CA2096764C - Blocking water coning in oil and gas producing reservoirs - Google Patents
Blocking water coning in oil and gas producing reservoirsInfo
- Publication number
- CA2096764C CA2096764C CA002096764A CA2096764A CA2096764C CA 2096764 C CA2096764 C CA 2096764C CA 002096764 A CA002096764 A CA 002096764A CA 2096764 A CA2096764 A CA 2096764A CA 2096764 C CA2096764 C CA 2096764C
- Authority
- CA
- Canada
- Prior art keywords
- acrylamide
- process according
- gelling composition
- gelling
- water
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Expired - Fee Related
Links
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/32—Preventing gas- or water-coning phenomena, i.e. the formation of a conical column of gas or water around wells
Abstract
A process for controlling the migration of a gelling composition for enhanced oil recovery by blocking water or gas coning comprises injecting a gelling composition into a subterranean formation where the density of the gelling composition is adjusted depending on the density of the formation brine or oil so that the gelling composition gels in a desired location of the formation.
Description
BLOCRING WATER CONING IN OIL AND GAS
PRODUCING RESERVOIRS
Field of the Invention The present invention relates to enhancing hydrocarbon production by blocking water-coning or gas-coning in oil and gas producing wells.
Background of the Invention A major problem associated with producing wells of oil and gas is the increased water coning. In most reservoirs, oil is produced from an oil zone which often lies over a water zone and beneath a gas zone.
During production of oil from a well, water underlying the oil zone may flow strongly upward into the lower pressure zone around the well and into the well to the oil zone level. Because the water is generally lower in viscosity than oil, the water may flow more rapidly than the oil and create a water zone around the well substantially inhihiting the entry of oil into the well. This water coning is especially serious in reservoirs which is subject to a bottom whter drive.
PRODUCING RESERVOIRS
Field of the Invention The present invention relates to enhancing hydrocarbon production by blocking water-coning or gas-coning in oil and gas producing wells.
Background of the Invention A major problem associated with producing wells of oil and gas is the increased water coning. In most reservoirs, oil is produced from an oil zone which often lies over a water zone and beneath a gas zone.
During production of oil from a well, water underlying the oil zone may flow strongly upward into the lower pressure zone around the well and into the well to the oil zone level. Because the water is generally lower in viscosity than oil, the water may flow more rapidly than the oil and create a water zone around the well substantially inhihiting the entry of oil into the well. This water coning is especially serious in reservoirs which is subject to a bottom whter drive.
Gas-coning may also happen during oil production. This cause is a reduction in oil production resulting in an increase in gas:oil ratio. The downward flow of the lower viscosity gas into the oil zone around the production well interferes with the flow of oil into the wellbore.
Several references provide somewhat limited solutions to the above described problems. For example, U.S. Pat. No. 3,866,682 discloses controlling water and gas coning by forming a barrier having a shape like a hollow frustum in a production well. U.S. Pat. No.
Several references provide somewhat limited solutions to the above described problems. For example, U.S. Pat. No. 3,866,682 discloses controlling water and gas coning by forming a barrier having a shape like a hollow frustum in a production well. U.S. Pat. No.
3,404,734 discloses in-situ production of gels for plugging water coning. Additionally, U.S. Pat. No. 4,485,875 discloses in-situ production of gels by injecting a solution mixture of polyacrylamide, phenol and an aldehyde to selectively plug permeable zones. Moreover, U.S. Pat.No. 3,695,356 discloses a controlling mechanism by hydrolysis of gels formed by injecting water soluble, gel-forming materials.
Furthermore, U.S. Pat. No. 4,418,755 discloses inhibiting water flow by injecting a gelling agent into the formation.
Finally, it is well-known that, as disclosed in Water-Soluble Polymers for Petroleum Recovery (G.A. Stflhl and D.N. Schulz, editors, Plennum Press, New York, N.Y., 1988), pp. 299-312, a gelable polymer is most commonly used to divert the flow from the high permeability zones and fractures to the unswept oil-containing portions of the reservoirs.
For example, in the gelation of a gelable water soluble polymer, an aldehyde is condensed with a phenolic compound along with the polymer injected into the reservoir to form gels. The gels thus formed can reduce the permeability and divert the flow of injected fluids resulting in enhanced oil recovery.
However, none of the above described references disclose the use of gellable mixtures having different buoyancies relative to the brines of the reservoirs to control the location in the reservoirs where the gels are formed. The control of such gelation would more effectively block water coning allowing the entry of oil into the well for recovery. Gelling solutions with densities lower than oil can be injected in producing wells with gas-coning problems to float on top and produce a gel at the interface to block gas coning.
Summary of the Invention It is therefore an object of the present invention to provide a process for injecting a slow gelling composition having a density higher than formation brine and a gel time longer than the time required for gravity drainage of the mixture to the base of water coning zone.
It is also an object of the present invention to provide a gelling composition forming a gel that can be manipulated to rise or drain depending on its density so that it can be used as a cover for the body of water. It is another object of the present invention to provide a process for controlling the rate of the gelling composition migration by density differences between gelling compositions and formation brines.
The advantage of the invention is that the cover for the body of water can further be improved by adding a foaming surfactant to the gelling composition by bubbling a suitable gas through the composition to produce a foaming gel which is useful as an evaporation barrier.
Another advantage of the present invention is that dense gelling systems can be used to coat the bottom of disposal ponds to prevent seepage of hazardous materials. A further advantage of the present invention is that the gelling systems can be used in the bottom portions of producing or injection wells.
