DE2736277A1 - METHOD FOR TREATMENT OF UNDERGROUND FORMATIONS AND IN PARTICULAR OIL HOLES - Google Patents

Description

Methods of treating subterranean formations and in particular oil wells

The invention relates, and in particular, to a particularly simple method of treating subterranean formations oil wells to stabilize the clay against dispersion and expansion as a result of exposure to water.

The production of petroleum hydrocarbons]! is often disturbed by the presence of clays and other fine particles capable of migration in the formation. Normally, these fine particles, including the clays, are at rest and do not cause obstruction or obstruction of flow to the oil well via the capillary system of the formation. When the fines are disturbed, they begin to migrate in the production flow and often they also narrow the capillaries, where they form bridges and greatly reduce the flow rate.

The means that perturbs the quiescent fine particles is often the introduction of for the formation strange water. The extraneous water is often fresh water or relatively fresh water compared to that in the Formation present saline solution. A change in the water

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can cause the fine particles to come out of their deposits disperse or become free from adhesion to the capillary walls.

Sometimes the loss of permeability or permeability is due to swelling of clay with relatively fresh water with no migration attributable to. However, the swelling of clay is often accompanied by migration of the fine particles. Sometimes you can Non-swelling clays respond to extraneous water and begin to migrate. It is believed that swelling clays are the The main cause for the migration of the fine particles and / or the swelling are, since in the analysis of formation cores the The presence of swelling clays is an excellent indicator that the formation is against the ingress of extraneous water is sensitive, while the presence of non-swelling clays is simply inconclusive.

In general, swelling clays belong to the sraectic group, which includes clay grains such as montmorillonite, beidellite, Includes nontronite, saponite, hectorite and saukonite. Of these clay minerals, montmorillonite is most common in found by analyzing formation cores. Montmorillonite is usually associated with clay minerals known as mixed layer clays are known. For more information, see Jackson's monograph, "Textbook of Lithology," page referenced to 103.

Migrating fine particles comprise a lot of clays and other minerals of small particle sizes, ζ. Β .: feldspars, fine quartz particles, allophane, dadinite, talc, illite, chlorite and the swelling clays themselves. For additional information See Theng's monograph, "The Chemistry of Clay-Organic Reactions", pages 1-16.

Tone can also be used in areas other than bringing down cause trouble of permeability or permeability.

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If they are part of slates, sandstones or other formations, contact with extraneous water or sometimes with any water cause the formation to lose its strength or even falls apart. This is a problem when building foundations, road underlay, drilling wells and in any situation where the strength of the formation plays a role.

There have already been numerous attempts to reduce the negative effects of water on clay and / or other fine particles to control. Most of these attempts took place in the oil industry. One suggestion is to change the tone of the the swelling sodium form (or the rarer, swelling lithium form) into another cation form that is not as strong swells to transform.

Examples of cations, which are relatively non-swelling clays are potassium, calcium, ammonium and hydrogen ions. If a solution of these cations, mixed or individually, When flowing over a clay mineral, they easily replace the sodium ions and the clay turns into a relatively non-swelling one Form converted, see Theng, Tables 2, 3 and 4. The use of an acid, of potassium, calcium or ammonium ions to exchange for sodium ions was successful in preventing damage to formations that opposed are susceptible to clogging or deterioration as a result of clays in their composition.

In the following, the state of the art and individual measures insofar as they relate to the invention, received. For more details, refer to each of the following referenced references, in the present

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Description will only be given to the extent deemed necessary. These. Prior art references are:
US Patents: 2,761,843, 2,801,984, 2,801,985,

2 940 729, 3 334 689, 3 382 924, 3 419 072, 3 422 890,

3 483 923, 3 578 781, 3 603 399, 3 741 307, 3 827 495, 3 827 500, 3 833 718,

Barkraan, J. H .; Abraras, A .; Darley, H.C.H .; and Hill, H.J. ; "An Oil Coating Process to Stabilize Clays in Fresh Water Flooding Operations", SPE-4786, SPE by AIME, Symposium on Formation Damage Control, New Orleans, La., USA, February 7/8, 1974;

Coppel, Claude E .; Jennings, Harley X .; and Reed, M.G .; "Field Results From Wells Treated With Hydroxy-Aluminum ", Journal of Petroleum Technology, (Sept. 1973), pp. 1108-1112;

Graham, John W .; Monoghan, P.H .; and Osoba, J.S .; "Influence of Propping Sand Wettability of Productivity of Hydraulically Fractured Oil Wells ", Petroleum Transactions, AIME, Vol.216 (1959);

Hower, Wayne F .; "Influence of Clays on the Production of Hydrocarbons ", SPE-4785, SPE from AIME, Symposium on Formation Damage Control, New Orleans, La., USA, 7-8 February 1974;

Hower, Wayne F .; "Adsorption of Surfactants on Montraorillonite", Clays and Clay Minerals, Pergamon Press (1970), Vol.18, pp.97-105;

Hoover, M.F .; and Butler, G.B .; "Recent Advances in Ion-Containing Polymers ", J. Polymer Sci., Symposium No. 45, 1-37 (1974);

Jackson, Kern C; Textbook of Lithology, McGraw-Hill Book

Company (1970) j (Library of Congress Catalog Card No. 72-958LO),

Pp. 95-103;

Theng, B.K.G .; The Chemistry of Clay-Organic Reactions, John Wiley and Son (1974) (Library of Congress Catalog Card No. 74-12524), pp. 1-16;

Veley, CD .; "How Hydrolyzable Metal Ions Stabilize Clays To Prevent Permeability Reduction ", SPE-2188, 43rd Annual

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Fall Meeting of SPE of AIME, Houston, Texas, USA (29.9.2.10.1968);

Milchem Incorporated, "Milchem's Shale-Trol Sticky Shale Can't Stop You Anymore ", DF-5-75 1M;

Chemergy Corporation, "Maintain Maximum Production With PermaFIX and PermaFLO Treatments for Clay / Fine and Sand Control.

However, the exchange of other ions for sodium in clay is only a temporary aid. In the preparation of Of a borehole, the presence of sodium ions in the water of the formation allows that sodium ions in turn Hydrogen, potassium, ammonium or calcium ions rapidly substitute. The result is that the clay is converted back to the swelling or dispersible form, so that it is available again for damage if extraneous water is introduced. In the US patent 3,382,924, column 3, lines 45-75 and column 4, lines 1-3 Calcium ions are used to replace the sodium ions in nuclear clays (lines 51-53). The calcium ions protect the Kern (lines 54-57). If treatment is stopped (lines 58-63), the sodium chloride salt solution (Line 64) the calcium ions are in turn replaced and the core is replaced with regard to the flow in stage 7 (lines 65-68) strongly contracted, as indicated in line 75, column 3 and lines 1-3, column 4.

Since simple cations can easily be exchanged again and the treatment is not permanent, have already been Efforts made to avoid treatment with hydrogen, potassium, calcium, or ammonium ions (and probably also some other ions). Anionic, polycationic polymers or complexes were more successful.

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The most prominent of these were ZrOCl ₉ and Al (OH) Cl.

c. χ y

In the aforementioned U.S. Patent 3,382,924 and Veley CD. "How Hydrolyzable Metal Ions Stabilize Clays to Prevent Permeability Reduction" describes the use of ZrOCl ^ in the polycationic form of ZrOCIp, which is explained in this reference. Hydroxyaluminum reaction products of HCl and Al (OH) ,, wherein the formulas of Al (OH) ₁ Cl ₁ ^ ₅ to (Al (OH) ₂ ,, Cl ₀ -, rich, are disclosed in U.S. Patents 3,603,399 , 3,827,495, 3,827,500 and 3,833,718 and in the reference by Coppel, Jennings and Reed, "Field Results From Wells Treated With Hydroxy-Aluminum".

The inorganic, polycationic polymers are complexes that help control the migration of fine particles and swelling clays are very successful. However, there are limitations in several ways. Hydroxy aluminum compounds require post-in-place setting time in the presence of clay. This hardening time is a disadvantage, since assembly and production times are lost during this waiting time. Hydroxy aluminum compounds can only withstand a limited amount of carbonate material in the formation. Hydroxy-aluminum compounds can also be used be removed by subsequent treatment of the formation with acid. Is zirconyl chloride in terms of the pH range of the fluid to be put in place limited and can be removed again by acid under certain conditions. For other types of clay treatments See U.S. Patent 3,741,307.

