MX2014009589A - Compositions and methods for treatment of well bore tar. - Google Patents

Abstract

Of the many compositions and methods provided herein, one method includes a method comprising: contacting tar resident in a well bore with a tar stabilizing polymer comprising at least one polymer selected from the group consisting of a styrene polymer, an acrylate polymer, a styrene-acrylate polymer, and any combination thereof; and allowing the tar stabilizing polymer to interact with the tar to at least partially reduce the tendency of the tar to adhere to a surface.

Description

COMPOSITIONS AND METHODS FOR THE TREATMENT OF TAR HOLLOW OF A WELL FIELD OF THE INVENTION The present invention relates to methods and compositions for use in underground operations. More particularly, the present invention relates to tar stabilizer polymers used to treat pitch pit residues and associated methods of use.

BACKGROUND OF THE INVENTION Many of the underground operations involve drilling a well hole from the surface with rock and / or soil to penetrate an underground formation containing fluids that are desirable for production. In the course of drilling operations and other underground operations, drill string and / or other equipment may come into contact with tar and rock areas (eg, heavy hydrocarbons, asphalt and bitumen); in many of these operations, it may be desirable to drill the hole in the well through these tar-containing zones. However, tar is a relatively sticky substance that can adhere easily to any surface with which it comes into contact, including the wellbore surfaces and / or any equipment used during the drilling operation. The tar can also be dissolved in many synthetic treatment fluids used in the course of drilling operations, increasing the sticky and adhesive properties of the tar. If a sufficient amount of tar is adhered to the surfaces of the wellbore or drilling equipment, it can, among other problems, prevent the drill string from rotating, prevent fluid circulation, or impede the efficiency of a drilling operation. . In some cases, it may be necessary to remove and / or dismantle the drill string in order to eliminate tar accumulations, a process that can cause numerous cost and safety problems. The accumulation of tar in the drilling equipment and / or in the drilling well can also prevent any further downhole operation, including cementing, acidification, cracking, sand control and recovery treatments. In addition, soft, sticky tar that reaches the surface can contaminate surface equipment, including solids control equipment.

The existing methods for the management of these problems resulting from the tar incursion into the wellbore It can be problematic. Some of these methods involve making an increase in the hydrostatic pressure of the hole in the well in order to push the tar from the shaft well to the surface. However, this increase in hydrostatic pressure can damage the hole in the well and / or a portion of the underground formation. Other conventional methods use treatment fluids comprising dispersants, surfactants and / or solubilizers, which allow the tar particles to dissolve or homogenize with the treatment fluids. However, the tar particles can not be easily separated from the fluid once they have been dissolved or homogenized with the fluid. The presence of the tar particles in the treatment fluid can alter their rheological properties and / or suspension capacity, which may limit their use in subsequent operations. On the other hand, the addition of these dispersants, surfactants, and solubilizers can increase the complexity and cost of the drilling operation.

SUMMARY OF THE INVENTION The present invention describes methods and compositions for use in underground operations. More particularly, the present invention describes stabilizing polymers of tar used to treat tar residing in the pit of a well and the associated methods of use.

One embodiment of the present invention provides a method for the treatment of pit pit pit. The method may comprise contacting pitch resident in the pit of a well with a tar stabilizing polymer comprising at least one polymer selected from the group consisting of a styrene polymer., an acrylate polymer, a styrene acrylate polymer and any combination thereof. The method may further comprise allowing the tar stabilizing polymer to interact with the tar to at least partially reduce the tendency of the tar to adhere to a surface.

Another mode of. The present invention provides a method for the treatment of tar in the wellbore. The method may comprise the use of an auger to enlarge the wellbore in an underground formation comprising tar. The method may further comprise the circulation of a drilling fluid through the drill bit to remove cuttings from the drill bit, wherein the drilling fluid comprises an aqueous fluid and a tar stabilizer polymer comprising at least one polymer selected from the group that consists of a styrene polymer, an acrylate polymer, a styrene acrylate polymer and. any combination of them.