According to the present invention, a process for controlling the migration of a gelling mixture for enhanced oil recovery by blocking water or gas coning comprises injecting a gelling mixture into a subterranean formation where the density of the gelling mixture is adjusted to be higher than the density of the formation brine or lower than oil.
Detailed Description of the Invention According to the present invention, a process for controlling the migration of a gelling composition for blocking water or gas coning in a producing or injection well comprises injecting a gelable composition into the formation and the gelling composition forms a gel in the subterranean formation; wherein the density of the gelling composition is adjusted depending on the density of the formation brine.
All soluble and gellable polymers that are suitable for high salinity formation temperature (preferably acrylamide-containing polymers) or monomers which form gels in-situ upon being injected in the formation can be utilized in the present invention. It is presently preferred, however, that the polymer have a molecular weight of at least about 100,000 and more preferably 100,000 to 20,000,000. The upper limit is not critical as long as the polymer is still soluble and can be pumped into the formation. The term "soluble" used herein refers to those polymers, and monomers that are soluble or dispersible in water or a suitable medium such as oil.
The presently preferred class of acrylamide-containing polymers are those selected from the group consisting of homopolymers of acrylamide, homopolymers of methacrylamide, copolymers of acrylamide and acrylic acid, copolymers of acrylamide and potassium acrylate, copolymers of acrylamide and sodium acrylate, copolymers of acrylamide and N,N-dimethylacrylamide, copolymers of acrylamide and methacrylamide, copolymers of acrylamide and sodium 2-acrylamido-2-methylpropane sulfonate, copolymers of acrylamide and N-vinyl-2-pyrrolidone, terpolymers of acrylamide, N,N-dimethylacrylamide and 2-acrylamido-2-methylpropane sulfonate, and terpolymers of acrylamide, N-vinyl-2-pyrrolidone, and sodium 2-acrylamido-2-methylpropane sulfonate. The ratio of the monomers in the above-described polymers is not critical; provided however, that at least 5 mole % of acrylamide or methacrylamide is present in the above-described polymers.
Particularly preferred are homopolymers of acrylamide, copolymers of acrylamide and sodium acrylate, copolymers of acrylamide and sodium 2-acrylamido-2-methylpropane sulfonate, copolymers of acrylamide and N-vinyl-2-pyrrolidone, and a terpolymers of N-vinyl-2-pyrrolidone, acrylamide and sodium 2-acrylamido-2-methylpropane sulfonate. However, other polymers with more subunits may also be utilized in the practice of this invention.
Additionally, within the scope of this invention is the use of combinations of homopolymers, copolymers, terpolymers, and tetrapolymers utilizing the above listed monomers.
Other suitable polymers are polysaccharides such as xanthan, glucans, cellulosic materials, and mixtures thereof.
Presently preferred monomers that form gels in-situ upon being injected into the wells include, but are not limited to acrylamide, N-vinyl-2-pyrrolidone, sodium 2-acrylamido-2-methylpropane sulfonate, N,N-dimethylacrylamide, acrylic acld, alkali metal salt of acrylic acid, and mixtures thereof. A presently preferred crosslinking system in-cludes, but is not limited to phenol and formaldehyde; resorcinol and formaldehyde; furfuryl alcohol and formaldehyde; and mixtures thereof.
The polymers or monomers that form gel in-situ are generally present in the composition in the amount of from about 0.05 to about 10 weight percent, preferably from about 0.1 to about 5 weight percent, and most preferably from 0.2 to 4 weight percent. The concentration of poly-mer in the composition depends to some degree upon the molecular weight of the polymer. A high molecular weight results in a higher viscosity of the resulting gel for a particular concentration of polymer.
Water generally makes up the rest of the inventive composi-tion.
An aqueous solution containing the water soluble acrylamide-containing polymer having a density higher than the formation brine density can be pumped into the formation so that it forms gel in the formation in a desirable location of the formation so that water coning can be blocked.
The nature of the underground formation treated is not critical to the practice of the present invention. The composition of the present invention can be used in or can be injected into, fresh water, salt water, or brines, as well as at a temperature range of from about 70F to about 400F, preferably from about 150F to about 350F, and most preferably from 200F to 300F. However, at temperatures higher than 170F, homopolymers of acrylamide and copolymers of ac-rylamide and an alkali metal salt of acrylic acid are not suitable.
7 20967~4 -For temperatures lower than 170F, homopolymers of acrylamide, copolymers of acrylamide and an alkali metal salt of acrylic acid can be used in combination with a suitable crosslinking system.
The following specific examples are intended to illustrate the advantages of this invention, but are not intended to unduly limit this invention.
Example I
This example demonstrates that a gel can be formed in a different location in a simulated brine depending on its buoyancy, relative to the brine.
The runs were carried out by injecting 1/3 pore volume (PV) of a gelling mixture containing 5.7% Pfizer Oil Field Products Floperm 325 (prepared by mixing 10.0 g Floperm 325 R (a resorcinol solution), 6.76 g of Floperm 325 F (formaldehyde solution)~ 3.75 g of Floperm 325 S-II (a salt mixture of aqueous sodium chloride/potassium chloride in 10/1 ratio) and 79.49 g of water. The pH of this solution was adjusted to 9.0 by Floperm 325 C (a sodium hydroxide solution) before injection into a horizontal sandpack containing brines with different densities as shown in Table I below. The injection was made through a horizontal injection port located on the side of the sandpack at a point near the middle.
h h ~V rV al r~ r~o X r~ r.
