injected
into pipelines to prevent crude oil from plugging said
pipelines.
12. The enzymatic fluid of claim 1, wherein said fluid reduces
asphaltines and waxes at an injection wellbore prior to injection
as well as minimizing wellbore build up during production that
occurs at an end of an enhanced oil recovery cycle, wherein said
cycle includes a water-alternating-gas (WAG) and enzyme system.
13. The enzymatic fluid of claim 1, wherein during
water-alternating-gas operations said fluid does not affect the
normal heat transfer provided by the steam to surrounding well
formations or to said deposits, wherein said deposits include crude
oil.
14. A method for enhanced recovery of oil or other hydrocarbon
deposits in a subterranean formation using an enzymatic fluid,
wherein said deposits are releasable by initially independently
adding said enzymatic fluid directly to a pump for pumping said
fluid into said oil formation followed by a water composition
injection, followed by an optional period of idle process time
allowing said fluid and said water composition to soak said
formation, followed by injection of gas into said formation,
followed by recovery of said deposits by pumping or other
means.
15. The method of claim 14, wherein said fluid is initially diluted
for cold, heated or ambient injection in any combination prior to
adding said fluid to said formation.
16. The method of claim 14, wherein adding said fluid after initial
water-alternating-gas of said gas is accomplished.
17. The method of claim 14, wherein said fluid is GREENZYME.RTM.
and wherein said deposits include crude oil.
18. The enzymatic fluid of claim 14, wherein said gas is miscible,
partially miscible, or fully immiscible with either said enzymatic
fluid, said hydrocarbon deposits, and/or said subterranean
formation.
19. The method of claim 14, wherein the method for injecting said
enzymatic fluid includes a process referred to as
water-alternating-gas (WAG).
20. The method of claim 14, wherein using said fluid for
pre-treatment on injection well or treatment of said subterranean
formation during a water injection cycle wherein said enzymatic
fluid is injected as cold, heated, or ambient liquid in any
combination, into said formation, is accomplished.
21. The method of claim 14, wherein said enzymatic fluid has heat
stability for optionally heating to at least 80 degrees Celsius
before injecting into a well, thereby minimizing pour point
problems that may exist and maximizing injection of gas
injections.
22. The method of claim 14, wherein diluting said fluid with water
in a range of 0.01 to 99 percent and more specifically diluting
within a working range of 3 to 10 percent of enzymatic fluid in
water prior to adding to the total injection water.
23. The method of claim 14, wherein said fluid is incrementally
diluted to stimulate wells that are at an unacceptable level of
production prior to restarting a WAG injection process.
24. The method of claim 14, wherein using said fluid for
pre-treatment or treatment of said formation during enhanced oil
recovery such that injecting said fluid and intermixing with water
is accomplished and said fluid and water are sent into said
formation and wherein said formation is a well that is subsequently
not used for a period of time allowing for soaking of said well
prior to another phase of enhanced oil recovery including, but not
limited to pumping and using water for one or more cycles during
said recovery.
25. The method of claim 14, wherein said injecting of said fluid
into pipelines to prevent crude oil from plugging said pipelines is
accomplished.
26. The method of claim 14, wherein said fluid provides a means for
reducing asphaltines and waxes at an injection wellbore prior to
injection as well as minimizing wellbore build up during production
occurring at an end of an enhanced oil recovery cycle, wherein said
cycle includes a WAG cycle.
27. The method of claim 14, such that during WAG operations said
fluid does not affect the normal heat transfer accomplished by
providing steam to surrounding well formations or to said deposits,
wherein said deposits include crude oil.
28. A system for enhanced recovery of oil or other hydrocarbon
deposits in a subterranean formation using an enzymatic fluid, said
deposits are releasable by initially adding said enzymatic fluid
directly to a pump for pumping said fluid, combined with water
forming a water composition, into said oil formation through an
injection well followed by an additional period of time allowing
said fluid and said water composition to soak said formation by
said composition moving from said injection well to one or more
producing wells followed by injection of gas into said formation,
followed by recovery of said deposits by pumping or other
means.
29. The system of claim 34, wherein said fluid is GREENZYME.RTM.
and wherein said deposits include crude oil.
Description
FIELD OF INVENTION
[0001] The present disclosure relates to the release or recovery of
subterranean hydrocarbon deposits and, more specifically, to a
system for enhanced oil recovery (EOR), by utilizing enzyme
compositions and water-alternating-gas (WAG) methods for injecting
ambient, cold or heated fluids containing enzymes, followed
alternatingly, with gas injection into subterranean formations.
BACKGROUND OF INVENTION
[0002] It is a common practice to treat production wells and other
subterranean formations with various methodologies in order to
increase petroleum, gas, oil or other hydrocarbon production using
enhanced (secondary or tertiary) oil recovery. Enhanced oil
recovery processes include Water-Alternating-Gas (WAG), cyclic
steam, steamflood, in-situ combustion, the addition of
micellar-polymer flooding, and microbial solutions.
DEFINITIONS
[0003] One common practice regarding enhanced oil recovery is to
treat viscous crude in subterranean formations using cyclic steam
to increase overall recovery of original oil in place (OOIP) in
wells or hydrocarbon zones that otherwise have low recovery rates.
A cyclic steam-injection process includes three stages. The first
stage is injection, during which a slug of steam is introduced into
the reservoir. The second stage, or soak period, requires that the
well be shut in for several days to allow uniform heat distribution
to thin the oil. Finally, during the third stage, the thinned oil
is produced through the same well. The cycle is repeated as long as
oil production is profitable.
