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Publication numberUS3481400 A
Publication typeGrant
Publication dateDec 2, 1969
Filing dateApr 3, 1967
Priority dateApr 3, 1967
Publication numberUS 3481400 A, US 3481400A, US-A-3481400, US3481400 A, US3481400A
InventorsHeilhecker Joe K, Kaiser Albert D Jr, Kerver John K, Mckinney Joseph M
Original AssigneeExxon Production Research Co
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Treatment of solids plugged wells with reversibly adsorbable inhibitor
US 3481400 A
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Description  (OCR text may contain errors)

Dec. 2, 1969 K. KERVER ETAL TREATMENT OF SOLIDS PLUGGED WELLS WITH REVERSIBLY ADSORBABLE INHIBITOR Filed April 5, 1967 PRODUCTION BBLS- DAY 8 Sheets-Sheet 1 TOTAL FLUID VERSENE TREATME ML L LESS THAN l0 BBL.

AVERAGE INHIBITOR SQUEEZE\ TOTAL PEODUCTION I lDAY JAN.

APRIL JULY OCT.

INVENTORS. JOHN K- KERVER, JOE K. HEILHECKER, BY JOSEPH M. McKINNEY,

ALBERT D. KAISER,JR.,

Dec. 2, 1969 Filed April 5, 1967 TREATING SOLUTION REQUIRED, 55 GAL-DRUMS J. K. KERVER ET AL 3,481,400 TREATMENT OF SOLIDS PLUGGED WELLS WITH REVERSIBLY ADSORBABLE INHIBITOR 8 Sheets-Sheet 3 PERCENT PORE SPACE CONTAINING GYPSUM DEPOSIT O |oo (PLUGGED) AVERAGE MEANS'QUEEN WELL POROSITY I5.I

NET THICKNESS"9.9 FT.

WELL BORE-"'8 IN TREATING SOLUTION TETRASODIUM SALT OF ETHYLENE DIAMINE TETRA ACETIC ACIDZ (30%) O .5 I L5 2 2.5 3 3.5

RADIAL DEPTH OF GYPSUM DEPOSIT, FT.

EFFECT OF RADIAL EXTENT OF GYPSUM DEPOSITION AND PERCENT IN PORE SPACE ON THE AMOUNT OF TREATING SOLUTION REQUIRED FOR CLEANOUT INVENTORS. JOHN K. KERVER, JOE K- HEILHECKER, BY JOSEPH M. McKINNEY,

ALBERT o. KAISER, JR.,

5 ATTORNEY- Dec. 2, 1969 TREATMENT OF SOLIDS PLUGGED WELLS WITH REVERSIBLY Filed April 5, 1967 PERCENT OF PORE SPACE CONTAINING GYPSUM SUSCEPITIBLE TO SOLUTION J. K. KERVER ET AL ADSORBABLE INHIBITOR 8 Sheets-Sheet 4 MAXIMUM FRACTION OF GYPSUM DEPOSIT SOLUBLE IN ONE PORE VOLUME OF TREATING SOLUTION.

SOLUTION CONCENTRATION PERCENT TETRASODIUM SALT OF ETHYLENE DIAMINE TETRA ACETIC ACID- cfiya v INVENTORJ. JOHN K- K ERVER JOE K- HEILHECKER, BY JOSEPH M. McKINNEY,

ALBERT o. KAISER, JR.,

1969 J. K. KERVER ET AL 3,481,400

TREATMENT OF SOLIDS PLUGGED WELLS WITH REVERSIBLY ADSORBABLE INHIBITOR Filed April 5. 1967 8 Sheets-Sheet 5 l W HOLISILNI swn au 2 w i 5 0 I 2 5 ,.H.H, 7. .WZWWM 1 i 5' M7 4- FRACTU RED WITH 14,000 GALS.O|L FOLLOWED BY INHIBITOR JAN AND 43 0OO LBS. 8'l2 MESH SAND OCT.

JULY

APR

8 8 88 28 g 8 8 8 m N M10 rs'raa 'NOliOflGOHd INVENTORS.