~ Z
3 ~: r~ L~ ~D
O ^
P~
rJ
P~ h ~d ~, ~
r~o ~o r.~ ~o O
rc~
r~ a ~ I rC ~
, rn r,~ ~
rV rD - ~
~ O
p~ ~ r~o ~r~ r~ rn ~
bO O ,r~ lO rn ~D
r.~l o ~r.~ ,1 rn O O ~1 0 rd ~V
PC OO OO r-l rr~
~H I + + I +
rD O r.~
r ~ ~;
a~ ~
`D rl r.~ 3 r--l o rc I
rD r.~ ~ oo c~ . h ~; r~ ~ o r~ rV
r~ D r~ 3 r~ o ~ o~ ~
rr ~
rD ~ or~~ ~ O rV
~d h t rn r~~
r~ ~1 ~,. E~
rr O O O O
rX r.~ooo r~o rn rV O O O O
r~ ~ rD
~I r--lr-l r~l p ~9 Lq rn 1~ rn r-l rD
h ~,1 h rD O h rV) r7 r~ a~ 3 ~ P 3 , rn rC~P¢ a~o ¢ ~ d ~Vr:n r~ ~~D
rl rV ~r,!~ + ;~r~ r!~ 3 U rl rl~:1 rD rl ' r~
a h ~ ~ a~o ~
~ m u~a~,l ou~ -~10 ~-I O
r ~ ,~~Irc~
rn ~ rn o Z p O ¢
Z 11 r~ ~
~r.~ ~ OC!~ un r~ ~dZ,~ r.) In runs 1, 2 and 4, gels were formed in the bottom of the sandpack. In run 3, however, the lower density gelling solution floated to the top and produced a layer of gel.
The above results indicate that the gel can be manipulated to rise up or drain depending on its density. Should there be a case where upper zone needs isolation a low density gel can be used. In the case of gas coning into oil zone, a gelling mixture in a light hydrocarbon solvent could be injected. Because of its lower density, the gelling mixture should float on the top of oil and block gas coning once set into a gel. The rate of gelling mixture migration can be controlled by the density difference.
Example II
In one run (run 5, Table II), 1/3 pv of a gelling mixture of 2% low molecular weight polyacrylamide (Allied Colloids DP9-3976) in synthetic seawater with 500 ppm Na2Cr2O7.2H2O and 2,500 ppm Na2S2O3.sH2O, was injected from the top of a vertical sandpack which contained a 20-30 mesh Ottawa sand and had been flooded with Bartlesville, Oklahoma tap water. The synthetic seawater contained the following:
NaHCO3 3.69 g Na2SO4 77.19 g NaCl 429.00 g CaClz-2H2O 29.58 g MgC12-2H2O 193.92 g distilled H2O bring to 1.0 1 The sandpack which was at room temperature was shut in for gelation.
Because of the higher density (1.0235g/mL vs. 1.0 g/mL), the gelling mixture moved to the bottom of the 30.5 cm pack and formed a gel about 14.8% of total volume of the pack. The lower volume (14.8% vs. 33.3%) of the gel might be due to dilution with water in counter current flow.
This would not be a problem in an actual well treatment which would allow the residence brine to move up around the sinking gelling mixture.
Three similar runs (6-8) were performed in glass beads packs flooded with Bartlesville, Oklahoma tap water. The gelling mixtures were 5.7% Pfizer Floperm 325 in Bartlesville tap water with a density of 1.018 g/mL. The results are summarized in the following Table II.
Table II
Delay Ave. Perm Time Location Run No. Packing Material (darcy) (days) of Gel Ottawa Sand, 20-30 mesh 56.8 12 14.870 volume in the bottom 6 Glass Beads, 40-50 mesh 26.6 22 6.6% volume in the bottom 7 Glass Beads, 40-50 mesh 17.0 10 16.7% volume in the bottom 8a Smaller glass beads 6.6 10 mostly on top aA by-pass line from the bottom to the top of pack avoided counter current formation.
The gel time was too short for the slow moving mixture to sink down before setting.
The data in run 8 indicate that for a glven reservoir, the gel time should be long enough to allow the gelling mixture to move to the desired location before setting.
These examples describe a gel placement strategy which is beneficial in many oil field operation. The gel density is manipulated to be lower or higher than the residence fluids for placing the gel in a desired locatlon. For example, if the object is to block water coning 1l- 20967~4 in subterranean formations, it would be better to use a slow gelling mixture with a density higher than the residence brine. This will allow the gelling mixture to sink into the bottom of the cone and blocking a larger area for a given gel volume than a gelling mixture with the same density as the residence brine which would block a smaller area for the same volume. Another application of the higher density gel can include blocking of the bottom portions of injection or producing wells. Yet another application for the higher density gels can include the treatment of disposal ponds containing hazardous waste materials to prevent the seepage of these hazardous materials.
Since the gelling system with a density lower than water will float on top (run 3, Table I), these systems can be used to make a gel cover for a body of water. One can include a foaming surfactant in the lighter gelling compositions to produce floating foam gels which can be used as an insulator against heat loss for a body of water, such as in a solar pond.
Gelling solutions with densities lower than oil can be injected into a gas coning well. These solutions should float on the top of oil and set into a gel blocking the gas from flowing into the oil zone.
The results shown in the above examples clearly demonstrate that the present invention is well adapted to carry out the objects and attain the ends and advantages mentioned as well as those inherent therein. While modifications may be made by those skilled in the art, such modifications are encompassed within the spirit of the present invention as defined by the specification and the claims.
