Non-aqueous, acid-soluble, high-density fluids for well completion and method

FIELD: oil and gas industry.

SUBSTANCE: method involves displacement of the first fluid on a hydrocarbon basis, which is present at a non-cased interval of a well shaft, with the second fluid, contact of the second fluid to acid natural formation fluid so that the third fluid is formed, where the second fluid contains aqueous liquid dispersed as a disperse phase in oily liquid, and surface active substance (SAS) based on amine and chosen so that the above contact performs protonation of at least some part of SAS with formation of the third fluid included in an emulsion containing oily liquid reversely dispersed as a disperse phase in aqueous liquid, where at least 40 vol % of any solid substances that do not refer to a proppant and are present in the fluid are water-soluble at pH that is lower than or equal to 6.5, and SAS has the above said structure. An underground well treatment system. The fluid containing a reversible invert emulsion containing an aqueous liquid dispersed as a disperse phase in oily phase and the above SAS.

EFFECT: improving destruction efficiency of a filter cake.

20 cl, 6 dwg, 3 tbl, 2 ex

 

The LEVEL of TECHNOLOGY

Reversible invert emulsion drilling fluid emulsion based water-in-oil" used for drilling boreholes penetrating one or more of the productive strata of crude oil. Such emulsion drilling fluid lubricates the drill bit and reduce the total time required for drilling of boreholes. These drilling fluids are emulsions of water-in-oil", where the water or aqueous phase dispersed in a continuous phase of hydrocarbon-based or based oily liquid. Such emulsion "water in oil", used as drilling fluids, can be stabilized nonionic amine emulsifier, and have a relatively high pH value, which ensures that the emulsifier keeps the non-ionic hydrophobic character during drilling.

When drilling the well reached its total depth and has been able to penetrate one or more oil-bearing formations, then emulsion drilling fluid emulsion based water-in-oil" in contact with externally supplied acid, which protonium nonionic amine emulsifier, whereby he receives a cationic charge, which increases its solubility in water. "Externally supplied" means that the acid or other fluid is pumped or otherwise injected into the wellbore from the surface. Received proton�created water-soluble emulsifier has a hydrophilic property and the resulting oil and water phases of the emulsion invert, giving the emulsion oil-in-water" in the wellbore. Emulsion oil-in-water has a lower viscosity than the emulsion "water in oil", from which it was formed.

Inverted low viscosity emulsion oil-in-water" wets reservoirs to increase oil production. In addition, the fluid on the basis of emulsions of oil-in-water" it is easier to remove by washing and thus to facilitate subsequent operations.

Acid, which is used for bending the drilling fluid emulsion based water-in-oil" and which caused his conversion, is usually in the form of externally supplied water acid solution, which is injected into the well. However, it is known that such operations give emulsions of aqueous acid solution - crude oil and sedimentation of crude oil. Attempts to prevent formation of emulsions "aqueous acid solution - crude oil and sedimentation of crude oil include the use of anionic sulfonate surfactants in acid solution. Although anionic sulfonate surfactants work well to prevent the formation of emulsions "aqueous acid solution - crude oil and sludging of crude oil anionic sulfonate surfactants may react with amine emulsifier �donkey its protonation by the acid, which leads to the emulsifier, which becomes water soluble and does not pay an emulsion of "water in oil" emulsion type "oil in water". This may prevent the wetting of water and faster cleaning, but used aqueous acid solution is added to the internal aqueous phase of the emulsion, which leads to increased viscosity of the emulsion. Thus formed a highly viscous emulsion "water in oil" can be difficult to remove and can cause damage to productive formations of crude oil, through which the wellbore. In addition, the deliberate addition of acid for the treatment of the emulsion into the wellbore leads to additional costs and risks in the process.

BRIEF DESCRIPTION of the SEVERAL VIEWS of the DRAWINGS

Variants of embodiment of the invention relating to non-aqueous acid-soluble, high-density fluid for the well completion and method described with reference to the following figures. The same numerical designations are used in all the figures, which refer to the same elements and components.

Fig. 1 illustrates the wellbore after drilling and prior to completion according to the embodiment of the embodiment of the present invention;

Fig. 2 shows the equipment of the column for the well completion, installed in the wellbore according to the embodiment of the embodiment of the present invention;

Nafig. 3 shows a reversible invert emulsion fluid, the replacement fluid hydrocarbon-based in the wellbore according to the embodiment of the embodiment of the present invention;

Fig. 4 shows the establishment of equipment column for completion in the wellbore according to the embodiment of the embodiment of the present invention;

Fig. 5 shows the contacting reversible invert fluid-based emulsion "water in oil" with the natural formation fluid emulsion oil-in-water" according to the embodiment of the embodiment of the present invention; and

Fig. 6 shows a block diagram of a method according to the embodiment of the embodiment of the present invention.

Summary of the INVENTION

The present application relates in one embodiment of the invention, the method comprising the displacement of the first fluid is hydrocarbon-based, present in the uncased interval of the wellbore, the second fluid and contacting the second fluid with the natural formation fluid for a time period sufficient to produce a third fluid, at least part of the second fluid wherein the second fluid comprises a reversible invert emulsion containing an aqueous fluid, a reversible dispergirovannoyj as a dispersed phase in an oily liquid, and a surfactant based on amine, where the surfactant on �Snov, amine selected that contacting the second fluid with the natural formation fluid for a sufficient period of time protonium at least part of the surfactant based on amine in the second fluid with the formation of the third fluid comprising an emulsion containing oily liquid, dispergirovannoyj as a dispersed phase in an aqueous fluid, where at least 40% vol. solids that are not related to proppant that are present in the second fluid are water-soluble at acidic pH or at a pH less than or equal to 6.5.

The present application also relates in another embodiment of the invention, the fluid comprising a reversible invert emulsion containing an aqueous fluid, a reversible dispergirovannoyj as a dispersed phase in an oily liquid and a surfactant based on amine, where the surfactant based on amine selected so that contacting the fluid with the natural formation fluid for a sufficient period of time protonium at least part of the surfactant based on amine in the fluid with a second fluid comprising an emulsion containing oily liquid, dispergirovannoyj as a dispersed phase in an aqueous liquid, where at least 40% vol. solids that are not related to the proppant, which�s are present in the fluid, are water-soluble at acidic pH or at a pH less than or equal to 6.5, where the surfactant based on amine has the structure:

where R1is C8-C24hydrocarbon radical;

where R2and R3are independently selected from C2-C10substituted or unsubstituted hydrocarbon radical, ethylene oxide, propylene oxide, or combinations thereof; and

where a+b is greater than or equal to 2.

In the following embodiment of the invention the invention provides a fluid for processing near-wellbore zone, comprising a reversible invert emulsion containing an aqueous fluid, a reversible dispergirovannoyj as a dispersed phase in an oily liquid, and a surfactant based on amine, where the surfactant based on amine selected so that contacting of fluid for processing near-wellbore zone with acid fed, at least partially, the natural formation fluid for a sufficient period of time, protonium at least part of the surfactant based on amine with the formation of an emulsion containing oily liquid, dispergirovannoyj as a dispersed phase in an aqueous fluid, where the fluid for processing near-wellbore zone has a density of at least 1617,3 kg/m3and �least about 40 vol.% any solids present in the fluid for treatment of near-wellbore zone, are water-soluble at acidic pH or at a pH less than or equal to 6.5.

In another embodiment of the invention provides a method that includes drilling an uncased interval of a well bore with a reversible invert emulsion drilling fluid and contacting the invert emulsion drilling fluid with the natural formation fluid for a time period sufficient to form an emulsion with a continuous aqueous phase, at least part of the drilling fluid, where the drilling fluid includes an invert emulsion containing an aqueous fluid, a reversible dispergirovannoyj as a dispersed phase in an oily liquid and a surfactant based on amine, where the surfactant based on amine selected what contacting the drilling fluid with the natural formation fluid for a sufficient period of time protonium at least part of the surfactant based on amine to form an emulsion with a continuous aqueous phase containing an oily liquid, dispergirovannoyj as a dispersed phase in an aqueous fluid, where the drilling fluid has a density of at least 1617,3 kg/m3and at least 40% vol. any solids present in the drilling fluid, are in�directoryname at acidic pH or at a pH less than or equal to 6.5.

This section is the essence of the invention is presented in order to introduce a number of concepts that are further described below in the detailed description. This section is the essence of the invention is not intended to identify key or important features and is not intended for use as a means of limiting the claimed subject invention.

DETAILED DESCRIPTION

First, it should be noted that in the development of any such actual variant embodiment of the invention take many specific decisions on its implementation to achieve specific goals set by the developer, such as consistency with the corresponding system and related business restrictions, which will vary from one implementation to another. In addition, it should be understood that such a development might be complex and time-consuming, but, nevertheless, common to specialists in this field of technology due to this description. In addition, used/disclosed here, the composition may also include some components other than those specified. In section of the invention and this detailed description, each numerical value should be read once as a variable by the term "about" (if it is not already expressed as modified) and then read again to�to not changed unless otherwise specified in the context. Also in section of the invention and this detailed description it should be understood that a concentration range that is described as used, suitable, or the like, implies that any and every concentration within the range, including the endpoints should be considered as specified. For example, "the range of 1 to 10" should be read as referring to all possible numbers from the continuous set between approximately 1 and approximately 10. Thus, even if specific data points within the range, or even if no data points within the range, are explicitly identified or refer to only a few specific numbers, it should be understood that the inventors are aware and understand that any and all data points in the range must be treated as specified, and that inventors possessed the knowledge of the entire range and all points within the range.

As indicated in the description and the claims, "approximately" means including "when".

The following definitions are provided to help specialists in the art to understand the detailed description.

The term "treatment" or "treating" refers to an underground operation, which uses a fluid with the desired function and/or for a desired purpose. The term "processing" or "processing�ivanie" does not imply any particular action by the fluid.

The term "hydraulic fracturing" refers to the process and techniques of rupture of geological formations and the creation of cracks, i.e. the rock around the wellbore by pumping fluid at very high pressure (pressure above defined clamping pressure cracks), in order to increase the rate of production from an oil reservoir. Methods of hydraulic fracturing in other ways, using conventional techniques known in the art.

Used herein, the new numbering scheme for groups of the Periodic system are taken from Chemical and Engineering News, 63(5), 27 (1985).

Used here, the term "liquid composition" or "liquid medium" refers to a material which is liquid at the conditions used here. For example, the liquid medium may include water and/or organic solvent, which is above the freezing point and below the boiling point of a material at a specific pressure. Liquid medium can also refer to the supercritical fluid.

The term "solids, non-proppant" as used here, refers to solids, which may include various weighting agents, but which does not include proppants, which remain insoluble to carry out their functions. Examples of solids include proppant solids for gravel packs, sand and�such.

Trunks wells that were previously drilled with the receipt of one or more of the productive strata of crude oil using reversible drilling fluids based emulsion "water in oil", stabilized by nonionic emulsifiers with a high pH value. When the borehole reaches its full depth, emulsion "water in oil" is in contact with the aqueous acidic solution to invert the emulsion, that is, in order to form a low viscosity emulsion of "oil in water", in which the water wets the surface of the formation in the wellbore and facilitates cleaning of the wellbore. In an embodiment of the invention the method comprises the displacement of the first fluid is hydrocarbon-based, present in the uncased interval of the wellbore, the second fluid and contacting the second fluid with the natural formation fluid for a time period sufficient to form a third fluid, at least part of the second fluid wherein the second fluid comprises a reversible invert emulsion containing an aqueous liquid, dispergirovannoyj as a dispersed phase in an oily liquid, and a surfactant based on amine selected so that contacting the second fluid with the natural formation fluid for a sufficient period of time protonium, at least part of the surface�of active substances on the basis of amine in the second fluid, to form a third fluid comprising an emulsion containing oily liquid, dispergirovannoyj as a dispersed phase in an aqueous fluid, where at least 40% vol. solids that are not related to proppant that are present in the second fluid are water-soluble at acidic pH or at a pH less than or equal to 6.5.

