Hydrocarbon formation treatment method

FIELD: oil and gas industry.

SUBSTANCE: above described formation is brought into contact with fluid medium, where fluid medium is at least the medium which at least partially dissolves or at least partially displaces the brine in the above formation, and subsequently, the above formation is brought into contact with composition including the following: non-ionic fluorated polymer surface-active substance - NFPSAS, which contains at least one bivalent unit represented with structural formulae, and solvent; at that, when composition is brought into contact with the above formation, the above mentioned NFPSAS has turbidity point which is higher than the temperature of the above formation. Invention is developed in dependent claims.

EFFECT: increasing production rate of wells, where brine or gas condensate is present.

25 cl, 3 ex, 20 tbl, 3 dwg

 

BACKGROUND of the INVENTION

In the technique of underground drilling is known that in some wells (e.g., some oil and/or gas wells) is present in the brine in the geological formation bearing hydrocarbons, close to the borehole (also in the technique known as "bottomhole zone"). The brine may be of natural origin (for example, relict water) and/or may be the result of operations conducted in the well.

In the case of some wells (e.g., some gas wells) liquid hydrocarbons (also known in the art as "condensate") can form and accumulate in the bottom-hole zone of the well. The presence of condensate can cause a large reduction in the relative permeability of gas and condensates, thus, the productivity of the well is reduced.

The presence of brine and/or gas condensates in a well bore zone of the geological formation bearing hydrocarbons, can inhibit or stop the preparation of hydrocarbons from the well and therefore is usually undesirable.

We tested different approaches to increase the production of hydrocarbons such wells. One approach, for example, includes the operation of crushing and wedging (e.g., before or simultaneously with the operation of gravel backfill) to reinforce bronzemist the geological formations, bearing hydrocarbon, located near the wellbore. Chemical treatment (for example, the introduction of methanol) was also applied to improve the performance of such oil and/or gas wells. The last treatment is typically introduced into the bottom zone of the well geological formation bearing hydrocarbons, where they interact with brine and/or condensate for their replacement and/or dissolution, thus contributing to increased receipt of hydrocarbon from the well.

Traditional treatment for improving the obtaining hydrocarbons from wells with brine and/or condensate in a well bore zone bearing a hydrocarbon geological formation, however, are often relatively short-lived, and require expensive and lengthy re-processing.

Identifying the acceptable chemical treatments and methods that will be effective to increase the efficiency of obtaining hydrocarbons and will be reliable, remains a problem, especially because of the conditions of wells, such as temperature, brine content and composition of the brine can vary in wells and/or even can vary over time in the well.

BRIEF description of the INVENTION

In one aspect, the invention provides a method of processing clastic formation bearing hydrocarbons, in which there is a brine, the pic is b includes the steps on which:

brought into contact clastic formation bearing hydrocarbons, with a fluid medium, where the fluid medium, at least one of at least partially dissolving or at least partially displacing brine in clastic formation bearing hydrocarbons; and

subsequently brought into contact clastic formation bearing hydrocarbons, the composition, the composition includes:

the nonionic fluorinated polymeric surfactant, including:

at least one divalent unit represented by a formula;

and at least one divalent unit represented by the formula:

or

where Rfis performanceline group having from 1 to 8 carbon atoms;

R, R1and R2each independently represents hydrogen or alkyl of 1 to 4 carbon atoms;

n is an integer from 2 to 10;

EO represents-CH2CH2O-;

each RA independently represents-CH(CH3)CH2O - or-CH2CH(CH3)O-;

each R independently represents an integer from 1 to about 128; and

each q independently represents an integer from 0 is about 55; and

the solvent

moreover, when the composition is brought into contact with clastic formation bearing hydrocarbons, the nonionic fluorinated polymeric surfactant has a point cloud, which is higher than the temperature of clastic formation bearing hydrocarbons. In some embodiments, the implementation of Rfis performatic.

In some embodiments, implementation, when the composition is brought into contact with clastic formation bearing hydrocarbons, formation, mainly, does not contain precipitated salt. In some embodiments, implementation, fluid in the main, does not contain surfactants. In some embodiments, implementation, fluid medium includes at least one of toluene, diesel, heptane, octane or condensate. In some embodiments, implementation, fluid at least partially dissolves the brine. In some embodiments, implementation, fluid medium includes at least one of a polyol or Paleologo ether, where the polyol and paleology ether independently have from 2 to 25 carbon atoms. In some embodiments, implementation, polyol or paleology ether, at least one of 2-butoxyethanol, ethylene glycol, propylene glycol, poly(propylene glycol), 1,3-propane diol, 1,8-octanediol, diethylene m is nematologia ether, ethylene glycol monobutyl ether or dipropyleneglycol nanometrology ether. In some embodiments, implementation, fluid further includes at least one monohydroxy alcohol, ether or ketone having independently from 1 to 4 carbon atoms.

In some embodiments, implementation, fluid medium includes at least one of water, methanol, ethanol or isopropanol. In some embodiments, implementation, fluid medium includes at least one of nitrogen, carbon dioxide or methane. In some embodiments, the implementation, the composition includes at least 50 weight percent (in some embodiments, the implementation of at least 60, 70, 80 and 90 weight percent solvent based on the total weight of the composition. In some embodiments, the implementation, the composition further includes water.

In some embodiments, the implementation, the solvent includes at least one of a polyol or Paleologo ether, where the polyol and paleology ether independently have from 2 to 25 carbon atoms; and the solvent comprises at least one monohydroxy alcohol, ether, or ketone independently having from 1 to 4 carbon atoms. In some embodiments, implementation, polyol or paleology ether, at least one of 2-butoxyethanol, ethylene glycol, propylene glycol, poly(propylene glycol), 1-propane diol, (1,8-octanediol, diethylene glycol nanometrology ether, ethylene glycol monobutyl ether or dipropyleneglycol nanometrology ether. In some embodiments, the implementation, the solvent includes at least one monohydroxy alcohol, independently having from 1 to 4 carbon atoms.

In some embodiments, the implementation, the nonionic fluorinated polymeric surfactant has srednetsenovoj molecular weight in the range from 1000 to 30000, 40000, 50000, 60000, 75000, 100000 or more grams/mol. In some embodiments, implementation, clastic formation bearing hydrocarbons, is descending well. In some embodiments, implementation, clastic formation bearing hydrocarbons, has at least one first gas permeability prior to bringing into contact of the formation with the fluid medium and the bringing into contact of the formation with the composition and at least one second gas permeability after bringing into contact of the formation with the fluid medium and the bringing into contact of the formation with the composition, where the second gas permeability of at least 5 percent (in some embodiments, implement, on at least 10, 15, 20, 30, 40, 50, 60, 70, 80, 90, 100, 110, 120, 130, 140 or even at least 150 percent or more) greater than the first gas permeability. In some embodiments, domestic the, relative permeability is the relative permeability for gas.

In some embodiments, the implementation, the method may also include the tolerance of the condensate flow in clastic formation bearing hydrocarbons, after bringing into contact of the formation with the fluid medium and before the bringing into contact of the formation with the composition.

In some embodiments, the implementation, the formation has a condensate, where the fluid medium, at least one of at least partially dissolving or at least partially displacing condensate. In some embodiments, the implementation of the wellbore navigate through clastic formation bearing hydrocarbons, the method further includes obtaining hydrocarbons from the well after bringing into contact clastic formation bearing hydrocarbons, the composition. In some embodiments, implementation, clastic formation bearing hydrocarbons, has at least one crack. In some embodiments, implementation, crack contains many propping agents.

BRIEF description of the GRAPHICAL MATERIAL

For a more complete understanding of the characteristics and advantages of the present invention has following detailed description with reference to the accompanying figures, in which:

Figure 1 is a schematic of the representation of the example implementation of offshore oil and gas platforms, on which device is used for processing the well bottom zone of this invention,

Figure 2 is an enlarged fragment of figure 1, which depicts bottomhole zone for those of embodiments associated with fractured formation; and

Figure 3 is a schematic illustration of the installation of the flooding of the core for the study of core samples and other materials, using the compositions and methods according to this invention.

DETAILED description of the INVENTION

Meanwhile, the creation and application of various embodiments according to this invention discussed in detail below, it is necessary to take into account that this invention is applicable ideas of the invention, which can be applied in a wide variety of individual contexts. Specific embodiments of, discussed here, are merely illustrative of specific ways to create and use the invention and do not limit the scope of the invention.