Furthermore, U.S. Pat. No. 4,418,755 discloses inhibiting water flow by injecting a gelling agent into the formation.
Finally, it is well-known that, as disclosed in Water-Soluble Polymers for Petroleum Recovery (G.A. Stflhl and D.N. Schulz, editors, Plennum Press, New York, N.Y., 1988), pp. 299-312, a gelable polymer is most commonly used to divert the flow from the high permeability zones and fractures to the unswept oil-containing portions of the reservoirs.
For example, in the gelation of a gelable water soluble polymer, an aldehyde is condensed with a phenolic compound along with the polymer injected into the reservoir to form gels. The gels thus formed can reduce the permeability and divert the flow of injected fluids resulting in enhanced oil recovery.
However, none of the above described references disclose the use of gellable mixtures having different buoyancies relative to the brines of the reservoirs to control the location in the reservoirs where the gels are formed. The control of such gelation would more effectively block water coning allowing the entry of oil into the well for recovery. Gelling solutions with densities lower than oil can be injected in producing wells with gas-coning problems to float on top and produce a gel at the interface to block gas coning.
Summary of the Invention It is therefore an object of the present invention to provide a process for injecting a slow gelling composition having a density higher than formation brine and a gel time longer than the time required for gravity drainage of the mixture to the base of water coning zone.
It is also an object of the present invention to provide a gelling composition forming a gel that can be manipulated to rise or drain depending on its density so that it can be used as a cover for the body of water. It is another object of the present invention to provide a process for controlling the rate of the gelling composition migration by density differences between gelling compositions and formation brines.
The advantage of the invention is that the cover for the body of water can further be improved by adding a foaming surfactant to the gelling composition by bubbling a suitable gas through the composition to produce a foaming gel which is useful as an evaporation barrier.
Another advantage of the present invention is that dense gelling systems can be used to coat the bottom of disposal ponds to prevent seepage of hazardous materials. A further advantage of the present invention is that the gelling systems can be used in the bottom portions of producing or injection wells.
According to the present invention, a process for controlling the migration of a gelling mixture for enhanced oil recovery by blocking water or gas coning comprises injecting a gelling mixture into a subterranean formation where the density of the gelling mixture is adjusted to be higher than the density of the formation brine or lower than oil.
Detailed Description of the Invention According to the present invention, a process for controlling the migration of a gelling composition for blocking water or gas coning in a producing or injection well comprises injecting a gelable composition into the formation and the gelling composition forms a gel in the subterranean formation; wherein the density of the gelling composition is adjusted depending on the density of the formation brine.
All soluble and gellable polymers that are suitable for high salinity formation temperature (preferably acrylamide-containing polymers) or monomers which form gels in-situ upon being injected in the formation can be utilized in the present invention. It is presently preferred, however, that the polymer have a molecular weight of at least about 100,000 and more preferably 100,000 to 20,000,000. The upper limit is not critical as long as the polymer is still soluble and can be pumped into the formation. The term "soluble" used herein refers to those polymers, and monomers that are soluble or dispersible in water or a suitable medium such as oil.
The presently preferred class of acrylamide-containing polymers are those selected from the group consisting of homopolymers of acrylamide, homopolymers of methacrylamide, copolymers of acrylamide and acrylic acid, copolymers of acrylamide and potassium acrylate, copolymers of acrylamide and sodium acrylate, copolymers of acrylamide and N,N-dimethylacrylamide, copolymers of acrylamide and methacrylamide, copolymers of acrylamide and sodium 2-acrylamido-2-methylpropane sulfonate, copolymers of acrylamide and N-vinyl-2-pyrrolidone, terpolymers of acrylamide, N,N-dimethylacrylamide and 2-acrylamido-2-methylpropane sulfonate, and terpolymers of acrylamide, N-vinyl-2-pyrrolidone, and sodium 2-acrylamido-2-methylpropane sulfonate. The ratio of the monomers in the above-described polymers is not critical; provided however, that at least 5 mole % of acrylamide or methacrylamide is present in the above-described polymers.
Particularly preferred are homopolymers of acrylamide, copolymers of acrylamide and sodium acrylate, copolymers of acrylamide and sodium 2-acrylamido-2-methylpropane sulfonate, copolymers of acrylamide and N-vinyl-2-pyrrolidone, and a terpolymers of N-vinyl-2-pyrrolidone, acrylamide and sodium 2-acrylamido-2-methylpropane sulfonate. However, other polymers with more subunits may also be utilized in the practice of this invention.
Additionally, within the scope of this invention is the use of combinations of homopolymers, copolymers, terpolymers, and tetrapolymers utilizing the above listed monomers.
Other suitable polymers are polysaccharides such as xanthan, glucans, cellulosic materials, and mixtures thereof.
Presently preferred monomers that form gels in-situ upon being injected into the wells include, but are not limited to acrylamide, N-vinyl-2-pyrrolidone, sodium 2-acrylamido-2-methylpropane sulfonate, N,N-dimethylacrylamide, acrylic acld, alkali metal salt of acrylic acid, and mixtures thereof. A presently preferred crosslinking system in-cludes, but is not limited to phenol and formaldehyde; resorcinol and formaldehyde; furfuryl alcohol and formaldehyde; and mixtures thereof.