Also, another embodiment of the present invention provides a treatment fluid. The treatment fluid may comprise an aqueous fluid. The treatment fluid may further comprise a tar stabilizing polymer comprising at least one polymer selected from the group consisting of a styrene polymer, an acrylate polymer, a styrene acrylate polymer and any combination thereof.

The features and advantages of the present invention will be readily apparent to those skilled in the art. Since those skilled in the art can make numerous changes, these changes are within the spirit of the invention.

DETAILED DESCRIPTION OF THE INVENTION The present invention describes methods and compositions for use in underground operations. More particularly, the present invention: discloses tar stabilizing polymers used to treat pitch resident pit pit and associated methods of use. As used herein, the term "tar stabilizing polymer" is refers to a polymer that can interact with the tar residing in the pit of a well, in such a way that the tar is less sticky and / or less able to adhere to a surface. One of the many advantages of the present invention, many of which are not discussed or mentioned herein, is that the tar treated with the compositions and methods described herein may be substantially less sticky and / or less capable of adhering to a surface. As a result, the tar treated in this manner may be susceptible to grid separation of the treatment fluids, drilling cuttings, tar sands and the like.

The embodiments of the present invention describe tar stabilizer polymers comprising a styrene polymer, an acrylate polymer, a styrene acrylate polymer or any combination thereof. Suitable tar-stabilizing polymers can generally be emulsified in an aqueous fluid according to the present embodiments. In some embodiments, the tar stabilizing polymers can be ionic or nonionic in nature. In certain modalities, the. Tar stabilizing polymers can interact with the tar residing in the pit of a well in such a way that the properties of the tar are altered. tar. In certain embodiments, the tar stabilizer polymers can be bonded or coated on the tar in such a way that the tar becomes less tacky. .

Examples of styrene polymers that may be suitable for use in the embodiments of the present invention include, but are not limited to, styrene copolymers that include the styrene co-monomers or any derivative thereof. In some embodiments, the styrene polymer can be made with the polymerization of styrene, which can be substituted or unsubstituted. The styrene can be substituted for any number of different groups that will be apparent to those skilled in the art, including without limitation, chlorine groups, bromine groups, fluoro groups, alkyl groups, alkoxy groups, alkenyl groups, alkynyl groups, aryl groups and substituted versions thereof. The combinations of styrene polymers may also be suitable, in certain embodiments. In some embodiments, the styrene polymer may comprise styrene in an amount in a range of about 90% to about 100% by weight of the styrene polymer, about 95% to about 100% by weight of the styrene polymer, or about 99 % to about 100% by weight of the styrene polymer. In a In one embodiment, the styrene polymer may consist of styrene. In some embodiments, the styrene polymer may be essentially free of acrylate and / or acrylic acid.

Examples of acrylate polymers which may be suitable for use in the embodiments of the present invention include, but are not limited to, acrylate copolymers, which include the acrylate co-monomers or any derivative thereof. The alkyl acrylate can be substituted by any number of different groups that will be apparent to those skilled in the art, including without limitation, chlorine groups, bromine groups, fluoro groups, alkyl groups, alkoxy groups, alkenyl groups, alkynyl groups, aryl groups . and replaced versions thereof. According to the present embodiments, the acrylate may comprise two or more units individually selected from the group consisting of -acrylate, methacrylate, -ethylacrylate, -propylacrylate, -butylacrylate, -tert-butylacrylate, n-hydroxyethyl methacrylate, potassium acrylate. , pentabromobenzyl acrylate, methyl methacrylate, ethyl methacrylate, n-nitrophenyl acrylate, methyl 2 (acyloxymethyl) acrylate, cyclohexyl acrylate, n-ethylhexyl acrylate and any derivatives thereof. Combinations of acrylate polymers can also be adequate, in certain modalities. In some embodiments, the acrylate polymer can be formed by the polymerization of acrylic acid, which can subsequently be neutralized to form the acrylate copolymer. In some embodiments, the acrylate polymer may comprise acrylate in an amount ranging from about 90% to about 100% by weight of the acrylic polymer, about 95% to about 100% by weight of the acrylate polymer or about 99%. % to about 100% by weight of the acrylate polymer. In one embodiment, the acrylate polymer may consist of acrylate. In some embodiments, the acrylate polymer may be essentially free of styrene.