JOHN K. KERVER,

JOE K. HEILHECKER, BY JOSEPH M.McKINNEY,

ALBERT D-KAISER,JR.,

2, 1969 J. K. KERVER ET AL 3,481,400

TREATMENT OF SOLIDS PLUGGED WELLS WITH REVERSIBLY ADSORBABLE INHIBITOR Filed April 5, 1967 8 Sheets-Sheet 6 o o o N 5 g 8 g T 2 Ir la 2 V r 1 z i i S O a 0 I 2 n: E O Q I 5 w m 2 I j O w Lu 0 F 1 Z 3 I Q m z f o 0 0 0 w 2 Z w 1 0 I l! m j 2 8 z 2 g :3 0 2 I I: 4 r- 9 a: J o O a m o 0 IO 7 T "2 N oo o o o o o INVENTORS.

ouvswvas/uouamm wsw foaeaosov umowv JOHN K, KERvg-R,

7 JOE K- HEILHEOKER, BY JOSEPH mm KINNEY,

ALBERT o. KAISER, 0a.,

1969 J. K. KERVER ET AL 3,481,400

. TREATMENT OF SOLIDS PLUGGED WELLS WITH REVERSIBLY ADSORBABLE INHIBITOR O o O o 0 Q 8 g E INVENTORS. UBlI'I/INSW imamasa m nouvamaouoo uouamm JOHN KERVER JOE K. HEILHECKDER,

JOSEPH M-MCKINNEY, ALBERT D- KAISER, JR..

BY NEY United States Patent US. Cl. 166--279 28 Claims ABSTRACT OF THE DISCLOSURE The productivity of a formation penetrated by a well plugged with water insoluble solids is restored by treating the plugged formation by fracturing or perforating to form a passageway for well fluids through the plugged formation or by treatment with an aqueous solution of a polyamino polycarboxylic compound to solubilize and remove the deposited solids at least to the extent also to form a passageway for well fluids through the plugged formation. After treatment, either by fracturing on'perforating or with the polyamino polycarboxylic compound, the formation has a desorbable inhibitor introduced or injected into it which prevents or suppresses deposition of additional solids by desorption of the inhibitor by the produced well fluids.

BACKGROUND OF THE INVENTION Field of the invention The present invention is directed to the treatment of wells which have become plugged by deposition of water insoluble solids in the formation adjacent the wells.

Description of the prior art It is known to' treat wells with polyamino carboxylic compounds to solubilize solids deposited in permeable formations and to remove the solubilized solids. However, removal of the solubilized solids has not alleviated the problem of deposition of additional solids in the treated formation. It is also known to use citric and other organic acids to treat subsurface earth formations to dissolve solids and to open up passageways for flow of hydrocarbons. It is also known to fracture hydraulically substantially impermeable subsurface earth formations containing hydrocarbons or other desirable fluids to allow production of well fluids from the fractured formation. It is also known to treat wells with inhibitors but heretofore it was not known to inject into the formation inhibitors which prevented deposition of water insoluble solids.

Specific prior art considered in connection with this invention is represented by the following listed US. Patent: 2,877,848.

SUMMARY OF THE INVENTION The invention may be briefly described and summarized as involving an improvement in a method of treating a well which has become at least partially plugged by deposition of water insoluble solids in a permeable for mation adjacent the bore hole of the well wherein the plugged formation is treated with an aqueous solution "ice of a polyamino carboxylic compound to solubilize the deposited solids and the solubilized solids removed from the permeable formation or by hydraulic fracturing or other means such as by perforating to form or open up at least one passageway through the plugged permeable formation. The particular improvement involves injecting into and adsorbing in the treated formation an effective amount of a reversibly adsorbable or a desorbable inhibitor effective to prevent deposition of additional solids in the treated formation. Thereafter, well fluids including water are produced through the treated formation containing a small but effective amount of said inhibitor desorbed from said treated formation such that deposition of solids in the treated formation is suppressed.

In effect a zone is formed adjacent the .well bore from which deposited solids are removed at least in part or through which a passageway is formed followed by depositing in the zone an effective amount of a desorbable inhibitor which is effective to prevent deposition of additional solids in the zone. Then, well fluids such as hydrocarbons and water are produced through the zone containing an amount of desorbed inhibitor effective to prevent solids deposition in the zone.