Another treatment to control the undesirable effects of swelling clays and wandering fine particles is the use of organic, cationic, surfactants. If the organic fraction of the cation is sufficient is large, the organic cation does not easily become

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replaced. For this purpose, reference is made to the references by Hower, Wayne, F. "Influence of Clays on the Production of Hydrocarbons" and "Adsorption of Surfactants on Montmorillonite". Have cationic surfactants however, the tendency for the oil to wet the formation, and this is seen by certain circles as an advantage, see FIG the reference by J.H.Barkman "An oil coating process ..." However, numerous petroleum professionals consider an oil wetting Formation as a disadvantage, since it inhibits the production of oil and accelerates the production of aqueous fluids, see the J. W. Graham reference, "Influence of Propping Sand Wettability of Productivity of Hydraulically Fractured Oil Wells ".

The object of the invention is to avoid the disadvantages of the previously known method and to provide an improved and simple one Process for stabilizing clay and other fine particles against dispersion and expansion as a result of the Find exposure to water.

According to the invention, organic, polycationic polymers used to counteract the deleterious effects of swelling clays and / or wandering, fine particles in earth formations and in particular to prevent or reduce oil wells. For this purpose, an aqueous solution of the organic, polycationic Polymer is allowed to flow behind the clay to be treated until the organic, polycationic polymer replacing the clay ion, usually the sodium ion, and converting the clay into a more stable form, which is a very much is less likely to swell or wander. The organic polycationic polymers of the invention have several advantages. They can be applied to all types of formation regardless of the carbonate content. They are acid resistant, i. H. the formation can later be treated with acid without losing its clay-treating ability to destroy. They are in place in aqueous solutions including a wide range of salt solutions and acids and place. Treatment with organic, polycationic polymers is practically permanent. the

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Il

organic, polycationic polymers are very resistant to removal by salt solutions, oils or acids. Oil wetting of the formation can be avoided. They can be adjusted to withstand the pH range. Furthermore, no setting time is required, and studies have shown that only a time of less than 1 minute is required for complete adsorption on the clay. Formations with very low permeability or permeability can be treated. The retention of high permeability after the treatment of clays and fine particles can be achieved. Adaptation to wide temperature ranges of the formation is possible. The polymers were at temperatures of 21-149 ⁰ C.untersucht, however, it is assumed that the region may be even wider.

There is a wide range of uses for the organic polycationic polymers. These applications include the use of organic, polycationic Polymers alone as a primary treatment agent or as an aid in other treatments.

According to the invention, the application basically comprises a certain class of organic, polycationic polymers and procedures for their introduction. The polymers have a molecular weight above about 1000 and preferably above 1,500 up to about 3,000,000 and preferably less than about 100,000. The organic, polycationic polymers can be used in any earth formation or permeable mass which contains clay and in which swelling of the clay could be a problem. The polymers can be used to treat both naturally and artificially consolidated structures or formations can be applied.

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Any suitable method of application can be used in view of the description given. For some applications, such as surface structures or exposed structures, it can be advantageous to simply spray the polymer onto the permeable mass. The essential feature is the contact between the clay particles to be treated and the polymer. In a preferred embodiment, a carrier fluid is used. A preferred carrier fluid is water or an aqueous medium. The water can contain other ingredients which do not significantly interfere with the dispersion or dissolution of the polymer in the medium. The water carrier can be gelled or thickened for certain applications. Such ingredients or additives may include salts, mineral acids, low molecular weight organic acids, surfactants, wetting agents or coupling agents such as silanes or conventional additives used in consolidation treatments, stimulation treatments or in drilling oil wells. The carrier fluid can also be a normally liquid, polar-substituted hydrocarbon such as an alcohol. A polar hydrocarbon is normally required to satisfactorily disperse or dissolve the polymer within the carrier. Under certain conditions, the polymer can be dispersed or emulsified in a non-polar carrier liquid. The carrier fluid or the carrier liquid preferably has a boiling point in the range from about 25 to 200 ^° C. and a viscosity of less than about 10 cP (centipoise). Higher viscosity fluids can be used for certain applications, but are generally not practical because of the pressure or pumping requirements. The organic, polycationic polymer should be present in the carrier fluid in a concentration within the range from about 0.01 to 25% by volume, based on the carrier fluid. Lower or higher concentrations can be used

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can be used, but they are generally not practical.

A preferred aqueous carrier fluid is a saline solution containing from about 0 to 40% salt or up to the saturation limits at the temperature of use. The preferred salt concentration is about 2 to 12% by weight, but concentrations up to about 35 % can be used, as can fresh water. The salt can be an alkali metal salt, alkaline earth metal salt, ammonium salt, or a mixture thereof. Such salts include the halides, sulfates, carbonates, oxides, or mixtures thereof. The halides of potassium, sodium, magnesium, calcium, ammonium, or mixtures thereof are preferred in terms of economy and solubility. Aqueous acids at approximately the same concentrations can also be used. These acids include hydrofluoric acid, hydrochloric acid, nitric acid, phosphoric acid, sulfurous acid and sulfuric acid. Low molecular weight organic acids such as acetic acid and sulfonic acids can also be used under certain conditions. Conventional additives such as inhibitors, surfactants, coupling agents, wetting agents and other agents can be employed where desired and particularly in cases of using the organic polycationic polymer in conventional treatment procedures. The carrier fluid preferably contains salts or acids which cause shrinkage or prevent swelling until the polycationic polymer has treated the clay particles. Typically, treatment occurs virtually immediately upon contact between the formation and the treatment fluid. The carrier fluid and the formation are created by injecting the carrier fluid into the formation, applying the fluid to the formation, or flowing the fluid through the formation and past the formation, respectively

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in such a way that minimal disruption or Suspension of individual particles within the formation is brought into contact. The treatment procedure according to the invention is therefore particularly advantageous, when the permeability is low and maintaining a maximum permeability or permeability is a critical characteristic.

In chemical injection operations such as sealing leaks in dams, mines, tunnels, foundations and the like, see U.S. Patents 2,940,729, 2,801,984, 2,801 and 5 334 689 - there are cases when the permeability decreases and the formation refuses to accept chemical injector. This is usually done by the Disturbance of the pH value or caused by osmotic disturbances, caused by the introduction of an extraneous water (chemical injection agent) into the formation. By Pretreatment of the injection hole with an organic, polycationic The permeability of the polymer can be retained; so that sufficient chemical injection agent is injected and can spread in a sufficiently large radius to seal leaks.

When creating gas, oil and / or water boreholes a common problem is the collapse of the soft formation around the wellbore and production of sand. Since the production of sand is very undesirable, several means have been used to stop sand production suggested a means is the gravel or gravel packing. Gels and / or salt solutions are applied to the gravel or Gravel, usually classified sand or particulate material, in place around the borehole to wash the production break.

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1h

One way of working is the gravel or crushed stone or Sand settled and compacted. A lining or a sieve is then flushed into the borehole and arranged across the formation. The fluff sand now holds back the formation sand and the sieve holds the Packsand back. This enables the production of fluids that are free of sand. If the gravel or crushed stone, however is pumped in place, the loose solids of the formation are forced back and form a compaction front between the formation and the packing sand. This front, especially if it contains clays, often limits the Flow of fluid into the wellbore after the gravel pack is in place. the Use of organic, polycationic polymers in a pre-rinse in the carrier fluid for the gravel or Ballast packing or in a fluid after the ballast or gravel packing is in place, can the Switch off loss of permeability in the compaction front or make it less severe. Furthermore, organic, polycationic polymers, which over the neighborhood the gravel or crushed stone packing was washed out, the migration of fine particles into the gravel or crushed stone packing such fine particles often clog the gravel pack.

Hydraulic fracturing with sand or the sand packing of any cavity can be a gravel packing be similar except that the grain size can be different. The use of organic, polycationic Polymers in connection with a sand fracturing ring gives the same favorable result.

During sand consolidation or consolidation, hard, hardening resins for gluing grains of sand together

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used. The formation sand itself can be treated in this way or it can be a sand coated with a pre-resin as. Sand packing can be used. The use of organic, Polycationic polymers in connection with a sand solidification can prevent the back migration of fine Prevent particles and clays in the bulk of the sand solidification and prevent the clogging effect of a compaction front, if one should form, reduce.

