Compositions of liquids for treatment of wells, which includes compounds with retarded liberation of percarbonate, and their application methods

FIELD: oil and gas industry.

SUBSTANCE: well treatment liquids include water, at least one hydratable polymer, granules of sodium percarbonate with the coating retarding its liberation. As per the first version, the above coating is non-organic material. As per the second version, the above coating includes mixture of styrene-acrylate and butyl acrylate. Underground formation hydraulic fracturing method involves granules of sodium percarbonate with coating from non-organic material retarding its liberation. Inventions have been developed in dependent claims.

EFFECT: avoiding premature viscosity reduction of treatment liquid due to using sodium percarbonate granules with the coating retarding its liberation.

23 cl, 4 tbl, 6 ex, 6 dwg

 

Prior art

The present invention generally relates to liquid compositions for treatment of wells and methods of use thereof, and more precisely to liquids for well treatments and methods that include composition with delayed release of percarbonate.

The internal pressure in the oil well displaces on the surface of only the first 3% and 10-20% can be extracted by conventional pumping. Access at least part of the remaining oil requires more advanced technology. To access commonly used viscous fluid for processing of drilling wells, the opening of the oil reservoir and the treatment of subterranean formations penetrated by wells. For example, often practiced hydraulic fracturing as a means to increase production. During hydraulic fracturing in the well is pumped under high pressure viscous liquid to the treatment well. As soon as the pressure of the natural reservoir is exceeded, the fluid for fracturing begins fracturing, which usually continues to grow during discharge. When, during processing, the gap widens to a suitable width, the liquid can also be added proppants (e.g., grains of sand, aluminum pellets, or other material). Proppants remain in p is obtained break to prevent closing of the gap and the formation of a conductive channel, passing from the well to the treated layer, when removing the frac fluid. Processing technology is usually required fluid for well treatment, reaching a maximum viscosity when injected into the gap that affects the length and width of the gap. The viscosity of most liquids for hydraulic fracturing creates water-soluble polysaccharides such as galactomannan or derivative thereof. To increase the viscosity of the liquid usually add staplers, such as borate, titanate or zirconium ions.

Once formed an appropriate number of breaks is usually desirable that the viscosity of the liquid decreased to levels close to the viscosity of the water after placing proppant. It allows you to extract part of the liquid for processing without obtaining excessive amounts of proppant after opening and returning the well to production. Removing the frac fluid is achieved by reducing the viscosity of the liquid to a lower value, such that it gushes from the reservoir in a natural way. Introduction to liquid chemical agents, referred to as thinner or Rasizade agent, can lead to the achievement of this reduction of viscosity or conversion. Typically, these agents are either oxidants or enzymes that break down polymeric structure is round gel.

Liquids for processing are used in treatments to combat sand, such as gravel filter. In the treatment of gravel filters liquid for processing suspends particles (usually referred to as "particles of gravel") for delivery to the desired region of the well, e.g., near unconsolidated or kabupaten zones of the layer for forming gravel filter to improve the fight against the sand. Normal mode gravel filter includes placing the screen to fight the sand in the well and the seal ring between the screen and the well gravel particles of a certain size to prevent the flow of sand layer. Particles of gravel are used to prevent clogging of the screen by the particles of the formation or migration of produced hydrocarbons and the screen serves to prevent particles in the tubing. As soon as gravel filter is essentially in place, the viscosity of the liquid for processing can be reduced, so that it is possible to extract. In some cases, the fracturing and gravel processing filter are United in one treatment (commonly referred to as "hydraulic fracturing with the installation of the filter). In such operations the hydraulic installation of the filter processing usually end with the installation screen of the gravel filter in place with the Hydra is PLICSCOM the fracturing by injection through the annular space between the casing and screen. In this case, hydraulic fracturing could end end shielding of the crack. In other cases, the fracture can be performed prior to installation of the screen and placing gravel filter.