Reduced productivity in certain wells in West Texas and elsewhere is attributed to deposition of water insoluble salts such as gypsum (CaSO .2H O) and the like in permeable formations in the immediate vicinity of the well bore. In accordance with the present invention, it has been found that these deposits may be cleaned out or a passageway formed through them and prevented from reoccurring by following the treatment by injecting a desorbable inhibitor which is desorbed from the treated formation by the produced fluids which are thereby -inhibited'from depositing additional solids to plug the well. In the present invention, the inhibitor may be injected or forced into the formation without pre liminary treatment of the formation.

BRIEF DESCRIPTION OF THEAFDRIAWING The invention will be further described by reference to the drawing in which:

FIGURE 1 is a plot'of data illustrating the effect of the present invention on a well where production had decreased to less than 10 barrels per day by deposition of solids; 1

FIGURE 2 is a similar plot showipg how production declines even after treatment with alkali and acid but is maintained and increased by the present invention;

FIGURE 3 illustrates the radial deposition of gypsum solids in a well and the removal of same;

FIGURE 4 illustrates the solubility of gypsum solids in a treating reagent;

FIGURE 5 illustrates an embodiment of the invention where the formation is fractured and then treated with inhibitor;

FIGURE 6 is an adsorption isotherm of an inhibitor useful in the present invention;

FIGURE 7 is an adsorption breakout curve for the same inhibitor; and

FIGURE 8 illustrates desorption of the same inhibitor from a core from a Means-Queen well.

DESCRIPTION OF THE PREFERRED EMBODIMENTS In the practice of the present invention the well is preferably treated with a polyamino polycarboxylic com pound such as a polyamino polycarboxylic acid or a salt thereof such as a sodium salt. As specific examples of the preferred compounds useful in cleaning or treating wells may be mentioned the alkylene polyamino polycarboxylic acids. Preferred compounds are alkali metal salts of alkylene polyamino polycarboxylic acids. Compounds in which organic groups, for example, hydroxy or hydroxyethyl groups are substituted for hydrogen in the polyamino polycarboxylic acids at positions other than in the carboxylic group are suitable for use in this invention.

Of the preferred alkali metals salts of alkylene polyamino polycarboxylic acids, the alkali metal salts of ethylene diamine tetra-acetic acids are especially valuable. Any of the mono-, di-, tri-, or tetra-alkali metal salts of ethylene diamine tetra-acetic acid can be used. The particular salt that is used will depend in part upon the material causing the plugging of the formation. For example, when it is known that precipitation of calcium carbonate is causing the reduced permeability of the formation, the trisodium salt of ethylene diamine tetra-acetic acid may be employed. The sodium salts of ethylene diamine tetraacetic acid are preferred alkali metal salts because of their availability as ordinary commercial products. The alkylene polyamino polycarboxylic acids, for example, ethylene diamine tetra-acetic acid, can also be used but are generally not as desirable as their alkali metal salts. The chelating ability of ethylene diamine tetra-acetic acid or the sodium salt. depends on pH. The sodium salt is alkaline and chelation occurs to a greater extent in an alkaline solution than in an acid solution. Examples of effective substituted polyamino polycarboxylic acid compounds are the trisodium salt of N-hydroxyethyl ethylene diamine triacetic acid and the monosodium salt of N, N-di (a hydroxyethyl) glycine.

Aqueous solutions of the alkali metal salts of ethylene diamine tetra-acetic acid are alkaline and tend to remain alkaline when used in the well. A slightly alkaline condition facilitates the formation of complexes of alkaline earth metal compounds. The alkali metal salts of ethylene diamine tetra-acetic acid not only solubilize the alkaline earth metal compounds plugging the formation but also hold them in solution to prevent their rcprecipitation at points deeper in the formation. When the principal cause of plugging of an injection well is the formation of deposits of iron oxide or iron sulfide, cleaning of the well is improved by the addition of a mineral or organic acid to the alkali metal salt of ethylene diamine tetra-acetic acid. Preferred acids are the organic acids such as citric or lactic acid. Iron salts of citric or lactic acid tend to remain soluble whereas iron salts of mineral acids may become neutralized and precipitated by long contact with limestone.