[0004] Cyclic steam injection is used extensively in heavy-oil
reservoirs, tar sands, and in some cases to improve injectivity
prior to steamflood or in-situ combustion operations.
[0005] Cyclic steam injection is also called steam soak or the huff
`n` puff (slang) method. Steamflooding is another method of thermal
recovery in which steam generated at the surface is injected into
the reservoir through specially distributed injection wells.
[0006] When steam enters the reservoir, it heats up the crude oil
and reduces its viscosity. The heat also distills light components
of the crude oil, which condense in the oil bank ahead of the steam
front, further reducing the oil viscosity. The hot water that
condenses from the steam and the steam itself generate an
artificial drive that sweeps oil toward producing wells.
[0007] Another contributing factor that enhances oil production
during steam injection is related to near-wellbore cleanup. In this
case, steam reduces the interfacial tension that ties paraffins and
asphaltenes to the rock surfaces while steam distillation of crude
oil light ends creates a small solvent bank that can miscibly
remove trapped oil.
[0008] Steamflooding is also known as continuous steam injection or
steam drive. In-situ combustion is a method of thermal recovery in
which fire is generated inside the reservoir by injecting a gas
containing oxygen, such as air. A special heater in the well
ignites the oil in the reservoir and starts a fire.
[0009] The heat generated by burning the heavy hydrocarbons in
place produces hydrocarbon cracking, vaporization of light
hydrocarbons and reservoir water in addition to the deposition of
heavier hydrocarbons known as coke. As the fire moves, the burning
front pushes ahead a mixture of hot combustion gases, steam and hot
water, which in turn reduces oil viscosity and displaces oil toward
production wells.
[0010] Additionally, the light hydrocarbons and the steam move
ahead of the burning front, condensing into liquids, which adds the
advantages of miscible displacement and hot waterflooding.
[0011] In-situ combustion is also known as fire flooding or
fireflood.
[0012] Other types of in-situ combustion are dry combustion, dry
forward combustion, reverse combustion and wet combustion which is
a combination of forward combustion and waterflooding.
[0013] Micelles are a group of round hydrocarbon chains formed when
the surfactant concentration in an aqueous solution reaches a
critical point. The micellar costs depend upon the cost of oil,
since many of these chemicals are petroleum sulfonates.
[0014] Micellar-polymer flooding is an enhanced oil recovery
technique in which a micelle solution is pumped into a reservoir
through specially distributed injection wells. The chemical
solution reduces the interfacial and capillary forces between oil
and water and triggers an increase in oil production.
[0015] The procedure of a micellar-polymer flooding includes a
preflush (low-salinity water), a chemical solution (micellar or
alkaline), a mobility buffer and, finally, a driving fluid (water),
which displaces the chemicals and the resulting oil bank to
production wells. The previously defined methods for enhanced oil
recovery (EOR) all still leave residual hydrocarbons in the well.
In some EOR, processes are combined to compensate for
inefficiencies in one of more of the methods. In California, the
injected steam volume is of the order of 10,000 barrels per cycle
injected over about 2 weeks. In Cold Lake, Alberta, with oil
viscosities that are 10-20 times higher than California, steam
injection volumes are larger--perhaps 30,000 barrels per cycle
injected over a month.
[0016] Hydraulic fracturing is accomplished by injecting a
hydraulic fracturing fluid into the well and imposing sufficient
pressure on the fracture fluid to cause formation breakdown with
the attendant production of one or more fractures. Usually a gel,
an emulsion or foam, having a proppant, such as sand or other
suspended particulate material, is introduced into the fracture.
The proppant is deposited in the fracture and functions to hold the
fracture open after the pressure is released and fracturing fluid
is withdrawn back into the well. The fracturing fluid has a
sufficiently high viscosity to penetrate into the formation and to
retain the proppant in suspension or at least to reduce the
tendency of the proppant of settling out of the fracturing fluid.
Generally, a gelation agent and/or an emulsifier is used in the
fracturing fluid to provide the high viscosity needed to achieve
maximum benefits from the fracturing process.
[0017] After the high viscosity fracturing fluid has been pumped
into the formation and the fracturing has been completed, it is, of
course, desirable to remove the fluid from the formation to allow
hydrocarbon production through the new fractures. The removal of
the highly viscous fracturing fluid is achieved by "breaking" the
gel or emulsion or by converting the fracturing fluid into a low
viscosity fluid. The act of breaking a gelled or emulsified
fracturing fluid has commonly been obtained by adding a "breaker",
that is, a viscosity-reducing agent, to the subterranean formation
at the desired time. This technique can be unreliable sometimes
resulting in incomplete breaking of the fluid and/or premature
breaking of the fluid before the process is complete reducing the
potential amount of hydrocarbon recovery. Further, it is known in
the art that most fracturing fluids will "break" if given enough
time and sufficient temperature and pressure.
[0018] Several proposed methods for the breaking of fracturing
fluids are aimed at eliminating the above problems such as
introducing an encapsulated percarbonate, perchlorate, or
persulfate breaker into a subterranean formation being treated with
the fracturing fluid. Various chemical agents such as oxidants,
i.e., perchlorates, percarbonates and persulfates not only degrade
the polymers of interest but also oxidize tubulars, equipment, etc.
that they come into contact with, including the formation itself In
addition, oxidants also interact with resin coated proppants and,
at higher temperatures, they interact with gel stabilizers used to
stabilize the fracturing fluids which tend to be antioxidants.