Examples of styrene acrylate polymers which may be suitable for use in the embodiments of the present invention may include, but are not limited to, styrene acrylate copolymers and mixed copolymers including at least one unit comprising styrene, a substituted styrene and any derivative thereof; and at least one comprising -acrylate, -methacrylate, ethylacrylate, -propylacrylate, -butylacrylate, -tert-butylacrylate, n-hydroxyethyl methacrylate, potassium acrylate, pentabromobenzyl acrylate, methyl methacrylate, ethyl methacrylate, n-hydroxyethyl acrylate, -nitrophenyl, methyl acrylate 2 (acyloxymethyl) cyclohexyl acrylate, n-ethylhexyl acrylate and any derivatives thereof. Suitable combinations of styrene acrylate polymers may also be suitable, in certain embodiments.

In some embodiments, the tar stabilizer polymers may be provided in the form of a latex emulsion or a powder. For example, a latex emulsion that can be used comprises the tar stabilizing polymer. In some embodiments, the latex emulsion may be in the range of about 5% to about 60% active by weight. In some embodiments, the latex emulsion may have a pH in the range of about 2 to about 4. The latex emulsion may further comprise a surfactant. Generally, any surfactant that emulsifies and / or suspends the tar stabilizing polymers can be used in the embodiments of the fluids of the present invention. In certain embodiments, it may be desirable to select a surfactant that does not emulsify the tar to be treated. In certain embodiments, the surfactants may be present in an amount sufficient to emulsify and / or suspend the tar stabilizing polymers. This amount may depend of, among other things, the type of surfactant used and the amount of tar stabilizer polymer to be emulsified and / or suspended. One skilled in the art will recognize, with the benefit of this disclosure, the type and amount of surfactant that must be added for a particular application. In another embodiment, the tar stabilizing polymers can be provided in the form of a powder which can, for example, be dispersed in water. In some embodiments, the tar stabilizing polymer can have, for example, a particle size of less than about 1 miera, less than about 500 nanometers or less than about 100 nanometers.

According to the present embodiments, one or more of the tar stabilizing polymer may be included in a treatment fluid as described herein. As used herein, the term "treatment fluid" refers to any fluid that can be used in an underground application in conjunction with a desired function and / or for a desired purpose. The term "treatment fluid" does not imply any particular action of the fluid or any component thereof. The treatment fluids can be used, for example, to drill, complete, recondition, fracture, repair, or in any way prepare the wellbore for the recovery of materials that reside in a, underground formation penetrated by the hole of the well. Examples of treatment fluids include, but are not limited to, cement compositions, drilling fluids, spacer fluids and marking fluids.

In some embodiments, at least one tar stabilizing polymer can be included in a treatment fluid in an amount sufficient to treat the tar in the wellbore. In certain embodiments, the concentration of the tar stabilizing polymer in the treatment fluid may be at least about 1 volume% of the fluid, and up to such an amount that the tar stabilizing polymer is precipitated out of the fluid. In certain embodiments, the concentration of tar stabilizing polymer in the treatment fluid may be in the range of about 1% to about 70% by volume of the fluid. In certain embodiments, the concentration of the tar stabilizing polymer in the treatment fluid may be in the range of about 1% to about 10% by volume of the fluid. In certain embodiments, the stabilizing polymer tar can be added to the treatment fluid in the form of a latex-type emulsion or dispersed particles. One skilled in the art, with the benefit of this Description, will be able to determine the appropriate concentration of the tar stabilizer polymer in the fluid for a particular application.

In some embodiments, the treatment fluid may further comprise an aqueous fluid. For example, the tar stabilizing polymer may be dispersed in the aqueous liquid to form the. treatment fluid. In one embodiment, a latex emulsion comprising a tar stabilizing polymer may be dispersed in the aqueous fluid. In another embodiment, a powder comprising a tar stabilizing polymer may be dispersed in the aqueous liquid. The aqueous fluid used in the treatment fluids of the present invention may be fresh water, distilled water or salt water (for example, water containing one or more salts dissolved therein). In certain embodiments, the treatment fluid may be an aqueous-based fluid. Generally, the water can be from any source, provided that it does not contain compounds that undesirably affect other components of the treatment fluid.