In secondary recovery processes where water flushes or Water flooding to be used for the extraction of oil is the only water available for injection into the injection wells is likely to swell clay and / or migration of fine particles which can clog the injection wells. One Pretreatment of injection wells with organic, polycationic polymers before flooding with the suspect Water can prevent damage from migration of fine particles and swelling of clay. This is in the the immediate vicinity of the borehole, where the permeability is very important, of particular importance. The treatment can be used to improve the water wetting properties a formation or any reduction in oil permeability in any one Prevent formation as a result of oil wetting of the formation where clay could be a problem.

Certain formations, together with substances that are removed or weakened by contact with water, naturally cemented or consolidated. As long as only hydrocarbons are produced, there are wells in these wells little trouble. However, if the water level is in Course of production increases and the water along with

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When the hydrocarbons are extracted, the production or extraction of sand begins. Sometimes the situation is so bad that a collapse of the borehole is the result. If the material for cementing the formation is clay, treatment of the vicinity of the borehole can be made the water breakthrough the production of sand and / or that Prevent the drill hole from collapsing.

When lining oil and gas wells, it is necessary to perforating the enclosure or a portion of an open hole below the enclosure or to drill the casing to complete the borehole and begin production. An accident in this one Well completion operation is when the fluid in the wellbore affects permeability as it often invades the formation when it is opened. The borehole can be an open borehole or through Perforation can be completed using shaped charges or spheres. As part of the completion fluid organic, polycationic polymers have the purpose of preventing damage to the permeability, if the pressure in the wellbore becomes higher than the formation pressure and the wellbore fluids enter the formation.

Acidification is a common technique in the art
Improvement of well production. Acid is pumped into the formation for the purpose of enlarging the pores and therefore increasing the permeability.
Often hydrochloric acid becomes in carbonate formations
such as limestone and dolomite, and hydrofluoric acid solutions are often used in sandstone formations. However, in some formations, acid treatment loosens the fine particles, causing them to migrate and clog

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cause. A feature of these formations is that acidification improves production, but a decrease occurs the production rate soon increases as fine particles migrate to clogging positions. The use of organic, polycationic Polymers before, during and / or after the acidification brings on the promotion of fine particles a minimum.

Hydraulic fracturing is another common technique in the art for improving well production. The wellbore is pressurized until the formation bursts and the resulting fracture sets large areas of conveying formation area free. The cracks are usually caused by growing together by pumping sand into them prevented the break. However, fracturing fluid that penetrates the fracture surface often interacts with the clays and deteriorates the permeability. This damage is particularly critical when the permeability is low, i.e. H. at Values from about 10 millidarcy to 0.1 millidarcy. The use of organic, polycationic polymers in conjunction with breaking operations has proven to be very successful.

It is far better to prevent damage from swelling clays and / or wandering fine particles than that Correct or repair damage as it occurs. Much of this damage is irreversible. In the cases In which damage has already occurred, however, the use of organic polycationic polymers can be used as the primary treatment agent in conjunction with other treatments, much of the lost permeability bring back.

During the drilling process there is often trouble with boreholes, especially with air- and gas-drilled boreholes

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by the swelling and swelling of fort nations, which be penetrated by the borehole. These formations contain clay minerals that when wetted with aqueous Fluids such as fog or foam drilling cause the formation to slide, which often creates the risk of a Sticking of the drill chain and / or the drill bit in the Drilling is caused. Some of these formations will be in the field as "mud slate" (gumbo shale) designated. The treatment and / or impregnation of these formations with the compositions according to the invention can avoid the risk of swelling or swelling of the formations. The treatment can also be used during drilling operations or closure operations are used where two-phase fluids, such as emulsions, foam, mist, smoke or gaseous dispersions, haze or slurries can be used.

The organic, polycationic ones used according to the invention Polymers can generally be used as quaternary polymers with nitrogen or phosphorus as the quaternary or cationic Atom in an aliphatic, cycloaliphatic or aromatic chain. Tertiary sulfur can replace the quaternary nitrogen or phosphorus in the polymers. The ratio of cationic atoms to carbon atoms is preferably about 1: 2 to 1: 36 and the molecular weight is above about 1000. The organic, Polycationic polymer is polar and therefore it is generally like in polar solvents or carrier fluids soluble or easily dispersible in an aqueous medium or in an alcohol. An alcohol can be used as the carrier fluid if contact between water and the permeable mass or formation to be treated is to be avoided. Examples of these polycationic polymers include

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Polyethylene amines, polyvinylpyridiniurasalze or Polyallylaramoniumsolze.

Preferred organic polycationic polymers according to of the invention can be characterized and explained by the following formulas and examples:

Γ ²

Ζ —R.

where mean:

R. = an organic, aliphatic, cycloaliphatic or aromatic radical with 2 to 40 carbon atoms or a hydrogen radical, and if R ^ is a cyclic, aliphatic radical, Z and R ₂ can belong to the ring;

R ₂ , R, and R ^, = organic radicals according to the definition of R ,, which contain up to 6 carbon atoms and 0 to 2 oxygen or nitrogen atoms, where when Z = sulfur, R ^ is not present;

Z = a cation derived from nitrogen, phosphorus or sulfur;

X = an anion such as halogen, nitrate or sulfate ion;

η = an integer equal to the number of monomer units in the polymer; and

m = an integer equal to the number of anions required to maintain electrical neutrality.

The organic radicals or hydrocarbon radicals can be straight-chain, branched or cyclic, aliphatic radicals,

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-Y-

aromatic radicals, unsaturated radicals, substituted radicals or combinations thereof. The organic residues can be horaoaliphatic or heteroaliphatic, d. H. they can contain other atoms such as oxygen or nitrogen or also not included. The organic radicals can be homocyclic or heterocyclic; H. they can like other atoms Contain or not contain oxygen or nitrogen. Furthermore, the organic radicals can be substituted or unsubstituted alkyl radicals, aryl radicals or combinations thereof, with each remainder up to 40 and preferably up to contains up to 6 carbon atoms.

The following compounds are examples of the preferred polycationic polymer classes:

(1) If Z = sulfur, a sulfonium polymer:

1 S +

where an example is derived from the following monomer: H ₂ C = CHCO ₂ CH ₂ CH ₂ S (CHx) ₂ CI, poly-2-acryloxyethyldimethyl-

sulfonium chloride; with

R. = 2-acryloxyethyl, R ₂ = methyl, R, = methyl, R ^ = not available and X = chloride;

(2) if Z = phosphorus, a phosphonium polymer:

R,:

^R r ~? ^R 3 I ■ <

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wherein an exemplary monomer is H 1 C 1 -C 4 CH-CH glycidyltributylphosphonium chloride; with R ₁ = glycidyl, R ₂ = butyl, _{R 1 = butyl, R 4} = butyl and X = chloride;

(3) when Z is nitrogen, quaternary ammonium polymers;

(3a) being an example of a quaternary, integral alkyl polymer is:

CH.

CH ₀ —CH = —N-

^{2 2} I.

CH.

Cl

Polydimethylethylene ammonium chloride, and another example of a polymer:

CH ₃ OSO ₃ -

CH.

CH.

. _ Ν— CH ^ —CH ^ Ν ± —CH-jCH-2 CH ^ CH,

CH.

namely the condensation product of Ν, Ν, Ν ¹ , N'-tetramethylethylenediamine and Λ , 4-bichlorobutane;

(3b) Compounds with the quaternary nitrogen atom built into the cyclic ring, with an example of a Polymer is:

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_Y n

the condensation product of 4-chloropyridine;

(3c) Connection with the integral in the alkyl chain and the aryl radical, quaternary nitrogen atom, being an exemplary Polymer is:

the condensation product of 1- (4-pyridyl) -3-chloropropane; and another example of a polymer:

Cl

N-CH ₂ -CH ₂ -

the condensation product of pyrazine and 1,2-ethylene dichloride;

(3d) compounds with pendant quaternary alkyl groups, where an example is the following polymer:

Polyvinyl trimethyl ammonium chloride,

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SiS

(3e) Compounds with quaternary groups attached to a cyclic backbone, an example of a such polymer is:

Poly-1,4-phenylene oxide-2-methylene trimethylammonium bromide;

(3f) Compounds having quaternary groups attached to a carbocyclic ring, an example of which is a such polymer is:

Polyvinyl-4-benzyltrimethylammonium chloride;

(3g) Compounds with quaternary nitrogen groups attached to a polymethacrylate skeleton, one example being for such a polymer is:

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CH ₂ -C

C = O 0

Cl

OH

CH.