Also, the use of oxidants as breakers is disadvantageous from the
point of view that the oxidants are not selective in degrading a
particular polymer. In addition, chemical breakers are consumed
stoichiometrically resulting in inconsistent gel breaking and some
residual viscosity which causes formation damage.
[0019] Water-alternating-gas is an enhanced oil recovery process
whereby water injection and gas injection are alternately injected
for periods of time to provide better sweep efficiency and reduce
gas channeling from the injector to the producer. This process is
used primarily in miscible or immiscible CO.sub.2 floods to improve
hydrocarbon contact time and the sweep efficiency of the CO.sub.2.
This process is used to maintain or improve existing production
while increasing the amount of original oil in place (OOIP) that is
recovered beyond primary and secondary recovery methods. Other
oxidized gases have also been shown to help increase oil
yields.
[0020] The use of enzymes to break fracturing fluids may eliminate
some of the problems relating to the use of gaseous oxidants. For
example, enzyme breakers have been found to be very selective in
degrading specific oxygen containing polymers such as partially
hydrolyzed polyacrylamides, carboxylmethyl cellulose, or
polyethylene oxide. The enzymes do not effect the tubulars,
equipment, etc. that they come in contact with and/or damage the
formation itself The enzymes also do not interact with the resin
coated proppants commonly used in fracturing systems. Enzymes react
catalytically such that one molecule of enzyme may hydrolyze up to
one hundred thousand (100,000) polymer chain bonds resulting in a
cleaner more consistent break and very low residual viscosity.
Consequently, formation damage is greatly decreased. Also, unlike
oxidants, enzymes do not interact with gel stabilizers used to
stabilize the fracturing fluids.
[0021] It has been discussed previously that there are several
methods of recovering oil from individual wells or groups of wells,
however, no art is disclosed that indicates an enzyme has been used
as an additive for water-alternating-gas (WAG) injection in
tertiary oil recovery.
[0022] Therefore, there exists a need for a method of injecting an
enzyme composition used in conjunction with water-alternating-gas
(WAG) injection that improves water's ability to recover additional
oil, that has a wide temperature range for activity and being
active at temperatures for preheating up to and about 80 to 90
degrees Celsius with additional subterranean liquid phase
temperature stability under pressure, and is non-reactive with
miscible or immiscible gases being injected. The disclosure
provides several methods for injecting an enzyme composition as an
additive in the water phase for WAG treatments of hydrocarbon
deposits, that is not a breaker for the dissolution of polymeric
viscosifiers, but improves injectivity and oil recovery through its
catalytic ability to release oil from solid surfaces while, at the
same time, reducing surface tension and decreasing contact angle
associated with the crude oil flow.
DESCRIPTION OF PRIOR ART
[0023] U.S. Pat. No. 5,267,615, to Christiansen, et. al., and
unassigned, describes a process for recovering oil from a porous
gas cap of a subterranean hydrocarbon-bearing formation comprising
placing a volume of an oil-immiscible water in a gas cap to
mobilize and displace heretofore substantially immobile oil
residing therein then injecting a volume of an oil-immiscible
non-aqueous gas into the gas cap to drive the mobilized oil from
the gas cap. The ratio of volume of oil-immiscible water to the
volume of the non-aqueous gas is no greater than about 1:10 and
further the first two steps constitute an injection cycle and
recovery of the oil which is mobilized from the gas cap by the
oil-immiscible water and driven from the gas cap by the
oil-immiscible non-aqueous gas during the injection cycle. All the
while substantially retaining the oil-immiscible water in the gas
cap.
[0024] U.S. Pat. No. 4,813,484, to Hazlitt, Randy, and assigned to
Mobil Oil Corp., describes a method for producing hydrocarbonaceous
fluids from a subterranean formation comprising injecting an
aqueous slug into a formation which fluid contains; water, a
surfactant, and a decomposable chemical blowing agent. The chemical
blowing agent then decomposes in-situ thereby generating gas in an
amount and rate sufficient to form foam with the surfactant,
foaming the aqueous slug and then injecting a drive fluid thereby
displacing hydrocarbonaceous fluids from the formation.
[0025] U.S. Pat. No. 4,846,276, to Haines, Hiemi, and assigned to
Marathon Oil Co., describes an oil recovery process for recovering
a low viscosity crude oil from an oil-bearing zone of a
subterranean formation comprising, injecting a gas into an
oil-bearing zone of a subterranean formation via an injection well
in fluid communication with the oilbearing zone, with the gas
injected at an injection pressure substantially below the minimum
miscibility pressure of the gas into low-viscosity crude oil.
Secondly, displacing the low-viscosity crude oil away from the
injection well toward an oil production well in fluid communication
with the oil-bearing formation and continuously recovering the
low-viscosity crude oil from the oil production well. The injection
of the gas is terminated upon substantial diminution of continuous
crude oil recovery from the production well and water is then
injected into the oil-bearing zone of the formation via the
injection well whereby low-viscosity crude oil is displaced away
from the injection well toward the oil production well where
recovering the low-viscosity oil from the oil production well takes
place and water injection is terminated.
[0026] U.S. Pat. No. 5,634,520, to Stevens, et. al., and assigned
to Chevron, USA, describes a process for the enhanced recovery of
oil from an oil-bearing reservoir formation comprising injecting
effective oil producing amounts of a non-condensable gas and an
aqueous drive fluid simultaneously into the formation,
characterized in that the gas and aqueous drive fluid begins from
an initial preselected water to gas ratio and increases to a ratio
of 2:1 to 3:1 and wherein the amount of the gas injected is
effective to reduce the viscosity of the oil or to increase its
mobility through the reservoir formation.