In certain embodiments, the treatment fluids of the present invention may further comprise a viscosity agent, for example, to assist in the suspension of the tar stabilizing polymers in the treatment. Suitable viscosifying agents may include, but are not limited to, colloidal agents (eg, clays such as bentonite, polymers and guar gum), emulsion forming agents, diatomaceous earths, biopolymers, synthetic polymers, chitosans, starches, gelatins, or mixtures thereof.

Other additives suitable for use in the underground treatment fluids can also be added to the modalities of the treatment fluids. The treatment fluids of the present invention may comprise any of those additional additives that do not undesirably interact with the tar stabilizing polymer or other fluid components. The treatment fluids used in the methods of the present invention optionally may comprise any number of additional additives, including, but not limited to, salts, surfactants, fluid loss control additives, gases (eg, nitrogen, carbon dioxide) surface modifying agents, tackifiers, foaming agents, corrosion inhibitors, scale inhibitors, catalysts, clay control agents, biocides, friction reducers, antifoaming agents, sealing agents, dispersants, flocculants, hydrogen sulfide scavengers, dioxide scavengers carbon, oxygen scavengers, lubricants, viscosity separators, weighting agents (e.g., barite), relative permeability modifiers, resins, particulate materials (e.g., carrier particles), wetting agents, coating enhancement agents, and the like . Weighting agents can be used, for example, in treatment fluids, such as drilling fluids to provide a sufficient density to, for example, control formation pressures. One skilled in the art, with the benefit of this disclosure, will be able to determine which additional additives are appropriate for a particular application.

As will be appreciated by those skilled in the art, with the benefit of this disclosure, the modalities of the treatment fluids may be used in a variety of underground operations for the treatment of tar residing in a well borehole. With the treatment of tar with a tar stabilizing polymer, as described herein, the adhesiveness of tar can be reduced, facilitating the removal of tar from a shaft well or other surface, for example. In some embodiments, the present invention describes a method comprising tar resident in contact with the pit of a well with a tar stabilizing polymer, and allowing the tar stabilizing polymer to interact with the tar to at least partially reduce the tendency of the tar to adhere to a surface. In this way, it is possible to facilitate the removal of tar from the shaft well or other surface can. In one embodiment, a treatment fluid comprising the tar stabilizing polymer can be introduced into the wellbore so that the tar stabilizing polymer has contact with the tar. One skilled in the art, with the benefit of this disclosure, should be able to determine the appropriate amount of time - to allow the tar stabilizing polymer to interact with the tar in order to at least partially reduce the adhesiveness of the tar. In certain embodiments, after the tar stabilizing polymer was allowed to interact with the tar, then the tar can be removed from the wellbore with any possible means of the given application.

In some embodiments, a treatment fluid comprising a tar stabilizing polymer may be introduced into the wellbore as a drilling fluid. For example, an auger can be used to expand the hole in the well, and the treatment fluid that It comprises the tar stabilizing polymer can circulate in the hole of the well up to the bit. In some embodiments, the drilling fluid may pass through the interior of a drill string, which exits at a distal end thereof (eg, through the auger), and returns to the surface through an annular space. between the drill string and the wall of a well. Among other things, the circulating drilling fluid must lubricate the drillstring, bring the drilling cuttings to the surface and / or balance the formation pressure exerted on the wellbore. In certain embodiments, the drilling fluid may have a density in the range of about 0.899 kg / 1 (7.5 pounds per gallon) to about 2.15 kg / 1 (18 Ib / gal); and alternatively from about 1.43 kg / 1 (12 pounds / gal) to about 2.15 kg / 1 (18 lb / gal).