To facilitate understanding of this invention listed below are a number of expressions. Expressions that are defined in the description, take the values known to a person skilled in areas relevant to this invention. The form of the singular is not intended to refer only to a single unit, what about include the General class, in a specific example can be used for illustration. Here the terminology used to describe specific embodiments of the invention, but its use does not limit this invention except as set forth in the claims.

The term "brine" means water with at least one dissolved salt electrolyte (for example, having any non-zero concentration, which can be, in some embodiments, implementation, less than 1000 parts per million by weight (ppm) or more than 1000 ppm, more than 10,000 ppm, more than 20000 ppm 30000 ppm 40000 ppm 50000 ppm 100,000 ppm, 150000 ppm or even more than 200,000 ppm).

The expression "conditions of the descending wells" means the temperature, pressure, humidity and other conditions that commonly found in subterranean clastic formations.

The expression "homogeneous" means the macroscopic homogeneity across strata and not a predisposition to spontaneous macroscopic separation of the phases.

The expression "formation bearing hydrocarbons" includes formation bearing hydrocarbons in the field (i.e. underground formation bearing hydrocarbons), and parts of such formations, bearing hydrocarbons (for example, core samples).

The term "crack" means the crack made by man. During operation, for example, cracks are typically made by the introduction of squeezing the fluid in p is zemnoy geologicheskiy formation at a rate and pressure, sufficient for opening cracks (i.e. exceeding the strength of rocks).

The expression "hydrolyzable silane group" means a group having at least one part of the Si-O-Z, which is hydrolyzed with water at a pH of from about 2 to about 12, where Z represents H or substituted or unsubstituted alkyl or aryl.

The expression "non-ionic" means the absence of ionic groups (e.g., salt) or groups (e.g.,- CO2H, -SO3H, -OSO3H, -P(=O)(OH)2), which are completely ionized in water.

The expression "normal boiling point" means the boiling point at a pressure of one atmosphere (100 kPa).

The expression "polymer" means a molecule with a molecular weight of at least 1000 g/mol, which structure includes multiple repetition of units, what is happening, actually or conceptually, from molecules of low relative molecular mass.

The expression "polymer" means comprising a polymer.

The term "solvent" means a homogeneous liquid material (including any water with which it can be mixed), is capable of at least partially dissolving the nonionic fluorinated polymeric surfactant (a substance)with which it was mixed at 25°C.

The expression "miscible with water" means soluble in water in all proportions.

In the expression "performance", with respect to the borehole, means the ability of a well to produce hydrocarbons; namely, the ratio of the flow rate of hydrocarbons to the pressure drop, where the pressure drop is the difference between the average reservoir pressure and dynamic bottom hole pressure of the well (i.e., the flow per unit driving force).

As used in this description, the expression "mostly without precipitated salts"refers to the amount of salts that are found under conditions of downward wells that settle. In one example, mostly without precipitated salt means a salt that is not more than 5% above the quantity of product solubility at a given temperature and pressure. In another example, the formation becomes mostly without precipitated salt, when the amount of salt in the formation is reduced, dissolved or replaced, so that the salt does not prevent the interaction (e.g., adsorption) nonionic fluorinated polymeric surfactants with the formation.

The expression "point cloud" surfactant refers to the temperature at which the non-ionic surfactant becomes inhomogeneous in the water. This temperature may depend on many variables (e.g., concentration of surfactant, solvent concentration, solvent composition, concentration of the odes, the concentration and composition of electrolyte concentration and composition of oil phase and the presence of other surface-active substances).

As used here, the expression "mainly contains no surfactant" refers to a fluid that may contain surface-active substance in a quantity insufficient to ensure that the fluid had a point cloud, for example when it is below its critical concentration of micelles. Fluid which mainly contains no surfactant, can be fluid medium, which contains a surfactant, but in quantities insufficient to change the wettability, for example clastic formation bearing hydrocarbons, under conditions of downward well. Fluid which mainly contains no surfactants, contains the weight percent of surfactant, as low as 0 weight percent.

Methods according to this invention used for the treatment of clastic formations bearing hydrocarbons, in which there is a brine. The brine may be a relic or derelictio water, mobile (for example, with a cross over) or stationary (e.g., residual) water of natural origin or water, the resulting action on the formation (e.g. the R, water from the aqueous washing fluid or water and squeezing fluid). In some embodiments, the implementation of the brine is relict water. Typically, the methods according to this invention is applied, when the brine that is a clastic formation bearing hydrocarbons, it has a high salt content and/or when a high level of water saturation is in formation.

In some embodiments, implementation, clastic formation bearing hydrocarbons, includes at least one of the deposits of dry gas, wet gas deposits, deposits of flue gas condensate, gas reserves in tight gas deposits of coal seams or reservoir storage.

Fluids (liquids and gases), applicable in this invention are at least one of at least partially dissolving or at least partially replacing the brine in clastic formation bearing hydrocarbons. In some embodiments, implementation, fluid at least partially displaces the brine in clastic formation bearing hydrocarbons. In some embodiments, implementation, fluid at least partially dissolves in brine clastic formation bearing hydrocarbons. Examples of applicable fluid include polar and/or miscible with water, solvents such as odnoo the Ohm alcohols, having from 1 to 4 or more carbon atoms (e.g., methanol, ethanol, isopropanol, propanol or butanol; polyols, such as glycols (e.g. ethylene glycol or propylene glycol), end arcangioli (for example, 1,3-propandiol, 1,4-butanediol, 1,6-hexanediol or 1,8-octanediol), polyglycols (e.g., diethylene glycol, triethylene glycol or dipropyleneglycol) or triola (for example, glycerol, trimethylolpropane); ethers (e.g. diethyl ether, methyl t-butyl ether, tetrahydrofuran, p-dioxane); politologie esters such as glycol ethers (for example, monobutyl ether of ethylene glycol, onomatology ether of diethylene glycol, onomatology broadcast dipropyleneglycol, onomatology ether of propylene glycol or glycol ether, available under the trade designation "DOWANOL" from Dow Chemical Co., Midland, MI); and ketones (such as acetone or 2-butanone). Applicable fluids include liquid or gaseous hydrocarbons (e.g. toluene, diesel, heptane, octane, condensate, methane and isoparaffin solvents, obtained from Total Fina, Paris, France, under the trade designation "ISANE and from Exxon Mobil Chemicals, Houston, TX, under the trade designation "ISOPAR") and other gases (e.g. nitrogen and carbon dioxide).

Composition applicable in the implementation of the present invention include nonionic fluorinated polymeric surfactant, and RA is the maker.

Applicable nonionic fluorinated polymeric surfactants include:

at least one divalent unit represented by the formula:

and at least one divalent unit represented by the formula:

or

Rfis performanceline group having from 1 to 8 carbon atoms. Illustrative of the groups Rfinclude performer, perforated, performaer, performatic (for example, PERFLUORO-n-butyl or PERFLUORO-sec-butyl), performancel, perferences, perforated and perforatin;

R, R1and R2each independently represents hydrogen or alkyl of 1 to 4 carbon atoms (e.g. methyl, ethyl, n-propyl, isopropyl, butyl, isobutyl or t-butyl);

n is an integer from 2 to 10;

EO represents-CH2CH2O-.

Each RA independently represents-CH(CH3)CH2O - or-CH2CH(CH3)O-.

Each R independently represents an integer from 1 to about 128.

Each q independently represents an integer from 0 to about 55. In some embodiments, the implementation of q can be in the range from 1 to 55, and the ratio of p to q is at IU is e, from 0,5, 0,75, 1, or 1.5 to 2.5, 2.7, and 3, 4, 5 or more.