The polyamino polycarboxylic acid compounds are suitably used in an amount and for a time sufficient to dissolve the deposited solids from the pores of the formation which are plugged by the solids. Referring now to FIGURE 3, it will be clear that a 30% solution of the tetra sodium salt of ethylene diamine tetra-acetic acid (known to the trade as Versene) will dissolve out the gypsum plugged pore space of a well in the Means-Queen field in West Texas. The data illustrate the effect of de= gree of plugging on the amount of Versene required as well as the effect of the radial depth of the deposited gypsum. Thus the treatment produces a zone around the well bore which is substantially free of plugging deposits.

The amount of the polyamino polycarboxylic acid compound employed therefore depends on the degree and depth radially of plugging. Usually an amount within the range from about 1 to drums (55 gallons each) of solution of sodium salt of polyamino polycarboxylic acid (ethylene diamine tetra-acetic acid)preferably about 10 drums--is suflicient to dissolve a gypsum deposit extending 2 feet into the formation and filling 25% of the pore space. Dilferent amounts will be required depending on the strength of the aqueous solution, the degree of plugging, and extent of removal desired.

Table I below illustrates the amount of gypsum which may be deposited in a well suffering from plugging:

TABLE L-MAXIMUM GYPSUM DEPOSITION IN FORMATION 7 Amount of Gypsum Distance Gypsum Deposit Extends From Well Bore it. Lbs.-

( lbs/rm) Based on average Means-Queen well:

Porosity, percent 15.1 Net thickness, .ft. 9.9 Well Bore Diameter, in. 8

Inv order to remove the deposited solids such as gypsum, it is necessary that the solid deposit be contacted with fresh treating reagent and the solubilized solids be removed. FIGURE 4 illustrates the effect of Versene solution concentration on solution of the deposited solid as percent of pore space containing gypsum susceptible to solution. It will be apparent that the strength of the solution has an effect on degree of removal of gypsum deposit.

Wells have been treated successfully in the Means- Queen field in Texas in the following manner:

(1) Pull tubing, drill and scrape well bore.

(2) Reperforate casing into the formation.

(3) Produce well for about 3 days to test production.

(4) Place 15 to 30 barrels of fresh water, followed by 275 gallons of Versene treating solution (Versene-100) mixed with 5 barrels of fresh water, followed by 275 gallons'of Versene treating solution mixed with 20 barrels of fresh water in the well bore and inject fresh water and concentrated Versene solution into formation at a slow rate at or less than 0.1 barrel per minute. Shut well in for 24 hours.

(5) Inject one half of the remaining Versene treating solution into the formation slowly and maintain slow pumping for about 12 hours, then shut well in for 12 hours.

(6) Slowly inject remaining Versene treating solution and shut Well in for 48 hours.

(7) Overfiush formation with fresh water.

(8) Place well on production and produce dissolved scale and any excess Versene treating solution. Test production rate by pumping well for 3 days.

(9) Inject gallons of inhibitor mixed with 30 barre'ls of water into formation. Overfiush with 100 barrels of fresh Water. Shut well in for about 12 hours and return well to production.

While the several foregoing steps have been used, it is to be emphasized that the invention involves essentially opening up a passageway into and through the plugged formation and then injection of an inhibitor to prevent further deposition of plugging solids.

These operations resulted in production of increased amounts of oil and water from the treated wells as shown in FIGURES 1 and 2 Where the practice of the present invention in 20 treatments allowed the obtaining of an unobvious result in production of increased amounts of fluids over a sustained period of time. In these operations the desorbed inhibitor concentration in the produced fluid has been maintained at at least 10 ppm. over a period of time ranging from 9 to 23 weeks which substantially lessened gypsum deposition.

The present invention also involves treatment of the plugged formation by fracturing the plugged formation prior to injection of the desorbable inhibitor. When hydraulic fracturing is employed a fracturing fluid which suitably may be a hydrcarbon liquid such as crude petroleurn or fractions thereof may be used. Also emulsions of oil and water may be used as the fracturing liquid or gelled hydrocarbons containing a metallic soap or a so dium salt of a fatty acid may be used as the fracturing liquid.*0ther viscous fluids may be iused as the fracturing fluid. The fracturing fluid may contain a propping agent such as sand, solids which resist crushing such as deformable polymers, glass beads, metallic spheres such as aluminum pellets, nut shells and inany other propping agents known in the art to hold the passageways open; or the fracturing fluid may be free of propping agent but may be followed by a liquid which contains a propping agent to hold the fractures or passageways open.