The polymers or monomers that form gel in-situ are generally present in the composition in the amount of from about 0.05 to about 10 weight percent, preferably from about 0.1 to about 5 weight percent, and most preferably from 0.2 to 4 weight percent. The concentration of poly-mer in the composition depends to some degree upon the molecular weight of the polymer. A high molecular weight results in a higher viscosity of the resulting gel for a particular concentration of polymer.
Water generally makes up the rest of the inventive composi-tion.
An aqueous solution containing the water soluble acrylamide-containing polymer having a density higher than the formation brine density can be pumped into the formation so that it forms gel in the formation in a desirable location of the formation so that water coning can be blocked.
The nature of the underground formation treated is not critical to the practice of the present invention. The composition of the present invention can be used in or can be injected into, fresh water, salt water, or brines, as well as at a temperature range of from about 70F to about 400F, preferably from about 150F to about 350F, and most preferably from 200F to 300F. However, at temperatures higher than 170F, homopolymers of acrylamide and copolymers of ac-rylamide and an alkali metal salt of acrylic acid are not suitable.
7 20967~4 -For temperatures lower than 170F, homopolymers of acrylamide, copolymers of acrylamide and an alkali metal salt of acrylic acid can be used in combination with a suitable crosslinking system.
The following specific examples are intended to illustrate the advantages of this invention, but are not intended to unduly limit this invention.
Example I
This example demonstrates that a gel can be formed in a different location in a simulated brine depending on its buoyancy, relative to the brine.
The runs were carried out by injecting 1/3 pore volume (PV) of a gelling mixture containing 5.7% Pfizer Oil Field Products Floperm 325 (prepared by mixing 10.0 g Floperm 325 R (a resorcinol solution), 6.76 g of Floperm 325 F (formaldehyde solution)~ 3.75 g of Floperm 325 S-II (a salt mixture of aqueous sodium chloride/potassium chloride in 10/1 ratio) and 79.49 g of water. The pH of this solution was adjusted to 9.0 by Floperm 325 C (a sodium hydroxide solution) before injection into a horizontal sandpack containing brines with different densities as shown in Table I below. The injection was made through a horizontal injection port located on the side of the sandpack at a point near the middle.
h h ~V rV al r~ r~o X r~ r.
~ Z
3 ~: r~ L~ ~D
O ^
P~
rJ
P~ h ~d ~, ~
r~o ~o r.~ ~o O
rc~
r~ a ~ I rC ~
, rn r,~ ~
rV rD - ~
~ O
p~ ~ r~o ~r~ r~ rn ~
bO O ,r~ lO rn ~D
r.~l o ~r.~ ,1 rn O O ~1 0 rd ~V
PC OO OO r-l rr~
~H I + + I +
rD O r.~
r ~ ~;
a~ ~
`D rl r.~ 3 r--l o rc I
rD r.~ ~ oo c~ . h ~; r~ ~ o r~ rV
r~ D r~ 3 r~ o ~ o~ ~
rr ~
rD ~ or~~ ~ O rV
~d h t rn r~~
r~ ~1 ~,. E~
rr O O O O
rX r.~ooo r~o rn rV O O O O
r~ ~ rD
~I r--lr-l r~l p ~9 Lq rn 1~ rn r-l rD
h ~,1 h rD O h rV) r7 r~ a~ 3 ~ P 3 , rn rC~P¢ a~o ¢ ~ d ~Vr:n r~ ~~D
rl rV ~r,!~ + ;~r~ r!~ 3 U rl rl~:1 rD rl ' r~
a h ~ ~ a~o ~
~ m u~a~,l ou~ -~10 ~-I O
r ~ ,~~Irc~
rn ~ rn o Z p O ¢
Z 11 r~ ~
~r.~ ~ OC!~ un r~ ~dZ,~ r.) In runs 1, 2 and 4, gels were formed in the bottom of the sandpack. In run 3, however, the lower density gelling solution floated to the top and produced a layer of gel.
The above results indicate that the gel can be manipulated to rise up or drain depending on its density. Should there be a case where upper zone needs isolation a low density gel can be used. In the case of gas coning into oil zone, a gelling mixture in a light hydrocarbon solvent could be injected. Because of its lower density, the gelling mixture should float on the top of oil and block gas coning once set into a gel. The rate of gelling mixture migration can be controlled by the density difference.
Example II
In one run (run 5, Table II), 1/3 pv of a gelling mixture of 2% low molecular weight polyacrylamide (Allied Colloids DP9-3976) in synthetic seawater with 500 ppm Na2Cr2O7.2H2O and 2,500 ppm Na2S2O3.sH2O, was injected from the top of a vertical sandpack which contained a 20-30 mesh Ottawa sand and had been flooded with Bartlesville, Oklahoma tap water. The synthetic seawater contained the following:
NaHCO3 3.69 g Na2SO4 77.19 g NaCl 429.00 g CaClz-2H2O 29.58 g MgC12-2H2O 193.92 g distilled H2O bring to 1.0 1 The sandpack which was at room temperature was shut in for gelation.
Because of the higher density (1.0235g/mL vs. 1.0 g/mL), the gelling mixture moved to the bottom of the 30.5 cm pack and formed a gel about 14.8% of total volume of the pack. The lower volume (14.8% vs. 33.3%) of the gel might be due to dilution with water in counter current flow.
This would not be a problem in an actual well treatment which would allow the residence brine to move up around the sinking gelling mixture.
Three similar runs (6-8) were performed in glass beads packs flooded with Bartlesville, Oklahoma tap water. The gelling mixtures were 5.7% Pfizer Floperm 325 in Bartlesville tap water with a density of 1.018 g/mL. The results are summarized in the following Table II.