Fig. 1 shows an uncased borehole with the barrel 10 after drilling and prior to completion according to the embodiment of the embodiment of the present invention. As shown in Fig. 1, the uncased interval of the well bore 10 is located below the upper cased interval 34 of the wellbore 10, but may also be located in the upper uncased interval of the wellbore, or combinations thereof. Wells with openhole barrel 10 contains a fluid hydrocarbon-based 12. Filter cake 14 is deposited on the front surface of the wells with openhole barrel 10. In an embodiment of the invention, the first fluid is a hydrocarbon-based 12 can circulate for a time period sufficient to remove at least part of any drill cuttings debris 32 present in the wellbore, prior to displacement of the first fluid is a hydrocarbon-based 12.

Layer 16 includes natural fluid 18 containing carbon dioxide, hydrogen sulfide and/or similar substance so that the pH for p�defined fluid less than or equal to approximately 6.5. The hydrostatic pressure drop 30 can be positive (represented by the symbol "+" in the figure) to prevent the natural flow of the fluid 18 into the borehole with the uncased wellbore 10.

In an embodiment of the invention shown in Figure 2, the equipment column for the well completion 20 is set and/or placed in the borehole with the uncased wellbore 10 in the presence of drilling fluid hydrocarbon-based 12. In an alternative embodiment of the invention, the equipment column for the well completion 20 may be installed and/or placed in the borehole with the uncased wellbore 10 after the displacement of the drilling fluid hydrocarbon-based 12, also referred to herein as the first fluid, the second fluid comprising a reversible invert emulsion containing an aqueous fluid, a reversible dispergirovannoyj as a dispersed phase in an oily liquid, and a surfactant based on amine, where the surfactant based on amine selected so that contacting the second fluid with the natural formation fluid 18 for a sufficient period of time protonium at least part of the surfactant based on amine in the second fluid with the formation of the third fluid, comprising, an emulsion containing oily liquid, dispergirovannoyj as a dispersed �Aza in an aqueous liquid, where at least 40% vol. solids that are not related to proppant that are present in the second fluid are water-soluble at acidic pH or at a pH less than or equal to 6.5. The hydrostatic pressure drop 30 can be positive (represented by the symbol "+" in the figure) to prevent the natural flow of the fluid 18 into the borehole with the uncased wellbore 10.

As shown in Fig. 3, the first fluid is a hydrocarbon-based 12 replace the second fluid 22, comprising a reversible invert emulsion containing an aqueous fluid, a reversible dispergirovannoyj as a dispersed phase in an oily liquid, and a surfactant based on amine, where the surfactant based on amine selected so that contacting the second fluid with the natural formation fluid 18 for a sufficient period of time leads to the protonation of at least part of the surfactant based on amine in the second fluid 22 to form a third fluid (see Figure 5) comprising the emulsion, containing oily liquid, dispergirovannoyj as a dispersed phase in the aqueous fluid, where at least 40% vol. solids that are not related to the proppant, which are located in the second fluid 22, are water-soluble at pH less than or equal to 6.5. Filter cake 14 still� may be present on the surface of layer 16. In an alternative embodiment of the invention, filter cake 14 can be the result of deposition from the second fluid 22. The hydrostatic pressure drop 30 can be positive (represented by the symbol "+" in the figure) to prevent the natural flow of the fluid 18 into the borehole with the uncased wellbore 10.

Fig. 4 shows the installation of equipment column for the well completion in the range of 20 wells with openhole barrel 10 according to the embodiment of the invention the present description. As shown in Fig. 4, the packers for the well completion 24 may be positioned so as to capture the second fluid 22 in the annular space in contact with the filtration crust 14. As also shown in Fig. 4, the packers for the well completion 24 can be placed in the reservoir with low permeability and/or in the separating compartment 26, which may be in the uncased borehole with the barrel 10. The hydrostatic pressure drop 30 may be neutral or balanced (represented by the symbol "0" in the figure) to prevent the natural flow of the fluid 18 into the borehole with the uncased wellbore 10 and to prevent further penetration of the filter cake 14 into the reservoir 16.

Fig. 5 shows the contacting of the second fluid 22 - invert emulsion "water in oil" - with a sour natural plastilina 18 by diffusion with the formation of the emulsion oil-in-water", called here the third fluid 28, in the uncased borehole with the barrel 10 according to the embodiment of the invention the present description. The phase reversal is accomplished by diffusion of acidic fluids from the reservoir (natural formation fluid 18) to the second fluid 22 with obtaining emulsion oil-in-water". The third fluid 28 becomes hydrophilic and therefore facilitates removal of the filter cake 14, formally located on the surface of layer 16. Then the well can be further stimulated by the action of acid, or the like. The hydrostatic pressure drop 30 may be neutral or balanced to negative (represented by the symbol "0" and " - " in the figure) to allow the natural fluid 18 to flow into the well with openhole barrel 10 due to diffusion and/or pressure drop.

As shown in Fig. 6 according to the embodiment of the invention, the method (100) may include a displacement of the first fluid is hydrocarbon-based, in the uncased interval of the wellbore, the second fluid (102). The method may in some cases enable circulation of the first fluid is a hydrocarbon-based during the period of time sufficient to remove at least part of any drill cuttings debris or filtration crust present in the wellbore before Vitesse�amount of force the first fluid is a hydrocarbon-based (101). The method may in some cases enable the positioning node of the well completion in an uncased interval of the well bore in the presence of the first fluid (105). The method may further include the establishment of packers host completions in the well bore to hold the second fluid in the annular space in contact with the filtration cortex (106). The method may further include contacting the second fluid with a sour natural formation fluid for a time period sufficient to form a third fluid, at least part of the second fluid (103). The method may in some cases enable the displacement of the third fluid fluid for the well completion (104) and/or other means for the well completion, well-known in the art.

In an embodiment of the invention, the interval may first be drilled with a conventional drilling fluid hydrocarbon-based, such as drilling fluid hydrocarbon-based with heavier particles of barite, drilling fluid hydrocarbon-based or the like as the first fluid. Before positioning the lower node completions in the well normal first fluid may be pumped into circulation at a rate effective to remove at least part of the present wreckage of drill cuttings, for example, by units ' application�ia or erosion of the whole or part of the filter cake in the zone completions, for example, to ensure the reduction of the thickness of ordinary filter cake from the drilling mud, such as, for example, the maximum refinement, achievable by circulating drilling mud. Accordingly, in the embodiment of the invention, the method may further include circulating the first fluid is a hydrocarbon-based during the period of time sufficient to remove at least part of any drill cuttings debris and/or filter cake present in the wellbore prior to displacement of the first fluid is hydrocarbon-based.

In an embodiment of the invention the uncased interval of the well bore may be located below the upper cased interval of the wellbore, the upper uncased interval of the wellbore, or combinations thereof.

In an embodiment of the invention the usual first drilling fluid hydrocarbon-based, present in the uncased interval, can then be at least partially replaced by the second fluid is hydrocarbon-based, including emulsion system "water in oil", which may be reversible emulsion system "water in oil", which inhibits the re-accumulation of insoluble in acid filter cake and promotes the condition where the annular space is located here contain a reduced number of insoluble in acid materials. In an embodiment of the invention the second fluid is compatible with the existing first fluid and/or any fluid for the well completion or other fluids that are added sequentially. In an embodiment of the invention the second fluid hydrocarbon-based includes less than or equal to about 60 vol.%, or less than or equal to about 50 vol.%, or less than or equal to approximately 40% vol., or less than or equal to about 30 vol.%, or less than or equal to about 20 vol.%, or less than or equal to about 10 vol.%, or less than or equal to about 5 vol.%, or less than or equal to about 1 vol.%, or less than or equal to about 0.1 vol.% solids that are not related to the proppant, which are insoluble in acid. For purposes of this invention, a solid substance that is insoluble in acid, refers to a solid substance which is 99.9 wt.% or more insoluble in acidic aqueous solution or a solid substance in which less than about 0.1 wt.% is soluble in acidic aqueous solution having a pH value less than or equal to about 6.5, or having a pH less than or equal to about 6. In an embodiment of the invention the second �luid hydrocarbon-based contains less than or equal to approximately 0.1 wt.% barium sulfate, also known in the art barite.

In an embodiment of the invention, when the wellbore is treated so that the first fluid is displaced at least partially by the second fluid, the processing interval of the wellbore may include a single objective to create a reversible acid-soluble non-aqueous emulsion system of the fluid in the uncased interval and in some cases, conventional non-aqueous fluid in another section of the wellbore, for example in a cased portion of the wellbore located above the considered interval.

In an embodiment of the invention the second fluid in the considered interval, is equivalent to or higher density than the first fluid previously displaced by the second fluid and/or chemically and/or physically compatible with the first fluid. In an embodiment of the invention the second fluid is tolerant to conditions of pressure and temperature and the presence of H2S and/or CO2present in the wellbore a limited period of time. In embodiments of the invention less than 50 wt.% the second fluid present in the wellbore, in the presence of natural fluid does not invert emulsion oil-in-water", also referred to herein as the third fluid, within a time period less than a sufficient period of time required for protonation, at least part of the surfactant based on amine in the second fluid to produce the third fluid comprising an emulsion containing oily liquid, reversible dispergirovannoyj as a dispersed phase in an aqueous liquid. In an embodiment of the invention a surfactant based on amine, the concentration of the surfactant based on amine, a buffer system present in the second fluid, or a combination thereof is selected so that less than 50 wt.% the second fluid present in the wellbore in contact with the acidic nature of the fluid drawn into the emulsion oil-in-water" within 12 hours or less, or within 24 hours, or less, or within 48 hours or less.

In an embodiment of the invention, the node of the well completion may be positioned in uncased interval in the presence of the first fluid, second fluid and third fluid. In an embodiment of the invention, the node positioning completion in an uncased interval in the presence of the first fluid or in the presence of the second fluid when the second fluid is used to drill wells, and the first fluid is not used. In an embodiment of the invention, when the second fluid is in place, you can then take the initial operation of the well completion, including the establishment of one and�and more primary lower isolation packer for completions, which include mechanical isolation packers, and the like, grip or otherwise retain the second fluid in the annular space in contact with the filtration crust.

In an embodiment of the invention the method comprises the displacement of the first fluid with a second fluid disposed in a horizontal well or a borehole with a large inclination of the trunk, which can then be filled with gravel according to methods known in the art. In an embodiment of the invention, the first fluid is not used, and the second fluid according to the present description is used for the formation of a filter cake and is also used in combination with the fluid on the basis of a gravel packer, wherein the second fluid comprises a reversible invert emulsion containing an aqueous liquid, dispergirovannoyj as a dispersed phase in an oily liquid and a surfactant based on amine, where the surfactant based on amine selected so that contacting the second fluid with a sour natural formation fluid for a sufficient period of time protonium at least part of the surfactant based on amine in the second fluid to produce the third fluid comprising an emulsion containing oily liquid, reversible dispergirovannoyj as a dispersed phase in an aqueous fluid�, where at least 40% vol. any solids that are not related to proppant present in the second fluid is water soluble at pH less than or equal to 6.5.