Nonionic fluorinated polymeric surfactants described above, are usually obtained by copolymerization of:

at least one compound represented by the formula

and at least one compound represented by the formula:

or

Nonionic fluorinated polymeric surfactants described above can be obtained, for example, by techniques known in the art (for example, by means of free radical initiated copolymerization containing nonafterburning acrylate with poly(alkylene) acrylate (for example, monoacrylates or diacrylate) or mixtures thereof). By adjusting the concentration and activity of the initiator, the concentration of monomers, the temperature and the transfer agents circuit, it is possible to control the molecular weight of a copolymer of polyacrylate. Description of the receipt of such polyacrylates are disclosed, for example, in U.S. patent No. 3787351 (Olson), which is included in this description by reference. Getting monomers of nonformalizability described, for example, in U.S. patent No. 2803615 (Ahlbrecht et aL), which is included in this description by reference. Examples perifericheskikh polymeric esters and aluchemie described, for example, in U.S. patent No. 6664354 (Savu et al.), included in this description by reference.

The methods described above to create structures containing nonafterburning, can be used to create heptaparaparshinokh since heptaparaparshinokh, which can be obtained, for example, by the methods described in examples 2 and 3 of U.S. patent No. 2732398 (Brice et al.), included in this description by reference.

Acceptable nonionic fluorinated polymeric surfactants typically have srednetsenovoj molecular weight in the range from 1000 to 10000 g/mol, 20,000 g/mol to 30,000 g/mol to 40,000 g/mol and 50,000 g/mol or even 100000 g/mol, although higher and lower molecular weight may also be used. Also within the scope of the present invention is the use of mixtures of nonionic fluorinated polymeric surfactants.

In some embodiments, the implementation of the nonionic fluorinated polymeric surfactant does not contain hydrolyzable Milanovich groups. This can be an advantage, for example the extension of the shelf life of the composition.

Examples of applicable solvents include organic solvents, water and a combination of this. Examples of organic solvents include polar and/or miscible with water Rast is oriali, such as monohydroxy alcohols, independently having from 1 to 4 or more carbon atoms (e.g., methanol, ethanol, isopropanol, propanol and butanol; polyols, such as, for example, glycols (e.g. ethylene glycol or propylene glycol), end arcangioli (for example, 1,3-propandiol, 1,4-butanediol, 1,6-hexanediol or 1,8-octanediol), polyglycols (e.g., diethylene glycol, triethylene glycol or dipropyleneglycol) or triola (for example, glycerol, trimethylolpropane); ethers (e.g. diethyl ether, methyl t-butyl ether, tetrahydrofuran, p-dioxane; politologie ethers, such as glycol ethers (for example, monobutyl ether of ethylene glycol, onomatology ether of diethylene glycol, onomatology broadcast dipropyleneglycol, onomatology ether of propylene glycol or glycol ether, available under the trade designation "DOWANOL" from Dow Chemical Co., Midland, MI); ketones (such as acetone or 2-butanone), easily gasified fluids (e.g., ammonia, low molecular weight hydrocarbons or substituted hydrocarbons, condensation and supercritical or liquid carbon dioxide) and this mixture.

In some embodiments, the implementation, the solvent includes at least one of a polyol or Paleologo ether and at least one monohydroxy alcohol, ether, or ketone independently having from 1 to 4 carbon atoms. In these embodiments, assests the tion, if a component of the solvent is a member of two functional classes, it can be used as each class, but not both. For example, the methyl ether of ethylene glycol can be paleology ether or monohydroxy alcohol, but not both.

In some embodiments, implementation, component (s) of the solvent and/or the fluid can have a normal boiling point less than 650°F (343°C) (in some embodiments, implementation, less than 450°F (232°C)); for example, to facilitate the removal of solvent and/or fluid from the well after the treatment.

In some embodiments, the implementation, the solvent and/or fluid medium includes a polyol, which is independently from 2 to 25 (in some embodiments, the implementation of 2-20, 2-10, 2-8, or even 2-6) carbon atoms. In some embodiments, the implementation, the solvent and/or fluid medium includes paleology ether, which is independently has from 3 to 25 (in some embodiments, the implementation 3-20, 3-10, 3-8, or even 5-8) carbon atoms.

Although not wishing to contact theory, believed that the more desired processing results of the formation is obtained when the composition is used in a specific formation bearing hydrocarbons, is homogeneous under conditions (for example, temperature (temperature) and the composition of the brine), occurring in the formation. Accordingly, the amount of fluid itip can be chosen that it is, at least one solvent or a replacement a sufficient amount of brine in the formation, so that when the composition is added to a formation, the nonionic fluorinated polymeric surfactant has a point cloud, which is above at least one of the temperature detected in formation. In some embodiments, the implementation, the amount of fluid and type can be chosen so that it is at least one solvent or a replacement a sufficient amount of brine in the formation, so that when the composition is brought into contact with the formation, formation, mainly, does not contain precipitated salt.

The effectiveness of the compositions described here, to improve the performance of a single formation (with optional condensate) can typically be determined by the ability of the composition to dissolve the quantity of brine that remains (and optional condensate) in the formation after the bringing into contact of the formation with the fluid medium. Therefore, at this temperature a large number of compositions having lower solubility of brine and/or condensate) (i.e. compositions that can dissolve relatively lower amount of brine or condensate)will typically be needed than in the case of compositions having a higher solubility of the brine (and/recondense) and containing the same surfactant at the same concentration.

One suitable way to assess whether the composition is homogeneous under the conditions provided in clastic formation bearing hydrocarbons, involves combining (e.g., container) model brine composition nonionic fluorinated polymeric surfactant, a solvent at a given temperature and then mixing the sample with brine composition. Over time, the mixture can be estimated (for example, 5 minutes, 1 hour, 12 hours, 24 hours or longer) to see were divided whether phase or become opaque. By adjusting the relative amounts of brine and composition, it is possible to determine the maximum capacity of the accumulation of brine (above which there is a separation phase) composition at a given temperature. Changing the temperature at which carry out the above procedure, typically leads to a more complete understanding of the suitability of compositions for treatment of the proposed wells.

Typically, the compositions used in this invention include from at least, 0,01, 0,015, 0,02, 0,025, 0,03, 0,035, 0,04, 0,045, 0,05, 0,055, 0,06, 0,065, 0,07, 0,075, 0,08, 0,085, 0,09, 0,095, 0,1, 0,15, 0,2, 0,25, 0,5, 1, 1,5, 2, 3, 4 or 5 percent by weight to 5, 6, 7, 8, 9, or 10 percent by weight of the nonionic fluorinated polymeric surfactants on the basis of the total weight of the composition. For example, the amount of the nonionic fluorinated polymeric surface is but active agents in the compositions may be in the range from 0.01 to 10; 0.1 to 10, 0.1 to 5, 1 to 10 or even in the range of 1-5 percent by weight of the nonionic fluorinated polymeric surfactant based on the total weight of the composition. Lower and higher amounts of the nonionic fluorinated polymeric surfactants in the compositions can also be used and may be desirable for some applications.

The amount of solvent in the composition typically varies with inverse number of components in the compositions applicable in the implementation of the present invention. For example, based on the total weight of the composition, the solvent may be present in the composition in an amount of at least 10, 20, 30, 40 or 50 percent by weight or more to 60, 70, 80, 90, 95, 98 or even 99 percent by weight or more.

In some embodiments, the implementation of the composition applicable in the implementation of the present invention can optionally include water (e.g., solvent). In some embodiments, the implementation, the compositions of this invention, generally, do not contain water (i.e. contain less than 0.1 percent by weight water based on the total weight of the composition).

Ingredients for the compositions described here, including the nonionic fluorinated polymeric surfactant and solvent can be combined using known in the art methods for combining these is ipov materials, including the use of traditional magnetic stirring or mechanical mixer (e.g., combined static mixer and recirculating pump).

Typically, the amount of the nonionic fluorinated polymeric surfactant and solvent (and type of solvent) depends on the specific application, since conditions typically vary between formation bearing hydrocarbons, for example at different depths in the formation and even over time in this formation. Primarily, the methods according to this invention can be installed for individual formations and conditions.

Methods according to this invention can be applied, for example, hydrocarbons (e.g., at least one of methane, ethane, propane, butane, hexane, heptane or octane) from a hydrocarbon bearing subterranean clastic formations (in some embodiments, the implementation of the predominantly Sandstone). In some embodiments, implementation, formation bearing hydrocarbons, includes at least one of the shale, conglomerate, diatomite, sand or Sandstone.