Table II
Delay Ave. Perm Time Location Run No. Packing Material (darcy) (days) of Gel Ottawa Sand, 20-30 mesh 56.8 12 14.870 volume in the bottom 6 Glass Beads, 40-50 mesh 26.6 22 6.6% volume in the bottom 7 Glass Beads, 40-50 mesh 17.0 10 16.7% volume in the bottom 8a Smaller glass beads 6.6 10 mostly on top aA by-pass line from the bottom to the top of pack avoided counter current formation.
The gel time was too short for the slow moving mixture to sink down before setting.
The data in run 8 indicate that for a glven reservoir, the gel time should be long enough to allow the gelling mixture to move to the desired location before setting.
These examples describe a gel placement strategy which is beneficial in many oil field operation. The gel density is manipulated to be lower or higher than the residence fluids for placing the gel in a desired locatlon. For example, if the object is to block water coning 1l- 20967~4 in subterranean formations, it would be better to use a slow gelling mixture with a density higher than the residence brine. This will allow the gelling mixture to sink into the bottom of the cone and blocking a larger area for a given gel volume than a gelling mixture with the same density as the residence brine which would block a smaller area for the same volume. Another application of the higher density gel can include blocking of the bottom portions of injection or producing wells. Yet another application for the higher density gels can include the treatment of disposal ponds containing hazardous waste materials to prevent the seepage of these hazardous materials.
Since the gelling system with a density lower than water will float on top (run 3, Table I), these systems can be used to make a gel cover for a body of water. One can include a foaming surfactant in the lighter gelling compositions to produce floating foam gels which can be used as an insulator against heat loss for a body of water, such as in a solar pond.
Gelling solutions with densities lower than oil can be injected into a gas coning well. These solutions should float on the top of oil and set into a gel blocking the gas from flowing into the oil zone.
The results shown in the above examples clearly demonstrate that the present invention is well adapted to carry out the objects and attain the ends and advantages mentioned as well as those inherent therein. While modifications may be made by those skilled in the art, such modifications are encompassed within the spirit of the present invention as defined by the specification and the claims.
Claims (14)
1. A process for controlling the migration of a gelling composition for enhanced oil recovery by blocking water coning comprising injecting a gelling composition having a density higher than a subterranean formation brine into said subterranean formation.
2. A process according to claim 1 wherein said gelling composition comprises a water-soluble acrylamide-containing polymer suitable for high salinity formations.
3. A process according to claim 2 wherein said acrylamide-containing polymer is polyacrylamide.
4. A process according to claim 2 wherein said acrylamide-containing polymer is a copolymer of acrylamide and N-vinyl-2-pyrrolidone.
5. A process according to claim 2 wherein said acrylamide-containing polymer is a copolymer of acrylamide and sodium 2-acrylamido-2-methylpropane sulfonate.
6. A process according to claim 2 wherein said acrylamide-containing polymer is a terpolymer of acrylamide, N-vinyl-2-pyrrolidone, and sodium 2-acrylamido-2-methylpropane sulfonate.
7. A process according to claim 1 wherein said gelling composition comprising at least two monomers that form gels in-situ upon being injected in said formation.
8. A process according to claim 7 wherein said monomers are selected from the group consisting of acrylamide, N-vinyl-2-pyrrolidone, sodium 2-acrylamido-2-methylpropane sulfonate, N,N-dimethylacrylamide, acrylic acid, alkali metal salts of acrylic acid, and mixtures thereof.
9. A process according to claim 1 wherein said gelling compositions comprises crosslinkable monomer pair selected from phenol-formaldehyde, resorcinol-formaldehyde, furfuryl alcohol-formaldehyde, and mixtures thereof.
10. A process according to claim 9 wherein said crosslinkable monomer pair is resorcinol-formaldehyde.
11. A process according to claim 1 wherein said injecting is carried out in said formation having a temperature of from about 70°F to about 400°F except when homopolymers of acrylamide and copolymers of acrylamide and an alkali metal salt of acrylic acid are used.
12. A process for controlling the migration of a gelling composition wherein said gelling composition having a density higher than a residence brine is applied in a waste treatment disposal pond to prevent the seepage of hazardous waste materials.
13. A process for controlling the migration of a gelling composition for enhanced oil recovery by blocking gas-coning comprising injecting a gelling composition having a density lower than oil in a subterranean formation.
14. A process according to claim 13 wherein said gelling composition having a density lower than residence brine is applied in a solar pond to prevent loss of heat and evaporation of water.