In some embodiments, tar can be found while drilling the wellbore. The wellbore zones can be in. Contact intentionally or not during drilling. For example, modalities may include drilling in pit areas that contain tar sands. The term "tar sands" does not imply or require any specific present quantity of tar. In some modalities, one or more Wells of generally horizontal wells can be drilled through the tar sands. According to the present embodiments, a tar stabilizing polymer can be included in the drilling fluid while the hole in the well is being tapped in these tar-containing zones. In this way, the. The tar stabilizer polymer contained in the treatment fluid can modify at least a part of the tar so that it is less tacky, making it less likely to adhere to the drill string and other tubular used in the drilling operations. Tar modified in this way can produce tar cuts that can be removed more effectively from the well bore. In addition, the tar that is drilled may be less likely to flow into the hole of the well or the underground formation since the plastic properties of the tar can be altered. In the same way, the treated tar that forms on the surface of the hole of the well can act to stabilize the well hole. In addition, the tar treated with the tar stabilizing polymers can be separated from a treatment fluid by passing the fluid through a grid or similar separation apparatus.

In some embodiments, a treatment fluid comprising a tar stabilizing polymer may be introduced into the pit of a well as a pill for local treatment, where the treatment fluid is introduced into the wellbore to interact with the tar in a specific part of the wellbore. In some embodiments, the pill can be introduced into an area of the well pit containing tar sands. The pill should enter the hole of the well and interact with the tar residing in the well, thus modifying at least a part of the tar, so that it becomes less sticky. In certain embodiments of this type, the tar stabilizing polymer is allowed to interact with the tar resident in the well for at least a sufficient time to at least partially reduce the adhesiveness of the tar. In some modalities, this may be more than about an hour. In others, more time will be required to at least partially reduce the adhesiveness of the tar, depending on, among other factors, the temperature inside the wellbore and the amount of tar in the part of the wellbore under treatment. An expert in the art, with the benefit of this description, will be able to determine the. appropriate amount of time to allow the tar stabilizing polymer to interact with the tar. In certain modalities, after the Tar stabilizing polymer interacts with the tar, then the tar can be removed from the pit well with any practicable means for the given application. In some embodiments, the pill may be used before and / or after a non-aqueous piercing fluid, which may comprise any number of organic liquids, including, but not limited to, mineral oils, synthetic oils, esters, paraffin oils, diesel oil and the like.

In some embodiments, the amount of the tar stabilizing polymer present in the treatment fluid can be monitored while the tar stabilizing polymer flows through the well. For example, once a unit of the tar stabilizing polymer in a treatment fluid is allowed to interact with a tar unit in a wellbore, the tar stabilizer polymer unit could decrease from the treatment fluid and therefore it is unable to interact with additional tar. For this reason, it may be desirable to monitor the concentration of the tar stabilizing polymer in the treatment fluid to determine if more should be added. In some embodiments, the tar stabilizer polymer may be added to the treatment fluid before the treatment fluid is treated. introduce, for example, a batch mixing process into the hole of the well. In some embodiments, it may be desirable to continue adding the tar stabilizing polymer in the treatment fluid (eg, in the "on the fly" mixture) in accordance with. the monitored concentration of the tar stabilizing polymer in the treatment fluid. In some embodiments, the concentration of tar stabilizing polymer in the treatment fluid can be monitored directly. In some embodiments, the concentration of tar stabilizing polymer in the treatment fluid can be monitored indirectly by measuring the decrease in tar stabilizing polymer of the treatment fluid. The concentration of the tar stabilizing polymer in the treatment fluid can be monitored, for example, by means of analytical polymer spectroscopy, chromatography, gravimetry and quantitative precipitation.

To facilitate a better understanding of the present invention, the following examples of specific modalities are given. In no way should the following examples be read to limit or define the entire scope of the invention.

EXAMPLE 1 A water-based fluid was formulated as shown in Table 1.

A water-based fluid was also formulated as shown in Table 2.

A 50g sample of tar sand (25% tar in bulk) was placed in a first 1/2 laboratory barrel along with 133. lg of base fluid 1 and a steel test rod. A 12.5g sample of tar was placed in a second 1/2 laboratory barrel along with 216.9 g of base fluid 2 and a steel test rod. The barrels were hot rolled for 16 hours at 66.7 ° C (about 150 ° F) below 14.06 kg / cm2 (200 psi) in a rolling chamber, and the test bars were inspected for tar build-up. The Base Fluid 1 was contaminated with tar sand, and the tar accumulated on the test rod. The Fluid 2 Base was contaminated with tar and the tar accumulated on the test rod.