[0027] U.S. Pat. No. 5,515,919, to Stevens, et. al., and assigned
to Chevron, USA, describes a process for the enhanced recovery of
oil from an oil-bearing reservoir formation comprising at least
periodically sequentially injecting effective oil producing amounts
of a non-condensable gas and an aqueous drive fluid into the
formation characterized in that the gas and aqueous drive fluid are
injected at a preselected water to gas ratio and the amount of gas
injected prior to switching to injection of aqueous drive fluid as
measured in hydrocarbon pore volume, is less than 0.25% wherein the
amount of the gas injected is effective to reduce the viscosity of
the oil or to increase its mobility through the reservoir
formation.
[0028] U.S. Pat. No. 4,860,828, to Oswald, et. al., and assigned to
The Dow Chemical Co., describes a method for recovering
hydrocarbons from a subterranean formation comprising injecting,
under non-steam flood conditions, into the subterranean formation
through an injection well, a first fluid selected from group
consisting essentially of a drive fluid of a gas or a gas/aqueous
fluid mixture and a miscible fluid to move the hydrocarbon from the
formation to a producing well and a second fluid which is a
mobility control fluid comprising a surfactant/water mixture
wherein the surfactant component of the mobility control fluid
consists essentially of a mixture of at least one alkylated
diphenyl sulfonate and at least one alpha-olefin sulfonate.
[0029] U.S. Pat. No. 5,711,373, to Lange, Elaine, and assigned to
Exxon Production Research Co., describes a method for
predetermining the amount of a hydrocarbon liquid remaining in a
subterranean formation resulting from introducing a substantially
non-aqueous displacement fluid into the formation and producing at
least a portion of the hydrocarbon liquid. The method comprises
determining a solubility parameter for the hydrocarbon liquid in
the formation before introducing the displacement fluid into the
formation, determining a solubility parameter for the displacement
fluid before introducing it into the formation, determining the
difference between the hydrocarbon liquid and displacement fluid
solubility parameters, predetermining, from the difference, the
amount of hydrocarbon liquid that should remain in the formation
resulting from introducing the displacement fluid into the
formation, introducing a substantially non-aqueous displacement
fluid into the formation and producing at least a portion of the
hydrocarbon liquid.
[0030] U.S. Pat. No. 5,465,790, to McClure, et. al., and assigned
to Marathon Oil Co., describes a process for enhanced recovery of
hydrocarbons from a subterranean formation, penetrated by at least
one injection well and at least one production well in fluid
communication with the formation, the formation having
heterogeneous permeability with an aqueous fluid present in the
higher permeability layers and oil present in the lower
permeability layers. The process steps comprise; injecting an
aqueous surfactant solution into the formation via the at least one
injection well with the surfactant solution having a surfactant
dissolved therein in an amount effective to imbibe into and create
an interface tension gradient within the lower permeability layers.
The interface tension gradient causes displacement of a first
quantity of oil from the lower permeability layers into the higher
permeability layers and injecting a first aqueous fluid into the
formation via the at least one injection well sweeping at least a
portion of the first quantity of oil from the higher permeability
layers to the at least one production well. A gas is then injected
into the formation via the at least one injection well with a
portion of the gas entering the lower permeability layers by
gravity segregation displacing a second quantity of oil from the
lower permeability layers to the higher permeability layers. A
second aqueous fluid is then injected into the formation via the at
least one injection well thereby sweeping at least a portion of the
second quantity of oil from the higher permeability layers to the
at least one production well and portions of the first and second
quantities of oil are recovered from the at least one production
well.
[0031] U.S. Pat. No. 5,363,915, to Marquis, et. al., and assigned
to Chevron, USA, describes a method of enhancing recovery of
petroleum from an oil bearing formation during injection of
non-condensable gas comprising at least periodically injecting a
foam into the oil bearing formation where the foam comprises a
mixture of a gas phase consisting essentially of non-condensable
gas and a water phase containing an effective amount of at least
one non-ionic surfactant having an HLB value of about 14 to less
than 20 and which is selected from among ethoxylated alkyl phenols;
ethoxylated linear secondary alcohols; propoxylated, ethoxlated
primary alcohols and mixtures thereof
[0032] U.S. Pat. No. 5,363,914, to Teletzke, Gary, and assigned to
Exxon Production Research Co., describes a method for recovering
oil from a subterranean oil-containing formation comprising
sequentially injecting into the formation through an injection well
in communication therewith a slug of an aqueous solution containing
a high concentration of a gas mobility control agent. The slug is
of sufficient size to satisfy retention of the agent within pore
spaces contacted by the high concentration solution followed by a
slug of an aqueous solution containing a low concentration of a gas
mobility control agent. The gas as the primary oil displacing
fluid, is selected from the group consisting of carbon dioxide,
hydrocarbon gas, inert gas and steam whereby the gas and said slugs
of aqueous solution containing the gas mobility control agent form
a mixture in the formation that significantly reduces gas mobility
in more permeable regions of the formation wherein oil is recovered
at a spaced apart producing well.