-N-CH

CH.

Foly-J-methacryloxy-CP-hydroxypropyltrimethylammonium chloride);
and another example of such a polymer is:

/ -! ti / -lit 2 " ^CH 2 -CH ₂ Cl 3 η 2 ι N ^{+ V} CH ι
C = O
I. CH ₃ CH ₃ ι
H-N-CH

Polyacrylamido-1-propy1-3-trimethylammonium chloride;

(3h) Compounds having quaternary nitrogen groups pendant from a heterocyclic ring, an example being for such a polymer is:

CH ₂ -CH

CH

Poly-4-vinyl-N-methylpyridinium iodide; 809807/0839

(3i) Compounds having a heterocyclic ring which contain quaternary nitrogen groups, an example being for such a polymer is:

CH.

W CH-

CH;

Cl

Polymer of diallyldimethylammonium chloride.

The invention is explained in more detail in several embodiments with reference to the following examples, all of the information in Parts, percentages, ratios and concentrations, unless otherwise specified, are expressed by weight are.

Examples

The test procedure for polycationic polymers is explained in more detail below:

Test cell composition

The polycationic polymers were examined in a simulated formation, which sand, fine sediments and Contained clay. The test cell was packaged by inserting a single-pierced gourami stopper into a glass tube. To prevent sand from falling through, a sieve made of wire mesh was covered with a thin layer of glass wool coated and attached to the top of the at the bottom

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of the glass tube inserted stopper arranged. Next was to prevent clogging of the screen the sand pack packed a layer of sized sand on top of the plug and screen. The next Layer was the sand pack, with the sand pack being the test medium. It was packed in a moist state so that the sand, the fines and the clay adhered to one another in such a way that the formation of layers of the packing was avoided. Finally, a layer of pure sand was overlaid to protect the sand pack from particulate contamination the two lower layers applied.

The sand packing consisted of 85% by weight of the pure sand (Oklahoma sand No. 1) with a mesh size of 0.21-0.088 mm, 10% by weight of quartz with a mesh size of < 0.053 mm, 5% by weight of montmorillonite (Wyoming bentonite) with a surface area of about 750 m ² / g and 0.75 ml Sa]
bare moisture was sufficient.

about 750 m / g and 0.75 ml of salt water, what a noticeable

The cell dimensions were: inner diameter of the tube 2.32 cm,

ο inner cross-sectional area of the pipe = 4.23 cm; Sand packing column height = 8.04 cm; Tube volume (sand packing area) = 33 »09 car; Porosity = about 30 % and the height of the column of pure sand (Oklahoma sand # 1) (both the top and bottom columns) = 1.51 cm.

The test cell composition became constant from test to test maintained. The values given above are the mean values of several cells from consecutive Test examinations.

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Average values for some flow rates on test cells

temperature Flow rate
(ml / min) Test sequence or working method flowing + K = 140.5 md 25.9 15.67 + step 62.5 24.25 95.5 41.50 Fluid

1 standard saline solution

2 treatment solution 5 standard saline solution

4 fresh water

5 15% HCl

6 fresh water

7 diesel oil

8 fresh water

9 diesel oil

The initial stage of using standard saline was to calibrate the sand pack. As fresh water tap water was used. Fresh water and deionized water are used in terms of their properties Clay swell roughly equivalent and they are the critical test of whether a step in the treatment of clay was effective or not.

The treatment stage with 15% HCl was used for the test permanent action of clay treatment chemicals in the presence of acid.

The stages diesel oil-fresh water-diesel oil were used for the investigation the longevity of the clay treatment chemical

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in the presence of oil. If the diesel oil rate is higher as the water rate, the system was considered to be wetted by water.

Composition of the standard salt solution

salt Wt% NaCl .7.5 CaCl ₂ 0.55 MgCl _? .6H _? 0 0.42 water 91.53 Pressure and temperature

A pressure of 3.52 atu was used during all treatment stages maintained on the reservoir.

The reservoir had a heating mantle which maintained the desired temperature for the test liquids. On the A heating tape was used in the test cell.

Berea kernels were used in a Hassler pod apparatus, the core and reservoir being heated to the test temperature. The 5.1 cm long core rested on a cushion Sand with a grain size of 0.25-0.42 mm and a height of 1.9 cm and was inevitably soiled by a buffer layer of sand with a grain size of 0.25 0.42 mm at a height of 1.9 cm at the top with a overlying layer of sand (Oklahoma No. 1) protected at a height of 0.64 mm. These layers of sand provided about 2% of the specific resistance of the cell.

Properties of the Berea sandstone core + X-ray analysis average value (%)

Quartz 79.0

Dolomite 4.0

Kaolinite 11.0

Illite 3.7

Mqntmorillonite and 2,3

Mi sensenichttone

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- 37 - Other analyzes 2.8 % 31 Acid solubility 21.96% porosity 2.8 md Permeability

+ This is an average of 16 cores and it is considered representative of that for the test cores used sandstone block.

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Table 1

Names for the clay treatment chemicals and solutions used in the examples

Chemical name

description

Comparing it, it lacked any chemical to treat volume

OHAL Hydroxyaluminum compounds with the following proportions in the examples: AI ^ (OlOi-Cl

ZrOCIp zirconyl chloride, according to analysis = ZrOCl ₂ .8H _? 0

IEI 1olyäthylenimin, a polymer of aziridine

PL) MDAA Polydi methyl dial IyI ammoniumchlor id

SB Ctondard Salt Solution

FW fresh water

TEPA tetraethylene pentamine

EDCA condensate of ethylene dichloride and ammonia

EDCAM condensate of ethylene dichloride and ammonia, sub-treated with methyl chloride

TETA. Triethylenetetraamine

BDCTMDA condensate of Λ , 4-dichlorobutene with Ν, Ν, Ν ', Ν'-tetramethylethylenediamine

DMAECH condensate of dimethylamine with epichlorohydrin

BDMAECH condensate of dimethylarain with epichlorohydrin, branched with ammonia

DMABCD condensate of dimethylamine with 1,4-dichlorobutane HXDA 1,6-hexanediamine

DEAPA diethylaminopropylamiri

TADATO condensate of triethanolamine / diethanolamine / T ₃ 11 oil

TADATOQ TADATO, quelled with CH ₅ Cl

HBEOTO distillate residue from hexanediamine, reacted with ethylene oxide and esterified with tall oil and acidified with hydrochloric acid.

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C0
OD
O

Table II
The clay treatment flow test at 23.9 ⁰ C

E.g. 12 3 4 5 6 7 8 9

Treatment solution

Chemical or polymer. Cf. PDMLAA FEMEAA FBMEAA ΓΕΜΕΑΑ PEMEAA PEMEAA FEMEAA sat

Molecular weight ^b - 37,000 37,000 37,000 37,000 37,000 50,000 75,000

Concentration (%) 0 0 4 2 0.4 0.4 2 2 2 Solvent S3 S3 FW FW FW SB SB SB S3

calibration

Standard saline 14.6 13.4 12.3 13.4 15.2 14.6 14.4 12.6 15.2 (ml / min)

Flow tests (% 2_des
Calibration values

Solution ml

Standard saline solution 500 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0

Treatment solution 300 - - 17.1 23.1 3.5 ^ 80.8 49.3 39.8 31.5

Standard salt solution 500 - _ - 99.2 82.1 5.0 10 ^, 4 102.6 100.0 92.1-

fresh water 500 1.0 - 99.2 88.1 - 68.5 104.2 100.0 61.6

15% HCl 400-70.1 86.1 73.1-71.2 73.6 79.7 82.9

fresh water 500-0.6 94.3 85.1-6 *, 6 91.7 85.9 68.4

a) = A flow was stopped before the full specified volume was delivered

was

b) = Bie molecular weights are given to -10%.