EXAMPLE 2 As shown in Table 3, the two fluid samples were prepared using the base fluid 1 described in Table 1. The fluid samples are designated in Sample A and B in the table below. The styrene acrylate polymers used in this example were obtained as an emulsion and were used as such. The Baracor 700 ™ Corrosion Inhibitor is an anti-corrosion additive commercially available from Halliburton Energy Services, 'Houston, Texas. After the hot rolling for 16 hours at 66.7 ° C (150 ° F approx.) below 14.06 kg / cm2 (200 psi) in a rolling chamber, the mass of the test rod was determined with any accumulation of tar and after that the accumulated tar was cleaned. These masses and the mass of the tar buildup for each sample are presented in Table 3.

EXAMPLE 3 In this example, the tar was selected from fluids containing tar. The base fluid 1 was combined with the tar sand and, in two cases, a treatment additive, as shown below in Table 4. The tar-containing fluids were hot rolled and then poured with a sieve material. vibratory to evaluate the possible properties of sieve obstruction. A sieve can be considered valid if the tar is sticky and begins to seal / clog the sieve openings thus preventing a fluid from draining effectively. Sample C was a reference base for untreated and adhesive tar, and left the sieve to become dirty. Sample D was an unsuccessful treatment with a sodium salt, which also caused the sieve to become dirty. Sample E was a chemical-tar treatment with styrene acrylate polymers that resulted in a non-adhesive tar and minimized sieve becoming soiled. The styrene acrylate polymers used in this example (E) were the same as in the previous tests.

EXAMPLE 4 In this example, another water-based fluid was formulated as shown in Table 5. This water-based fluid in Table 5 appears as Base Fluid 3.

The fluid samples were prepared by adding the styrene copolymer to Base Fluid 3 in different amounts to determine its effect on pit pit pit, as shown in Table 6 below. The fluid samples are shown in Samples F and G of the following table. The styrene copolymer was obtained from a latex emulsion (approximately 45% active weight) and used as received. The Baracor 700MN 'corrosion inhibitor available from Halliburton Energy Services, Inc. was also added to the fluid samples, as indicated in the following table. Tar sands with approximately 80% sands and 20% bitumen by weight were used for this test. A steel rod was used to simulate the interaction of the drill string with the tar sands. For each test, the tar sands were placed in a laboratory barrel along with the respective fluid sample and the steel rod. The system was accelerated by laminating at 25 ° C (approximately 77 ° F) for 16 hours in a rolling chamber. The mass of the steel rod was determined before the test without accumulated tar and after the accumulated tar test. The mass of the rod was also measured after rinsing with a water jet. These masses and the accumulated tar mass for each sample are reported in the following table. very little sticky and easy to remove.

As shown in the table above, the tar lands were treated with the styrene copolymer with the tar that does not get sticky by nature. A part of the tar stuck lightly to the steel rod but was only mechanically pressed to the rod as it slid easily with a jet of water, thus revealing the non-stick nature of the tar.

EXAMPLE 5 In this example, two additional fluid samples were prepared by adding an acrylate copolymer of Base Fluid 3 in different amounts to determine its effect on pit pit pit, as shown in Table 7. Fluid samples they are designated in Samples H and I in the following table. The acrylate copolymer was obtained as a latex emulsion (about 45% by active weight) and used as received. The Baracor 700 ™ corrosion inhibitor, available from Halliburton Energy Services, Inc., was also added to the fluid samples, as indicated in the following table. The tar sands, with approximately 80% sand and 20% bitumen in weight were used for this test. A steel bar was used to simulate the interaction of drill string with tar sands. For each test, the tar sands were placed in a laboratory barrel along with the respective fluid sample and the steel rod. The system was then accelerated by rolling at about 25 ° C (about 77 ° F) for 16 hours in a rolling chamber. The mass of the steel rod was determined before the test without accumulated tar and after the accumulated tar test. The mass of the rod was also measured after rinsing with a jet of water. These masses and the accumulated tar mass for each sample are presented in the following table.