[0033] U.S. Pat. No. 5,358,045, to Sevigny, et. al., and assigned
to Chevron, USA., describes a method of recovering hydrocarbons
from a reservoir during gas injection into a reservoir comprising
at least periodically injecting gas and a foam-forming composition
into a reservoir wherein the reservoir temperature is not less than
about 100.degree. F. The foam-forming composition comprises brine
having not less than about 10% TDS, an effective foam-forming
amount of a surfactant comprising a C10-16 AOS having a major
amount of at least one of C10 AOS and C12 AOS, and an effective
amount of at least one solubilizing component to increase the brine
tolerance of the foam-forming composition, which solubilizing
component is a mixture comprising a formulation where M is H, an
alkali metal, alkaline earth metal, or ammonium, and R1 is a linear
C6-C16 alkyl group and contacting hydrocarbons in the reservoir
with the foam and the gas so as to assist in the recovery of
hydrocarbons from the reservoir.
[0034] U.S. Pat. No. 5,203,411, to Dawe, et. al., and assigned to
The Dow Chemical Co., describes a method for recovering
hydrocarbons from a subterranean formation which comprises
injecting, sequentially or simultaneously, into the subterranean
formation containing hydrocarbons; a drive fluid selected from the
group consisting of a gas to drive the hydrocarbons, a gas/aqueous
fluid mixture to drive the hydrocarbons, a miscible fluid to thin
or solubilize and carry the hydrocarbons, and a miscible
fluid/aqueous fluid mixture to thin or solubilize and carry the
hydrocarbons from the formation to a producing well. Additionally
injected is a mobility control fluid of a surfactant/aqueous fluid
mixture comprising a mixture of one or more alkylated diphenyl
sulfonate surfactants and one or more foam forming amphoteric
surfactants under conditions such that the hydrocarbon is recovered
from the subterranean formation.
[0035] U.S. Pat. No. 5,134,176, to Shu, Paul, and assigned to Mobil
Oil Corp., describes an aqueous crosslinked copolymeric gel-forming
composition comprising; (a) water, (b) a water-dispersible
polyvinyl amine copolymer where the polyvinyl amine copolymer is a
copolymer of vinylamine and vinylamide having a structure wherein R
is an alkyl or aryl group having up to 10 carbon atoms and (a) and
(b) are mole fractions of each co-monomer unit such that a+b=1, and
a is not equal to 0 and b is not equal to 0 and a crosslinking
agent which is selected from the group consisting of phenolic
resins and mixtures of a phenolic component and an aldehyde wherein
the crosslinking agent is present in an amount effective to cause
gelation of an aqueous solution of the polyvinyl amine
copolymer.
[0036] U.S. Pat. No. 5,076,357, to Marquis, David, and assigned to
Chevron, USA, describes a method of enhancing recovery of petroleum
from an oil bearing formation during injection of a non-condensable
gas comprising at least periodically injecting a preformed foam
into the oil bearing formation. The preformed foam comprises a
mixture of gas, water and an effective foam-forming amount of an
alpha olefin sulfonate (AOS), with the AOS comprising a mixture of
hydroxysulfonates and alkene-sulfonates and further wherein the
hydroxy-sulfonates comprise 3-hydroxy- and 4-hydroxy-sulfonates
with the ratio of 3-hydroxy-sulfonates to 4-hydroxy-sulfonates
being at least about 3.
[0037] U.S. Pat. No. 4,940,090, to Hoskin, et. al., and assigned to
Mobil Oil Corp., describes a process for recovering oil from a
subterranean oil-bearing formation having relatively high
permeability zones and relatively low permeability zones penetrated
by at least one production well in fluid communication with a
substantial portion of the formation, comprising the steps of (a)
injecting into the formation an aqueous gel-forming composition
comprising water and a water-dispersible polyvinyl alcohol
copolymer with the polyvinyl alcohol copolymer selected from the
group consisting of copolymers of vinyl alcohol and vinyl alkyl
sulfonate ether having a specific structure and copolymers of vinyl
alcohol and vinyl-acrylamide ether, having the structure wherein R
is an alkyl or aryl group having up to 10 carbon atoms; M+ is Na+,
K+ or other counter ions and a and b are mole fractions of each
co-monomer unit such that a+b=1, and a>o and b>o and a
crosslinking agent which is a mixture of a phenolic component and
an aldehyde. The crosslinking agent is present in an amount
effective to cause gelation of the polyvinyl copolymer and is
injected as a flooding fluid into the formation that preferentially
enters the low permeability zones and the fluids, including oil
from the formation, are recovered via the production well.
[0038] U.S. Pat. No. 4,828,029, to Irani, Cyrus, and unassigned,
describes an improved method for recovering oil from a
subterranean, hydrocarbon-bearing formation which is penetrated by
at least one injection well and at least one production well
wherein a liquid non-aqueous displacement fluid is injected into a
formation through an injection well and fluids are produced from
the production well with the improvement comprising dissolving in
the non-aqueous displacement fluid an effective amount of a
surfactant and a cosolvent prior to injecting the fluid into the
formation. The cosolvent is adapted to increase the solubility of
the surfactant in the displacement fluid. The displacement fluid is
selected from the group comprising carbon dioxide, nitrogen, and
mixtures of any combination selected from the group comprising
carbon dioxide, nitrogen, and light hydrocarbons.
[0039] U.S. Pat. No. 4,676,316, to Mitchell, Thomas, and assigned
to Mobil Oil Corp., describes a method for improved enhanced
recovery of oil from a subterranean hydrocarbon-bearing reservoir
by water-alternating-gas flooding, the improvement which comprises
effecting simultaneous mobility and profile control by injecting
into the reservoir an aqueous solution of a water-soluble polymer
in combination with a stable foam-forming surfactant in an amount
of from about 0.05% to 2.0% of the aqueous solution, and injecting
into the reservoir a gas under pressure sufficient to effect
mobility of hydrocarbon deposits and continuously recovering oil at
a producing well of the reservoir.