Figure 1 schematically shows an illustrative offshore oil and gas platform, having the General designation 10. Semi-submerged platform 12 is placed in the center above the submarine clastic formation bearing hydrocarbons 14 located under the IOE is Kim bottom 16. The underwater pipeline 18 extends away from the platform 20 of the platform 12 to the mouth of 22 installation, including the blowout preventer 24. The platform 12 is shown with a lifting device 26 and a derrick 28 for raising and lowering the columns of tubes, such as the trigger column 30.

Shaft 32 passes through different layers of the earth, including the formation bearing hydrocarbons 14. The bracket 34 fastened with cement from the well bore 32 by means of cement 36. The trigger column 30 may include various means, including, for example, the strainer Assembly to combat sand 38, which is placed in the bore 32 adjacent to a formation bearing hydrocarbons 14. Also from the platform 12 through the well bore 32 extends the supply tube of the washing solution 40, has a section of the discharge gas or fluid 42, placed next to a formation bearing hydrocarbons, 14, as shown with the operational area 48 between packers 44, 46. When you need to work the area near wellbore formation bearing hydrocarbons 14 adjacent to the operational area 48, the trigger column 30 and the supply pipe of the washing solution 40 is lowered through casing 34 until such time as the strainer Assembly to combat sand 38 and the section of the discharge gas or fluid 42 will not be installed next to the area near wellbore formation bearing hydrocarbons 14, including perf the radio 50. Then describe here the composition is injected into the supply pipe 40 for the gradual processing region near wellbore formation bearing hydrocarbons 14.

Also in figure 2, the treatment area is depicted next to the housing 34, the cement 36 within the perforation 50. The enlarged fragment showing a crack 57, which added proppant 60. Crack 57 shown in relation to the "crushing" 62 and the areas surrounding the region of the wellbore 32, showing undeveloped formation bearing hydrocarbons 14. The damaged area 64 has a lower permeability and shown between undeveloped formation bearing hydrocarbons 14, and the bracket 34.

Although the graphics depict marine work, the person skilled in the art will understand that the compositions and methods for treatment of the operational zone of the wellbore is equally well suited for use in onshore operations. In addition, although the graphic materials depicts a vertical well, the person skilled in the art will understand that the methods of this invention can equally be suitable, for example, for use in deviated wells, inclined wells or horizontal wells.

Schematic diagram of the device for flooding of the core 100, which is used to define attributes is through the permeability of the sample substrate, shown in figure 3. Device for flooding the core 100 includes piston pumps (model # 1458; obtained from General Electric Sensing, Billerica, MA) 102 for introducing a fluid medium 103 at a constant speed in the battery fluid 116. Numerous discharge hole 112 on kindergaten 108 used to measure the pressure drop through the four sections (2 inches each) core 109. Discharge hole 111 used to measure the pressure drop across the length of the core. Two back pressure regulator (model # BPR-50 obtained from Temco, Tulsa, OK) 104, 106 used to control the hydrodynamic pressure at the inlet and outlet respectively of the core 109. The flow of fluid passed through the vertical core to prevent gravity segregation of gas. Kindergaten high pressure (type Hassler, model UTPT-1×8-3K-13, available from Phoenix, Houston TX) 108, regulators back pressure 106, batteries, fluid 116 and the piping was inside the oven with adjustable pressure and temperature (Model DC 1406F; maximum temperature of 650°F (343°C), available from SPX Corporation, Williamsport, PA) at the investigated temperatures.

Basically, I believe that it is desirable to take into account the duration of the downtime after crack formation bearing hydrocarbons, were in contact with the compositions described here. For example, the duration of the OS is anouki well may be several hours (for example, 1-12 hours, about 24 hours or even more (e.g., 2-10) days.

The person skilled in the art after considering this specification it will be clear that the implementation of the present invention must take into account various factors, including, for example, ionic strength of the composition, pH (e.g. a pH range from about 4 to about 10) and radial stress around the wellbore (for example, from about 1 bar (100 kPa) to about 1000 bar (100 MPa)).

Typically, after processing according to this invention the hydrocarbons then receive from the wellbore at high speed compared with the speed before processing. In some embodiments, the implementation, where the formation has at least one crack formation has at least one first conductivity before bringing into contact of the formation with the composition and at least one conductivity after bringing into contact of the formation with the composition, and where the second conductivity, at least 5 (in some embodiments, implement, on at least 10, 20, 30, 40, 50, 60, 70, 80, 90, 100, 110, 120, 130, 140 or even at least 150 or more) percent higher than the first conductivity.

In some embodiments, implementation, clastic formation bearing hydrocarbons, has at least one crack. Some of these options ASU is estline, crack contains many propping agents. Disjoining materials cracks typically injected into the formation as part of the hydraulic handle cracks. Typical propping agents known in the art include those made of sand (e.g., Sands Ottawa, Brady or Colorado are often seen as white or brown Sands with different ratios), covered by resin sand, sintered bauxite, ceramics (i.e. glasses, crystalline ceramics, glass ceramics, and combinations thereof), reinforced thermoplastics, organic materials (e.g., ground or crushed walnut shell, shell seeds, seeds, fruits and processed wood and clay. Sandy propping agents are available, for example, from Badger Mining Corp., Berlin, WI; Borden Chemical, Columbus, and HE Fairmont Minerals, Chardon, OH. Thermoplastic propping agents are available, for example, from Dow Chemical Company, Midland, MI; and BJ Services, Houston, TX. Propping agents on the basis of clay available for example, from CarboCeramics, Irving, TX and Saint-Gobain, Courbevoie, France. Propping agents of the ceramic sintered bauxite available, for example, from Borovichi Refractories, Borovichi, Russia; 3M Company, St.Paul, MN; CarboCeramics and Saint Gobain. Propping agents of the glass bubbles and balls available, for example, from Diversified Industries, Sidney, British Columbia, Canada and 3M Company. In some embodiments, implementation, propping agents form blocks inside forms the tion and/or wellbore. Propping agents can choose them to be chemically compatible with fluids and compositions described here. Crushed solid particles can be introduced into the formation, for example, as part of the hydraulic treatment cracks, wrestling with sand brought into the wellbore/formation as part of any treatment to combat sand, such as gravel filter or a fracture with the installation of a strainer.

The method can be carried out, for example, in laboratory conditions (for example, the core sample (i.e. part) formation bearing hydrocarbons) or in the field (for example, on the underground formation bearing hydrocarbons located in the bottom of the descending wells). Typically, the methods according to this invention is applicable to conditions the downward wells with pressure in the range from about 1 bar (100 kPa) to about 1000 bar (100 MPa) and a temperature in the range from approximately 100°F (37.8°C) to 400°F (204°C), although they can also be used for processing formation bearing hydrocarbons, and other conditions.

In addition to brine and optionally condensation formation bearing hydrocarbons, there may be other materials (for example, asphalt or water). Methods according to this invention can also be applied in these cases.

Different ways (e.g., injection), well-known specialists of the oil and gas sector can be used in accordance with this invention for the contact formations in underground formations, bearing hydrocarbon, with fluids and compositions comprising a solvent and a nonionic fluorinated polymeric surfactant. Column flexible pipes, for example, can be used for delivery of fluid and composition in a separate zone in the formation. In some embodiments, implementation, during implementation of the present invention may be desirable to separate a separate zone in the formation (for example, conventional seals) for contact with the fluid medium and composition.

Advantages and embodiments of the present invention is additionally illustrated by the following examples, but the specific materials and quantities as set forth in these examples, as well as other conditions and details should not be construed as limiting the invention. Unless otherwise indicated, all parts, percentages, ratios, etc. in the examples and the rest of this description are by weight.

EXAMPLE 1

The nonionic fluorinated polymeric surfactant ("Nonionic fluorinated polymeric surfactant A") was obtained essentially as in example 4 of U.S. patent No. 6664354 (Savu), in addition to the use of 15.6 grams (g) of 50/50 white spirits/organic peroxide initiator (tret-butyl peroxy-2-ethylhexanoate, available from Akzo Nobel, Arnhem, the Netherlands under the trade designation "TRIGONOX-21-C50 is) instead of 2,2'-azobisisobutyronitrile, and with 9.9 g of 1-methyl-2-pyrrolidinone added to the downloads.