Table III

the temperature and the solvent in the case of organic, polycationic

cal polymers

E.g. ( ⁰ C) 10 62, 1 62, C. Q-z 3 14th • ι 62, C. 62.5 Test temperature 62.5 5 C. 3 62.5 CI
s S 1

Chemical or polymer cf. PLMEAA FDHDAA PDMDAA PDMDAA PDHDAA ΡΞΙ FDMDAA

Molecular weight ^b - 37,000 37,000 37,000 57OOC 37,000 2CC00 37OCO

Concentration (%) 0 2 0.4 0.4 0.4 0.4 0.1 0.4

Solvent SB SB SB SB 15% KC1 15% HC1 i5% ÄCl 3% CaCl ₂

calibration

Standard saline solution (al / min) 23 26 32 38 18 45 ^ 9.6 29.0

§Flow tests _ (_%) _ des
Calibration values

Solution ml

Standard saline solution 500 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0

Treatment solution 3OC - 50.0 90.6 96.1 63.9 62.6 98.0 65.5

Standard saline 500-111.5 106.0 135.5 136.1 113.3 ^ 32.7 75.2

fresh water 500 1.1 ^C 126.9 111.9. 147.0 130.0 120.0 ^ 67.3 82.8

15% HCl 400-40.0 93.8 ^a 39.5-20.0

fresh water 500 - 100.0 156.3 131.5 - - - 79.3

a) = A solution of 3% HF and 12% HCl was used instead of the 15% HCl.

b) = The molecular weights are given within an error limit - 10%. For

PDMDAA is the number average molecular weight given; for FEI is none more precise information available.

c) = The flow investigation was after 100 ml of fresh water as a result of the low Flow rate canceled.

Csbeile IV

Organic, polycationic polymers, which generally consist of alternating Ethyl engrupper. and amine groups

O <D OO O

E.g.

Treatment solution chemical or polymer Mo 1 ekul ρ r gev: i ent Concentration (%) Solvent Solvent pH "value

Calibration standard saline solution (ml / min)

Flow tests (.c?) _ 9.es

Worth seeing

Solution ml

Standard saline solution

Treatment solution JOO

Standard salt solution fresh water 15% HCl fresh water 23

ELCA EDCA 7500 ⁸ 25OCO ^a

0.25 S3

, 28

S3

ZJ.

EDCAK EDCAH

ο ,;

SE
4th

2000 ^l υ, t> SB

S3 4

2 ?,

', ε 23.0 17.2

100.0 80.2

^ 00.9 56.0

120.7

¹ OO, O 59.6 56.7 46.2 31.3 74.5

■ i ^ i?

9B, p

^ 30.6

60.5

100.0 110.8 ^ 02.3 130.7 82.4

100.0 101.7 100.0 35.6 14.8

157.0 210.2 1-14.4

E.g.

Table IV (continued) 24 25 26 27

28

30th

Chemical or Polymer FEI FEI FEI FEI FEI TEFA TETA

Molecular weight 20000 ^c 200C0 ^c 300 ^c 12OO ^C 100C00 ^c 189 146

Concentration (%) 1.0 1.0 0 _r 3 0.3 1.0 1.0 1.0

Solvent SB "<5% HC1 SB SB 15% HC1 SB SB

calibration

Standard salt solution (ml / min) 21.4 25.4 21.4 23.5 21.9 22.6 26.2

Solution ml

Standard saline solution 500 100.0 100.0 100.0 100.0 100.0 100.0 100.0

Treatment solution 300 7.5 51.2 123.8 102.1 11.4 115.0 139.8

Standard saline solution 500 6.1 70.0 126.2 110.6 25.1 95.1 _e 114.5

fresh water 500 - 94.5 146.7 139.0 1.1 2.8 ^G 0.4

15% HCl 400 15.0 - 58.9 22.6 -

fresh water 500 - - 3.9 4.7 -

a) = This molecular weight is accurate to about i 2500, with the chloride counterion not

is included.

b) = This molecular weight is accurate to about -500, with the chloride counterion not

is included.

'c). * The spread of this molecular weight is not known. d) = These tests were conducted at 62.5 ⁰ C '.

Table V

Various organic polycationic polymers
Example 315233

Chemical or polymer molecular weight
Concentration (%)
solvent
Solvent-pH-Vert

Calibration_
Standard saline solution (ml / min)

§IE25H

Solution ml

Standard saline solution 500

Treatment solution 300

Standard saline solution 500

fresh water 500

15% HCl 400

fresh water 500

23.6

21.2 19.4

22.2

BDCTMDA DMAECH DMAECE DMECH DMAECH 4th 1500 i75O ^a 75OO ^b 75OO ^b 75OO ^b 0.37 0.37 0.185 0.037 S3 SB SB SB SB 4th 4th 4th 4th

100.0
114.4

111.9

150.4

7 ^, 2

154.3

100.0
109.4
121.2
159.4
44.8
184.0

100.0
108.8
134.5
182.0
93.8
156.2

100.0 117.6 131.1 155.4 82.4 128.8

30.3

100.0

113.2

122.1

6.9

Table V (continued)

E.g.

37

3β

40

41

Chemical or polymer DHASCH DMAECH BDMAECH DMABDC

Molecular weight 1? 50 ^a 750O ^ i75OO ^b 1500

Concentration (%) 0.37 0.37 0.37 0.39

Solvent 5% KC1 5% HC1 SB SB

Solvent pH - 4 4

calibration

Standard saline solution (ml / min) 26.3 35.3 21.4 23.1 Flow tests _ ^ _ (.% 2_des
Calibration values

Solution ml

Standard saline solution 500 100.0 100.0 100.0 100.0

Treatment solution 300 76.0 103.1 79.9 108.2

Standard saline solution 500 85.2 106.2 130.7 116.9

fresh water 500 108.7 124.9 112.1 124.2

15% HCl 400 10.9 85.5 3 ^, 6 51.5

fresh water 500 117.5 113.3 112.1 160.2

a) = The molecular weight spread "is about i 250

b) = The molecular weight spread is about. - 2500

c) = These tests were carried out at 62.5 ° C.

HXDA LEAiA 116 130 1.0 1.0 SB S3 4th 4th

22.2

23, c

100.0 100.0 122.5 114.8 104.9 ^ 04.4 2.6 0.4

Table VI

Treatment of clay with anionic, cationic polymers at 25.9 ⁰ C

E.g.

42

45

a) = not determined

b) = 18 hours

Treatment solution ml Cf. - HOAl ZrOCIp 500 - - _a _a Chemical or polymer 300 0 2.5 1.2 Molecular weight 300 3% CaCl ₂ 2% KC1 2% KC1 Concentration (%) 100 solvent 100 11.9 15.2 15.8 calibration - 300 300 100.0 100.0 100.0 500 74.0 85.5 68.4 500 60.0 61.8 41.1 Standard saline solution (ml / min) - 42.8 54.8 Flow tests - 45.4 29.7 solution - b - Standard saline solution 38.0 40.7 51.6 3% CaCl ₂ 1.1 44.1 51.6 deionized water 27.6 25.5 Treatment solution 1.0 0.6 Rinsing Curing time 3% NaCl deionized water 15% HCl deionized water

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1 * 0

Table VII

Organic, polycationic polymers as clay treatment agents in a carbonate-containing formation

Test sand composition

material

Sand, grain size 0.21-0.088 mm

Marble splinters, grain size 0.21-0.088 mm

Quartz, grain size < 0.053 mm nontmorillonite

Weight?
Pack A

75

10

10

Pack B 0

10

Ex .;

Treatment solution chemical or polymer cf.

Molecular weight

Concentration (%)

Solvent FW

calibration
used Si
Standard salt

Flow tests_ £%) _ of the calibration value

Solution ml

Standard saline solution 500 100.0

Treatment solution. 500

Standard saline solution 500

fresh water 500 2.8

15% HCl 400

fresh water. 500

47

FDMDAA PDMDAA 57000 37000 0.4 0.4 SB SB

calibration (ml / min) A. , 0 A. , 6 B. 3, 2 used sand 15th 13th Standard saline solution

100.0 100.0 105.9 93.8 122.1 96.9 125.0 109.4 76.5 .- 169.1 _

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E.g.

Table VIII

Impairment of water wetting by clay stabilizers

48 49 50; 51 52

Extension of ex. 32 38 33 14th 16 Treatment solution Chemical or polymer DMAECH BDMAECH DMAECH FDMAA FEI Concentration (%) 0.37 0.37 0.37 0.4 0.1 solvent SB SB SB 15% HC1 15% HC1 Strength test (.%) Of the calibration

worth

in the original example

Fluid (liquid) ml

Diesel oil

fresh water

Diesel oil

500 139 2 68, 2 72, 2 94 , 4 84, 1 5CO 24, 1 16, 8th 24, 2 13th , 3 83, 7th 500 132, 1 61, 7th 72, 2 85 92, 9

CJ ISJ

te

Table VIII A

Clay treatments with organic, polycationic polymers that contain oxygen bonds

E.g.