[0040] U.S. Pat. No. 3,529,668, to Bernard, George, and assigned to
Union Oil Co., describes a Drive fluid, gas with a liquid injected
into a well to displace the oil in a well whereas the ratio of gas
to liquid is between 5 to 15 as measures at well conditions
regarding temperature and pressure.
[0041] U.S. Pat. No. 3,779,315, to Boneau, David, and assigned to
Phillips Petroleum Co., describes a method for producing
hydrocarbons from a subterranean hydrocarbon-containing formation
penetrated by at least a first well bore and reducing the flow of
gas into the well bore from a gas cap positioned in the upper
portion of the formation, comprising: passing a preselected volume
of polymeric solution into the hydrocarbon-containing formation at
a location lower in elevation than the gas cap; terminating the
injection of the polymeric solution and producing fluids entering
the well bore while at least intermittently injecting one of a
gas-water admixture, or volumes of gas and water into said gas cap
of said hydrocarbon-containing formation. The polymer of the
polymeric solution is one of partially hydrolyzed polyacrylamides,
carboxylmethyl cellulose, or polyethylene oxide.
[0042] U.S. Pat. No. 3,788,398, to Shepard, Cecil, and assigned to
Mobil Oil Corp., describes a method of producing oil from a
subterranean reservoir having an oil zone and a gas cap, with the
gas cap being penetrated by an injection system and the oil zone
being penetrated by a production system. The production system
comprises the steps of (a) injecting via the injection system into
the gas cap a fluid that is miscible with the oil in the oil zone
and the gas in the gas cap; (b) injecting gas via the injection
system into the gas cap; (c) injecting via the injection system
into the gas cap, water, in an amount less than the amount required
to extend the water into the oil zone and (d) producing oil via the
production system from the reservoir.
[0043] U.S. Pat. No. 4,856,589, to Kuhlman, et. al., and assigned
to Shell Oil Co., describes a process for recovering oil from a
reservoir, penetrated by at least one injection well and one
production well comprising: formulating an aqueous surfactant
solution such that the surfactant is present in the solution at a
concentration less than its critical micelle concentration,
injecting the surfactant solution into the reservoir and injecting
a gas to displace the surfactant solution through the reservoir to
assist in the recovery of hydrocarbons at the production well.
[0044] U.S. Pat. No. 5,678,632, to Moses, et. al., and assigned to
Cleansorb Limited, describes a method of acidising an underground
reservoir which comprises: injecting into the reservoir an isolated
enzyme and a substrate for the enzyme, which substrate is capable
of being converted into an organic acid by the enzyme and allowing
the enzyme to catalyze the conversion of the substrate into the
acid. The enzyme and substrate are injected into the well bore
simultaneously.
[0045] U.S. Pat. No. 4,971,151, to Sheehy, Alan, and assigned to
BWN Live-Oil Pty. Ltd., describes a method for recovering oil from
a reservoir having a population of endogenous microorganisms
comprising adding to the reservoir, nutrients comprising a
non-glucose-containing carbon source and at least one other
non-glucose-containing nutrient. The nutrient is growth effective
for the endogenous microorganisms, maintaining the reservoir for a
time and under conditions sufficient for the substantial depletion
of at least one of the added nutrients wherein the added nutrients
and depletion of at least one of the added nutrients results in
microorganisms having reduced cell volume and increased surface
active properties and thereafter subjecting the reservoir to oil
recovery means.
[0046] U.S. Pat. No. 5,083,610, to Sheehy, Alan, and assigned to
BWN Live-Oil Pty. Ltd., describes a method for recovering oil from
a reservoir having a population of endogenous microorganisms
comprising adding to the reservoir, nutrients, comprising a
non-glucose-containing carbon source and at least one other
non-glucose-containing nutrient. The nutrient is growth effective
for the endogenous microorganisms maintaining the reservoir for a
time and under conditions sufficient for the substantial depletion
of at least one of the added nutrients wherein the added nutrients
and depletion of at least one of the added nutrients result in
microorganisms having reduced cell volume and thereafter subjecting
the reservoir to oil recovery means.
[0047] WIPO Patent Publication No WO9635858A1, to Djabbarah, et.
al., and assigned to Mobil Oil Corp., describes a steamflood method
for producing oil from a subterranean, oil-containing formation by
injecting steam into the formation and recovering oil from a
production well, characterized in that a mixture of a
noncondensable gas and an aqueous surfactant-polypeptide solution
is injected into the formation through a well, to form a foam which
reduces the permeability of swept zones, forcing injected steam
into unswept areas of the formation.
[0048] WIPO Patent Publication No WO9304265A1, to Frazier, et. al.,
and assigned to Chevron, USA, describes a method for recovering
hydrocarbons from a formation comprising at least periodically
injecting a gas and a foam-forming composition into a formation so
as to provide a foam, wherein the composition comprises water and
effective foam-forming amounts of at least one cationic and at
least one anionic surfactant. The ratio of the at least one anionic
surfactant to the at least one cationic surfactant is selected such
that the surfactants do not form substantial amounts of precipitate
when mixed together; contacting the hydrocarbons in the formation
with the foam and the gas so as to assist in the recovery of
hydrocarbons.
