CA1232126A

CA1232126A - Treating fines-containing earthen formations

Info

Publication number: CA1232126A
Application number: CA000462218A
Authority: CA
Inventors: Robert K. Knight; David R. Watkins; Leonard J. Kalfayan; Donald C. Young
Original assignee: Union Oil Company of California
Current assignee: Union Oil Company of California
Priority date: 1983-09-02
Filing date: 1984-08-31
Publication date: 1988-02-02
Also published as: NL8402644A

Abstract

ABSTRACT OF THE DISCLOSURE
Method for treating earthen formations which contain water-sensitive, finely divided particulate matter wherein there is injected into the formation steam or a mixture of steam and hot water containing an effective fines-stabilizing amount of a compound containing ammoniacal nitrogen selected from the group consisting of ammonium hydroxide, and a water-soluble ammonia or ammonium ion precursor selected from the group consisting of amides of carbamic acid and thiocarbamic acid, derivatives of such amides, tertiary carboxylic acid amides and their substituted and alkylated derivatives. A
preferred additive is urea. If the formation is a subsurface oil-containing formation, the treatment can be part of a method for enhanced oil recovery.

Description

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This invention relates to a method for treating earthen formations which contain clay, shale or other fines to improve the flow of fluid through the formation. More particularly the invention relates to such a method wherein the decrease in the permeability of the formation upon contact with water is minimized and the permeability can even be increased.
Many earthen formations contain clays, shales, and/or fines, such as silt sized or smaller particles. The formation can be exposed at the surface of the earth, e.g., roadbeds, hillsides and the like, or it can be a subterranean formation, including both those just below or near the surface in which formations, footings or walls of structures rest, and those a substantial distance below the surface from which oil, gas or other fluids can be produced.
When contacted by water, water-sensitive clays and shales, for example montmorillonite, can swell and decrease the permeability of the formation. Other non-clay fines often are free to move and tend to be carried along with a fluid flowing through the formation until they become lodged in pore throats, i.e., the smaller interstices between the grains of the formation. This at least partially plugs the openings and reduces the permeability of the formation. Thus finely divided particulate matter can obstruct flow through a formation by swelling, migration or both.
Wren footings or foundations of buildings rest in formations containing such fines, damage or at least great inconvenience often stems from the inability of the earth to carry away water due to decreased permeability of the formation when wet. Likewise, drainage of formations surrounding septic tanks and underlying roadbeds is desirable.
One common instance in which fluids are produced from or injected into formations is in connection with the production of oil. Often it is desired to treat oil-bearing formations to increase the amount of oil recoverable therefrom. One popular method is to inject steam into the formation. The steam can be either dry or wet, i.e., it can contain a liquid USSR 528,877 - 1 -water phase. In some instances steam is injected via a well, the well is then shut in temporarily and allowed to soak, and subsequently production is commenced from this same well. In other instances, steam is injected via one well and acts as a drive fluid to push oil through the formation to one or more offset wells through which the oil is produced. In either instance, when the steam reaches the subterranean formation, it at least partially condenses, thus exposing the formation rocks to fresh water. Even though the steam may act to mobilize the oil in the formation, if the formation contains fines and water-sensitive clays, the permeability of the Formation can be so reduced as a result of the contact of the fines by the earache water, the increase in oil production can be lower than expected, and, in some instances, production can even be lower than before the treatment.
In another instance a fines-containing subterranean formation penetrated by a well may require stimulation because of water damage which occurred during drilling or fracturing operations.
Various treatments have been proposed to stabilize clays in a Formation Such treatments include injecting into the formation solutions containing such materials as potassium hydroxide, sodium silicate, ZOO hydroxy-aluminum, organic acid chrome complexes, organic polymers and salts owe a hydrous oxide-:Eorming metal such as zirconium oxychloride.
While each of these treatments has met with some success in particular applicatiolls, the need exists for a further improved method for -treating a tines containing formation to minimize the adverse effect of the fines on Formation permeability, particularly when such a formation is contacted by a fluid containing water.
Therefore, this invention is directed to providing a method err reducirlg the permeability damage in and/or increasing the permeability of formations containing finely divided particulate matter due to passage of a fluid there through, and for inhibiting permeability impairment due to I