Treatment solution
Chemical or polymer concentration (%)
solvent

calibration

Standard saline solution (ml / min)

Flow tests _ (% 2 des
Calibration values

Solution ml

Standard saline solution 500

Treatment solution 100

Standard saline solution 500

fresh water 500

15% HCl 400

fresh water 500

Diesel oil 500

fresh water 500

Diesel oil 500

52A

52B

52B

TADATO TADATO HBEOTO 0.86 0.7 0.68 SB SB SB

23.0

27.0

19.7

100.0 100.0 100.0 89.1 81.5 56.9 95.7 98.5 93.4 115.2 136.3 136.0 46.1 33.7 39.1 140.4 118.5 181.7 110.9 84.4 97.5 33.9 26.7 86.3 113.5 86.7 86.8

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Table IX

OD
O
CD

Test investigations for tone stabilization in Berea kernels, pressure: 3 »52 atm .; Temp. ■ 62.5 ⁰ C e.g. 53 54 55 56 57 58 59 60 61

Treatment solution

Chemical or polymerizate none none ZrOCIo ZrOCl- ZrOCl «ZrOCIo OKAl FDMDAA PDMDAA Concentrate xon (%) 1.2 - 1.2 * 1.2 * 1.2 * 2.5 0 * 4 0.4

Solvent Comp. Cf. 2% KC1 2% KC1 4% xci 3% HC1 FW SB SB

calibration

Standard saline solution (ml / min) 14.0 11.8 27.0 24.8 10.6 17.2 16.0 19.0 5.3

Flow tests _ (%) _ of the calibration

Calibration values

jjo sung ml ■ VN

Standard saline solution 300 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100, Q

Treatment solution 200 - - 39.3 145.2 ° -c, d 50.0 87.5 90.5 85.5

Standard saline solution 300 - - 3.7 28.2 - 55.6 62.5 ^e 105.3 96.4

fresh water 300 0.5 - 48.0 19.8 - 104.7 53.7 121.1 108.4

15% HCl 250 - 35.6 _a - 46.4 - - 4.3 16.3 38.6

fresh water 300 - 211.7 - 100.8 - - 215.6 204.2 596.4

Diesel oil 300 _____ 112.5 60.5 255.4

fresh water 300 - 52.5 - 35.0 ^ 3.2 ^ 04.8

Diesel oil 300 _____ 106.3 33.7 224.1

a) - Standard saline solution was used instead of fresh water at this stage of the flow test

was used so that the increase in permeability by acidification could be measured.

b) - 100 ml of 5% HCl were sent through before the treatment solution.

c) - 100 ml of 4% KCl solution were sent through before the treatment solution.

d) - After the injection of 85 ml of the treatment solution, no detectable flow

rate found.

e) - The treatment solution was followed by rinsing with 100 ml of 1% KCl solution.

co cn ho

ο co to «ο

Table X

Treatments to remedy previous harmful influences on the Permeability of Berea Kernels

63

Treatment solution VnI Cf. VnI Cf. 15th te VoI Cf. • Hq te Chemical or polymer VUIt
480 - 390 - O , 0 510 - 26.0 Concentration (%) 76 none 23 SB Λ , 5 155 5% KCl 0.6 solvent - (T)) Dofp 98 CD) O , 42 102 CD) 2.4 Indexed fluid - (F) 22.6 36 (F) - , 7 237 (F) 33.0 Standard saline solution - (F) 5.6 - (F) 1021 (F) 29.0 deionized water _- (E) - _ (R) 2801 (R) 15.2 Treatment solution (F) - (F) (F) deionized water (F) - (F) (F) deionized water (F) - (F) (F) deionized water

Table X (continued)

E.g. '65 Vol. (D) rate 66 (D) rate , 7 67 Vol. (D) rate , 4 68 Vol. (D) rate , 0 Chemical or polymer FMDAA
Concentration (%) 0.4
Solvent SB 300 (F) 10.6 ZrOCl ₀
2.2 ^
SB (F) 17th , 2 450 (F) 13th , 82 420 (F) 18th , 2 indexed fluid 96 (F) 4.4 Vol. (F) 0 , 03 FKDAA
0.4
5% HCl 348 (F) 0 , 3 ZrOCl ₀
2.2 ^
5% HCl I 7 (F) 0 , 9 Standard saline solution 98 (R) 3.5 390 (R) 0 , Oi 5 97 (R) 4th , 0 92 (R) , 0 deionized water 30 (F) 8.1 10 (F) C. - > 728 (F) 13th , 0 234 (F) 29 , 0 - Handling solution 450 (F) 11.4 28 (F) - - 1505 (F) 25th , 0 1008 (F) ^ 2 , 0 deionized water 600 (F) 11.4 7th (F) - 2717 (F) 25th 2705 (F) 4th deionized water - . the i original direction deionized water - Comparison = blind sample or no means
= not carried out
Vol. = Flow rate in (ml / min)
(D) = direction of flow
(F) = flow in forward direction, i.e. H
(R) ■ «flow in the opposite direction
Pressure = 3.52 atm
Temperature = 62.5 C ⁰

Example 69

A milk river sample from a borehole was placed in fresh water near Medicine Hat, Alberta, Canada. The rehearsal began on the Separate layers in 10 seconds. After one minute, the edges were observed to slip or wear away; after five minutes the sample had disintegrated into a discontinuous mound.

Example 70

A sample of the formation described in Example 69 (Milk Kiver) was placed in fresh water containing 0.8% FDMDAA contained. There was no observable decay of the sample. After 24 hours there was a trace of separation on the Stratification present, after 6 months there was no other appearance of destruction; the sample showed no erosion or no slipping and the jagged edges of the layers on the sample edges were still very easy to distinguish.

Examples 69 and 70 show that PDMDAA can reduce the collapse of can prevent oil wells, which so-called "spring shale" or "shale clays" penetrate. These water-sensitive Formations are not uncommon and cause problems during drilling by collapsing into the borehole and Closing the drill pipe. In addition to problems caused by the seizing of drill pipes, water-sensitive formations can also result in boreholes deviating from the dimensions and problems with inserting the bezels when drilling is complete. Examples of water sensitive formations, Which problems arise when drilling, inserting the surrounds or cementing boreholes, are MiIk River shale, Canada; Atoka Sand, Eastern Oklahoma, Glenrose Shale, South Louisiana and Anwhac Shale, South Texax, USA.

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- fs -

to

Tobelle XI

Treatment with organic, polycationic polymers

in a polar solvent

E.g.

Beha Chem Mole Konz Lösu

Eich Stan

Flow tests calibration value

Solvent ml

Standard saline treatment solution Standard salt solution fresh water 15% HCl fresh water

72

73

Treatment solution Cf. PDMDAA DMAECH DMAECH Chemical or polymer - 37000 ⁸ i75O ^b 75OO ^c Molecular weight (%) 0 0.4 0.37 0.37 Concentration (%) M. M. M. M. solvent calibration 25.6 25.0 24.2 22.9 Standard saline solution (ml / min)

100.0

107.0 77.7 11.7

100.0 142.8 93.2 115.6 56.8 95.6

100.0 99.6

123.6

159.1 57.0

120.7

100.0

110.5 91.7

138.0 41.9

130.1

M = methanol

a) - t 3700

b) - t

c) - · t 2500

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- MJf -

Table I gives the names for the clay treating chemicals and solutions used in the examples.

Table II, Examples 1 to 9, are tests of polydiallyldimethylammonium chloride of various molecular weights at room temperature. The first two examples provide comparative values of the results in the absence of clay treatment chemicals. The result of example ? is interesting in that hydrochloric acid is often used as a clay treatment chemical. Examples 3 and 4 show cases using fresh water as the carrier fluid for the clay treating chemical. Examples 5 and 6 show that lower concentrations of clay treatment chemicals may require salt in the carrier fluid (treatment solution). Perhaps there is a short reaction time before the clay treating chemical can bind to the clay, and during this period a salt environment is required to keep the clay under control. Examples 7-8 and 9 lead to the conclusion that the optimum molecular weight has been exceeded because the protection provided by the ollydiallyldimethylammonium chloride decreases again with the molecular weight.