In hydraulic fracturing operations a hydraulic pressure is'imposed on the formation to be fractured sufiicient to lift the overburden and open up cracks and passageways. In this particular instance, the plugged formation is hydraulically fractured by imposing on it a hydraulic pressure sufficient to overcome the tectonic stresses. Usually this will be at least equivalent to 0.7 pound per foot of depth of the formation which causes the plugged formation to be cracked or fractured and at least a passageway formed through it into the unplugged portions of the formation for production of hydrocarbons. In the Means-Queen field about 1.0 p.s.i./foot is required. After the plugged formation has been hydraulically fractured, the desorbable "inhibitor is injected through the fractured formation and adsorbed in and on the rock for desorption by the wellfluids and to prevent plugging of the cracks or passages formed by the fracturing operation.

In conducting the fracturing operation, the fracturing liquid ,is pumped down the well against the exposed plugged formation under confined conditions. Such confined conditions may involve isolating the plugged formation with a packer as is well known in the art or by closing off the annulus between he tubing and easing at the well head and pumping fracturing fluid down the tubing. As pumping proceeds, pressure builds up to a point sufficient to fracture the formation. Fracturing is indicated by a sudden drop is pressure indicating that fracturing liquid is entering the plugged formation.

The inhibitor may be injected immediately after the fracturing liquid, if desired, without allowing the well to clean itself by production before injecting the inhibitor. However, it may be preferred to produce the fractured well prior to injecting the inhibitor for a time of about 20 to 36 hours, usually about 24 hours, following which the inhibitor is injected into and allowed to contact the fractured formation as will be described further hereinafter. In some case the inhibitor may be injected ahead of the fracturing liquid as a spearhead and in a sense may also act at least as the initial fracturing liquid.

It is contemplated that the present invention may also be used in wells before deposition of water insoluble solids occurs. In such instances the steps employed may be the same as where deposition or plugging has taken place. Thus, the present invention contemplates injection or forcement of the inhibitor for water insoluble solids such as gypsum into the formation without any prelimi nary treatment to open up a passageway such as by perforating, fracturing, or treatment with polyamino polycarboxylic compound, and the like. In this case, the inhibitor is adsorbed by the formation rock and desorbs with the produced fluid effectively preventing deposition of water insoluble solids such as gypsum and the like.

A well in west Texas in which production had declined due to deposition of gypsum'in the producing formation was treated with an aqueous potassium hydroxide solution followed by treatment with 30% hydrochloric acid. This treatment temporarily restored production of oil from about barrels per day to about barrels per day but declined again soon thereafter. This well was then hydraulically fractured using 14,000 gallons of oil and 43,000 pounds of 8 to 12 mesh sand as a.

propping agent. Thereafter the fractured well was treated by injection of 165 gallons of a phosphate ester of the condensation product of low molecular weight alcohol with ethylene oxide. Fracturing restored oil production to about 60 barrels per day and inhibitor treatment at least maintained "or increased production. The produc tion curves for total fluid and oil produced are illustrated in FIGURE 5.

The inhibitors employed in the present invention are illustrated by the organic phosphates, ethoxylated organic phosphates, amino substituted organic phosphates, or ganic phosphona tes, acrylic-acrylamide polymers, and the like. Specific inhibitors are: an acrylic acid-acrylamide polymer and a phosphate ester of the condensation product of low molecular weight alcohol with ethylene oxide, which are believed to have structural formulas,

respectively, as follows:

-CH2(|TH l on,

Where x and y are at least 3.

where a=3 to 4, and b=2.

which are used as aqueous solutions. The inhibitor employed in the specific well operations illustrated in FIG URES 1 and 2 is the above-identified phosphate ester of the condensation product of low molecular weight alcohol with ethylene oxide.

The inhibitor; used in the present invention must not only be active in preventing the precipitation or growth of water insoluble crystals such as gypsum crystals but must also possess particular adsorptive properties. Thus the inhibitor must be adsorbed by the formation rock surface. The adsorption also must be at least partially reversible, so that the inhibitor may be desorbed into the produced well fluids. The reversible desorption must be at a low corilcentration so that desorption of a small amount of inhibitor may continue in a well for several months time.