In an embodiment of the invention, the second fluid may then be left in place in the annular space between any installed equipment for well completion and uncased bore. In an embodiment of the invention, the second fluid may be in place when a sand filter or other form of completion equipment positioned in the wellbore before or after gravel packing. In an embodiment of the invention for gravel packing can be performed in the presence of the second fluid using a compatible fluid carrier comprising a cushioning material known in the art. In an embodiment of the invention for gravel packing can be performed after the second fluid will come into contact with the natural formation fluid for a time period sufficient to form a third fluid, at least part of the second fluid wherein the second fluid comprises a reversible invert emulsion containing aqueous fluid reversibly dispersed as a dispersed phase in an oily liquid, and a surfactant based on amine, where the surfactant based on amine you�so early, that contacting the second fluid with the natural formation fluid for a sufficient period of time protonium at least part of the surfactant based on amine in the second fluid with the formation of the third fluid comprising an emulsion containing oily liquid, reversible dispergirovannoyj as a dispersed phase in an aqueous fluid, where at least 40% vol. solids that are not related to proppant that are present in the second fluid are water-soluble at acidic pH or at a pH less than or equal to 6.5.

In an embodiment of the invention, at least part of the second fluid can be replaced in the bottom of the annular space in the well completion other second fluid having even less solids and/or a lower density than the second fluid before or after any form completions equipment that positioned in the wellbore. This second alternative fluid can be used depending on the conditions specified by the received allowable differential pressure generated by the columns of fluid during pumping operations and/or in other situations, as is well understood specialists in this field of technology.

In an embodiment of the invention, the upper cased interval in the wellbore can then �be displaced from a conventional non-aqueous fluid to the fluid for completion on the basis of the net required density of brine, using techniques well known to those skilled in the art.

In an embodiment of the invention after installation of the completion equipment different intervals of a borehole containing the second fluid, and then can be stimulated by contacting the second fluid with the natural formation fluid present in the wellbore for a sufficient time to form a third fluid comprising an emulsion containing oily liquid of the second fluid, reversible dispergirovannoyj as a dispersed phase in the aqueous fluid of the second fluid in combination with natural fluid.

Accordingly, in the embodiment of the invention, at least part of the second fluid is acidified by the natural fluid present in the wellbore to turn the emulsion "water in oil" in the third fluid containing emulsion oil-in-water". In an embodiment of the invention, the third fluid has a lower viscosity than the second fluid. In an embodiment of the invention, the viscosity of the second fluid is higher than the viscosity of the third fluid.

In an embodiment of the invention the second fluid comprises a reversible invert emulsion containing an aqueous fluid, a reversible dispergirovannoyj as a dispersed phase in an oily liquid, and a surfactant based on amine, DG� surfactant based on amine selected that contacting the second fluid with the natural formation fluid present in the wellbore for a sufficient period of time protonium at least part of the surfactant based on amine in the second fluid to produce the third fluid comprising an emulsion containing oily liquid, reversible dispergirovannoyj as a dispersed phase in the aqueous fluid. In an embodiment of the invention, at least 40% vol. solids that are not related to proppant that are present in the second fluid are water-soluble at acidic pH or at a pH less than or equal to 6.5. In an embodiment of the invention the second fluid comprises a buffer system selected so that it has sufficient buffer capacity that contacting the second fluid with the natural formation fluid present in the wellbore for a sufficient period of time protonium at least part of the surfactant based on amine in the second fluid with the formation of the third fluid. In an embodiment of the invention a surfactant based on amine is a component of the buffer system. In an embodiment of the invention a surfactant based on amine is a base and the protonated form of the surfactant at about�Novo amine is a conjugate acid of the buffer system. In an embodiment of the invention, the buffer system contains additional acid paired with a corresponding base and/or base with the corresponding conjugate acid that is different from and (in addition) selected surfactants based on amine.

In an embodiment of the invention, the interval can be chemically stimulated by only contacting the second fluid with the natural formation fluid for a time period sufficient to form a third fluid, at least part of the second fluid, or in combination with other external stimulating means comprising feeding an external stimulating fluid, such as the supply of acid solution in the interval of the wellbore. In an embodiment of the invention suitable external stimulating fluid can be served by dropping the ball or otherwise opening of the chosen interval and the injection of fluid into the reservoir to stimulate treatment wells and the like. In embodiments of the invention supplied from the outside of the stimulating fluid may be an aqueous solution of acid. In embodiments of the invention acid in an aqueous solution of acid may be selected from inorganic acids such as hydrochloric acid, or with organic acids such as acetic acid, ants�Aya acid, glycolic acid or a combination thereof. In embodiments of the invention externally supplied acid is hydrochloric acid and is served in the interval in the form of an aqueous solution of acid having from about 1% to about 36% by weight HCl in the solution or 10% to about 15% HCl by weight.

In an embodiment of the invention enabling processing of the second fluid leads to the treatment of the emulsion with the formation of the third fluid, which in turn leads to destruction of the filter cake and the dissolution of residual acid-soluble solids present in the annular space of the wellbore in the interval, due to the stimulation. This method saves the operation time and increases the potential future results of stimulation without requiring additional and problematic future moves.

In an embodiment of the invention, the method may include positioning node of the well completion in an uncased interval in the presence of a third fluid, i.e. after stimulation. In an embodiment of the invention, the method may further include the displacement of at least part of the third fluid, at least one other fluid for the well completion. In an embodiment of the invention, the method may further include the displacement of a fluid hydrocarbon on�Novo, located above the uncased interval of the well bore, the fluid for the well completion.

In an embodiment of the invention the first fluid includes oily liquid, which is the same as that oily fluid present in the second fluid. In an embodiment of the invention a sufficient period of contact between the second fluid and natural formation fluid required to stimulate the well to produce a third fluid, is defined as the time required for the conversion of more than 50 wt.% the second fluid in the third fluid at the conditions existing in the well, or in simulated conditions representing the environmental conditions of the well. In an embodiment of the invention a sufficient period of contact between the second fluid and natural formation fluid required to stimulate the well to produce a third fluid is at least 12 hours or at least 24 hours or at least 48 hours. In an embodiment of the invention a sufficient period of contact between the second fluid and natural formation fluid required to proteinopathy at least part of the surfactant based on amine, or at least 50 wt.% surfactant based on amine, Pris�according to a second fluid, to get the third fluid, at least part of the second fluid, or at least 50 wt.% the second fluid is at least 12 hours or at least 24 hours or at least 48 hours.

In an embodiment of the invention, the contact between the emulsion "water in oil" and formation fluid present in the well for the formation of the emulsion oil-in-water", does not include physical impact, but is a passive process or a diffusion process where the emulsion "water in oil" (for example, the second fluid) give the opportunity to have contact with the natural fluid present in the borehole, no additional mechanical energy or influence. In an embodiment of the invention, the contact of water in the emulsion "water in oil" (for example, the second fluid) is achieved by closing at least part of the borehole for a period of time sufficient for conversion of at least 50 wt.% fluid containing emulsion "water in oil" (for example, the second fluid) in the fluid comprising the emulsion oil-in-water" (for example, the third fluid). In an embodiment of the invention, at least part of the well is closed for a period greater than or equal to about 12 hours, or greater than or equal to about 24 hours, or greater than or equal to about 48 hours, or greater than or equal�th approximately 100 hours, or greater than or equal to approximately 500 hours.

In an embodiment of the invention the natural formation fluid has an acidic pH. In embodiments of the invention natural fluid contains dissolved carbon dioxide as carbonic acid, hydrogen sulfide or a combination thereof.

In an embodiment of the invention the second fluid contains a surfactant based on amine having the structure:

where R1is C8-C24hydrocarbon radical;

where R2and R3are independently selected from C2-C10substituted or unsubstituted hydrocarbon radical, ethylene oxide, propylene oxide or combinations thereof and where a+b is greater than or equal to 2. In an embodiment of the invention a surfactant based on amine contains from about 2 to about 30 moles of ethylene oxide, propylene oxide or a combination thereof.

As used herein, the term hydrocarbon radical includes C1-20unbranched, branched and cyclic alkyl radicals, C6-20aromatic radicals, C7-20alkyl-substituted aromatic radicals, C7-20arylamidine alkyl radicals, halogen radicals, hydrocarbon radicals with different substituents and the like. In addition two or more� such radicals may together form a condensed ring system, including partially or fully hydrogenated condensed ring systems, or they can form metallocycle with metal. Suitable uglevodonasyschennye radicals include mono-, di - and trisubstituted functional groups, is also relevant here to radicals comprising an element of Group 14, where each of the hydrocarbon groups containing from 1 to 20 carbon atoms. Examples of different hydrocarbon radicals with substituents include substituents containing heteroatoms of Group 15 and/or Group 16. Other functional groups suitable for use as substituents include organic and inorganic radicals, where each of the functional groups contains hydrogen and carbon atoms from Groups 13, 14, 15, 16 and/or 17, or 1 to 20 carbon atoms, oxygen, sulfur, phosphorus, silicon, selenium or their combination. In addition, functional groups may include one or more functional groups substituted with one or more additional functional groups. Examples of functional groups included in the term hydrocarbon radical, include amines, phosphines, ethers, esters, thioethers, alcohols, amides and/or derivatives thereof.

In an embodiment of the invention a surfactant based on amine includes ethoxycarbonyl tall Amin; soya amine; N-alkyl-1,3-d�of aminopropan, where the alkyl is a hydrocarbon, C12to C22or a combination of both. In an embodiment of the invention a surfactant based on amine contains from about 2 to about 30 moles of ethylene oxide, propylene oxide or combinations thereof. In an embodiment of the invention a surfactant based on amine contains from 2 to 30 moles of ethylene oxide.

Used here, the high-density fluid has a density greater than or equal to approximately 1557,4 kg/m3. Suitable examples include FAZEPROtm(M-I SWACO, Houston, TX), which is a mud-based reversible hydrocarbon emulsion. In an embodiment of the invention the second fluid is prepared with a minimal amount of barite or other insoluble in acid weight agents. In an embodiment of the invention the second fluid contains less than or equal to about 60 vol.%, or less than or equal to about 50 vol.%, or less than or equal to approximately 40% vol., or less than or equal to about 30 vol.%, or less than or equal to about 20 vol.%, or less than or equal to about 10 vol.%, or less than or equal to about 5 vol.%, or less than or equal to about 1 vol.%, or less than or equal to about 0.1 vol.%barite or other insoluble in acid weight agents.

In an embodiment of the invention the second fluid comprises a reversible emulsion system having a density of greater than or equal to approximately 1557,4 kg/m3,or greater than or equal to approximately 1617,3 kg/m3to , or greater than or equal to approximately 1677,2 kg/m3to , or greater than or equal to approximately 1737,1 kg/m3to , or greater than or equal to approximately 1797 kg/m3to , or greater than or equal to approximately 1856,9 kg/m3and/or at least 40% vol., or at least 50 vol.%, or at least 60 vol.%, or at least 70 vol.%, or at least 80 vol.%, or at least 90 vol.%, or at least 95 vol.%, or at least 99% vol. solids that are not related to proppant present in the second fluid, based on the total weight of solids, non-proppant that are present in the fluid are water-soluble at acidic pH or at a pH less than or equal to about 6.5, or less than or equal to 6.0, or from about 4.0 to about 6.5, or from about 5 to about 6.

In an embodiment of the invention the second fluid contains from about 30% to about 70% by volume of an oily liquid. In an embodiment of the invention, oily liquid selected from the group consisting of diesel oil, mineral oil, synthetic oils and combinations thereof. In an embodiment of the invention the second fluid contains from about 30% to about 70% aqueous liquid. In an embodiment of the invention the aqueous liquid is water, sea water, brine containing organic or inorganic dissolved salts, or a combination.

In an embodiment of the invention the second fluid contains from about 0.1 to about 20 wt.% surfactants based on amine or combination of surfactants based on amine. In an embodiment of the invention the second fluid contains from about 0.5 to about 15 wt.%, or from about 1 to about 10 wt.%, or from about 2 to about 5 wt.% surfactants based on amine.