The core with the parameters defined below, cut from a block of rock. The core was dried in an oven at 100°C for 24 hours and then weighed. The core is then Packed in a polytetrafluoroethylene (PTFE), aluminum foil and Packed in a heat-shrinkable tube (available under the trade designation "TEFLON HEAT SHRINK TUBING from Zeus, Inc., Orangeburg, SC). The wrapped core was placed in kindergaten inside the furnace at the experimental temperature.

Conducted a preliminary rinsing, applying the fluid for pre-washing before handling the formation Sandstone gas condensate having a brine with high salinity and/or high water saturation. The example was carried out using a core of Berea Sandstone at a temperature of 322°F (161°C).

The initial permeability was measured using nitrogen at 75°F (23,9°C). The initial saturation of the brine 30% were established by injection of a measured value of the brine in vakuumirovaniya the core. The salinity of the used brine was 180600 ppm. NaCl. The relative gas permeability at initial water saturation was measured using nitrogen at 75°F (23,9°C). Table 1 (below) contains the properties of the core and the conditions of the method.

The Berea Sandstone
Table 1
Kern
Length, inches (cm)by 5.87 (14,91)
Diameter, inches (cm)1 (2,54)
Porosity, %20
Pore volume, cm315,38
Swi (pumping salt water), %30
Temperature, °F (°C)322 (161)
k, millidarcy311

Was the mixture of synthetic hydrocarbons, which shows properties of retrograde condensate. Table 2 (below) represents the composition of a mixture of synthetic gas. Two-phase waterflooding liquid mixture is performed using a dynamic method of filling, which is also known as the way of the quasi-stationary mode, passing the fluid through the top regulator back pressure above the pressure dew point at 5500 psig (37,91 MPa) pressure core located below the pressure dew point by means of the lower back pressure regulator. This experiment was completed when the pressure of the Kern 2600 psig (17,92 MPa). Table 3 summarizes the results of preliminary the Oh processing of two-phase flow.

Table 2
Componentmol.%
Methane70
n-butane16,5
n-Heptane7
n-Dean3
n-Dodecan2
n-Pentadecane1,5

Table 3
krgkroScore improve
Pre-processing 2-phase flowof 0.0660,075
Paleorrota 2-phase flow0,112to 0.1271,7

Then the core was washed 20 Provimi volumes of fluid (described in table 5 (below). Pre-washing removed the brine with high salinity and the core and, thus, it prevented the working solution (composition given in table 4 (below)from reaching the cloud point that could occur in the presence of brine with high salinity or high water saturation. The core was then treated with 20 pore volume of the composition As described in table 4 (below), and then kept for 15 hours. Steady-state two-phase flow of gas and condensate is then performed under the same conditions as pre-treatment two-phase flow. In table 3 (above) has finalized the result for the post of two-phase flow. The results showed that chemical treatment increased the relative permeability of gas and condensate approximately 1.7. In table 6 (below) shows the results of interoperability testing between the composition and the brine used in example 1 at 160°C.

Table 4
Component compositionwt.%
The nonionic fluorinated polymeric surfactant And2
Propylene glycol (PG)69
Isopropyl alcohol (IPA)29

Table 5
Component of a fluid mediumwt.%
Propylene glycol (PG)70
Isopropyl alcohol (IPA)30

Table 6
The brine gramsComposition (table-4), gBrine, wt.%Solubility
1420Transparent
1,253,7525Transparent
1,53,530Slightly cloudy
1,753,2535Muddy

The results showed that pre-rinsing fluid medium provides an effective means of processing formations of Sandstone, receiving fluids gas condensate with present high salt is part of the brine. Preliminary leaching can also be applied in the processing of formations with high vodonasyshennost as pre-washing can dissolve or displace most of the water before the formation process nonionic fluorinated polymeric surface-active substance. Liquid pre-flow can reduce or eliminate the possibility of a working solution, to achieve a cloud point during the processing of the above-mentioned formations, thus making the treatment more effective.

EXAMPLE 2

This method was applied liquid pre-washing before handling the formation Sandstone with low permeability of gas condensate, which has a high salinity present brine. The method was performed on the sample core sandy collector characteristics described in table 7 (below), when the temperature of the reservoir 279°F (137,2°C). In Table 7 (below) illustrates the properties of the core and the conditions of the method.

Table 7
KernSandstone
Length, inches (cm)1,9
Diameter, inches (cm)1 (2,54)
Porosity, % 13
Pore volume, CC3,17
Swi, %15
Temperature, °F (°C)279 (137,2)
k, millidarcy7,3
kg(Swi)6,9

The receiving core

The core was dried in an oven at 100°C for 24 hours and then weighed. Then the core was wrapped in a polytetrafluoroethylene (PTFE), aluminum foil and a heat-shrinkable tube "TEFLON HEAT SHRINK TUBING". Wrapped core was placed in kindergaten inside the furnace at 279°F (137,2°C).

The receiving core

The initial permeability was measured using nitrogen at 75°F (23,8°C). The initial saturation of the brine 15% was established by injection of a measured volume of brine in vakuumirovaniya the core. The salinity of the used brine was over 230,000 ppm with the composition of the brine table 8 (below). The relative permeability for gas when the initial water saturation was measured using nitrogen at 75°F (23,8°C).

Table 8
Chemicalg/l
NaCl225,2
CaCl2 1,5
KCl3,1

Got a synthetic hydrocarbon mixture showing the properties of a retrograde gas condensate. In table 9 (below) presents the composition of a mixture of synthetic gas. Two-phase waterflooding liquid mixture is performed using a dynamic method of filling, which is also known as the way of the quasi-stationary mode, passing the fluid through the top regulator back pressure above the pressure dew point at 5500 psig (37,91 MPa) pressure core located below the pressure dew point by means of the lower back pressure regulator. This experiment was completed when the pressure of the Kern 2600 psig (17,92 MPa). Table 10 (below) the results of pre-treatment two-phase flow.

Table 9
Componentmol.%
Methane95
Propane1
n-Heptane1,25
n-Dean1,25
n-Penta is a perfect combination 1,5

Table 10
krgkroScore improve
Pre-processing 2-phase flow0,067to 0.032n/a
Paleorrota 2-phase flow0,0910,0431,36

Then the core was washed with 9 volumes of pore fluid (described in table 11 below). Flushing fluid displaces the brine high salinity of the core and thus prevents the composition (described in table 11 below) from reaching the cloud point, which may occur in the presence of high salinity brine, located in the core. The core was then treated with 20 volumes of pores of the composition described in table 11 (below), and then kept for 15 hours. Steady-state two-phase flow of gas and condensate is then performed under the same conditions as pre-treatment two-phase flow. In table 10 (above) has finalized the result for the post of two-phase flow. The results showed that the chemical processing which has increased the relative permeability of gas and condensate at approximately 1,36.

Table 11
Componentwt.%
The nonionic fluorinated polymeric surfactant And2
Propylene glycol (PG)69
Isopropyl alcohol (IPA)29

Table 12
Component of a fluid mediumwt.%
Propylene glycol (PG)70
Isopropyl alcohol (IPA)30

EXAMPLE 3

In this example, the liquid pre-wash was applied before processing the formation Sandstone gas condensate, which was originally present in the water. The example was carried out using the core of Berea Sandstone at a temperature of 275°F (135°C).

The core dimensions, defined below, cut from a block of bedrock. The core was dried in an oven at 100°C for 24 hours and then weighed. Then the core was wrapped in a polytetrafluoroethylene (PTFE), aluminum foil and termophilous the Xia tube "TEFLON HEAT SHRINK TUBING". Wrapped core was placed in kindergaten inside the oven at 275°F (135°C).

The initial permeability was measured using nitrogen at 75°F (23,8°C). The initial saturation of the brine 26% were established by injection of a measured volume of brine in vakuumirovaniya the core. The relative permeability for gas when the initial water saturation was measured using nitrogen at 75°F (23,8°C). In table 13 (below) shows the properties of the core and the conditions of the method.

Table 13
KernThe Berea Sandstone
Length, inches8
Diameter, inches (cm)1 (2,54)
Porosity, %20
Pore volume, CC20,59
Swi, %26
Temperature, °F (°C)275 (137,2)
k, millidarcy231

The composition of the brine is given in table 14.