FIGURE 6 shows an adsorption isotherm of a phosphate ester of the condensation product of low molecular weight alcohol with ethylene oxide on to 270 mesh silica sand. The' gisotherm shape necessary for successful use in this invention is illustrated. This is an isotherm that rises rapidly at low equilibrium concentrations and then levels off with increasing concentration. This means that a substantial amount of inhibitor can remain adsorbed on the sand and still be in equilibrium with a solution containing at low concentration of inhibitor. At least half of the reversibly desorbable inhibitor should be adsorbed at an equilibrium concentration of less than 500 mgm./liter.

Reservoir rock formations are composed of limestone, clay, and other materials as well as sand, and it has been found that inhibitor is often irreversibly adsorbed by clay and unavailable for desorption. Therefore, testing of reservoir rock samples for the adsorption and desorption of inhibitors is desirable.

FIGURE 7 shows an adsorption breakout curve for the above-mentioned phosphate ester on a core sample from the Means-Queen field. In this test a 2000 mgm./ liter aqueous solution of inhibitor was flowed into the core. The eflluent was analyzed for inhibitor and the results are shown. These data show the adsorptive capacity of the rock to be 0.73 mgm. inhibitor per gram of rock or 0.56 gallon of inhibitor per barrel of pore space.

FIGURE 8 shows the desorption of inhibitor from a Means-Queen core following equilibrium adsorption of the same inhibitor at a concentration of 50,000 mgm./

liter. As shown, the desorbed inhibitor concentration was maintained at a level of more than 10 mgm./ liter for 300 pore volumes flow. Long continued desorption is necessary for successful practice of the present invention. Only certain inhibitors possess this desired property. For use in this invention an inhibitor must possess adsorption-desorption characteristics such that it can be desorbed at a concentration of at least 2 mgm./liter for at least about 50 pore volumes flow.

In the practice of the present invention when the well is treated with a polyamino polycarboxylic compound, it is important that the treating agent be injected'into and remain in contact with the plugged formation over a period of time for good results. For example, a first batch may be slowly injected and maintained in contact for 24 hours, a second batch for an additional 24 hours, and a third batch for 24 hours, for a total of 72 hours. Field operations have involved well shut-in times for 24, 24, and 72 hours for a total of 120 hours. A minimum time of at least 2 to about 12 hours may be satisfactory but the longer times are preferred. The shut-in times may range from 12 to 652 hours if desired with times of 24 to 326 hours preferred.

The inhibitor must also remain in contact with and be adsorbed by or in the treated formation whether the formation is treated with a polyamino polycarboxylic compound or by fracturing. For example, after injection of the inhibitor as an aqueous solution, the well may be shut in for 24 hours. A minimum shut-in time is about 2 to 8 hours. Shut-in time is required for the inhibitor to come to adsorption equilibrium with the surface of the formation rock. Thus, a shut-in or contact time of 6 hours to 326 hours may be employed.

The amount of inhibitor injected should be sufficient to satisfy the adsorptive capacity of the particular formation rock contacted. This may vary from 0.1 to 50 mgm./ gram depending on the minerals which make up the rock matrix. Clay has a large adsorptive capacity while that of sand or limestone is low. For the Means-Queen field in west Texas the amount injected may be about 0.2 to 2.0 mgm./gram. As a general statement, with respect to formation rock, amounts of 0.1 to about 24 mgm./ gram may be used satisfactorily. The well fluids produced through the treated formation containing adsorbed in hibitor preferably contain at least 10 p.p.m. of desorbed inhibitor although 2 p.p.m. may suffice'in some instances. The produced well fluids may contain from about 2 to 100 p.p.m. of desorbed inhibitor for best results; however, desorbed concentration depends primarily on rock properties. Usually for the first week after treatment the concentration is above 100 p.p.m. Ordinarily, in field treatments 165 gallons of gypsum inhibitor are used on the first treatment with subsequent treatments employing only 55 gallons each. An amount within the range of 27 to 550 gallons as an aqueous solution containing from about 0.5 to about 50 percent by weight of inhibitor may be used. The amount of inhibitor injected, of course, will depend on the type of formation which has been fractured, perforated, or treated to remove deposited solids. Ordinarily a volume of formation is treated such that when its adsorptive capacity has been satisfied, the formation desorbs inhibitor at a sutlicient concentration to provide protection for a time which may range from about 3 to about 6 months or longer. The volume employed may vary widely between formations treated. It may be desirable to repeat the treatment of the well when the inhibitor concentration in the produced liquid falls below a selected concentration. Usually this may be about 10 p.p.m. but may be as low as 2 p.p.m.