In an embodiment of the invention the second fluid includes one or more buffer systems. Suitable buffer systems include a buffer system containing triethanolamine, sodium hydroxide, sodium acetate, sodium bicarbonate, calcium hydroxide, calcium acetate and/or calcium carbonate. Other examples of suitable buffer systems include carbonic acid/carbonate, potassium carbonate, phosphoric acid/potassium phosphate or sodium, acetic acid/sodium acetate. In an embodiment of the invention, the buffer system includes�, without limitation: phosphate buffers; sulphate buffers; buffers, acetic acid/acetates; buffers on the basis of mono - and polycabonate acids with a chain length from C1to C10; buffers on the basis of substituted carboxylic acids such as lactic, ascorbic and tartaric acid; and buffers on the basis of carboxylic acids, which are unsaturated bond, such as maleic and fumaric acid and the like. The second fluid may thus include any buffer system, known to those skilled in the art. In an embodiment of the invention, the buffer and/or concentration of the buffer may be selected in accordance with the natural fluid present in a particular wellbore and/or in accordance with desired a sufficient period of time required for protonation at least part of the surfactant based on amine in the second fluid to produce the third fluid comprising an emulsion containing oily liquid, reversible dispergirovannoyj as a dispersed phase in an aqueous liquid.

In an embodiment of the invention a system for processing a subterranean well includes a first fluid comprising a reversible invert emulsion containing an aqueous fluid, a reversible dispergirovannoyj as a dispersed phase in an oily liquid, and a surfactant-based �Mina, where a surfactant based on amine selected so that the contact of the first fluid with the natural formation fluid for a sufficient period of time protonium at least part of the surfactant based on amine in the first fluid with a second fluid comprising an emulsion containing oily liquid, reversible dispergirovannoyj as a dispersed phase in an aqueous fluid, where at least 40% vol. solids that are not related to the proppant, which are located in the first fluid are water-soluble at acidic pH or at a pH less than or equal to 6.5.

In an embodiment of the invention a system for processing a subterranean well includes a surfactant based on amine having the structure:

where R1is C8-C24hydrocarbon radical;

where R2and R3are independently selected from C2-C10substituted or unsubstituted hydrocarbon radical, ethylene oxide, propylene oxide or combinations thereof and where a+b is greater than or equal to 2. In an embodiment of the invention a surfactant based on amine contains from about 2 to about 30 moles of ethylene oxide, propylene oxide or combinations thereof. In an embodiment of the invention, the surface�but-active agent based on amine contains from 2 to 30 moles of ethylene oxide.

In an embodiment of the invention, the fluid comprises a reversible invert emulsion containing an aqueous fluid, a reversible dispergirovannoyj as a dispersed phase in an oily liquid and a surfactant based on amine, where the surfactant based on amine selected so that contacting the fluid with the natural formation fluid for a sufficient period of time protonium at least part of the surfactant based on amine in the fluid to form a second fluid comprising an emulsion containing oily liquid, reversible dispergirovannoyj as a dispersed phase in an aqueous fluid, where at least 40% vol. solids that are not related to proppant in the fluid are water-soluble at acidic pH or at a pH less than or equal to 6.5, where the surfactant based on amine has the structure:

where R1is C8-C24hydrocarbon radical;

where R2and R3are independently selected from C2-C10substituted or unsubstituted hydrocarbon radical, ethylene oxide, propylene oxide or combinations thereof and where a+b is greater than or equal to 2. In an embodiment of the invention a surfactant based on amine contains from approx�siteline 2 to about 30 moles of ethylene oxide, propylene oxide or combinations thereof. In an embodiment of the invention a surfactant based on amine contains from 2 to 30 moles of ethylene oxide.

In an alternative embodiment of the invention the productive interval of the wellbore may be drilled using what is called here a second fluid that includes a relatively high-density non-aqueous fluid prepared in such a way that commercial additives, including weighting agents are acid-soluble. Accordingly, in embodiments of the invention drilling fluid hydrocarbon-based, which does not include inverted emulsion or which contains more than 40% vol., or more than 50 vol.%, or more than 60% vol., or greater than 80% vol. solids which are not soluble in acidic aqueous solution is not used and thus cannot be replaced by what is called here the second fluid. To clarify this alternative embodiment of the invention, what is above called the second fluid, which is used in the absence of conventional drilling fluid hydrocarbon-based, here called the first acid soluble invert emulsion fluid and the third fluid are referred to the second acid-soluble emulsion of the fluid based on the emulsion� "oil in water".

In an embodiment of the invention a system for processing a subterranean well includes a first acid soluble invert emulsion fluid comprising a reversible invert emulsion containing an aqueous fluid, a reversible dispergirovannoyj as a dispersed phase in an oily liquid, and a surfactant based on amine, where the surfactant based on amine selected so that contacting the first fluid with the natural formation fluid for a sufficient period of time protonium at least part of the surfactant based on amine in the first acid soluble invert emulsion fluid, to form a second acid-soluble emulsion, a fluid emulsion based oil-in-water" containing emulsion containing oily liquid, reversible dispergirovannoyj as a dispersed phase in an aqueous fluid, where at least 40% vol. solids that are not related to proppant that are present in the first acid soluble invert emulsion fluid are water-soluble at acidic pH or at a pH less than or equal to 6.5.

In an embodiment of the invention, the oily liquid may include diesel oil, kerosene, paraffinic oil, crude oil, liquefied petroleum gas (LPG), toluene, xylene, ether, complex EF�p, mineral oil, biodiesel, vegetable oil, animal oil, acetone, acetonitrile, benzene, 1 - butanol, 2-butanol, 2-butanone, tert-butyl alcohol, carbon tetrachloride, chlorobenzene, chloroform, cyclohexane, 1,2-dichloroethane, diethyl ether, diethylene glycol, digim (dimethyl ether of diethylene glycol), 1,2-dimethoxyethan (Glim, DME), dimethyl ether, dibutyl ether, dimethylformamide (DMF), dimethylsulfoxide (DMSO), dioxane, ethanol, ethyl acetate, ethylene glycol, glycerin, heptane, hexamethylphosphoramide (HMPA)hexamethylenediamine (GMTF), hexane, methanol, methyl tert-butyl ether (MTBE), methylene chloride, N-methyl-2-pyrrolidinone (NMP), nitromethane, pentane, petroleum ether (naphtha), 1-propanol, 2-propanol, pyridine, tetrahydrofuran (THF), toluene, triethylamine, o-xylene, m-xylene, p-xylene or mixtures thereof.

In an embodiment of the invention, the oily liquid may include aromatic fractions of oil, terpenes, mono-, di - and triglycerides of saturated or unsaturated fatty acids, including natural and synthetic triglycerides, aliphatic esters, such as methyl esters of a mixture of acetic, succinic and glutaric acids, aliphatic ethers of glycols, such as monobutyl ether of ethylene glycol, mineral oils such as vaseline oil, chlorinated solvents such as 1,1,1-trichloroethane,perchloroethylene and methylene chloride, Devdariani kerosene, solvent-naphtha, paraffins (including linear paraffins), ISO-paraffins, olefins (especially linear olefins and aliphatic or aromatic hydrocarbons (such as toluene). Suitable terpenes include d-limonene, l-limonene, dipentene (also known as 1-methyl-4-(1-methylethenyl)-cyclohexene), myrcene, alpha-pinene, linalool and mixtures thereof.

Additional oily liquids include long chain alcohols (Monohydric alcohols and glycols), esters, ketones (including diketones and polyketone), nitrites, amides, amines, cyclic ethers, linear and branched esters, glycol ethers (such as monobutyl ether of ethylene glycol), ethers of polyglycols, pyrrolidone, such as N-(alkyl or cycloalkyl)-2-pyrrolidone, N-alkylpiperidines, N,N-dialkylacrylamide, N,N,N',N'-tetraalkylated, diallylsulfide, pyridine, hexylsilane phosphoric acid, 1,3-dimethyl-2-imidazolidinone, nitroalkanes, nitro compounds of aromatic hydrocarbons, sulfolane, butyrolactone and alkylen or allylcarbamate. They include polyalkylene glycols, esters of polyalkylene glycol, such as mono (alkyl or aryl) ethers of glycols, mono (alkyl or aryl) ethers of polyalkylene glycols and poly (alkyl and/or aryl) ethers of polyalkylene glycols, monoalkenes esters of glycols, monoalkenes esters of polyalkylene glycols (PAGS), pag�s esters, such as poly(alkyl and/or aryl) esters of polyalkylene glycols, dialkyl ethers of polyalkylene glycols, esters of dialkanolamine, N-(alkyl or cycloalkyl)-2-pyrrolidone, pyridine and alkylpyridine, diethyl ether, dimethoxyethane, methyl formate, ethylformate, methylpropional, acetonitrile, benzonitrile, dimethylformamide, N-methylpyrrolidone, ethylene carbonate, dimethylcarbonate, propylenecarbonate, diethylcarbamyl, ethylmethylketone and dibutylsebacate, lactones, nitromethane and nitrobenzene sulfones. Oily liquid may also include tetrahydrofuran, dioxane, dioxolan, methyltetrahydrofuran, dimethylsulfone, tetramethylarsonium and thiophene.

In an embodiment of the invention, the fluid for the well treatment can be used in combination with a fluid carrier, which may include any fluid gravel packing, the base fluid for fracturing or the like, which is understandable for specialists in this field of technology. It should be understood that necessarily insoluble components of various fluid media, including gravel, proppant, weighting agents and the like, should not be included in determining the number of components, insoluble in acid, which are present in the second fluid, as described here. Some non-exhaustive examples of fluid�-carriers include hydradermie gels (for example, Gary, polysaccharides, xanthan gum, hydroxyethyl cellulose and the like), cross-linked hydrotherapy gel, gelled acid (e.g., based on the gel), an emulsified acid (e.g., in a hydrocarbon dispersion medium), the aerated fluid (e.g., foam on the basis of N2or CO2and the fluid is hydrocarbon-based, including gelatinizing, foamed or otherwise gelled fluid is hydrocarbon-based. In addition, the fluid carrier may be a brine and/or may include a brine. Accordingly, in the embodiment of the invention, at least 40% vol. any solids that are not related to proppant that are present in the second fluid are water-soluble at pH less than or equal to 6.5.

In certain embodiments, embodiments of the invention, the fluid carrier includes acid. The crack may be traditional hydraulic fracture with the two "wings", but in certain embodiments, embodiments of the invention may be etched crack and/or "wormhole", such as are formed during acid treatment. The fluid carrier may include hydrochloric acid, hydrofluoric acid, ammonium bifluoride, formic acid, acetic acid, lactic acid, glycolic acid, maleic acid, tartaric acid, sulfamic acid, malic acid, whether�ssion acid, methylsulfinyl acid, Chloroacetic acid, aminopolycarboxylate acid, 3-hydroxypropionic acid, polyaminopolycarboxylic acid and/or salt of any acid. In certain embodiments, embodiments of the invention, the fluid carrier includes polyaminopolycarboxylic acid and is , monoammonium salts of and/or monosodium salts of . The choice of any acid as a fluid carrier depends on the purpose of acid, such as etching, decontamination, removal of particles, reacting with acid, and the like and, in addition, compatibility with the formation, compatibility with the fluids in the formation and compatibility with other components of the slurry for hydraulic fracturing and buffer fluids or other fluids that may be present in the wellbore. The choice of acid for the liquid carrier, as is known in the art, based on the characteristics of the specific embodiments of the invention and descriptions in this document.