Table 14
Sol PPM
NaCl59000
CaCl216000
MgCl2·6H2O3500

Got a synthetic hydrocarbon mixture showing the properties of a retrograde gas condensate. In table 15 (below) presents the composition of a mixture of synthetic gas. Two-phase flooding (ponding condensate-1) liquid mixture is performed using a dynamic method of filling, which is also known as the way of the quasi-stationary mode, passing the fluid through the top regulator back pressure above the pressure dew point at 4500 pounds per square inch pressure core located below the pressure dew point by means of the lower back pressure regulator. This experiment was completed at a pressure core 1500 pounds per square inch. In table 15 (below) shows the results of the preliminary processing of two-phase flow.

Table 15
Componentmol.%
Methane91,605
n-butane3,94
1,97
n-Pentadecane0,985
Water1,5

Then the core was washed 16 volumes of pores of methanol to displace the brine. Methanol washed by passing a two-phase mixture of gas condensate through the core. The core is then processed 19 pore volume of the composition described in table 17 (below), and then kept for 24 hours. Steady-state two-phase flow of gas and condensate (condensate flooding-2) is then performed under the same conditions as pre-treatment two-phase flow. In table 16 (below) has finalized the result for the flooding of the condensate-2. The results showed that the chemical treatment did not cause any effect on the relative permeability of gas and condensate.

Table 16
krgkroScore improve
Flooding condensate-1 (Pre-processing 2-phase flow)0,0740,025
Flooding condensate-20,082 0,0281,1
Flooding condensate-30,1210,0421,64

Table 17
Componentwt.%
The nonionic fluorinated polymeric surfactant And2
Methanol94
Water4

The following core washed 16 volumes of pores of toluene. Toluene and then washed by passing a two-phase mixture of gas condensate through the core. The core is then re-treated with 20 pore volume of the composition described in table 17 (above), and then kept for 24 hours. In conclusion, the steady-state two-phase flow of gas and condensate (condensate flooding-3) is then performed under the same conditions as pre-treatment two-phase flow. In table 16 (above) has finalized the result for the flooding of the condensate-3. The results showed that chemical treatment increased the relative permeability of gas and condensate approximately 1.64.

Comparative example a

Composition. Nonionic Porirua the Noah polymeric surfactant (2% by weight), methanol (94% by weight) and water (4% by weight) were mixed together using a magnetic stirrer and a mechanical stirrer.

Assessment of flooding core

The substrates. A sample core of Berea Sandstone was used in the evaluation of the flooding of the core. Kern had the properties shown in table 18.

Table 18
Length, inches (cm)1,0 (2,54)
Diameter, inches (cm)8,0 (20,32)
Pore volume, ml20,6
Porosity, %20,0

Porosity was measured using the method of expansion of the gas or by utilizing the difference in weight between dry and fully saturated the core sample. Pore volume is the total volume of the product and the porous structure.

Composition of synthetic condensate

Synthetic fluid environment of gas condensates containing 93 mole percent methane, 4 mole percent n-butane, 2 mole% n-decane and 1 mole percent n-pentadecane was used to assess the flooding of the core. Approximate values of various properties of the fluid are summarized in table 19 below.

Table 19
The saturation point, psi (PA)4200 (2,9×107)
The pressure of the core, psi (PA)1500 (1,0×l07)
Loss of fluid, V/Vt %3,2
The viscosity of the gas, the joint venture0,017
The viscosity of the oil, SP0,22
Surface tension, Dyne/cm5,0

The receiving core

The cores were dried for 72 hours in a standard laboratory oven at 95°C, and then wrapped in aluminum foil and TEFLON HEAT SHRINK TUBING". According to figure 3 wrapped core 109 placed in kindergaten 108 inside the furnace 110 at 75°F (24°C). Used the pressure load of 3400 pounds per square inch (2,3×107PA). The initial single-phase gas permeability was measured using nitrogen or methane at a dynamic pressure of 1200 psig (8,3×106PA).

Brine containing 92,25% water, 5.9% sodium chloride, 1.6% calcium chloride, 0,23% uranyl magnesium chloride and 0.05% potassium chloride, introduced in the core 109 in the following way. The output end of kindergaten connected to a vacuum pump, and a full vacuum was applied for 30 minutes with closed input on what slot. The outlet was closed and the inlet opened to allow a known volume of brine to flow into the core. For example, found 26% saturation relict water (i.e. 26% of the pore volume of the core was filled with water, allowing you to 5.3 ml of brine to flow into the core, before he closed the inner valve. The permeability was measured at saturation relict water 26% using a stream of nitrogen or methane at 1200 psig (8,3×106PA) and 75°F (24°C).

The way the flooding of the core. Again according to figure 3 wrapped core 109 in kindergaten 108 was placed in the furnace 110 at 275°F (135°C) for several hours to allow it to reach the temperature of the tank. Then the fluid synthetic gas condensates described above, was introduced at a flow rate of approximately 690 ml/hour until established a balance. The regulator back pressure at the inlet 106 installed at approximately 4900 psi (3,38×107 Pa), higher than the condensing pressure of the fluid, and the regulator back pressure at the outlet 104 installed on approximately 1500 pounds per square inch (3,38×107 Pa), respectively downhole pressure of the flowing well. The relative permeability for gas before processing then calculated to reduce stationary pressure. The composition of the surfactant introduced into the core without first injection of fluid into the core, to popitam is by dissolving or move the brine. After completing at least 20 pore volumes of the composition of the surfactant was kept in the core at 275°F (135°C) for 15 hours. Above the fluid synthetic gas condensate then introduced again at a flow rate of approximately 690 ml/hour using a piston pump 102 to achieve a state of equilibrium. The relative permeability for gas after treatment then calculated to reduce stationary pressure. After measurements of relative permeability introduced methane gas using a piston pump 102 for draining condensate and final measurement of single-phase gas permeability, to show that the core is not damaged.

The initial single-phase gas permeability, measured before saturation of the brine, the initial capillary number, the relative permeability for gas before treatment with the composition of surfactant, relative permeability for gas after treatment and the ratio of relative permeabilities for gas after and before treatment (i.e., the rate of improvement) for the comparative example And summarized in table 20 below.

Table 20
The permeability, millidarcys (md)231
The capillary numberof 1.1×10-5
The relative permeability for gas before processing0,084
The relative permeability of the gas after processing0,084
Score improve1,0

It will be understood that the specific embodiments of described here shown as an illustrative example, and not as restrictive. The main features of this invention can be used in different implementation without deviating from the scope of the invention. Specialists in this field confirm or will be able to detect using no more than routine experimentation, numerous equivalents to the specific procedures described here. Such equivalents will be considered as being within the scope of this invention and covered by the claims.

The use of single forms, together with the expression "comprising" in the claims and/or the specification may mean "one", but is also consistent with the meaning "one or more", "at least one" and "one or more than one." The use of the expression "or" in the claims is used to oboznacheny the "and/or", if unspecified reference to alternatives only or the alternatives are mutually exclusive, although the disclosure supports a definition that refers to only alternatives and "and/or". Throughout this application the terms "approximately" is used to indicate that a value includes the inherent change of the error for a device, the method was permanen to determine the value.

The expression "or combinations thereof", as used herein, refers to all permutations and combinations of these units, the preceding expression. For example, "a, b, C, or combinations thereof" is intended to include at least one of: a, b, C, AB, AC, BC, or ABC, and if order is important in a particular context, also BA, CA, CB, CBA, ICA, ASV, YOU or CAB. Continuing with this example, also included are combinations containing repeating one or more units or expressions, such as BB, AAA, MB, air force, AAASSS, SWAA, SAWAW, and so on. The person skilled in the art will understand that usually there is no limit to the number of units or expressions in any combination, unless otherwise clear from the context.

1. The method of processing clastic formation bearing hydrocarbons, in which there is a brine, and the method includes the steps are:
brought into contact clastic formation bearing hydrocarbons, with tech is whose environment where the fluid medium is at least one of at least partially dissolving or at least partially displacing brine in clastic formation bearing hydrocarbons; and
subsequently brought into contact clastic formation bearing hydrocarbons, the composition, the composition includes:
the nonionic fluorinated polymeric surfactant, including:
at least one divalent unit represented by the formula:

at least one divalent unit represented by the formula:



where Rfrepresents performanceline group having from 1 to 8 carbon atoms;
R, R1and R2each independently represents hydrogen or alkyl of 1-4 carbon atoms;
n is an integer from 2 to 10;
EO represents-CH2CH2O-;
each RA independently represents-CH(CH3)CH2O - or-CH2CH(CH3)O-;
each p independently represents an integer from 1 to about 128; and
each q independently represents an integer from 0 to about 55; and
solvent, and, when the composition is brought into contact with clastic formation, chosen to replace the first hydrocarbon, the nonionic fluorinated polymeric surfactant has a point cloud, which is higher than the temperature of clastic formation bearing hydrocarbons.