[0049] WIPO Patent Publication No WO9014496A1, to Buller, et. al.,
and assigned to University of Kansas, describes a method for
enhanced recovery of hydrocarbon fluids by the injection of a
flooding fluid into a subterranean hydrocarbon fluid bearing
formation through an injection well extending from the surface of
the earth into the formation to displace in-situ hydrocarbon fluids
from the formation towards at least one production well spaced at a
distance away from the injection well. The improvement comprises:
(1) first injecting a quantity of acidic water into the formation
through the injection well; (2) injecting a quantity of reversibly
gelable, water insoluble, alkaline beta 1,3 polyglucan homopolymer
solution, which solution gels immediately upon one of
neutralization and acidification thereof, into the injection well;
(3) injecting a drive fluid into the injection well and producing
at least some hydrocarbon fluids from the production well.
[0050] European Patent Publication No EP0305612A1, to Holm, Leroy,
and assigned to Union Oil Co., describes a method for reducing the
permeability of higher permeability zones of an oil bearing
subterranean reservoir having heterogeneous permeability and being
penetrated by at least one well. The method comprises first
injecting through a well and into the reservoir an aqueous liquid
solution of a water soluble surface active agent and a foam
emplacement gas mixture consisting essentially of carbon dioxide
and a crude oil-insoluble, noncondensable, non-hydrocarbon gas
wherein the injection is under conditions such that the gas mixture
maintains a density between 0.01 and 0.42 grams per centimeter in
the reservoir. Secondly, allowing stable foam to form in the higher
permeability zones and diverting subsequently injected gases into
lower permeability zones of the reservoir without destroying the
stable foam producing oil from the reservoir.
SUMMARY OF THE DISCLOSURE
[0051] One embodiment of the disclosure includes a method and
system of removing petroleum, oil and other hydrocarbon deposits
releasable by a substance from a subterranean formation below a
surficial formation. The method and system according to this
disclosure comprises, in combination, the steps of providing a hole
through the surficial formation to the subterranean formation,
injecting an enzyme fluid through the surficial formation to the
subterranean formation, storing the substance at the surficial
formation in the form of a liquid at the subterranean formation.
Also, for injection, providing a fluid that is non-reactive with
injections of miscible or immiscible gas and has temperature
stability sufficient for a sustained liquid phase of the enzymatic
fluid under pressure at the subterranean formation. The ability to
drive the liquid into the subterranean formation for releasing
hydrocarbon deposits with that liquid moving from an injection well
to one or more producing wells, and removing such released deposits
from the subterranean formation using enzymatic fluids is part of
the disclosure. Alternating the liquid injection cycle with an
injection cycle of a miscible, near miscible or immiscible gas with
the ability to drive the gas into the subterranean formation
through an injection well for releasing hydrocarbon deposits with
that gas, and removing released deposits thru one or more producing
wells separate from the injection well from the subterranean
formation in combination with the enzymatic fluid is also part of
the present disclosure.
[0052] Another embodiment of the disclosure is a method and system
for injecting an enzyme composition into a well as a treatment for
enhanced oil recovery (EOR) within a water-alternating-gas process
cycle sometimes referred to as WAG.
[0053] Another embodiment involves injecting miscible, near
miscible or immiscible gas including natural gas, nitrogen, flue
gas, CO2, hydrocarbon gas such as liquefied petroleum gas (LPG),
propane, butane and propane mixtures, methane enriched with other
light hydrocarbons, and methane under high pressure into a
wellbore.
[0054] Another embodiment of the disclosure includes the use of
GREENZYME.RTM. as the enzyme composition for WAG treatment or
pretreatment of at least one injection well and one or more
producing oil wells.
[0055] Another embodiment includes the use of an enzyme composition
for treatment between liquid and gas injection cycles or treatment
of the well during or after the water injection cycle such that the
enzyme can be injected as a heated liquid into the well if needed.
The use of an enzyme heated to 80 to 90 degrees Celsius before
injection into a well to minimize pour point flow restrictions and
to maximize injection pressure efficiency of the injected water or
gas is another aspect of the disclosure. It is noted that the
enzyme is active in a diluted range of 0.01 to 100 percent and is
suitable, but not limited to, a working range of 3 to 10 percent
for injection with water. Injection of enzyme may have different
points of addition and can occur along with large injections of
water that are part of a designed WAG treatment or in concentrated
or diluted enzyme fluids that are injected "on the fly" to water
injection lines that actively pump water. Metered addition of
enzyme to maximize efficient use of enzyme and optimize WAG
performance is also possible.
[0056] Another embodiment includes the use of an enzyme composition
in combination with water in a WAG treatment to extend the
effective consumption of miscible or immiscible gas being injected
thus improving overall capacity while offsetting or minimizing
reduced recoverability normally associated with reduced use of gas
injection. Some oil wells have formations that are suitable for
straight gas injection where no WAG treatment is used. This also
means a high rate of gas injection that may or may not be
sustainable as demand for straight gas and WAG injection grows.
[0057] Another embodiment includes the use of an enzyme composition
to be injected into a subsurface formation to improve the mobility
of heavier crude oils going from the injection well to one or more
producing wells and to prevent plugging in producing wellbores or
restricted flow areas as well as plugging the pipelines.
[0058] Another embodiment is the use of an enzyme composition for
penetrating asphaltenes and waxes at the injection wellbore prior
to or during WAG injection as well as minimizing similar build up
that can occur at one or more producing wellbores during
production.
[0059] Another embodiment includes use of an enzyme in WAG
operations such that the enzyme does not affect the normal function
or react with the gas being injected in the surrounding well
formations as it moves from an injection well to one or more
producing wells.