The fluid carrier may include a mixture of small particles, made of proppant. As stated elsewhere, it should be clear that necessarily insoluble components of proppant are not included in determining the number of components insoluble in acid, which are present in the second fluid, as described here. The choice of proppant includes many compromises imposed by economic and practical considerations. The criterion for choosing the type of proppant, size, distribution of particle size in the combined sample of proppant and its concentration based on the required conductivity fracture, which is a dimensionless quantity and can be selected by the specialist in this field of technology. Such proppants may be natural or synthetic, including, but not limited to, glass balls, ceramic balls, sand and bauxite, coated, or contain chemicals; more than one can be used sequentially or in a mixture of materials of different sizes or of different materials. The proppant may be coated with resin (curable) or covered with a pre-cured resin. Proppants and gravels in the same or different wells or treatments can be the same material and/or may have the same size, one and all, and the term proppant assumes that the proppant includes gravel in this description. In several variants of embodiment of the invention it is possible to use particles of irregular shape as unconventional proppant. In General the proppant used should have an average particle size from about 0.15 mm to �roughly 4.76 mm (from approximately 100 to approximately 4 mesh U.S.) or from approximately 0.15 mm to approximately 3,36 mm (from approximately 100 to approximately 6 mesh USA), often or from about 0.15 mm to 4.76 mm (from approximately 100 to approximately 4 mesh USA), more specifically, but not limited to, from 0.25 to 0.42 mm (40/60 mesh), of 0.42 to 0.84 mm (20/40 mesh), from 0.84 to 1.19 mm (16/20), from 0.84 to 1.68 mm (12/20 mesh) and 0.84-2,38 mm (8/20 mesh) sorted materials. Typically, the proppant must be present in the suspension in a concentration of from about 0.12 to about 0.96 kg/l, or from about 0.12 to about 0.72 kg/l, or from about 0.12 to about 0.54 kg/l. Also they are the suspensions where the concentration of proppant is up to 16 PPA (concentration of proppant in pounds per gallon of fluid carrier) (1,92 kg/l). If the slurry is foamed, the concentration of proppant is up to 20 PPA (2.4 kg/l).

The fluid media may also include a degradable material. In certain embodiments, embodiments of the invention, the degradable material includes at least one connection from lactide, glycolide, aliphatic polyester, poly(lactide), poly(glycolide), poly(ε-caprolactone), poly(orthoester), poly(hydroxybutyrate), aliphatic polycarbonate, poly(phosphazene) and poly(anhydride). In certain embodiments, embodiments of the invention, the degradable material includes at least one connection from a poly(saccharide), dextran, cellulose, chitin, chitosan�, protein, poly(amino acids), poly(ethylene oxide) and a copolymer comprising poly(lactic acid) and poly(glycolic acid). In certain embodiments, embodiments of the invention, the degradable material includes a copolymer comprising a first residue which contains at least one functional group of the following groups: a hydroxyl group, a carboxylic acid group and gidrolabilna acid group, the copolymer further comprising a second residue containing at least one of glycolic acid and lactic acid.

In certain embodiments, embodiments of the invention, the fluid carrier may in some cases include additional additives, including, but not limited to, acids, additives regulation of water loss, gas, corrosion inhibitors, scale inhibitors, catalysts, agents stabilize clays, biocides, friction reducers, combinations thereof and the like. For example, in some embodiments, embodiments of the invention may be desirable lather Lakokraska composition using a gas such as air, nitrogen or carbon dioxide.

Fluid carriers can be used to perform the totality of subterranean operations, including, but not limited to, drilling operations, fracturing operations and completions operations (e.g., gravel packing). In several Varian�Ah embodiment of the invention the composition can be used in the processing of parts of the underground reservoir. In certain embodiments, embodiments of the invention the composition can be administered in a wellbore that penetrates a subterranean formation, as a fluid for processing near-wellbore zone. For example, the fluid for processing near-wellbore zone can be given the opportunity to come into contact with an underground reservoir for some period of time. In some embodiments, embodiments of the invention, the fluid for processing near-wellbore zone can be given the opportunity to come into contact with hydrocarbons, formation fluids and/or sequentially injected fluids for processing near-wellbore zone. After a selected period of time the fluid for processing near-wellbore zone can be removed through the wellbore. In certain embodiments, embodiments of the invention, the fluids for the treatment of near-wellbore zone can be used in hydraulic fracturing operations.

Method and fluids alone or in combination with fluid-media - can also be suitable for gravel packing, or for fracturing and gravel packing in one operation (called, for example, hydraulic and gasket (frac and pack, frac-n-pack), hydraulic packing (frac-pack), operations STIMPAC (trademark of Schlumberger) or by other names) which are also widely used to stimulate production of hydrocarbons, water and other fluids from underground formations. These operations �fied injection of the composition and propping agent/material operations in hydraulic fracturing or gravel (the material usually called proppants used in hydraulic fracturing) operations in gravel packs. In reservoirs with low permeability objective of hydraulic fracturing is usually in the formation of long cracks with a large surface area which significantly increase the magnitude of the flow path of the fluid from the reservoir to the well. In reservoirs with high permeability for the purpose of hydraulic fracturing may be the formation of a short wide crack with high conductivity, in order to bypass near-wellbore damage zone caused by the drilling and/or completion, to ensure good communication for fluid between the oil - or gas-bearing reservoir and the wellbore and also to increase the surface area available for fluids entering the wellbore.

In an embodiment of the invention, the wellbore may be Packed with gravel or otherwise sealed with a proppant. In an embodiment of the invention the displacing fluid and the fluid medium gravel can have a density equivalent to or higher than the pore pressure of the reservoir to prevent Gazpromavia well. In embodiments of the invention when gravel packing, for example of the well/reservoir source drilling fluid, precipitating filtration crust, may be acid soluble invert emulsion system, called here� second fluid, because gravel gasket filtration captures crust into the reservoir and limits the direct contact between the filtration crust and fluids for processing near-wellbore zone placed after completion of gravel packing. Accordingly, the fluid remaining inside the main pipeline or other structure completion, has a very limited ability to communicate with the filtration crust. Reagents for the destruction of "high-density non-aqueous drilling systems are of limited use, since most systems require the barite to achieve the required density. Barite is insoluble in acid, and therefore, even subsequent acid treatment does not remove these solids. In addition, the condition of positive hydrostatic pressure drop required when you try to remove any of the filtration cortex, can lead to damage of the reservoir using conventional methods, resulting in a leak that move undissolved solids further into the reservoir, thus exacerbating the damage. Since the system according to the present description includes the agent for destruction as a functional part of the filter cake or the displacing fluid, then the trigger is the presence of acid gases (H2S, CO2and/or similar to them) in the injection fluid. About�and these have high gas diffusion rates and will be distributed in the filtration cork and displacing the fluid rapidly for some period of time. The chemistry of these gases in contact with the filtration crust formed by the second fluid and/or reversibly displacing fluid according to the present description, leads to a change in the chemistry of the emulsifying/wetting, making the filtration crust dispersible formed in the third fluid, and any non-produced solids wetted with water for future possible traditional acid treatment, removal and/or the like.

LIST of EMBODIMENTS of the INVENTION

The present invention offers the following options for realization of the invention:

A. the Method comprising the displacement of the first fluid is hydrocarbon-based, present in the uncased interval of the wellbore, the second fluid; and contacting the second fluid with a sour natural formation fluid for a time period sufficient to produce a third fluid, at least part of the second fluid wherein the second fluid comprises a reversible invert emulsion containing an aqueous liquid, dispergirovannoyj as a dispersed phase in an oily liquid, and a surfactant based on amine, where the surfactant based on amine selected that contacting the second fluid with a sour natural formation fluid for a sufficient period of time protonium at least h�nce surfactant based on amine in the second fluid with the formation of the third fluid, comprising an emulsion containing oily liquid, reversible dispergirovannoyj as a dispersed phase in an aqueous fluid, where at least 40% vol. any solids that are not related to proppant that are present in the second fluid are water-soluble at pH less than or equal to 6.5.

B. Method according to the embodiment of the invention A, further comprising circulating the first fluid is a hydrocarbon-based during the period of time sufficient to remove at least part of any drill cuttings debris present in the wellbore, prior to displacement of the first fluid is hydrocarbon-based.

V. Method according to the embodiment of the invention A or B, where the uncased interval of the wellbore located below the upper cased interval of the wellbore, the upper uncased interval of the wellbore, or combinations thereof.

G. Method according to the embodiment of the invention A, B, or C, further comprising a positioning node of the well completion in an uncased interval in the presence of the first fluid, second fluid and third fluid.

D. Method according to the embodiment of the invention A, B, C or D, further comprising the displacement of the third fluid fluid for the well completion.

E. Method according to the Embodiment of voploscheni� of the invention A, B, C, D, or E, further comprising the displacement of a fluid hydrocarbon-based above the uncased interval of the well bore, the fluid for the well completion.

J. the Method according to the embodiment of the invention A, B, C, D, E or F, wherein the first fluid includes oily liquid, which is the same as that oily fluid present in the second fluid.

Z. the Method according to the embodiment of the invention A, B, C, D, E, F or G, where a sufficient period of contact between the second fluid and natural formation fluid required for the protonation of at least part of the surfactant based on amine in the second fluid to form a third fluid, at least part of the second fluid is at least 24 hours.

I. Method according to the embodiment of the invention A, B, C, D, E, F, G or H, where the natural formation fluid includes dissolved carbon dioxide, hydrogen sulfide or a combination thereof.

K. the Method according to the embodiment of the invention A, B, C, D, E, F, G, H or I, where the surfactant based on amine has the structure:

where R1is C8-C24hydrocarbon radical;

where R2and R3are independently selected from C2-C10substituted or unsubstituted small drop�stout radical, ethylene oxide, propylene oxide or combinations thereof, and

where a+b is greater than or equal to 2.

L. the Method according to the embodiment of the invention A, B, C, D, E, F, G, H, I or J, wherein the second fluid has a density greater than or equal to about 13.5 lb/Gal (1617,3 kg/m3).

M. the Method according to the embodiment of the invention A, B, C, D, E, F, G, H, I, J or K, where the viscosity of the second fluid is higher than the viscosity of the third fluid.

N. Method according to the embodiment of the invention A, B, C, D, E, F, G, H, I, J, K or L, wherein the second fluid contains from about 30% to about 70% by volume of an oily liquid.

O. the Method according to the embodiment of the invention A, B, C, D, E, F, G, H, I, J, K, L or M, where oily liquid selected from the group consisting of diesel oil, mineral oil, synthetic oils, and combinations thereof.

P. the Method according to the embodiment of the invention A, B, C, D, E, F, G, H, I, J, K, L, M or N, where the second fluid comprises from about 30% to about 70% aqueous liquid.

P. the Method according to the embodiment of the invention A, B, C, D, E, F, G, H, I, J, K, L, M, N or O, where the aqueous liquid is water, sea water, brine containing organic or inorganic dissolved salts, or a combination.

S. the Method according to the embodiment of the invention A, B, C, D, E, F, G, H, I, J, K, L, M, N, O, or P, where a surfactant based on amine is diethoxycarbonyl talovym amine; diethoxycarbonyl soya amine; N-alkyl-1,3-diaminopropanol, where alkyl is from C12 to C22 hydrocarbon, or a combination.

T. System for the treatment of a borehole, including:

the first acid soluble invert emulsion fluid comprising a reversible invert emulsion containing an aqueous liquid, dispergirovannoyj as a dispersed phase in an oily liquid, and a surfactant based on amine, where the surfactant based on amine selected so that contacting of the first acid soluble invert emulsion fluid with an acid of the natural formation fluid for a sufficient period of time protonium at least part of the surfactant based on amine in the first acid soluble invert emulsion fluid to form a second fluid emulsion based oil-in-water" containing emulsion, containing oily liquid, dispergirovannoyj as a dispersed phase in an aqueous fluid, where at least 40% vol. any solids that are not related to proppant that are present in the first fluid are water-soluble at pH less than or equal to 6.5.

U. System for the treatment of a borehole of a variant embodiment of the invention R, where a surfactant based on amine has the structure of a�at:

where R1is C8-C24hydrocarbon radical;

where R2and R3are independently selected from C2-C10substituted or unsubstituted hydrocarbon radical, ethylene oxide, propylene oxide or combinations thereof, and

where a+b is greater than or equal to 2.

F. processing system, a borehole, comprising the second fluid according to any one of the embodiments of the invention A-Q.