Table III, Examples 10 to 17 show the changes in temperature and solvent for organic polycationic ones Polymers ,.

Dnc Example 10 shows that clogging of the sand pack can be expected when fresh water is introduced without prior treatment with a clay stabilizer.

The main difference between Example 10 and Example 1 is in temperature.

Examples 10-17 provide a range of temperatures and solvents for PDMDAA compared to Examples 1

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to 9 · As indicated in footnote a) for example 12, the increase in the air flow rate for the fresh water phase after the acid the dissolving of clay and fine particles by the hydrofluoric acid instead of the sole effect attributed by FDMDAA. The use of organic, polycationic polymers in connection with HF solutions is an important application.

Table IV, Examples 18-30, show organic polycationic ones Polymers which generally consist of alternating ethylene and amine groups.

The characteristic feature of the polymers is the structure: -Cl ₀ -CiIp-N. However, there are several changes to the nitrogen atom and they can occur in the same polymer molecule, that is:

-CH ₂ -CH ₂ -NH; H

-CH ₂ -CH ₂ -N-CH ₂ -CH ₂ -; H

-CH ₂ -CH ₂ -N-CH ₂ -CH ₂ -; and

-CH ₀ -CH ₀

-CH ₀ -CH ₀ -N ⁺ -CH ₀ -CH ₀ -. CH ₂ -CH ₂ -

It is believed that EDCA and PEI are the same polymer obtained by different synthesis, but their behavior is different. This is done on a

809807/0839

So

Reference is made to comparison of Example 20 with Example 27. Similar molecular weights and concentrations result in similar Results up to the last flow rate phase (fresh water after 15% HCl). Obviously, FEI is caused by HCl washed out.

It can be seen from Examples 18, 19 and 20 that there is an optimal molecular weight, with Example 19 being one something is of too high value.

The pH difference between Examples 21 and 22 shows that EDCAM is a little better at neutral pH. Since EDCAM is quaternized, the pH should contain nitrogen atoms do not change in this polymer.

The remainder of the compound in Table IV has primary, secondary and tertiary amines and a small percentage of quaternary Amines. Adjusting the pH to 4 practically converts the primary, secondary and tertiary amines into the ammonium state (amine hydrochloride).

Examples 29 and 30 are preferred embodiments according to U.S. Patent 2,761,843. Example 30 is in claims 6 and 11 of US Pat. No. 2,761,843 and is found in the table in column 6 thereof US patent specification. These two compounds can be a Do not prevent clogging of the test cell sand and the clay pack with fresh water. It is believed that the Molecular weights of TEPA and TETA are too low and that cation exchange takes place quickly when the standard salt solution is sent through. This removal of the amine oligomers enables the clay to swell when fresh Water is sent through.

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Si

The flow test investigation according to the invention appear the effects of the formation of geological formation more than the washout techniques of US Pat. No. 761,848, column 5, lines 25-7 ^. According to the invention the technique used to simulate the conditions in an actual borehole, i. H.:

Stage 1 - The calibration with saline solution simulates the flow the formation fluid;

Stage 2 - The treatment with a clay treatment agent or clay control agent simulates the treatment of the borehole;

Stage 3 - The saline flow simulates recirculation of the borehole for production. This stage is used to check whether the Formation saline removes the clay treating agent. Monomeric clay treatment agents such as potassium, Ammonium or calcium ions are removed at this stage;

Level M - The fresh water flow simulates the introduction of extraneous water into the formation;

Stage 5 - The 15% HCl flow simulates acidification treatment of the formation. If it is advantageous later in the operation of the borehole to clean it or to bring the borehole to better production with acid, it is an advantage if a clay treatment agent which is resistant to removal by cation exchange with hydrogen ions is present;

Level 6 - The fresh water flow simulates the introduction of extraneous water into the formation. This is used to check the resistance of the clay treatment agent to acid.

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Sä

The method of operation according to US Patents 2,761,843 and 2,761 is more for water or backwater clarification and wastewater treatment suitable where numerous polycationic compounds are used rather than for treating oil or water wells.

Table V, Examples 31 to 41 contains examples of organic, polycationic polymers which differ in their constitution from those of Tables II, III and IV are. Examples 31 and 39 have ion saturation in the carbon bond. Examples 32-38 have a hydroxyl group on the carbon bond. With the exception of Examples 40 and 41, they are effective Tone treatment agents or tone control agents. Examples 33, 34 and 38 show the concentration effects, where Example 38 has an unsuitable concentration.

Table VI, Examples 42 through 44 contains inorganic clay treatment agents and clay control agents, respectively. The examples 43 and 44 relate to inorganic, polycationic polymers according to the prior art.

Example 42 serves a dual purpose. It is the comparative example for Examples 43 and 44 and beyond it is also an example of removing a monomeric, cationic clay treating agent with a salt solution.

Examples 43 and 44 show that the inorganic, polycationic Polymers are not resistant to acid, so that if a borehole acidification is desired possibly a year after the treatment with an inorganic clay treatment agent it would be advisable to put the clay in the Treat the borehole again after the acidification treatment.

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Table VII, Examples 45 to 47 provides examples of how an organic, polycationic polymer as a clay treatment agent can act in a carbonate formation. The inorganic agents such as hydroxyaluminum compounds (HOAl) are not recommended for a formation containing more than 5% carbonate material because the reaction of the acidic Salt (low pH) with the carbonate convert the hydroxy aluminum chloride into the inactive aluminum hydroxide would. Furthermore, aluminum hydroxide has its own possibility as a clogging precipitate in the Capillaries to act on the formation. The metal salts of US Pat. No. 3,382,924 are pH considerate also acidic and have a tendency to be incompatible with carbonate components of a formation. Example 45 shows that one containing carbonate and clay Formation can be adversely affected or damaged in terms of the capacity for fluid production. on the other hand Example 46 shows that an organic, polycationic polymer exhibits a loss of permeability or permeability in a clayey and carbonate formation. The increase in permeability after acid treatment in Example 46 is likely attributable to the removal of carbonate by the acid. .

Since the marble pieces (marble splinters) had a pointed shape, they give a lower permeability than the sand they hold even though the particles of both materials have the same grain size. Example 47 clearly shows a low flow rate during calibration due to this influence. Example 47 shows an organic, polycationic Polymer that it is able to reduce the loss of permeability as a result of swelling and / or migration of trapped, prevent fine particles and clay in the formation even if carbonate is the main component of the Formation is.

809807/0839

Table VIII, Examples 48 to 52, show that polycationic polymers do not wet the formation with oil. Because cationic surfactants can treat clays and keep clays and fine particles from swelling and / or migration but have the disadvantage that they cause oil wetting of the formation, it appears advisable to use the organic, polycationic polymers for their ability to wet a formation by oil or to wet by water. Certain examples have additional flow rate phases added to the test procedure, namely with Hydrocarbon, fresh water and hydrocarbon. as suitable hydrocarbon, diesel oil was used. the Examples 48 through 51 show a pattern of high diesel oil flow and a low water flow. This is a good sign of water wetting. Example 52 shows one "neutral" state in which neither a particular oil wetting nor water wetting takes place.

The advantages which emerged from Examples 48 to 52 are that diesel oil has a viscosity about 2.5 times that of fresh water, yet a high diesel oil flow rate was obtained. If two phases or fluids in the same Kapillarströmungssystem are present, continues to exist here a condition is referred to as "relative permeability", whereby none of the flow rate is as high as when only a single phase or a single fluid would be present. Indeed, when both oil and water are present, the sum of the relative permeability for oil and the relative permeability for water in the pore spaces is seldom equal to the permeability of the formation in which there is only one fluid. In almost all cases the total value is lower.

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SS

For practical reasons, these flow rates are rates after the previous fluid had stopped flowing. This does not mean that the other fluid is completely through the current was evaded. On the contrary, a will Equilibrium is reached, creating a saturation that can no longer be canceled. The non-flowing fluid is still present, even if it can no longer be moved. The wetting fluid usually adheres to the capillary walls, while the non-wetting fluid is usually in the form of spheres trapped in pore enlargements.

Examples 49 to 51 not only show that the in general unwanted oil wetting by the organic, polycationic Polymer is unlikely, but that they also have the ratio of water to oil as it comes out of the formation can improve. This is another particular benefit.