migration, transformation and/or swelling of very fine particles within a porous formation.
The present invention attempts to stabilize a formation containing water-sensitive clays, shale and other fines by injecting steam into the formation and/or to stimulate a formation which has been damaged by water.
Briefly the present invention provides a method for treating or conditioning earthen formations, particularly those which contain finely divided particulate matter, such as water-sensitive clays and shale and/or other fines, which materials are free to move through the formation, lo transform and/or swell if contacted by an aqueous liquid, whereby the migration, transformation, and/or swelling of the fines is reduced so as to maintain a relatively high permeability through the formation and to increase the permeability of formations previously damaged. The method involves injecting into the formation steam to which has been added at some point prior to the time the steam contacts the formation an effective fines-stabilizing amount, typically more than 0.1 to 25 percent by weight based on the weight of the boiler feed water used to generate the steam, of a compound containing ammonia Cal nitrogen selected from the group consisting of ammonium hydroxide, and a water-soiuble ammonia or ammonium ion precursor selected from the group consisting of asides of carbamic acid and thiocarbamic acid, derivatives of such asides, tertiary carboxylic acid asides and their substituted and alkylated derivatives characterized by the formula:
X Al R - C - N

wherein I R is hydrogen, or an organic radical, particularly an alkyd group containing 1 to about 8 carbon atoms, or an -hydroxy substituted alkyd group containing 1 to about carbon atoms, (2) Al and R2 are independently selected from hydrogen and organic radicals, with alkyd groups containing 1 to about carbon atoms being the preferred organic radicals, and (3) X is oxygen or sulfur. The preferred additives are ammonium carbonate and urea, an aside of carbamic acid. urea is most preferred.
If the earthen formation is a subterranean formation, the treatment can be part of a method for enhanced oil recovery or a method -for stimulating production from a formation penetrated by one or more wells.
Most formations, regardless of their composition, contain at least some fines, detrital material or authigenic material which are not lo held in place by the natural cementations material that binds the larger formation particles, but instead are loose in the formation or become dislodged from the formation when food is passed through the formation, as a result of rainfall, flow of ground water or during production o-f formation fluids via a well penetrating the formation or injection of fluids into the formation from the surface or via a well. The loose fines tend to become dispersed in the fluids passing through the formation and migrate along with the fluid. They are carried along and are either carried all the way through the formation and can be produced i-f the fluid is flowing to a well, or they can become lodged in the formation in constrictions or pore throats and thus reduce formation permeability. In addition, if the fines are clays or shale which swell in the presence of water and the fluid passing through the formation is or contains water, permeability reduction can occur due to swelled clay or shale particles occupying a greater proportion of the formation pore volume.
Formation fines can be incorporated into the formation as it is deposited over geologic time, or in the case of subterranean formations, can be introduced into the formation during drilling and completion operations.
Fines are present to some extent in most sandstone, shales, limestones, clolomites and the like. Problems associated with the presence of fines are often most pronounced in sandstone-containing formations. "Formation fines"

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are defined as particles small enough to pass through the smallest mesh screen commonly available (400 United States Lucia, or 37 micron openings).
Ire composition of the fines can be widely varied as there are many different materials present in subterranean formations. Broadly, fines may be classified as being quartz, other minerals such as feldspar, Muscovite calcite, dolomite and Burt; water-swellable clays such as montmorillomite, beidellite, nontronite, sapient, hectorite and sequent, with montmorillonite being the clay material most commonly encountered; non-water-swellable clays such as coolant and isle; shales; and amorphous materials.
In the method of this invention, the above-described fines are stabilized, rendered less likely to reduce permeability when a water-containing fluid passes through the formation, and, in some instances, the permeability of the formation is increased compared to what it was prior to treatment. In the case of a subterranean formation penetrated by a well, the treatment can improve the production or injection capability of the well, i.e., stimulate the well.
kite the reasons for these effects on the formation permeability are not completely understood, and the invention is not to be held to any particular theory of operation, it is believed that the success of this method may be due to one or more of the following: (1) the ammonia or ammoniwn ions add to the total dissolved solids content both of the water component of the steam, if wet s-team is employed, and of the water condensing from the steam itself. These solids appear to decrease the swelling tendency of the clays when exposed to water, even water contacted subsequent to the carrying out of this method. I Some non-clay fines treated with steam alone appear to react hydrothermally to produce water-syllable clays which then reduce permeability. The presence of the ammonia or ammoniwn ions in the steam decreases the occurrence of this reaction to form clays. The Amelia or ammoni~ml iOII may react Whitehall water-swe71able clays to ~23~