H. Fluid, including:

reversible invert emulsion containing an aqueous liquid, dispergirovannoyj as a dispersed phase in an oily liquid, and a surfactant based on amine, where the surfactant based on amine selected so that contacting of a fluid with a sour natural formation fluid for a sufficient period of time protonium at least part of the surfactant based on amine in the fluid to form a second fluid comprising an emulsion containing oily liquid, dispergirovannoyj as a dispersed phase in an aqueous fluid, where at least 40% vol. any solids that are not related to proppant that are present in the fluid are water-soluble at pH less than or equal to 6.5, where the surfactant based on amine has a page�Churu:

where R1is C8-C24hydrocarbon radical;

where R2and R3are independently selected from C2-C10substituted or unsubstituted hydrocarbon radical, ethylene oxide, propylene oxide or combinations thereof, and

where a+b is greater than or equal to 2.

C. Fluid comprising the second fluid according to any one of the embodiments of the invention A-Q.

EXAMPLES

The fluid compositions according to the present description is offered as a demonstration of the reversible high-density fluid of appropriate quality, which inverts when exposed to a fluid or filtration crust subterranean formations containing some amounts of acid gases (CO2and H2S) found in reservoir fluids. In the illustrated embodiment of the invention, the fluids are very low relationship of oil to water and external phases on the basis of high-density brine to minimize the amount of insoluble in acid solids which act as weighting agents in the fluid. Offered developed formulations of the invention with the relationship of oil to water equal to 35:65.

Example Composition #1 uses barite API brand and is a reversible system with a minimum amount of acid-soluble solids.

An example of the composition of #2 is a reversible composition similar to the Sample Composition 1, but with higher content of acid-soluble solids.

Example composition #1
Material
Description
Specific gravityConc.UnitsFunction
Hydrocarbon base0,8140,220 (0,035)Barrel (m3)media
FAZEMUL0,91113,0
(37,1)
lb/ bbl (kg/m3)emulsifier/ wetting
NOVATEC F1,020,5
(1,43)
lb/bbl (kg/m3)the agent regulating fluid loss/
wetting
VERSAGEL HT 1,72,0
(5,71)
lb/bbl (kg/m3)thickener/ gelling agent
Lime*2,35,0
(14,25)
lb/bbl (kg/m3)alkaline buffer*
water1,00,129
(0,205)
Barrel (m3)internal phase
**Barite4,2352,95
(1006,96)
lb/bbl (kg/m3)solid weighting agent
ECF 25604,0
(1,41)
lb/bbl (kg/m3)the secondary shaft
CaCl2solution1,390,338 (0,54)Barrel (m3)internal phase: water activity and density agent
Notes:* Concentration may be imminent�designed, as required, to achieve the desired control and delay inversion of the emulsion.
** Concentration may be adjusted to achieve the required density of the fluid.

Example composition #2
Material DescriptionSpecific gravityConc.UnitsFunction
Hydrocarbon base0,8140,130 (0,021)WASmedia
FAZEMUL0,91113,0 (37,1)lb/bbl (kg/m3)emulsifier/ wetting
NOVATEC F1,020,5 (1,43)lb/bbl (kg/m3)the agent regulating fluid loss /wetting
VERSAGEL HT1,71,5 (4,28)lb/bbl (kg/m3)thickener/ heliobas�Vatel
Lime*2,35,0 (14,25)lb/bbl (kg/m3)alkaline buffer*
water1,00,016 (0,0025)Barrel (m3)internal phase
**CaCO32,7304,96 (870,05)lb/bbl (kg/m3)solid weighting agent ~
ECF 25606,0 (17,12)lb/bbl (kg/m3)secondary emulsifier
CaBr2solution1,700,338 (0,054)Barrel (m3)internal phase: water activity and density agent
Notes:* Concentration can be adjusted as required to achieve the desired control and delay of wettability.
** Concentration can be adjusted to achieve the demand�th density of the fluid.

The materials used in the Composition #1 and Composition #2, are the following:

Hydrocarbon baseDiesel
FAZEMUL®(MI-Swaco, Houston, TX) a surfactant based on ethoxylated fatty amine and polyethylene glycol (emulsifier)
NOVATEC F®(Schlumberger, Houston, TX) malaysiakini resin acid and the monomethyl ether of DIPROPYLENE (agent regulating fluid loss and secondary shaft for temperatures above 100°C)
VERSAGEL HT®(Schlumberger, Houston, TX) organophilic clay hectorite (thickener and gelling agent)
LimeSlaked lime (agent control alkalinity)
WaterFresh
BariteBarium sulphate
CaCO3Ground and sorted calcium carbonate
ECF 2560®(Schlumberger, Houston, TX) secondary emulsifier
CaBr2solutionA concentrated solution of calcium bromide

Although only few examples of embodiments of the invention described above in detail, specialists in the art well understand that many modifications are possible in the example embodiments of the invention without significant deviations from the present invention. Accordingly, it is understood that such modifications should be included in the scope of this invention as defined in the following claims. In the claims the "means plus function" are intended to cover the structures described herein as representing the specified function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail is used in the cylindrical surface for fastening together wooden parts, and the screw is used helical surface, in the light of fastening wooden parts a nail and a screw may be equivalent structures. This is a clear intention of the applicant not to invoke 35 U. S. C § 112, paragraph 6 for any limitations of any of the claims except where paragraph clearly uses the words "means for" together with the corresponding function.

1. The method comprising the
the displacement of the first fluid is hydrocarbon-based, in the uncased interval of the wellbore, the second fluid; and
contacting the second fluid with a sour natural formation fluid for a time period sufficient to form a third fluid, at least part of the second fluid,
wherein the second fluid comprises a reversible invert emulsion containing an aqueous liquid, dispergirovannoyj as a dispersed phase in an oily liquid, and a surfactant based on amine, where the surfactant based on amine selected so that contacting the second fluid with a sour natural formation fluid for a sufficient period of time protonium at least part of the surfactant based on amine in the second fluid to produce the third fluid comprising an emulsion containing oily liquid, dispergirovannoyj as a dispersed phase in an aqueous fluid, where at least 40% vol. any solids that are not related to proppant that are present in the second fluid are water-soluble at pH less than or equal to 6.5.

2. A method according to claim 1, characterized in that it further includes the circulation of the first fluid is a hydrocarbon-based during the period of time that is sufficient to remove, at �'ere, a portion of something from the wreckage of drilled solids, filter cake, or combinations thereof that are present in the wellbore, prior to displacement of the first fluid is hydrocarbon-based.

3. A method according to claim 1, characterized in that the uncased interval of the wellbore located below the upper cased interval of the wellbore.

4. A method according to claim 1, characterized in that it further comprises a positioning node of the well completion in an uncased interval in the presence of the first fluid, second fluid and third fluid.

5. A method according to claim 4, characterized in that it further includes the displacement of the third fluid fluid for the well completion.

6. A method according to claim 4, characterized in that it further includes a displacement fluid is hydrocarbon-based, which are above the uncased interval of the well bore, the fluid for the well completion.

7. A method according to claim 1, wherein said first fluid includes oily liquid, which is the same as that oily fluid present in the second fluid.

8. A method according to claim 1, characterized in that a sufficient period of contact between the second fluid and natural formation fluid required for the protonation of at least part of the surfactant based on amine in the second fluid to form a third flew�d, at least part of the second fluid is at least 24 hours.

9. A method according to claim 1, characterized in that the natural formation fluid contains dissolved carbon dioxide, hydrogen sulfide or a combination thereof.

10. A method according to claim 1, characterized in that the surfactant based on amine has the structure:

where R1is C8-C24hydrocarbon radical;
where R2and R3are independently selected from C2-C10substituted or unsubstituted hydrocarbon radical, ethylene oxide, propylene oxide or combinations thereof, and
where a+b is greater than or equal to 2.

11. A method according to claim 1, characterized in that the second fluid has a density higher than or equal to approximately 1617,3 kg/m3.

12. A method according to claim 1, characterized in that the viscosity of the second fluid is higher than the viscosity of the third fluid.

13. A method according to claim 1, characterized in that the second fluid contains from about 30% to about 70% by volume of an oily liquid.

14. A method according to claim 1, characterized in that the oily liquid is selected from the group consisting of diesel oil, mineral oil, synthetic oils, and combinations thereof.

15. A method according to claim 1, characterized in that the second fluid contains from about 30% to about 70% aqueous liquid.

1. A method according to claim 1, characterized in that the aqueous liquid is water, sea water, brine containing organic or inorganic dissolved salts, or a combination.

17. A method according to claim 1, characterized in that the surfactant based on amine is diethoxycarbonyl talovym amine; diethoxycarbonyl soya amine; N-alkyl-1,3-diaminopropanol, where alkyl is C12to C22a hydrocarbon; or a combination thereof, containing from 2 to 30 moles of ethylene oxide.

18. A system for processing a subterranean borehole, comprising:
the first acid-soluble reversible invert emulsion fluid comprising a reversible invert emulsion containing an aqueous liquid, dispergirovannoyj as a dispersed phase in an oily liquid, and a surfactant based on amine, where the surfactant based on amine selected so that contacting of the first acid soluble invert emulsion fluid with an acid of the natural formation fluid for a sufficient period of time protonium at least part of the surfactant based on amine in the first acid soluble invert emulsion fluid to form a second fluid emulsion based oil-in-water" containing emulsion, containing oily liquid, dispergirovannoyj to�to the disperse phase in an aqueous liquid, where at least 40% vol. any solids that are not related to proppant that are present in the first fluid are water-soluble at pH less than or equal to 6.5.

19. A system for processing a subterranean well according to claim 18, characterized in that the surfactant based on amine has the structure:

where R1is C8-C24hydrocarbon radical;
where R2and R3are independently selected from C2-C10substituted or unsubstituted hydrocarbon radical, ethylene oxide, propylene oxide or combinations thereof, and
where a+b is greater than or equal to 2.

20. Fluid, including:
reversible invert emulsion containing an aqueous liquid, dispergirovannoyj as a dispersed phase in an oily liquid, and a surfactant based on amine, where the surfactant based on amine selected so that contacting of a fluid with a sour natural formation fluid for a sufficient period of time protonium at least part of the surfactant based on amine in the fluid to form a second fluid comprising an emulsion containing oily liquid, dispergirovannoyj as a dispersed phase in an aqueous fluid, where at least 40% vol. any solids, not from�sasisa to the proppant, which are present in the fluid are water-soluble at pH less than or equal to 6.5, where the surfactant based on amine has the structure:

where R1is C8-C24hydrocarbon radical;
where R2and R3are independently selected from C2-C10substituted or unsubstituted hydrocarbon radical, ethylene oxide, propylene oxide or combinations thereof, and
where a+b is greater than or equal to 2.



 

Same patents:

FIELD: oil and gas industry.

SUBSTANCE: under the method of development of oil deposits with nonuniform permeability comprising successive injection via the injection well of the water suspension containing polymer, mud powder and SAS solution, prior to the suspension injection in the deposit the initial intake of the injection well is determined under pressure in water line ands water mineralisation; in water with salinity level 0.15-40 g/l complex action SASs with pour point not exceeding minus 30°C and kinematical viscosity 35-50 sSt are used, i.e. water-alcohol solution of non-ionic SAS-monoalkyl esters of PEG at the following ratio wt %: specified SAS 0.001-1.0, specified water rest, suspension and SAS solution are injected in volume ratio (1-3):1 depending on initial intake of the injection well - at intake 200-400 m3/day - 1-2:1, 400-500 m3/day - 2-3:1, over 500 m3/d - 3:1, between suspension and SAS solution water with salinity level 0.15-40 g/l or water suspension of polyacrylimide with concentration 0.0001-0.1 wt % is injected. Under another option during this method in water with salinity level 40-300 g/l the complex SAS with pour point minus 40°C max is used, containing complex action SAS with pour point minus 30°C max. and kinematical viscosity 35-50 sSt - water-alcohol solution of non-ionic SAS - monoalkyl esters polyoxyethylene glycol 90 wt % and alkyldimethylbenzylammonium chloride 10 % at following ratio of components in wt %: specified SAS 0.001-1.0, specified water - rest, suspension and SA solution are injected to the deposit in volume ratio (1-3): 1 depending on initial intake of the injection well at water line pressure - at intake 200-400 m3/day - 1-2:1, 400-500 m3/day - 2-3:1, over 500 m3/day - 3:1, and between suspension and solution the water with salinity level 40-300 g/l or water suspension of polyacrylimide with concentration 0.0001 0.1 wt % are injected.