2. The method according to claim 1, where, when the composition is brought into contact with clastic formation bearing hydrocarbons, the formation is not primarily contains precipitated salt.

3. The method according to claim 1, where the fluid mainly contains no surfactants.

4. The method according to claim 1, where the fluid includes at least one of toluene, diesel, heptane, octane or condensate.

5. The method according to claim 1, where the fluid medium at least partially dissolves the brine.

6. The method according to claim 1, where the fluid includes at least one of a polyol or Paleologo ether and a polyol and paleology ether independently have from 2 to 25 carbon atoms.

7. The method according to claim 6, where the polyol or paleology ether, at least, is one of the 2-butoxyethanol, ethylene glycol, propylene glycol, poly(propylene glycol), 1,3-propane diol, 1,8-octandiol, nanometrology ether of diethylene glycol, monobutyl ether of ethylene glycol or nanometrology ether dipropyleneglycol.

8. The method according to claim 1, where the fluid includes at least one monohydroxy alcohol, ether, or ketone independently having from 1 to 4 carbon atoms.

9. The method according to claim 1, where the fluid tridacnidae, at least one of water, methanol, ethanol or isopropanol.

10. The method according to claim 1, where the fluid includes at least one of nitrogen, carbon dioxide or methane.

11. The method according to claim 1, where the composition includes at least 50 wt.% solvent based on the total weight of the composition.

12. The method according to any one of claims 1 to 11, where the solvent includes water.

13. The method according to any one of claims 1 to 11, where the solvent includes at least one of a polyol or Paleologo ether and a polyol and paleology ether independently have from 2 to 25 carbon atoms.

14. The method according to item 13, where the polyol or paleology ether, at least one of 2-butoxyethanol, ethylene glycol, propylene glycol, poly(propylene glycol), 1,3-propane diol, 1,8-octandiol, nanometrology ether of diethylene glycol, monobutyl ether of ethylene glycol or nanometrology ether dipropyleneglycol.

15. The method according to item 13, where the solvent comprises at least one monohydroxy alcohol, independently having from 1 to 4 carbon atoms.

16. The method according to any one of claims 1 to 11, where Rfis performatic.

17. The method according to any one of claims 1 to 11, where the nonionic fluorinated polymeric surfactant has srednetsenovoj molecular weight in the range from 1000 to 50000 g/mol.

18. The method according to any one of claims 1 to 11, where clastic formation, the carrier uglevodorov is, represents a downward well.

19. The method according to any one of claims 1 to 11, where clastic formation bearing hydrocarbons, has at least one first gas permeability prior to bringing into contact of the formation with the fluid medium and the bringing into contact of the formation with the composition, and at least one second gas permeability after bringing into contact of the formation with the fluid medium, and bringing into contact of the formation with the composition, and where the second gas permeability of at least 5% greater than the first gas permeability.

20. The method according to claim 19, where the first and second gas permeability represent the relative permeability for gas.

21. The method according to any one of claims 1 to 11, further comprising a stage on which allow condensate flow in clastic formation bearing hydrocarbons, after bringing into contact of the formation with the fluid medium and before the bringing into contact of the formation with the composition.

22. The method according to any one of claims 1 to 11, where the formation has a condensate, and where the fluid medium, at least one of at least partially dissolving or at least partially displacing condensate.

23. The method according to any one of claims 1 to 11, where the wellbore navigate through clastic formation bearing hydrocarbons, the method further includes obtaining uglev the hydrocarbons from the well after bringing into contact clastic formation, bearing hydrocarbon composition.

24. The method according to any one of claims 1 to 11, where clastic formation bearing hydrocarbons, has at least one crack.

25. The method according to paragraph 24, where the crack contains a lot of propping agents.



 

Same patents:

FIELD: mining.

SUBSTANCE: viscoelastic composition for the use in underground formations includes, at least, one quaternary alkylamidoamine of the given formula and at least one indicated sub-additive when the ratio by weight is within 1000:1 and 5:1. Water-base fluid for the use in oil deposit includes indicated composition. Composition of high-density brine for oil deposit includes within 30-70 wt % of organic and/or inorganic salt and the composition mentioned above. Fluid of oil deposit termination in the form of high-density brine contains within 30-70 wt % of, at least, one organic or inorganic acid, within 0.1-4 wt % of, at least, one cationic surfactant from the modified group and, at least, one sub-additive from the modified group. The method of cracking underground formation includes provision of thickened fluid for water-base hydraulic fracturing, which includes water environment and effective amount of the above mentioned composition and injection of aqueous fluid through the well bore into the underground formation at a pressure, sufficient to break the formation. The invention is developed in the formula subclaims.

EFFECT: improvement of efficiency in upgrading permeability of underground formations.

24 cl, 4 ex

FIELD: oil-and-gas production.

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EFFECT: higher efficiency of tertiary oil extraction.

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FIELD: oil and gas production.

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EFFECT: increase of injection capacity of intake well and influx to the producing wells, start of development of leak-proof zones not covered by influence.

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EFFECT: increasing oil recovery from formations.

4 cl, 3 ex

FIELD: oil and gas industry.

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12 cl, 2 tbl, 8 dwg

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16 cl, 15 ex, 15 dwg

FIELD: process engineering.

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23 cl, 1 ex, 3 tbl

FIELD: chemistry.

SUBSTANCE: liquid composition contains the following: suspension on oil basis, which includes base oil, organophilic clay, polar activating agent, wetting agent, and composition improving the operability in winter conditions, which contains one or many composite monoesters of polyols and/or composite diesters of polyols. Composition is meant for hydraulic fracturing of underground formation, removal of combined wafer from productive underground formation. Hydraulic fracturing method of underground formation involves pumping to the formation under the pressure which is enough for fracturing, liquid for fracturing, which contains propping agent and suspension on oil base, which includes base oil, organophilic clay, polar activating agent, wetting agent and the above composition, or according to the other version - fracturing liquid containing the above suspension, and pumping to the formation subjected to fracturing under pressure which is enough for protection of cracks against joining of carrying liquid with propping agent. Production method involves circulation and/or pumping to production well of the liquid including the above suspension.

EFFECT: improving operability in winter conditions.

25 cl, 18 tbl, 3 ex, 4 dwg

FIELD: oil and gas industry.

SUBSTANCE: methods involving the use of composition for slow increase in adhesive ability, which includes water agent for increasing the adhesive ability and activating agent of slow separation of the acid which is used for stabilisation of particles and minimisation of particle migration inside underground formation. Invention has been developed in dependent claims.

EFFECT: improvement of operating flexibility and controllability of operations and mechanical elasticity of stabilised masses.

20 cl, 1 ex

FIELD: mining.

SUBSTANCE: viscoelastic composition for the use in underground formations includes, at least, one quaternary alkylamidoamine of the given formula and at least one indicated sub-additive when the ratio by weight is within 1000:1 and 5:1. Water-base fluid for the use in oil deposit includes indicated composition. Composition of high-density brine for oil deposit includes within 30-70 wt % of organic and/or inorganic salt and the composition mentioned above. Fluid of oil deposit termination in the form of high-density brine contains within 30-70 wt % of, at least, one organic or inorganic acid, within 0.1-4 wt % of, at least, one cationic surfactant from the modified group and, at least, one sub-additive from the modified group. The method of cracking underground formation includes provision of thickened fluid for water-base hydraulic fracturing, which includes water environment and effective amount of the above mentioned composition and injection of aqueous fluid through the well bore into the underground formation at a pressure, sufficient to break the formation. The invention is developed in the formula subclaims.

EFFECT: improvement of efficiency in upgrading permeability of underground formations.

24 cl, 4 ex

FIELD: mining.