transform them into materials which have less telldency to swell in water.
The methods of this invention can be employed to treat or condition fines-containing earthen formations which are episode at the surface, located just below the surface, or which are located a substantial distance below the surface and are penetrated by a well. In one manner of treating subterranean formations penetrated by a well, the treatment can involve an enhanced oil recovery method wherein steam is injected into the forination to mobilize oil, and the method of this invention prevents formation damage by the steam. In another instance the treatment can involve stimulation of a well penetrating a formation whose permeability has been impaired previously. Such impairment can occur in various ways depending on the previous history of the well, for example, wells drilled with water-base drilling fluid and/or whose surrounding formations have been exposed to water. As used herein the term 'stimulation" can include both improving the fluid flow rate through a formation and removing formation damage therefrom.

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The ammonium ion precursors suitable for use in this invention are water-soluble materials which hydrolyze in the presence of steam to form ammonia and/or ammonium ions.
One group of ammonium ion precursors are the asides of carbamic acid and thiocarbamic acid including urea, Burt, triuret, -Thor and ammon:ium carbamate. Urea is the most preferred additive for use in the present invention.
Another group of ammonium ion precursors are derivatives of carbamic acid and thiocarbamic acids including monomethylolurea and dimethylolurea.
Still another group of ammonium ion precursors are tertiary carboxylic acid asides and their substituted and alkylated aside counterparts characterized by the formula:

R
R-C-N

wherein (1) R is hydrogen or an organic radical, particularly an alkyd group containing 1 to about 8 carbon atoms, or an ~-hydroxy substituted alkyd group containing 1 to about 8 carbon atoms, (2) Al and R2 are independently selected from hydrogen and organic radicals, with alkyd groups containing 1 to about 8 carbon atoms being the preferred organic radical, and (3) X is oxygen or sulfur. Preferred tertiary carboxylic acid asides and their substituted and alkylated aside counterparts include Eormamicle, acetamide, N,N-dimethyl:Eormamide, N,N-diethylformamide, NUN-dimethylacetamide, N,N-dietllylacetamide, N,N-dipropylacetamide, NUN-dimethylpropionamide and N,N-diethylpropionamide. Other species which may be used include N-methyl,N-ethylacetamide, N-methyl, N-octylpropionamide, N-methyl, N-hexyl-n-butyramide, N-methyl,N-propylcaproamide, M,N-cliethyl-caprylamide and the like. N,N-dimethylformamide is an especially preferred tertiary carboxylic acid aside.
The ammonia or ammonium ion-containing additive should be ~32~3 employed in an amolmt which is effective Fiji stabilizing fines. This amount will vary depending especially on the nature and amount of fines present in the particular formation being treated and the particular ammonium ion-containing additive used. Typically, there is used more than 0.1 to 25 percent by weight ammoniwn ion-containing additive, preferably Us to 5 percent by weight, based on the weight of the boiler feed water used to generate the steam.
Additives which are liquid at ambient temperatures can be added directly either to the boiler feed water or to the steam itself. If I added to the steam, the addition can be made either at the surface as the s-team is being injected into the formation or down a well penetrating the formation to be treated, or the additive can be injected Donnelly via a separate conduit and mixed with the steam Donnelly prior to its entering the Formation Additives which are solids at ambient temperature can be added directly to the feed water or a concentrated solution thereof can be prepared and then employed as described above for a liquid additive. An example of a suitable concentrated solution is a solution containing 35 to 50 percent by weight urea and 65 to 50 percent by weight water.
If one of the chief objectives in the application of this treatment to an enhanced oil recovery method is to use steam to mobilize oil which otherwise would be difficult to recover, the amount of steam to be used is well known in the art and is the same as for steam treatments in general. If mobilization of oil is of secondary importance, as in treating a surface formation or a water injection well completed in a fines-contain:irlg formation to stabilize the fines, it is recommended that there be used the steam generated from about 250 to 3,000 barrels of feed water per vertical foot of formation to be treated. Preferably the steam should be injected at a rate of about 200 to 1500 barrels of feed water per day per well.
I the invention is further illustrated by the following examples ~L23~ 6 which are illustrative of various aspects of the invention and are no-t intended as limiting the scope of the invention as defined by the appended claims.
Example AL (Comparative Example) A California well T-33 having a depth of 1,124 feet which is newly completed produces for two months at a rate of 24 barrels per day (B/D) oil and 1 B/D water. It is desired to carry out an enhanced oil recovery -treatment of this well with steam. However, it is believed the formation may contain fines which might damage the permeability of the formation if treated with steam. That is, experience with nearby wells indicates the formation may be water sensitize.
. .
A one-inch- diameter core having-a length- of 2.7 inches is I==
removed from the well and tested in the laboratory to determine its sensitivity to water and its response to a treatment with steam containing ammonium ions. First a 3 percent by weight aqueous solution of sodium chloride is injected into the core at ambient temperature and 15 pi pressure for 3.5 hours at rates starting at 9.1 milliliters per minute (mls./min) and dropping to 4 mls./min. as the permeability stabilizes.
This established a base permeability of 92.8 millidarcys (muds.). Next, distilled water is flowed through the core at ambient temperature and 15 pi for 3.25 hours at rates starting at 6 mls./min. and dropping to 0.15 ml./min. where the permeability stabilizes at 3.5 percent of the base permeability to the sodium chloride solution. Next, there is added to boiler feedlYater 64 grams/liter gel of ammonium carbonate. Steam is generated and injected into the core at 500F. and 700 pi back pressure for 6 hours at a flow rate of 0.5 ml./min. Next, an aqueous solution containing 6~1 gel of amrnonium carbonate is injected into the core at ambient temperature and 15 pi for 6 hours at a flow rate of 13.2 mls./min. The permeability increased to 330 percent owe -the base permeability to the sodium chloride solution.