Table BA, Examples 52A to 52B are examples of polymers which contain ester and ether bonds. These condensates contain tall oil or tall oil condensates. You surrender good protection for clays and showed good resistance to acid washout.

There have been concerns about tall oil's long carbon chains which could cause oil wetting. However, Examples 52A and 52B show water wetting and Example 52B shows "neutral" wetting.

Table IX, Examples 53 through 61 shows tests for tone stabilization on berea kernels.

The Berea Formation is encountered in the state of Ohio, USA and in the neighborhood. It is often used as the standard for

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scientific and / or technical research used in the field of the petroleum industry. Natural formations often vary within very short distances. The differences are in a block of a formation of 15 χ 20 χ 15 cm noticeably. Some berea sections do not contain enough clay to be water sensitive. The ones selected for investigation Sections were examined prior to use to determine whether there was any reasonable assurance that they would be against were susceptible to clogging from fresh water. Example 53 shows that the cores from this block of Berea sandstone were sensitive to a current of fresh water. Example 5 ^ is also a comparison test. In example 5 ^ acid is used after calibration. Although only about 2.8% acid solubility was present, it must have occurred at an important location in the capillaries as the flow rate doubles after the acid treatment was. As can be seen from note (footnote) a), saline solution was used to evaluate the results of the acidification treatment to confirm. The following fresh water flow phase shows that despite the considerable opening of the core by the acid, the clay components were still in a state that they could negatively affect the permeability or permeability to a considerable extent.

Examples 55 to 58 show that the carbonate content in the core interferes with the injection of inorganic, cationic polymer, unless acid is used as the solvent . If the carbonate content was greater than 2.8%, ie on the order of 10%, the acid solvent would not be sufficient.

Example 59 shows that hydroxyaluminum compounds do this can handle special kernels. The acid solubility of 2.8% is within the expected tolerance of 5%

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Hydroxy aluminum compounds. The use of an acidic Carrier fluids would use the hydroxyaluminum compound before Alter injection into the nucleus.

Examples 60 and 61 show that pH is not a factor in treating clays with an organic polycationic Polymer is. There are good initial flow rates for fresh water without excessively acidic carrier fluids Refuge had to be taken.

Table X, Examples 62 to 68, show a treatment for eliminating previous negative impairments the permeability of Berea cores.

It is believed that the prevention of loss of permeability caused by swelling and / or migration of clays or other fine particles is the best way to ensure continued production of a well is. However, it is often necessary to treat previously damaged formations.

Examples 62, 63 and 64 are comparative tests which show that the cores are damaged or damaged by fresh water. That saline treatment is ineffective and, finally, that HCl can be negatively affected considerable help in reopening the core is that however, the core permeability is not permanently protected.

A comparison of Examples 63, 65 and 66 shows that that organic, polycationic polymers have a very good treatment to repair the damage. A comparison of Examples 64, 67 and 68 shows that acid alone gives good initial opening of the core, but that the organic,

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polycationic polymer better long-term results results.

Table XI, Examples 71 to 7 ^, show the use of alcoholic or organic polar solvents other than water than normal liquids to replace hydrocarbons.

In formations that do not produce sand, as long as only hydrocarbons be promoted, but release water from their own formation when the water level rises and the Water pumping begins, aqueous preparations of organic, polycationic polymers prevent decomposition or destruction without affecting the aqueous Preparation itself causes this destruction. However, some well operators fear one Introduction of any aqueous fluids in general, even fluids such as those used to prevent destruction or the disintegration of the formation by water wetting are designed. In addition, it is possible that extremely water-sensitive Formations exist. So to avoid the fears and even the possibility of a softening to avoid extremely water-sensitive formations, can be an organic, polycationic polymer in alcohol, ketone, monoethers of glycol or other non-aqueous Solvents are dissolved which have sufficient solubility for the polymers in question, and the The essentially non-aqueous solution of the polymers obtained can be used for treating the formation.

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Claims (14)

Claims 1.Method of treating a hole penetrated by a borehole, Subterranean formation containing clays to stabilize the clays or the clay against expansion and dispersion, characterized that an organic, polycationic polymer with a molecular weight of at least about 1000 with a carrier fluid is mixed, and that this fluid is pumped into the borehole. 2. The method of claim 1 for treating one of a Borehole penetrated, clays containing subterranean formation to stabilize the clays or the clay opposite Expansion and dispersion, characterized in that an organic, polycationic polymer with a carrier fluid is mixed, that this carrier fluid is pumped into the borehole and that the formation with the organic, polycationic polymer is brought into contact. 3 · The method of claim 1 for treating one of a Borehole penetrated, clays containing subterranean formation to stabilize the clays or the clay opposite Expansion and dispersion, characterized in that an organic, polycationic polymer with a Molecular weight of at least 1000 is mixed with a carrier fluid, the major cation atom Is nitrogen, phosphorus or sulfur, and that the carrier fluid is pumped into the wellbore. 809807/0139 4. The method of claim 1 for treating one of a
Subterranean formation penetrated by a borehole and containing clays for stabilizing the clays or the clay against expansion and dispersion, characterized in that at least one organic, polycationic polymer
having a molecular weight of at least 1000 in the form of the following compound is mixed with a carrier fluid: R ₁ -ZR ₃ R ₄ X. where mean: R. = an organic, aliphatic, cycloaliphatic
or aromatic radical having 2 to 40 carbon atoms or a hydrogen radical, and when R- is a cyclic, aliphatic radical, Z and Rp form the ring
belong; Rp, R, and R ^, = organic radicals according to the definition of R., which have up to 6 carbon atoms and 0 to 2
Contain oxygen or nitrogen atoms, where, when Z = sulfur, the radical R ^ is not present; Z = a cation; X = an anion; η = an integer equal to the number of monomer units in the polymer; and m = an integer equal to the number required to maintain electrical neutrality
Anions and that this is the organic, polycationic polymer containing carrier fluid is pumped into the wellbore. 809807/0839 5. The method according to claim 1, characterized in that the carrier fluid is aqueous and from 0 to 40% of a salt in the form of alkali metal salts, alkaline earth metal salts or ammonium salts and at least one organic, polycationic Polymer in a concentration of about 0.01 to 25%, by volume of the aqueous carrier fluid. 6. The method according to claim 1, characterized in that the carrier fluid is a normally liquid, substituted, polar hydrocarbon with a boiling point in the range of about 25 to 200 ⁰ C, and that the organic polycationic polymer in a concentration of about 0.01 to 25 wt .-%, based on the carrier fluid , is present. 7. The method according to claim 1, characterized in that the carrier fluid is aqueous and a mineral acid in the form of hydrofluoric acid, hydrochloric acid, phosphoric acid, Contains nitric acid or sulfuric acid. 8. Method of treating a hole penetrated by a borehole, Earth formation containing clays to stabilize the clays or the clay against expansion and dispersion, characterized in that the earth formation is brought into contact with a fluid which is an organic, polycationic polymer with a molecular weight of at least 1000, which has a ratio of cationic atom to carbon atoms of about 1: 2 to 1:36, is brought into contact. 9. Procedure for changing the water wetting conditions a subterranean formation, characterized in that the formation is brought into contact with a fluid, which is an organic, polycationic polymer with a molecular weight of at least 1000 and one Contains ratio of cationic atom to carbon atoms of about 1: 2 to 1:36. 809807/0039 10. Method of reducing the reduction in permeability or permeability of an earth formation containing clays, characterized in that the formation with a fluid is brought into contact, which is an organic, polycationic Polymer with a molecular weight of about 1000 and a ratio of cationic atom to Contains carbon atoms from about 1: 2 to 1:36. 11. Treatment composition for earth formation for prevention the swelling of clay, characterized in that it contains about 0.01 to 25 vol .-% added to an aqueous medium, organic, polycationic polymer containing a molecular weight of at least 1000 with a ratio of cationic atom to carbon atoms from about 1: 2 to 1:36. 12. The method according to claim 1 for the treatment of an underground formation, characterized in that a classified, solid, particulate material is pumped into the borehole. 13 · Method according to claim 1 for the treatment of an underground Formation in which a solid, particulate material is pumped into the borehole and that pressure is maintained in that borehole adjacent a formation in the borehole which is larger than that Adjacent formation break-up pressure. 14. The method of claim 1 for treating an underground Formation at which pressure is maintained in that borehole adjacent to a formation in that borehole which is greater than the fracture pressure of that adjacent formation. • 09807/0839