EFFECT: increased oil recovery of the deposit.

2 cl, 4 ex, 4 tbl

FIELD: oil and gas industry.

SUBSTANCE: under method of oil deposit development comprising determination of the injection well intake, oil recovery via the production wells, and injection via at least one injection well of the water dispersion of the water-soluble polymer and alkali metal hydroxide, this dispersion contains in wt %: water-soluble polymer 0.01-0.05, alkali 0.5-1.0, at definite intake values of the injection well the specified dispersion is injected until injection pressure increasing by 20-30%, its flushing in the deposit by the injected water in volume of tubing plus 1.0 m3, alkali composition in volume 10-30% of volume of injection of the specified dispersion is injected until specific intake decreasing by 10-20% and achievement of the injection pressure not exceeding the maximum permitted pressure on production string and production deposits, the specified compositions at specified water salinity under each of three options, and flush by water in volume 10-15 m3.

EFFECT: increased oil recovery of deposits and watercut reduction of production wells, spreading of process abilities.

3 cl, 1 ex, 2 tbl

FIELD: oil and gas industry.

SUBSTANCE: method envisages the usage of aqueous solutions of binary mixtures - inorganic or organic nitrate or hydrate of alkali metals, which are injected through individual channels. The method includes the mounting of equipment in wells at the selected area of a deposit. Each well is equipped with devices to control the temperature, pressure and composition of reaction products in a real time mode. Formation areas in vicinity to the well with a volume of at least 20 m3 are heated preliminarily up to a temperature of at least 100°C by injection of at least 2 t of binary mixture reagents. Cyclic heating of the formation area in vicinity to the well with a volume of at least 100 m3 and weight of 250 t is made up to a temperature of at least 140°C due to a reaction of at least 12 t of the binary mixture reagents. At that the first level of explosion safety is ensured by the alternation of injection of saltpetre solution portions, 1 t each, with portions of industrial water of at least 0.05 t each. The second level of explosive safety in the borehole is ensured by the continuous control and monitoring of the reaction process with the temperature limitation in the well bore below the pre-blasting temperature. This temperature is determined against signs of the reaction self-acceleration at recorded charts of time-temperature and time-pressure curves. In case of these signs the injection of a saltpetre decomposition initiator is stopped to the well. Further injection of the saltpetre solution with the weight of at least 10 t is made to the preheated formation. At that the third level of explosive safety is implemented in the reaction process in the formation, which is catalysed by the heat accumulated during the previous cycles. The third level of explosive safety is ensured by a ratio of the weight of the saltpetre injected to the pores and fractures of the formation to the weight of the rock. The ratio is equal mainly to 1 to 20. Low explosive probability, close to zero, is ensured by a mixture of 95 wt % of rock and 5 wt % of saltpetre. The injection of reagents at all cycles is made at continuous temperature control in the reaction zone and pressure and temperature control in the zone near the packer and in the process of the reagents injection for the purpose of timely cessation of the reaction when the parameters of the reaction exceed limits of permitted modes.

EFFECT: improved efficiency of oil production at worked-out deposits with an increased production safety.

4 cl

FIELD: oil and gas industry.

SUBSTANCE: this invention is related to production of oil-in-water emulsions with low viscosity during operations with oil. The method for reduction of apparent viscosity for hydrocarbon fluids occurring at oil extraction and transportation includes contact of the above hydrocarbon medium with effective quantity of composite containing at least one polymer with at least 25 mole percent of cationic monomers. The invention has been developed in dependent claims.

EFFECT: increase in oil production.

15 cl, 9 ex, 4 tbl, 4 dwg

FIELD: oil and gas industry.

SUBSTANCE: treatment method of underground hydrocarbon-containing formations involves the following: a) provision of a composition including a thickening initiator measuring pH, and a polymer capable of hydration in a certain pH range; b) pumping of a composition with pH value beyond the limits of the above pH range; c) activation of an action of pH thickening initiator for displacement of pH composition to the above range of its values, and d) provision of a possibility of increasing viscosity of the composition and shaping of a plug. According to another version, a processing method of underground hydrocarbon-containing formations involves the following: a) provision of a composition containing a polymer capable of hydration in a certain pH range; b) pumping of the composition with pH value beyond the limits of the above pH range; c) provision of a pH changing thickening initiator; d) activation of the action of the thickening initiator for displacement of pH composition to the above range of its values, and e) provision of a possibility of increasing viscosity of a composition and shaping of a plug. The invention has been developed in dependent claims.

EFFECT: improving efficiency of initiation and control of plug formation.

15 cl, 5 ex, 3 dwg

FIELD: oil-and-gas industry.

SUBSTANCE: invention relates to oil production, particularly, to from underground oil deposits. In compliance with this invention, at least one production well and one injection well can be used. Temperature distribution in the zone between said wells is analysed. In case temperature is distributed between said zones so that minimum temperature makes at least 20°C, maximum temperature does not exceed 320°C, while their difference makes at least 20°C, aqueous gel-forming preparations are injected via injection well that contain one or several chemical components. These preparations after injection in the deposit form gels under the effects of deposit temperature. Said preparations differ in type and/or concentration of chemical components. Chemical components and/or their concentration are selected to make gel-forming temperature and/or geol-forming time of the second and, if required, any other injected portion, differ from portions injected there before.

EFFECT: higher efficiency of oil extraction due to levelling of injectivity.

19 cl, 4 tbl, 7 dwg

FIELD: oil and gas industry.

SUBSTANCE: according to the method the first and second banks are injected through a hydrocarbon- or water-based displacement fluid to the designed area of the well. At that the availability of a residual saturation area is determined in productive formations with loose - loosely cemented porous and/or fractured reservoirs. The availability of an ultimate water saturation area, an undersaturated transition interval with a film water area and an intensive flow of water diffuse layers and a subarea of high oil content is determined. The availability of ultimate oil saturation is determined. The availability or unavailability of shale barriers at boundaries of the ultimate water saturation area and the transition interval is considered. The water saturated area is cut from the ultimate oil saturation area and an oil inflow is ensured to the productive formation from the subarea of high oil content. Injection is made to the design area of a producer and/or injector. At that the displacement fluid in injected in a quantity of 0.1 up to 500% of the first bank volume. The second bank is injected in a quantity of 0.1-250% of the first bank volume. Polymer resin is used as the first bank. Polymer hardener is used as the second bank. Upon injection the well is transferred to the hydrocarbon inflow mode.

EFFECT: increased efficiency of the method.

24 cl, 47 ex, 1 dwg

FIELD: oil and gas industry.

SUBSTANCE: in the development method of a non-homogeneous oil formation that includes injection to the formation of an aqueous solution of polyacrylamide (PAA), chrome acetate and magnesium oxide, the solution contains additionally a glass or basalt reinforcing microfiber pretreated by a 1-5% aqueous solution of AF9-6 or AF9-12 or constructional reinforcing microfiber (CRF) with the following concentration of components in the solution, wt %: PAA 0.3-1.0, chrome acetate 0.03-0.1, magnesium oxide 0.015-0.07, the above fibre 0.1-0.5.

EFFECT: increased efficiency of the method.

1 dwg, 2 tbl, 1 ex

FIELD: oil and gas industry.

SUBSTANCE: invention is related to hydrocarbons from underground formation. The method of raw oil recovery from a reservoir, including at least one oil-bearing porous underground subsurface with connate water and oil in cavities of the rock pores having API density less than 25° and containing suspended undissolved solids (SUS), lies in injection of input water to the rock, wherein the input water contains SUS and total content of dissolved solids (TCDS) in it is equal to 30000 ppm or less, the ratio of total content of multivalent cations (MC) in the input water to total MC content in connate water is less than 0.9, and receipt of water-in-oil emulsion inside hydrocarbon-bearing rock; total SUS content in the input water and raw oil is sufficient for SUS content in emulsion to be at least 0.05% per emulsion mass and SUS in the input water is equal to at lest 0.05 kg/m3 and average size of particles is 10 mcm or less, raw oil in pores contains at least 0.05% of SUS with the same average size, total acid number (TAN) of oil is at least 0.5 mg of KOH/g, asphaltene content in it is at least 1-20 wt % and resin content is 5-30 wt %. The invention also suggests increase in recovery degree of raw oil from the above reservoir with connate water and oil in cavities of the rock pores having API density less than 25° and containing SUS with average diameter less than 2 mcm in quantity equal to at least 0.01 wt %, with TAN of at least 0.5mg of KOH/g, asphaltene content of at least 1 wt % and resin content of 5-30 wt %, and the input water is injected to the rock in order to receive water-in-oil emulsion in it, where this water is collected by determination of MC content in connate water, extraction of the input water containing dissolved solids (DS) in quantity less than 30000 ppm, the total MC content is such that the ratio of total MC content in the input water to total MC content in connate water is less than 0.9 and contains at least 0.05 wt % of SUS with average diameter less than 2 mcm in the above water. Invention has been developed in dependent claims.

EFFECT: improving washing efficiency and reducing quantity of residual oil in the rock.

9 cl, 3 ex, 4 dwg, 4 tbl

FIELD: oil and gas industry.

SUBSTANCE: invention refers to the oil and gas production industry and can find application in developing heterogeneous terrigene or carbonate producing beds. In the method for an oil bed development, involving the oil bed water-flooding, injection of water solution banks containing alkali, a polymer, a surfactant, a microorganism culture and a nutrient medium, into injection holes, and sampling of products from the production wells, at the initial stage a deposit is developed by water-flooding in an amount adequate to achieve the collected compensation of water-flood liquid sampling of not less than 50%; once the oil sampling reaches 70% of the initial recovered reserves, residual prospective oil distributed over specific 1 m2 is mapped; the worked-out compartments are detected to inject the above solution into the centre injection holes with the following proportions, wt %: alkali - no more than 5, polymer - no more than 1, surfactant - no more than 0.5, microorganism culture - no more than 0.05, nutrient medium - no more than 0.5, water - the rest with varying the concentration C of the ingredients in the above solution proportional to the specified prospective oil for each C centre is determined depending on Cnk=ynCmaxk, wherein k is a type of the ingredient, n is the number of the centre, y is a proportionality factor of each centre; y is calculated by a linear equation y=a·x+b, wherein x is the specific prospective oil of the centre, t/m2, a, b are linear equation factors determined if y for xmax equals to 0, and if xmin equals to 1 from a system of equations wherein xmax and xmin are the maximum and minimum specific prospective oil values, respectively; injection cycles of the bank injection are repeated if an oil flow rate decreases to the pre-injection level.

EFFECT: higher displacement factor and better oil recovery of the productive formation.

1 ex

FIELD: oil and gas industry.