While the present invention has been described and illustrated by reference to removal of gypsum (CaSO 2H O) deposits, it is equally applicable to removal of other water insoluble solids deposited in a permeable formation. Specific examples of such deposits are: ferric oxide, ferrous sulfide, calcium carbonate, barium sulfate, str0ntium sulfate, and the like.

Likewise, other treating agents besides the polyamino polycarboxylic compounds may be used such as but not limited to citric acid, lactic acid, and the like. Treat ment with potassium hydroxide solutions followed by hydrochloric acid may also be employed.

The nature and objects of the present invention having been completely described and illustrated and the best mode contemplated set forth, what We wish to claim as new and useful and secure by Letters Patent is:

1. In a method for treating a well which has become at least partially plugged by deposition of water insoluble solids in a permeable formation adjacent the bore hole of the well and in which the plugged formation is treated with an aqueous solution of a polyamino polycarboxylic compound effective to solubilize the deposited solids fol lowed by removal of the solubilized solids from the permeable formation, the steps of:

injecting into and adsorbing in said treated formation an effective amount of a reversibly adsorbable inhibitor effective to prevent deposition of said solids in said treated formation; and

producing well fluids including water through said treated formation containing a small but effective amount of said inhibitor desorbed from said treated formation;

whereby deposition of solids in said treated formation is suppressed.

2. A method in accordance with claim 1. in which the polyamino polycarboxylic compound is a sodium salt of ethylene diamine tetra-acetic acid.

3. A method in accordance with claim 1 in which the inhibitor is a phosphate ester of the condensation prod not of a low molecular weight alcohol with ethylene oxide.

4. A method in accordance with claim 1 in which the inhibitor is an acrylic acid-acrylamide polymer.

5. A method in accordance with claim 1 in which the inhibitor is employed in an amount sufiicient to adsorb in said treated formation about 0.1 to about 50 mgm. per gram of treated formation.

6. A method in accordance with claim 1 in which the water in the produced well fluids contains at least 2 p.p.m. of desorbed inhibitor.

7. A method in accordance with claim 1 in which the well is shut in at least 12 hours before removal of solubilized solids and injection of inhibitor.

8. A method in accordance with claim 7 in which the well is shut in for about 16 to about 652 hours.

9. A method in accordance with claim 1 in which the well is shut in for at least 2 hours after injecting said inhibitor and before producing well fluids.

10. A method in accordance with claim 9 in which the well is shut in for about 24 to about 326 hours.

11. A method in accordance with claim 1 in which:

(a) the polyamino polycarboxylic compound is a sodium salt of ethylenediamine tetra-acetic acid;

(b) the inhibitor is a phosphate ester of the condensa= tion product of a low molecular weight alcohol with ethylene oxide;

(0) the inhibitor is employed in an amount sufiicient to adsorb in said treated formation about 0.1 to about 50 mgm. per gram of treated formation;

(d) the Water in the produced well fluids contains at least 2 p.p.m. of desorbed inhibitor; and

(e) the well is shut in at least 2 hours before removal of solubilized solids and injection of inhibitor and at least an additional 2 hours after injecting inhibitor and before producing well fluids.

12. A method in accordance with claim 1 in which the inhibitor has an. adsorption isotherm that increases rapid-- ly at low equilibrium concentration and levels OE With increasing concentration below about 500 mgm/liter.