Applications Claiming Priority (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US07/904,283 | 1992-06-25 | ||
| US07/904,283 US5259453A (en) | 1992-06-25 | 1992-06-25 | Blocking water coning in oil and gas producing reservoirs |
Publications (2)
| Publication Number | Publication Date |
|---|---|
| CA2096764A1 CA2096764A1 (en) | 1993-12-26 |
| CA2096764C true CA2096764C (en) | 1996-08-06 |
Family
ID=25418879
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA002096764A Expired - Fee Related CA2096764C (en) | 1992-06-25 | 1993-05-21 | Blocking water coning in oil and gas producing reservoirs |
Country Status (4)
| Country | Link |
|---|---|
| US (2) | US5259453A (en) |
| EP (1) | EP0577010A3 (en) |
| CA (1) | CA2096764C (en) |
| NO (1) | NO303507B1 (en) |
Families Citing this family (21)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US5270382A (en) * | 1992-04-24 | 1993-12-14 | Phillips Petroleum Company | Compositions and applications thereof of water-soluble copolymers comprising an ampholytic imidazolium inner salt |
| US5476145A (en) * | 1994-05-10 | 1995-12-19 | Marathon Oil Company | Selective placement of a permeability-reducing material in a subterranean interval to inhibit vertical flow through the interval |
| US5421410A (en) * | 1994-07-08 | 1995-06-06 | Irani; Cyrus A. | Plugging of underground strata to eliminate gas and water coning during oil production |
| US5682951A (en) * | 1995-12-07 | 1997-11-04 | Marathon Oil Company | Foamed gel completion, workover, and kill fluid |
| CA2212977C (en) * | 1996-08-20 | 2003-03-18 | Cyrus A. Irani | Method for plugging gas migration channels in the cement annulus of a wellbore using high viscosity polymers |
| US5916122A (en) * | 1997-08-26 | 1999-06-29 | Na Industries, Inc. | Solidification of aqueous waste |
| US6350380B1 (en) | 2000-10-03 | 2002-02-26 | Joseph G. Harrington | In situ immobilization within density variant bodies of water |
| GB0306333D0 (en) | 2003-03-20 | 2003-04-23 | Advanced Gel Technology Ltd | Restricting fluid passage and novel materials therefor |
| US8088716B2 (en) | 2004-06-17 | 2012-01-03 | Exxonmobil Upstream Research Company | Compressible objects having a predetermined internal pressure combined with a drilling fluid to form a variable density drilling mud |
| WO2007145731A2 (en) | 2006-06-07 | 2007-12-21 | Exxonmobil Upstream Research Company | Compressible objects combined with a drilling fluid to form a variable density drilling mud |
| US20050284641A1 (en) * | 2004-06-24 | 2005-12-29 | Baker Hughes Incorporated | Controlled variable density fluid for wellbore operations |
| EP2035651A4 (en) | 2006-06-07 | 2009-08-05 | Exxonmobil Upstream Res Co | Method for fabricating compressible objects for a variable density drilling mud |
| EP2038364A2 (en) | 2006-06-07 | 2009-03-25 | ExxonMobil Upstream Research Company | Compressible objects having partial foam interiors combined with a drilling fluid to form a variable density drilling mud |
| US8657005B2 (en) | 2010-04-30 | 2014-02-25 | Exxonmobil Upstream Research Company | Systems and methods for hydraulic barrier formation to improve sweep efficiency in subterranean oil reservoirs |
| CN104046344B (en) * | 2013-03-13 | 2017-06-06 | 中国石油天然气股份有限公司 | Oil-field flooding shake gels plugging agent |
| CN105332672A (en) * | 2015-11-17 | 2016-02-17 | 中国石油集团长城钻探工程有限公司 | Multi-element composite water-control oil-enhancement method for extracting oil |
| US10408032B2 (en) | 2016-09-28 | 2019-09-10 | Saudi Arabian Oil Company | Wellbore system |
| US11326435B1 (en) | 2021-01-11 | 2022-05-10 | Quidnet Energy, Inc. | Method and materials for manipulating hydraulic fracture geometry |
| CN113404459B (en) * | 2021-07-13 | 2022-07-22 | 西南石油大学 | Selective water plugging method for bottom water gas reservoir high-water-content gas well |
| CN113464087B (en) * | 2021-07-29 | 2022-12-06 | 西南石油大学 | Selective water plugging method for bottom water reservoir high-water-cut oil well |
| US11739620B1 (en) | 2022-02-18 | 2023-08-29 | Saudi Arabian Oil Company | Methodology to improve the efficiency of gravity drainage CO2 gas injection processes |
Family Cites Families (24)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US3297088A (en) * | 1963-12-30 | 1967-01-10 | Gulf Res & Devclopment Company | Process for preventing the coning of an undesirable fluid into a production well |
| US3404734A (en) * | 1967-04-17 | 1968-10-08 | Shell Oil Co | Method of plugging formations by in situ chemical means |
| US3695356A (en) * | 1970-09-15 | 1972-10-03 | Marathon Oil Co | Plugging off sources of water in oil reservoirs |
| US3733833A (en) * | 1971-08-30 | 1973-05-22 | Dow Chemical Co | Plugging of permeable materials |
| US3866682A (en) * | 1972-10-12 | 1975-02-18 | Mobil Oil Corp | Process for controlling water and gas coning |
| DD104951A1 (en) * | 1973-05-30 | 1974-04-05 | ||
| US4138992A (en) * | 1975-07-21 | 1979-02-13 | Shaffer Lloyd H | Viscosity stabilized solar ponds |
| US4418755A (en) * | 1979-02-14 | 1983-12-06 | Conoco Inc. | Methods of inhibiting the flow of water in subterranean formations |
| US4452227A (en) * | 1982-06-14 | 1984-06-05 | Lowrey Iii O Preston | Active thermal storage using the ground underlying a solar pond |
| US4485875A (en) * | 1983-02-28 | 1984-12-04 | Marathon Oil Company | Process for selectively plugging permeable zones in a subterranean formation |