BRIEF DESCRIPTION OF THE DRAWINGS
[0060] FIG. 1 is a schematic WAG injection stages with a
pretreatment stage using an enzyme composition such as
GREENZYME.RTM..
DETAILED DESCRIPTION
[0061] Disclosed is an improvement to water-alternating-gas (WAG)
processes for tertiary oil recovery that utilizes an enzyme
composition to increase the ability of the water phase to recover
and mobilize oil. In particular an enzyme trademarked as
GREENZYME.RTM., by Apollo Separation Technologies, Inc. of Houston,
Tex. GREENZYME.RTM. is a biological enzyme that is a protein based,
non-living catalyst for penetrating and releasing oil from solid
surfaces and demonstrates the following attributes:
[0062] GREENZYME.RTM. has the effect of increasing the mobility of
the oil by reducing surface tension, decreasing contact angles and
preventing crude oil that has become less viscous by heating or
other means, from re-adhering to itself as it cools.
[0063] GREENZYME.RTM. is active in water and acts catalytically in
contacting and releasing oil from solid surfaces.
[0064] GREENZYME.RTM. is effective up to 270 degrees Celsius in
liquid phase under pressure and is not restricted by variations in
the American Petroleum Institute (API) specific gravity ratings of
the crude oil.
[0065] GREENZYME.RTM. is not an oil viscosity modifier nor does it
change the chemical composition of the oil.
[0066] GREENZYME.RTM. is not reactive with miscible or immiscible
gases.
[0067] GREENZYME.RTM. is not a live microbe and does not require
nutrients or ingest oil.
[0068] GREENZYME.RTM. does not grow or plug an oil formation or
release cross-linked polymers.
[0069] GREENZYME.RTM. does not trigger any other downhole
mechanisms, except to release oil from the solid substrates. (ie:
one function).
[0070] Other suitable enzymes other than GREENZYME.RTM. are also
the subject of the present disclosure and can be used
interchangeably or separately from GREENZYME.RTM. to meet the EOR
requirements of individual wells.
[0071] Referring to FIG. 1, in an overview, the
water-alternating-gas (WAG) and enzyme system [4] is comprised of
four (4) stages. The first stage includes a normal water
composition injection stage [10] with at least one injection well,
an alternative period of idle process known as the soak stage [20],
followed by the gas injection stage [30] and then a recovery stage
[40] of produced oil by one or more producing wells that are
designed and configured to recovery oil from one or more injection
wells. This water-alternating-gas (WAG) and enzyme system [5] is
sequential and repeated based on the economics and availability of
gas to inject, water availability, energy requirements to both
produce oil and recover and re-inject the gas, and increased
production and recovery rates achieved thru the combination of gas
injection and enzyme addition. The water composition of the water
composition injection stage [10] may include any substance known to
those in the art.
[0072] During the water composition injection stage [10], enzymes
[115], such as GREENZYME.RTM. [110], are added to water and flow to
an injection pump [150] where it is then pumped down an injection
pipe [130], through the downhole well bore [135] and into the oil
well formation [140]. The water composition acts to release the oil
from solid surfaces, increase the mobility of the oil by reducing
surface tension, decreasing contact angles, preventing crude oil
that has become less viscous by heating or other means, from
re-adhering to itself as it cools and acts catalytically in
contacting and releasing oil from solid surfaces. Blockages in the
oil well formation [140] may be reduced or eliminated as well. The
enzymes [115] are pushed into the oil well formation [140] to
further contact oil particles [142] thereby increasing contact
volume.
[0073] The soak stage [20] as it is known, allows the water and
enzyme [115] composition to permeate the oil well formation [140]
and the enzymes [115] to reach maximum oil releasing efficiency.
The enzymes [115] remains active in the water or hot water
compositions and acts catalytically in contacting and releasing oil
from solid surfaces. It is not restricted by variations in the
American Petroleum Institute (API) specific gravity ratings of the
crude oil. The soak stage [20] lasts between 0-30 days depending on
the type and size of the oil well formation [140]. The soak stage
[20] may be omitted when the gas injection stage [30] immediately
follows the water composition injection stage [40].
[0074] Normally following the soak stage [20] is a gas injection
stage [30] to which a gas injection pump [160] is connected to the
oil well formation [140] via an injection pipe [130] and a wellbore
[135]. Miscible, near miscible or immicsible gas flows into the gas
injection pump [160] where it is under pressure and flows into the
oil well formation [140] via an injection pipe [130] and a wellbore
[135]. The gas then displaces the water composition and enzymes
[115] pushing oil particles [142] toward the part of the oil well
formation [140] where recovery operations occur.
[0075] Following the gas injection stage [30] is the recovery stage
[40] in which one or more extraction pump [165] is connected to the
oil well formation [140] via a retrieval pipe [170] and an uphole
well bore [175]. In the recovery stage [40], the extraction pump
[165] is activated causing the oil particles [142] to be
transferred from the oil well formation [140] through the uphole
well bore [175] and retrieval pipe [170] to be transferred for
refining.
[0076] This written description uses examples to disclose the
invention, including the best mode, and also to enable any person
skilled in the art to make and use the invention. The patentable
scope of the invention is defined by the claims, and may include
other examples that occur to those skilled in the art. Such other
examples are intended to be within the scope of the claims if they
have structural elements that do not differ from the literal
language of the claims, or if they include equivalent structural
elements with insubstantial differences from the literal languages
of the claims.
* * * * *