SUBSTANCE: invention is referred to the area of oil and gas industry, and namely to methods of producing horizons opening by wells. The method includes running in of drill pipes with a drilling bit and containers with pressure gages to the well. Upon the hole cleaning surveys are made in order to set drilling modes at drawdown, thereafter upon beginning of flushing liquid circulation with a gaseous agent at least three drawdown-generating modes are made for delivery of the aerated flushing fluid. At all modes values of pressure are measured, time is recorded and pressure losses are identified within the interval from the pressure gage installation site up to the wellhead. The curve is plotted with the obtained data and the required mode for delivery of the flushing fluid and gaseous agent is identified against this curve. The mode maintaining bottomhole pressure and the preset drawdown value is selected so that the permanent drawdown value is ensured at the stratum opening within its whole thickness regulating bottomhole pressure by circulation chocking at the blowing line, which values is calculated for all types of drilling operations considering the stage of deposit development. For conditions in the newly drilled deposits pressure variations are compensated by the blowing line choking, and its value is defined bore arch type of drilling operations by calculation. For conditions of the long-term operated deposits the value of chocking pressure is defined on-the-spot by direct measurements of buttonhole and formation pressure in real time mode.

EFFECT: improved quality of the productive strata opening, reduced time of opening, exclusion of emergencies during hole boring.

1 dwg

FIELD: oil and gas industry.

SUBSTANCE: invention is related to oil well drilling. The method for provision of substantially permanent mud flow characteristics within the temperature range from about 120°F (49°C) up to about 40°F (4°C) includes addition to drilling mud of an additive that contains the product of carboxylic acid reaction having at least two carboxyl fragments and polyamine with at least two functional amine groups provided that the additive does not contain alkoxylated alkylamides and/or amides of fatty acids. The composition consists of the product of carboxylic acid reaction having at least two carboxyl fragments and polyamine with at least two functional amine groups provided that the additive does not contain alkoxylated alkylamides and/or amides of fatty acids. The oil-based drilling mud contains the above composition.

EFFECT: improving efficiency of rheology regulation within the wide temperature range for horizontal drilling and deep water areas.

47 cl, 4 ex, 5 tbl

FIELD: chemistry.

SUBSTANCE: invention relates to foam-generating compositions of multipurpose application, intended for obtaining foam of low, medium and high repetition factor with application of fresh and hard water in concentration 1 vol. %, 3 vol. % and 6 vol. %. Invention can be applied in fire extinguishing, in particular in extinguishing fires of A and B classes, in inertisation of excavations, for suppression of dust in places of its generation, etc. Foam-generating composition includes sodium salts of alkylsulfates of primary high fatty alcohols of fraction C8-C10 and sodium salts of α-olefinsulfonates of fraction C14-C16, taken in weight ratio 100:(22-36), and water.

EFFECT: increased foam stability (time of flowing of 50% of liquid volume from foam) to 215-280 s, reduction of total content of SAS in concentrate of foam generator and reduction of its viscosity at 20°C to the level 25-40 mm2·s-1.

5 cl, 3 tbl,16 ex

FIELD: oil-and-gas industry.

SUBSTANCE: proposed method comprises driving the vertical section, initial zenith angle borehole deviation section, and sections of zenith angle increase with outcrop to horizontal, and driving horizontal borehole using techniques of driving and drilling in unstable strata. Vertical section and sections with zenith angle increase to 70° are driven with the help of polymer-emulsion water-based mud (PEWM). Sections with zenith angles over 70° and horizontal borehole composed by stable carbonate and unstable terrigenous deposits are drilled using hydrocarbon-based mud (HCBM). Portion of the latter is replaced by phase inversion with PEWM on reaching the design depth and forced in through borehole. Aforementioned techniques are changing between PEWM and HCBM by phase inversion in drilling. Changing PEWM into HCBM is performed by mixing PEWM with A inverter, that is, the mix of hydrocarbon fluid with inverse emulsion with NAEI making the active component, said NAEI being based on polyglycol ethers of fat acids or alcohols with NLB number not over 10 at hydrocarbon fluid-to-emulsifier ratio making 14-19:1, respectively, A inverter being added in amount of 28-35 vol. %. Subsequent changing HCBM into PEWM is made by adding B inverter to the latter, that is, the mix of direct emulsion emulsifier thereto with NAEI making the active component being based on polyglycol ethers of fat acids or alcohols with NLB number not over 11-14, with dioxane alcohol with weight ratio of hydroxyl groups of 15-36% at emulsifier-to-alcohols ratio of 2-3.5:1, respectively, B inverter being added to HCBM in amount of 1.75-4 vol. %. In compliance with another version, stable carbonate strata horizontal hole driving and drilling are performed using HCBM. Driving the sections in above-productive interval is performed with zenith angles over 70° with the help of PEWM. After reaching the design depth of horizontal hole, PEWM is forced in through borehole.

EFFECT: possibility of drilling over terrigenous Devonian deposits with unlimited zenith angles.

14 cl, 7 tbl

FIELD: oil and gas industry.

SUBSTANCE: stabilised emulsion composition includes oily fluid medium, fluid medium being at least partially non-mixed with oily fluid medium, and emulsion-stabilising agent containing the first ionic compound soluble in oily fluid medium or the above fluid medium, and the second ionic compound with a charge with an opposite sign relative to the first ionic compound. The proposed method involves production of the above composition of stabilised emulsion and its placement into an underground formation as a part of underground work. The method involves production of the above composition and drilling of a well in the underground formation using it. The method for obtaining the above composition involves the following: production of oily fluid medium; production of the above fluid medium; production of emulsion-stabilising agent including the first ionic compound, which is soluble in oily fluid medium or the above fluid medium, and the second ionic compound with the charge with opposite sign relative to the first ionic compound, and combination of oily fluid medium, fluid medium and stabilising agent with formation of composition.

EFFECT: improvement of emulsion stability and reduction of the stabilising agent amount.

17 cl, 1 tbl

FIELD: mining.

SUBSTANCE: method includes circulation of a system of drilling mud and efficient quantity of a foaming composition, made of a foaming agent and a stabilising polymer, addition of a gaseous agent into a liquid with speed sufficient to form a foam drilling mud and removal of the foamed drilling mud from a well. Drilling is carried out on the self-sacrificing foam, which is supplied into a well along the closed circulation cycle by means of pumping through a plant for circulation and regeneration of the self-sacrificing foam by means of injection of the self-sacrificing foam into a drilling string, direction of the flow of the self-sacrificing foam with rock sludge after evacuation from the well along the chute system into a sump for regeneration, soaking in the sump until self-sacrificing, return to the stage of addition of the gaseous agent for repeated foaming and return into the well. The foaming composition is a composition of the self-sacrificing foam on the basis of carbamide resins, previously modified with ammonia chloride, sulfanol, second group metal chlorides and water.

EFFECT: invention provides for high indices of technical characteristics of foam, such as half-life and expansion ratio of foam, and also stability and resistance of foam, improved environmental condition around a well, reduced prime cost of works.

10 cl, 4 dwg, 9 tbl

FIELD: oil and gas industry.

SUBSTANCE: mud solution containing an aqueous fluid and an additive to control fluid loss, containing at least one polymer microgel comprising a reaction product prepared by a polymerisation reaction of a polymer or a copolymer and a crosslinking agent, wherein the polymer or copolymer comprises at least one unit of at least one compound from a group of: polybutylene succinate, polybutylene succinate-co-adipate, polyhydroxy-butyrate-valerate, polyhydroxy-butyrate-covalerate, polyester amides, polyethylene terephthalates, sulphonated polyethylene terephthalate, polypropylene, aliphatic aromatic copolyester, chitins, chitosans, proteins, aliphatic polyesters, poly(hydroxyester ethers), poly(hydroxybutyrates), poly(anhydrides), poly(orthoesters), poly(amino acids), poly(phosphazenes), a copolymer thereof, a homopolymer thereof, a tetrapolymer thereof, and any derivative thereof. The method involves: preparing an aqueous compound for well treatment and containing the above additive, introducing the compound into a downhole formation, thereby allowing the additive to flow into a filter cake on the surface inside the downhole formation, allowing the filter cake to degrade, and extracting hydrocarbons from the formations. The method involves preparing the above mud solution, introducing it into the downhole formation, allowing the additive to flow into the filter cake on the surface inside the downhole formation, allowing the filter cake to degrade, and extracting hydrocarbons from the formation. The method involves preparing a filter thickener containing the above aqueous fluid and the additive, placing the thickener into the downhole formation with gravel packed filtration and a portion of the downhole formation. The invention is developed in the secondary claims.

EFFECT: more effective control of the fluid loss, reduced residual injury.

22 cl, 2 dwg, 1 tbl, 13 ex

FIELD: chemistry.

SUBSTANCE: surface-active composition, containing: a first surface-active subsystem containing a fluorinated PAD, a second PAD containing an organosilicon PAD, and optionally a solvent subsystem, where the composition is capable of foaming a fluid medium, which contains spectroscopically analysed crude oil and/or a condensate present in a producing formation. A drilling mud contains said surface-active composition. A completion fluid composition contains said surface-active composition. A hydraulic fracturing composition contains said surface-active composition. A formation stimulation composition contains said surface-active composition. A method of foaming a fluid medium containing oil and/or condensate involves analysing crude oil and/or condensate, preparing said surface-active composition, adding to well fluid and adding a foaming gas.

EFFECT: high stability of compositions over time and at high temperatures.

20 cl, 2 tbl, 1 dwg

FIELD: oil and gas industry.

SUBSTANCE: invention relates to the field of drilling oil and gas vertical and inclined wells under difficult geological conditions. In the method for construction of deep wells under difficult mining and geological conditions with application of thin clay drilling muds of the following composition, wt %: clay 4.0-7.0, carboxymethyl-cellulose 0.5-2.0, sodium or potassium chloride 2.0-15.0, calcium carbonate 3.0-7.0, water - balance; or of the following composition, wt %: clay 4.0-7.0, carboxymethyl cellulose 1.0-3.0, sodium or potassium chloride 2.0-15.0, calcium carbonate 5.0-12.0, water - balance; drilling of geological elements that differ in complexity along a well length is carried out with one composition of a drilling mud, besides, tunnelling of filtering rocks is performed with account of preservation of natural permeability of productive reservoirs, elimination of inflows of a reservoir fluid into a well due to cooldown of a thin clay mud by 15-25°C with simultaneous increase of pressure in it by 3-6% from the mining one.

EFFECT: invention provides for stability of geological elements in tunnelling of wells, prevention of processes of drilling muds (fluids) absorption, inflows of a reservoir fluid, preservation of natural permeability of productive reservoirs by 80-90% from the initial values.

FIELD: mining.

SUBSTANCE: well drilling method involves addition of effective amount of foam-forming composition to hydrocarbon base liquid in order to create foam hydrocarbon drilling fluid - FHDF, where foam-forming composition includes foam-forming agent and stabilising quantity of polymer, which is enough for formation of foam that is stable at temperature of at least 350°F; pumping of FHDF to drilling string during drilling; pumping of organophilic gas to the well or near distal end of drilling string or in/or near drilling bit at the speed which is enough for obtaining the drilling fluid having the required reduced weight of fluid column, and foam removal from the well. Well drilling method involves circulation of hydrocarbon drilling fluid system including hydrocarbon fluid and effective amount of foam-forming composition added to oil or gas well, where foam-forming composition consists of foam-forming agent and stabilising polymer which is sufficient for formation of foam stable at temperature of 350°F; addition of organophilic gas to the liquid at the speed which is enough for formation of the foam drilling fluid having the required reduced weight of fluid column, in which there increased is entrainment flow rate of fluid, increased amount of drilling slurry and other drilling by-products from the well and removal of foamed drilling fluid from the well.

EFFECT: increasing viscosity of base oil at low shift speeds and reduced speed of gravitational drainage through plateau border between foam cells.

26 cl, 2 ex, 3 tbl, 1 dwg

FIELD: oil-and-gas industry.

SUBSTANCE: initial furnace charge containing quartz feldspathic sand and/or quartzite and the material - magnesium oxide source, is dried and grinded. Before grinding diatomite is added at the amount of 0.2-10.0 wt % at the content in MgO furnace charge of 9.1-10.9 wt % in terms of the calcinated substance.

EFFECT: decrease of collapsibility of proppant granules at preservation of low density of material.

1 tbl

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