| CA1258734A (en) * | 1984-06-25 | 1989-08-22 | Roger C. Zillmer | Gel and process for preventing loss of circulation and combination process for enhanced recovery |
| US5030036A (en) * | 1984-11-21 | 1991-07-09 | Isl Ventures, Inc. | Method of isolating contaminated geological formations, soils and aquifers |
| US4584327A (en) * | 1985-05-24 | 1986-04-22 | Halliburton Company | Environmentally compatable high density drilling mud, cement composition or blow-out fluid |
| US4703799A (en) * | 1986-01-03 | 1987-11-03 | Mobil Oil Corporation | Technique for improving gravel pack operations in deviated wellbores |
| US4662449A (en) * | 1986-01-06 | 1987-05-05 | Texaco Inc. | Method for controlling bottom water coning in a producing oil well |
| ATE83021T1 (en) * | 1987-08-20 | 1992-12-15 | Kuegler Jost Ulrich | METHOD OF SEALING SOIL FORMATIONS, ESPECIALLY FOR MAKING LANDFILLS. |
| US4860830A (en) * | 1988-08-05 | 1989-08-29 | Mobil Oil Corporation | Method of cleaning a horizontal wellbore |
| US5132023A (en) * | 1988-12-19 | 1992-07-21 | American Cyanamid Company | Emulsified mannich acrylamide polymers |
| US4928766A (en) * | 1989-02-16 | 1990-05-29 | Mobil Oil Corporation | Stabilizing agent for profile control gels and polymeric gels of improved stability |
| US5132021A (en) * | 1989-08-11 | 1992-07-21 | American Colloid Company | In situ treatment of waste water to prevent ground water contamination |
| US5002127A (en) * | 1990-02-27 | 1991-03-26 | Halliburton Company | Placement aid for dual injection placement techniques |
| US5105884A (en) * | 1990-08-10 | 1992-04-21 | Marathon Oil Company | Foam for improving sweep efficiency in subterranean oil-bearing formations |
| US5067564A (en) * | 1990-10-12 | 1991-11-26 | Marathon Oil Company | Selective placement of a permeability-reducing material to inhibit fluid communication between a near well bore interval and an underlying aquifer |
| US5159979A (en) * | 1991-10-01 | 1992-11-03 | Mobil Oil Corporation | Method for limiting downward growth of induced hydraulic fractures |
-
1992
- 1992-06-25 US US07/904,283 patent/US5259453A/en not_active Expired - Lifetime
-
1993
- 1993-05-21 CA CA002096764A patent/CA2096764C/en not_active Expired - Fee Related
- 1993-06-24 EP EP19930110097 patent/EP0577010A3/en not_active Ceased
- 1993-06-24 NO NO932335A patent/NO303507B1/en not_active IP Right Cessation
- 1993-06-25 US US08/081,877 patent/US5368412A/en not_active Expired - Fee Related
Also Published As
| Publication number | Publication date |
|---|---|
| US5259453A (en) | 1993-11-09 |
| EP0577010A3 (en) | 1994-05-25 |
| NO932335D0 (en) | 1993-06-24 |
| CA2096764A1 (en) | 1993-12-26 |
| NO303507B1 (en) | 1998-07-20 |
| EP0577010A2 (en) | 1994-01-05 |
| NO932335L (en) | 1993-12-27 |
| US5368412A (en) | 1994-11-29 |
Similar Documents
| Publication | Publication Date | Title |
|---|---|---|
| CA2096764C (en) | Blocking water coning in oil and gas producing reservoirs | |
| US5379841A (en) | Method for reducing or completely stopping the influx of water in boreholes for the extraction of oil and/or hydrocarbon gas | |
| US4031958A (en) | Plugging of water-producing zones in a subterranean formation | |
| US4809781A (en) | Method for selectively plugging highly permeable zones in a subterranean formation | |
| US4569393A (en) | CO2 -Induced in-situ gelation of polymeric viscosifiers for permeability contrast correction | |
| EP0170893B1 (en) | Microbiocidal anionic sequesterants with polyvalent metal cations for permeability correction process | |
| US3762476A (en) | Subterranean formation permeability correction | |
| US4120361A (en) | Method for reducing the permeability of subterranean formations to brines | |
| US3741307A (en) | Oil recovery method | |
| US3965986A (en) | Method for oil recovery improvement | |
| US4785028A (en) | Gels for profile control in enhanced oil recovery under harsh conditions | |
| US3949811A (en) | Method for reducing the permeability of subterranean formations to brines | |
| US3556221A (en) | Well stimulation process | |
| US4940091A (en) | Method for selectively plugging a zone having varying permeabilities with a temperature activated gel | |
| US4630678A (en) | In-situ formation of polyvalent metal ions for crosslinking polymers within carbonate rock-containing reservoirs | |
| US3830302A (en) | Method for improving oil-water ratios in oil producing wells | |
| US4817720A (en) | Method for forming a barrier to fluid flow in an oil formation adjacent to a producing oil well | |
| CA1244584A (en) | Prepartially crosslinked gel for retarding fluid flow | |
| US4657944A (en) | CO2 -induced in-situ gelation of polymeric viscosifiers for permeability contrast correction | |
| GB2262117A (en) | Conformance control in underground reservoirs | |
| US3399725A (en) | Water flooding process for the recovery of petroleum and improved water flooding process | |
| US4095651A (en) | Process for selectively plugging areas in the vicinity of oil or gas producing wells in order to reduce water penetration | |
| EP0136773B1 (en) | Composition for cross-linking carboxyl polymers and the use thereof in treating subterranean formations | |
| US5322125A (en) | Foamed gels to reduce gas coning in matrix environments | |
| US3523581A (en) | Oil recovery process using viscosifier and shear-thickening liquid |
Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| EEER | Examination request | ||
| MKLA | Lapsed | ||
| MKLA | Lapsed |
Effective date: 20110524 |