Although the compositions and methods are described, in terms of "comprising", "containing" or "including" various components or steps, compositions and methods can also "consist essentially of" or "consist of" the various components and steps. Whenever a numerical range is described with a lower limit and an upper limit, any number and any included range within the range is described in a specific way. In particular, each range of values (in the form of "about A to about B," or the equivalent form, "from about A to B," or equivalently, "about AB") described in this document means that successively establishes each number and range encompassed within the broadest range of values. On the other hand, the indefinite articles "a" or "an", as used in the claims, are defined herein to mean one or more of one of the elements that it introduces. In addition, the terms of the claims have their common and ordinary meaning, unless the patentee explicitly and clearly defines the contrary.

Therefore, the present invention is well adapted to fulfill the aforementioned purposes and advantages, as well as those that are inherent thereto. The particular embodiments described above are illustrative only, since the present invention can be modified and practiced in different but equivalent ways by those skilled in the art having the benefit of the teachings of this document. Although particular embodiments are discussed, the invention covers all combinations of all those modalities. In addition, there are no limitations intended for the details of construction or design shown herein, except as described in the following claims. Therefore, it is evident that the illustrative particular embodiments described above can be altered or modified and all variations are considered within the scope and spirit of the present invention.

Claims (28)

NOVELTY OF THE INVENTION Having described, the present invention is considered as a novelty, and therefore the content of the following is claimed as property: CLAIMS

1. A method for the treatment of pit pit pit characterized in that it comprises: contacting tar residing in the pit of a well with a tar stabilizing polymer comprising at least one polymer selected from the group consisting of a styrene polymer, an acrylate polymer, a styrene acrylate polymer and any combination of the same; Y allowing the tar stabilizing polymer to interact with the tar to at least partially reduce the tendency of the tar to adhere to a surface.

2. The method according to claim 1, characterized in that the tar stabilizing polymer comprises the styrene polymer, the styrene polymer comprises a styrene copolymer.

3. The method according to claim 2, characterized in that the styrene copolymer comprises styrene in an amount within the range of from about 90% to about 100% by weight.

4. The method according to claim 3, characterized in that the styrene copolymer comprises styrene co-monomers.

5. The method according to claim 1, characterized in that the tar stabilizing polymer comprises the acrylate polymer, the acrylate polymer comprises an acrylate copolymer.

6. The method according to claim 5, characterized in that the acrylate copolymer comprises two or more units selected individually from the group consisting of -acrylate,. -methacrylate, -ethylacrylate, propyl acrylate, -butyl acrylate, -tert-butylacrylate, n-hydroxyethyl methacrylate, potassium acrylate, pentabromobenzyl acrylate, methyl methacrylate, ethyl methacrylate, acrylate. n-nitrophenyl, methyl 2 (acyloxymethyl) acrylate cyclohexyl acrylate, n-ethylhexyl acrylate and any derivatives thereof.

7. The method according to claim 1, characterized in that the tar stabilizing polymer comprises the acrylate polymer of styrene, the styrene acrylate polymer comprises a copolymer of styrene acrylate.

8. The method according to claim 1, characterized in that it also comprises the dispersion of at least one latex emulsion comprising the tar stabilizer polymer in an aqueous fluid to form a treatment fluid, and the introduction of the treatment fluid into the recess from the well.

9. The method according to claim 1, further characterized in that it comprises the dispersion of the tar stabilizing polymer in powder form in an aqueous fluid to form a treatment fluid; and the introduction of the treatment fluid into the wellbore.

10. The method according to claim 1, characterized in that the tar stabilizing polymer is present in a treatment fluid in an amount of about 1% to about 70% by volume of the treatment fluid.

11. The method according to claim 1, characterized in that the tar stabilizing polymer is present in a treatment fluid in an amount of about 1% to about 10% by volume of the treatment fluid.