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This example shows that the injection of fresh water sharply reduces the permeability of the core. Ever, the permeability can be restored, and even substantially increased by treatment with steam containing ammonium carbonate.
eye Well T-33 it riven a steam stimulation treatment as follows. A 42 percent by weight aqueous solution of urea is prepared and held in a blending tank. Eighty percent quality s-team it generated by a battery of steam generators and flowed down a carbon steel flow line towards the well. At the surface of the well a 7-foot long section of stainless steel conduit is positioned in the carbon steel flow line. The aqueous solution of urea is injected into the steam flowing to the well at the upstream end of the stainless steel conduit segment to minimize corrosion. Steam generated from 600 barrels of feed water per day is injected for 12.5 days. The first day 674 gallons per day of the 42 percent by weight aqueous solution of urea is added to the steam. The second day 337 gallons per day of -the same urea solution is added to the steam. For the remaining 10.5 days of the treatment, 168.5 gallons per day of the same urea solution is added to the steam. At the end of the treat-mint it is calculated that 2.3 billion Buts of heat is added to the formation. The well is shut in for 7 days and allowed to soak. The well is then returned to production. The product -lion rate is as follows:
sty week -160 B/D oil and 75 B/D water.
end week -108 B/D oil and 61 B/D water.
3rd week -98 B/D oil and 11 B/D water.
Thea week -90 B/D oil and 11 B/D water.

I

lust the treatment increases tile rate of oil production substantially with no observable evidence of permeability reduction due to swelling or movement of formation fines.
kite various specific embodiments and modifications of this invention have been described in the foregoing specification, further modifications are included within the scope of this invention as defined by the following claims.

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Claims

THE EMBODIMENTS OF THE INVENTION IN WHICH AN EXCLUSIVE
PROPERTY OR PRIVILEGE IS CLAIMED ARE DEFINED AS FOLLOWS:

l. A method for conditioning a fines-containing, earthen formation to increase the flow of fluids through the formation which comprises injecting into the formation steam containing an effective fines-stabilizing amount of a compound containing ammoniacal nitrogen selected from the group consisting of ammonium hydroxide, and a water-soluble ammonia or ammonium ion precursor selected from the group consisting of amides of carbamic acid and thiocarbamic acid, derivatives of such amides, tertiary carboxylic acid amides and their substituted and alkylated derivatives characterized by the formula:
wherein (1) R is hydrogen or an organic radical, (2) R1 and R2 are independently selected from hydrogen and organic radicals, and (3) X is oxygen or sulfur.
2. A method for treating a fines-containing earthen formation to stabilize the said formation against clay swell-ing and particle migration comprising injecting into the form-ation steam containing an effective fines-stabilizing amount of a compound containing ammoniacal nitrogen selected from the group consisting of ammonium hydroxide, and a water-soluble ammonia or ammonium ion precursor selected from the group consisting of amides of carbamic acid and thiocarbamic acid, derivatives of such amides, tertiary carboxylic acid amides and their substituted and alkylated derivatives characterized by the formula:

wherein (1) R is hydrogen or an organic radical, (2) R1 and R2 are independently selected from hydrogen and organic radicals, and (3) X is oxygen or sulfur.
3. In a method for enhanced oil recovery from a fines-containing subterranean formation penetrated by a well wherein steam is injected into the formation, the improvement which comprises injecting along with the steam an effective fines-stabilizing amount of a compound containing ammoniacal nitrogen selected from the group consisting of ammonium hydroxide, and a water-soluble ammonia or ammonium ion precursor selected from the group consisting of amides of carbamic acid and thio-carbamic acid, derivatives of such amides, tertiary carboxylic acid amides and their substituted and alkylated derivatives characterized by the formula:

wherein (1) R is hydrogen or an organic radical, (2) R1 and R2 are independently selected from hydrogen and organic radicals, and (3) X is oxygen or sulfur.
4. A method for stimulating a fines-containing subterranean formation penetrated by a well comprising injecting into the formation steam containing an effective fines-stabilizing amount of a compound containing ammoniacal nitrogen selected from the group consisting of ammonium hydroxide, and a water-soluble ammonia or ammonium ion pecursor selected from the group consisting of amides of carbamic acid and thiocarbamic acid, derivatives of such amides, tertiary carboxylic acid amides and their substituted and alkylated derivatives characterized by the formula:
wherein (1) R is hydrogen or an organic radical, (2) R1 and R2 are independently selected from hydrogen and organic radicals, and (3) X is oxygen or sulfur.
5. The method defined in claim 1 or 2, wherein the amount of the compound containing ammoniacal nitrogen is more than 0.1 to 25 percent by weight based on the weight of boiler feedwater used to generate the steam.
6. The method defind in claim 1 or 2, wherein the amount of the compound containing ammoniacal nitrogen is about 0.5 to 5 percent by weight based on the weight of boiler feedwater used to generate the steam.
7. The method defined in claim 1 or 2, wherein the compound containing ammoniacal nitrogen is added to the boiler feedwater used to generate the steam.
8. The method defined in claim 1 or 2, wherein the compound containing ammoniacal nitrogen is added to the steam.
9. The method defined in claim 1 or 2, wherein the earthen formation is a subsurface stratum penetrated by a well and the compound containing ammoniacal nitrogen is added to the steam at the surface of the well.
10. The method defined in claim 1 or 2, wherein the earthen formation is a subsurface stratum penetrated by a well and the compound containing ammoniacal nitrogen is added to the steam downhole before the steam enters the subsurface stratum.
11. The method defined in claim 1 or 2, wherein the fines include water-swellable clays.
12. The method defined in claim 1 or 2, wherein the compound containing ammoniacal nitrogen is an amide of carbamic acid selected from the group consisting of urea, biuret, triuret and ammonium carbamate.
13. The method defined in claim 1 or 2, wherein the compound containing ammoniacal nitrogen is urea.
14. The method defined in claim 1 or 2, wherein the compound containing ammoniacal nitrogen is thiourea.
15. The method defined in claim 1 or 2, wherein the compound containing ammoniacal nitrogen is a derivative of carbamic acid selected from the group consisting of monomethylolurea and dimethylolurea.
16. The method defined in claim 1 or 2, wherein the compound containing ammoniacal nitrogen is a tertiary carboxylic acid amide, sustituted tertiary carboxylic acid amide or derivative of a tertiary carboxylic acid selected from the group consisting of formamide, acetamide, N,N-dimethylformamide, N,N-diethylformamide, N,N-dimethylacetamide, N,N-diethylacetamide, N,N-dipropylacetamide, N,N-dimethylpropionamide and N,N-diethylpropionamide.
17. The method defined in claims 1 or 2, wherein the organic radical which comprises R is an alkyl group containing 1 to about 8 carbon atoms or an .alpha.-hydroxy substituted alkyl group containing 1 to about 8 carbon atoms.
18. The method defined in claim 1 or 2, wherein the organic radicals which comprise R1 and R2 are the same or different alkyl groups containing 1 to about 8 carbon atoms.
19. The method defined in claim 1 or 2, wherein the method for conditioning increases the permeability of the earthen formation at least 50 percent based on the permeability prior to the carrying out of the method for conditioning.
20. The method defined in claim 1 or 2, wherein the method for conditioning increases the permeability of the earthen formation at least 150 percent based on the permeability prior to the carrying out of the method for conditioning.
21. The method defined in claim 3 or 4, wherein the amount of the compound containing ammoniacal nitrogen is more than 0.1 to 25 percent by weight based on the weight of boiler feedwater used to generate the steam.
22. The method defined in claim 3 or 4, wherein the amount of the compound containing ammoniacal nitrogen is about 0.5 to 5 percent by weight based on the weight of boiler feed-water used to generate the steam.
23. The method defined in claim 3 or 4, wherein the compound containing ammoniacal nitrogen is added to the boiler feedwater used to generate the steam.
24. The method defined in claim 3 or 4, wherein the compound containing ammoniacal nitrogen is added to the steam.
25. The method defined in claim 3 or 4, wherein the earthen formation is a subsurface stratum penetrated by a well and the compound containing ammoniacal nitrogen is added to the steam at the surface of the well.
26. The method defined in claim 3 or 4, wherein the earthen formation is a subsurface stratum penetrated by a well and the compound containing ammoniacal nitrogen is added to the stream downhole before the steam enters the subsurface stratum.
27. The method defined in claim 3 or 4, wherein the fines include water-swellable clays.
28. The method defined in claim 3 or 4, wherein the compound containing ammoniacal nitrogen is an amide of carbamic acid selected from the group consisting of urea, biuret, triuret and ammonium carbamate.
29. The method defined in claim 3 or 4, wherein the compound containing ammoniacal nitrogen is urea.
30, The method defined in claim 3 or 4, wherein the compound containing ammoniacal nitrogen is thiourea.
31. The method defined in claim 3 or 4, wherein the compound containing ammoniacal nitrogen is a derivative of carbamic acid selected from the group consisting of monomethylolurea and dimethylolurea.
32. The method defined in claim 3 or 4, wherein the compound containing ammoniacal nitrogen is a tertiary carboxylic acid amide, substituted tertiary carboxylic acid amide or derivative of a tertiary carboxylic acid selected from the group consisting of formamide, acetamide, N,N-dimethylformamide, N,N-diethylformamide, N,N-dimethylacetamide, N,N-diethylacetamide, N,N-dipropylacetamide, N,N-dlmethylpropionamide and N,N-diethylpropionamide.
33. The method defined in claim 3 or 4, wherein the organic radical which comprises R is an alkyl group containing 1 to about 8 carbon atoms or an .alpha.-hydroxy substituted alkyl group containing 1 to about 8 carbon atoms.
34. The method defined in claim 3 or 4, wherein the organic radicals which comprise R1 and R2 are the same or different alkyl groups containing 1 to about 8 carbon atoms.
35. The method defined in claim 3 or 4, wherein the method for conditioning increases the permeability of the earthen formation at least 50 percent based on the permeability prior to the carrying out of the method for conditioning.
36. The method defined in claim 3 or 4, wherein the method for conditioning increases the permeability of the earthen formation at least 150 percent based on the perme-ability prior to the carrying out of the method for conditioning.
37. A method for treating an earthen formation to stimulate the flow of fluids through the formation comprising injecting into the formation steam containing an effective fines-stabilizing amount of urea.
38. In a method for enhanced oil recovery from a sub-terranean formation penetrated by a well wherein steam is injected into the formation, the improvement which comprises injecting along with the steam an effective fines-stabilizing amount of urea.
39. The method defined in claim 37 or 38, wherein the amount of urea employed is between about 0.1 to 25 percent by weight based on the weight of boiler feedwater used to generate the steam.