SUBSTANCE: viscoelastic composition for the use in underground formations includes, at least, one quaternary alkylamidoamine of the given formula and at least one indicated sub-additive when the ratio by weight is within 1000:1 and 5:1. Water-base fluid for the use in oil deposit includes indicated composition. Composition of high-density brine for oil deposit includes within 30-70 wt % of organic and/or inorganic salt and the composition mentioned above. Fluid of oil deposit termination in the form of high-density brine contains within 30-70 wt % of, at least, one organic or inorganic acid, within 0.1-4 wt % of, at least, one cationic surfactant from the modified group and, at least, one sub-additive from the modified group. The method of cracking underground formation includes provision of thickened fluid for water-base hydraulic fracturing, which includes water environment and effective amount of the above mentioned composition and injection of aqueous fluid through the well bore into the underground formation at a pressure, sufficient to break the formation. The invention is developed in the formula subclaims.

EFFECT: improvement of efficiency in upgrading permeability of underground formations.

24 cl, 4 ex

FIELD: mining.

SUBSTANCE: drilling mud additive ensuring thermal stability contains the mixture of: reaction product of amine and polyfunctional isocyanate and reaction product of carboxylic acid with, at least, two carboxylic fragments; of polyamine, containing two or more functional amine groups; and chemical substance, chosen out of the group, consisted of: alkoxylated alkylamine, amides of fatty acids and their compounds. The invention is developed in dependant claims.

EFFECT: providing the thermal stability of drilling muds.

29 cl, 4 tbl, 3ex

FIELD: mining.

SUBSTANCE: drilling mud additive ensuring thermal stability contains the mixture of: reaction product of amine and polyfunctional isocyanate and reaction product of carboxylic acid with, at least, two carboxylic fragments; of polyamine, containing two or more functional amine groups; and chemical substance, chosen out of the group, consisted of: alkoxylated alkylamine, amides of fatty acids and their compounds. The invention is developed in dependant claims.

EFFECT: providing the thermal stability of drilling muds.

29 cl, 4 tbl, 3ex

FIELD: mining.

SUBSTANCE: method of preparation for cementing of wells drilled using invert-emulsion drilling mud is characterised by the fact that casing column is lowered into the well and washed with invert-emulsion drilling mud; four flush fluids are pumped subsequently into the well: parting-displacement fluid, solvent fluid, washing fluid and displacement fluid, and their further forcing to behind-the-casing space with well cement mortar and flushing fluid with their complete displacement from the well and installation of well cement mortar in behind-the-casing space at the required interval; at that, mixture of invert-emulsion drilling mud with formation water and with organic solvent in volume ratio of (4-6):(2.5-5.5.):(0.5-1.5) respectively is used as parting-displacement flush fluid; mixture of organic solvent, tall oil and 40% of water solution of sodium hydroxide in volume ratio of (9.0-9.6):(0.2-0.5):(0.2-0.5) respectively is used as solvent flush fluid; water solution of detergent also acting as demulsifying agent with 0.5-4% mass concentration is used as washing flush fluid; light-weight cement slurry with density of 1.35-1.45 g/cm3 is used as displacement flush fluid. At that, rheological characteristics: plastic viscosity and dynamic shear stress of solvent flush fluid are higher than rheological characteristics of the previous one - parting-displacement fluid, and further washing flush fluid, and density and rheological characteristics of displacement flush fluid are higher than those of the previous one - washing flush fluid.

EFFECT: increasing the volume of dense contact of cement stone with enclosing surfaces.

4 cl, 1 ex, 3 tbl

FIELD: mining.

SUBSTANCE: method of preparation for cementing of wells drilled using invert-emulsion drilling mud is characterised by the fact that casing column is lowered into the well and washed with invert-emulsion drilling mud; four flush fluids are pumped subsequently into the well: parting-displacement fluid, solvent fluid, washing fluid and displacement fluid, and their further forcing to behind-the-casing space with well cement mortar and flushing fluid with their complete displacement from the well and installation of well cement mortar in behind-the-casing space at the required interval; at that, mixture of invert-emulsion drilling mud with formation water and with organic solvent in volume ratio of (4-6):(2.5-5.5.):(0.5-1.5) respectively is used as parting-displacement flush fluid; mixture of organic solvent, tall oil and 40% of water solution of sodium hydroxide in volume ratio of (9.0-9.6):(0.2-0.5):(0.2-0.5) respectively is used as solvent flush fluid; water solution of detergent also acting as demulsifying agent with 0.5-4% mass concentration is used as washing flush fluid; light-weight cement slurry with density of 1.35-1.45 g/cm3 is used as displacement flush fluid. At that, rheological characteristics: plastic viscosity and dynamic shear stress of solvent flush fluid are higher than rheological characteristics of the previous one - parting-displacement fluid, and further washing flush fluid, and density and rheological characteristics of displacement flush fluid are higher than those of the previous one - washing flush fluid.

EFFECT: increasing the volume of dense contact of cement stone with enclosing surfaces.

4 cl, 1 ex, 3 tbl

FIELD: oil-and-gas production.

SUBSTANCE: proposed method grinding raw mix, pelletizing fine batch, sieving preset-size granules, their drying, annealing and classification. Batch pelletising is performed in turbine mixer for 6-35 s at high-intensity circular motion of bulk that ensures normal acceleration of particles to 500-2500 m/s2 with batch moistening for 50-90% of normal level, and, after maturing for 0.5-6 min, granules are shaped to required sphericity in dish noduliser with addition of remaining amount of moistening solution. Proposed invention is developed in dependent claims.

EFFECT: higher yield and strength.

4 cl, 4 tbl

FIELD: oil-and-gas production.

SUBSTANCE: expanding grouting mortar comprises tempering fluid, water, and base consisting of Portland cement, filtration index reducer, i.e. hydroxyethylcellulose, polycarbonate as plasticiser, defoaming agent, expanding additive, accelerator of thickening and cementation, i.e. calcium chloride. Note here that said base additionally comprises silica-alumina pozzolanic admixture, i.e. meta white clay, while expanding additive is represented by product of combined grinding of blast-furnace slag and quicklime ''ДРС-НУ'' of average chemical composition, in wt %: CaO+MgO - 72-93; SiO2 - 7-23; Al2O3 - 0-4; Fe2O3 - 0-2.5; other impurities - 0-4.5; base as defoaming agent comprises polyglycol "ПЛАСТЭК ПГ-07", at the following ratio of components, in wt %: Portland cement - 91.8-94.2, hydroxyethylcellulose - 0.15-0.3, said plasticiser - 0.2-0.3, said expanding additive - 3.0-5.0, defoaming agent - 0.01-0.03, meta white clay - 0.5-2.0, calcium chloride - 0.5-2.5, while water content in solution allows water-to-base ratio of 0.48-0.64.

EFFECT: higher grouting capacity due to higher flowability, low filtration, increased expanding ability.

1 ex, 2 tbl

FIELD: oil-and-gas production.

SUBSTANCE: proposed acid-soluble backfill composition comprises backfill Portland cement, dust from electric filters of cement plants, admixture of silica-alumina composition and water. Additionally, it includes gypsum-alumina expanding cement and super plasticiser "ЦЕМПЛАСТ МФ" or Melflux and silica-alumina microspheres as said admixture at the following ratio of components, in wt % backfill Portland cement 17.6-33.5, gypsum-alumina expanding cement 3.3-17.6, said cement dust 3.3-20.1, said super plasticiser 0.06-0.13, silica-alumina microspheres 6.7-30.0, water 32.8-41.3.

EFFECT: complete acid-solubility of cement stone, higher strength.

1 ex, 2 tbl

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: production and exploratory well drilling, particularly foaming drilling fluids used during penetration through incompetent rock intervals and during primary productive oil and gas deposit opening in the case of abnormally low formation pressure.

SUBSTANCE: foam composition comprises surfactant, foam stabilizer, water, water hardness control additive and lubricant. The water hardness control additive is sodium silicate. The lubricant is VNIINP-117 emulsion. The foam stabilizer is polyacrylamide, the surfactant is sulphonole. All above components are taken in the following amounts (% by weight): sulphonole - 0.8-1.5, sodium silicate - 0.2-0.5, polyacrylamide - 0.1-0.5, VNIINP-117 - 0.5-2, remainder is water.

EFFECT: reduced power inputs for well drilling, as well as reduced coefficient of friction between drilling tool and well wall.

1 tbl

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