9 13. In the production of hydrocarbons from a well bore drilled to penetrate a permeable hydrocarbon productive earth formation in which water insoluble solids tend to deposit in and plug the earth formation adjacent the well, the method which comprises:

forming a zone adjacent saidwell bore from which deposited solids have been removed at least in part;

depositing and adsorbing in said zone an effective amount of a reversibly adsorbable inhibitor effective to prevent deposition of additional solids in said zone; and

producing hydrocarbons and water through said zone containing an amount of said inhibitor effective to prevent deposition of solids in said zone. 14. In a well drilled to penetrate a permeable productive formation which has beconfe plugged by deposition of water insoluble solids in the. formation adjacent the well, the method which comprises:

treating said plugged formation to form at least one passageway from the well through the plugged for- 'rnation;

injecting into said passageway and adsorbing in said formation an effective amount; of a reversibly adsorbable inhibitor effective to prevent deposition of solids in said passageway; and

producing well fluids through said passageway containing an amount of said de'sorbed inhibitor effective to prevent deposition of water insoluble solids in said passageway. 15. A method in accordance with claim 14 in which the well is treated by imposing a; sufficient pressure on a liquid in said 'well to fracture said plugged formation and form said passageway. j X

16. A method in accordance with claim 15 in which hydraulic pressure is imposed on said plugged formation by pumping a fracturing liquid against said plugged formation. 17. A method in accordance with claim 14 in which the Well is treated with an aqueous solution of a polyamino polycarboxylic compound effective to solubilize and remove at least a portion of the deposited solids and form said passageway.

18. A method in accordance with claim 17 in which the polyamino polycarboxylic compound is a sodium salt of ethylene diamine tetra-acetic acid.

19. In a well drilled to penetrate a permeable productive formation which may become plugged by deposition of water insoluble solids in the; formation adjacent the well, the method which comprises":

injecting into and adsorbing said formation an effective amount of a reversibly adsorbable inhibitor effective to prevent deposition of water insoluble solids in said formation adjacent the well bore; and

producing well fluids from said formation containing an amount of said inhibitor suflicient to prevent deposition of water insoluble solids in said formation adjacent the well bore.

20. A method in accordance with claim 19 in which the well fluids contain at least 2 ppm. of said inhibitor.

21. In a well drilled to penetrate a permeable productive formation for production of well fluids in which said formation may become plugged by deposition of water insoluble solids in the formation adjacent the well, the meth od which comprises:

injecting into and adsorbing in said formation an effective amount of a reversibly adsorbable inhibitor effective to prevent deposition of water insoluble solids in said formation adjacent the well on production of fluids from said formation.

22. A method in accordance with claim 21 in which the formation has become plugged by deposition of water insoluble solids in the formation adjacent the well and in which the plugged formation is treated to form at least one passageway from the well through the plugged formation prior to injecting salid inhibitor.

23. A method in accordance with claim 22 in which the well is treated by imposing a sufiicient pressure on a liquid in said well to fracture said plugged formation and form said passageway.

24. A method in accordance with claim 22 in which the well is treated with an aqueous solution of a polyamino polycarboxylic compound effective to solubilize and remove at least a portion of the deposited solids and form said passageway. H

25. A method in accordance with claim 24 in which the polyamino polycarboxy'lic compound is a sodium salt of ethylene diamine tetra-acetic acid.

26. A method in accordance 'with claim 21 in which the inhibitor is an ethoxylated organic phosphate.

27. A method in accordance with claim 21 in which the inhibitor is an acrylic acid-acrylamide polymer.

28. A method in accordance with claim 21 in which the inhibitor is a phosphate ester of the condensation product of low molecular weight alcohol with ethylene oxide. 7

References Cited UNITED STATES PATENTS 2,777,818 1/1957 Gambill.

2,852,077 9/1958 Cocks .166-42 x 2,877,848 3/1959 case 166-42 3,021,901 2/1962 Earlougher 166.42 3,179,170 4/1965 Bur'tch 166-41 3,254,719 6/1966 Root.

3,283,817 11/1966 Roberts.

CHARLES E. OCONNELLL, Primary Examiner I. A. CALVERT, Assistant Examiner US. Cl. X.R. 166-308, 312

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Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US3782469 *May 25, 1972Jan 1, 1974Cities Service Oil CoFormation and wellbore scale prevention
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Classifications
U.S. Classification166/279, 166/308.4, 166/312
International ClassificationC09K8/52, C09K8/528, C09K8/60, C09K8/64
Cooperative ClassificationC09K8/528, C09K8/64
European ClassificationC09K8/528, C09K8/64