12. The method according to claim 1, characterized in that the tar stabilizing polymer is present in a treatment fluid, the fluid of The treatment further comprises a viscosifying agent selected from the group consisting of a colloidal agent, a clay, a polymer, guar gum, an emulsion forming agent, diatomaceous earths, a biopolymer, a synthetic polymer, chitosan, a starch, a gelatin and any mixture thereof.

13. The method according to claim 1, characterized in that the tar stabilizing polymer is present in a treatment fluid, the treatment fluid further comprises at least one additive selected from the group consisting of a salt, a surfactant, a control additive. of fluid loss, a gas, nitrogen, carbon dioxide, a surface modifying agent, an adhesion agent, a foaming agent, a corrosion inhibitor, an inhibitor of scale, a catalyst, a clay control agent, a biocide, a friction reducer, an antifoaming agent, a sealing agent, a dispersant, a flocculant, a hydrogen sulfide sequestrant, a carbon dioxide sequestrant, an oxygen scavenger, a lubricant, a viscosifier, a separator viscosity, a weighting agent, barite, a relative permeability modifier, a resin, a particulate material, a particulate support agent, an age nte humectant, a coating intensifying agent, and any combination of them.

14. The method according to claim 1, characterized in that the tar stabilizing polymer is present in a treatment fluid, and wherein the method comprises the circulation of the treatment fluid to a drill bit to remove the cuttings from the drill bit .

15. The method according to claim 1, characterized in that the tar stabilizing polymer is present in a treatment fluid, and wherein the method further comprises introducing the treatment fluid into the well as a pill for a local treatment of the tar pit well.

16. The method according to claim 1, characterized in that it further comprises monitoring the concentration of the tar stabilizing polymer in a treatment fluid.

17. The method according to claim 1, characterized in that the tar stabilizing polymer is introduced into a pit area comprising tar sands.

18. A method for the treatment of pit pit pit, characterized because I understood: use a drill bit to expand the hollow of a well in an underground formation comprising tar; Y circulating a drilling fluid to the drill bit to remove the cuttings from the drill bit, wherein the drilling fluid comprises an aqueous fluid and a tar stabilizer polymer comprising at least one polymer selected from the group consisting of a styrene polymer, an acrylate polymer, a styrene acrylate polymer, and any combination thereof.

19. The method according to claim 18, characterized in that the underground formation comprises tar sands that make up the tar.

20. The method according to claim 18, characterized in that the tar stabilizing polymer comprises the styrene polymer, the styrene polymer comprises a styrene copolymer.

21. The method according to claim 20, characterized in that the styrene copolymer comprises styrene in an amount in the range of about 90% to about 100% by weight.

22. The method according to claim 20, characterized in that the styrene copolymer comprises styrene co-monomers.

23. The method according to claim 18, characterized in that the tar stabilizing polymer comprises the acrylate polymer, the acrylate polymer comprises an acrylate copolymer.

24. The method according to claim 23, characterized in that the acrylate copolymer comprises two or more units selected individually from the group consisting of -acrylate, -methacrylate, -ethylacrylate, propylacrylate,. -butylacrylate, -tert-butylacrylate, n-hydroxyethyl methacrylate, potassium acrylate, pentabromobenzyl acrylate, methyl methacrylate, ethyl methacrylate, n-nitrophenyl acrylate, methyl 2- (acyloxymethyl) acrylate, cyclohexyl acrylate, acrylate of n-ethylhexyl and any derivatives thereof.

25. The method according to claim 18, characterized in that the tar stabilizing polymer comprises the styrene acrylate polymer, the styrene acrylate polymer comprises a styrene acrylate copolymer.

26. The method according to claim 18, characterized in that the tar stabilizing polymer is present in the drilling fluid in an amount of about 1%. to approximately 10% by volume of the drilling fluid.

27. The method according to claim 18, characterized in that the drilling fluid further comprises a weighting agent.

28. A treatment fluid, characterized in that it comprises: an aqueous fluid; Y . A tar stabilizing polymer comprising at least one polymer selected from the group consisting of a styrene polymer, an acrylate polymer, a styrene acrylate polymer and any combination thereof.