Maintaining sufficient viscosity in these fluids for processing is important for several reasons. Maintaining sufficient viscosity is important fracturing and treatments in the fight with sand for transport of the particles and/or creating or increasing the width of the gap. Maintaining sufficient viscosity may be important for controlling and/or reducing the loss of fluid in the reservoir. In addition, the liquid to be processed with sufficient viscosity can be used to change the direction of flow of the fluid existing in the subterranean formation (e.g., formation fluids, other liquids for processing), to other parts of the reservoir, e.g., "blockage" of open space in the reservoir. At the same time, although it is often desirable to maintain sufficient viscosity for processing, also can be desirable to maintain the viscosity of the liquid for processing so that the viscosity at a certain time can be reduced for subsequent removal of the liquid from the reservoir. In addition, the viscosity can also help to determine the open width of the gap.

When choosing a thinner can be considered the beginning of decrease in viscosity, so what. liquefaction. Viscous fluid for treatment of wells in the process of dissolving prematurely, can precipitate suspended material proppant prior to the introduction of a sufficient distance in the created gap. In addition, premature liquefaction can cause the width of the gap layer is less desirable, causing excessive discharge pressure and premature termination of treatment.

On the other hand, the viscous fluid to handle wells that are in the process of dissolving too slowly can lead to slow recovery frac fluid from the received gap that inhibits the production of hydrocarbons. Moreover, proppants may move from a break that causes at least a partial closure and reduce the efficiency gap. Preferably, the gel fracturing should start liquefied upon completion of discharge. For practical purposes, the gel should preferably be completely liquefied within about 24 hours after completion of hydraulic fracturing.

In low-temperature wells are often used enzymatic thinners, but they are relatively expensive compared to oxidative thinners. In shallow wells often used percarbonate, but with deeper drilling percarbonate cause premature resize is their less preferred.

Accordingly, in the prior art there is a need for improved thinners, which can be used in various installations, depths, conditions and applications in oil wells.

The invention

In the description of the disclosed compositions for treatment of wells and their uses. In one implementation, the fluid for the well treatment comprises water; at least one gidratiruyuschimi polymer; and granules percarbonate sodium coated for slow release, in which the coating for sustained release is an inorganic material.

In another implementation, the fluid for the well treatment comprises water; at least one gidratiruyuschimi polymer; and granules percarbonate sodium coated for slow release, in which the coating for sustained release includes a mixture of a styrene-acrylate and butyl acrylate.

In another implementation, a method of fracturing a subterranean formation includes the injection under pressure into the well water hydraulic fluid from the first viscosity, in which the aqueous hydraulic fluid comprises water; at least one gidratiruyuschimi polymer; and granules percarbonate sodium coated for slow release of inorganic material; the formation of breaks in the underground reservoir g is draulically fluid from the first viscosity and dissolution of the coating for sustained release leading to the effects of water on percarbonate sodium after a certain period of time; interaction percarbonate sodium, at least one hydratious polymer to reduce the first viscosity to a second viscosity; and removing at least part of the hydraulic fluid from the second viscosity.

Disclosure of the invention may be better understood with reference to the subsequent detailed description of the various features of the disclosure and the included examples.

Brief description of drawings

Refer now to the figures, in which like elements are numbered alike:

figure 1 graphically illustrates the viscosity of the liquid at 75°F as a function of time for different granules percarbonate sodium, covered and uncovered silicate, and the liquid contains crosslinked guar;

figure 2 graphically illustrates the viscosity at 133°F as a function of time, comparing pellets percarbonate sodium coated silicate, and uncoated granules percarbonate sodium and fluid contains crosslinked guar;

figure 3 graphically illustrates the viscosity at 190°F as a function of time for different concentrations of granules percarbonate sodium coated silicate, and uncoated granules percarbonate sodium and fluid contains crosslinked guar;

figure 4 graphically illustrates the viscosity of the liquid at 75°F as a function of time for granules percarbonate sodium coated silicate, and uncoated granules perkerson is the sodium, moreover, the liquid contains a copolymer of acrylic acid and of acrylamide;

figure 5 graphically illustrates the viscosity of a liquid at 120°F as a function of time for granules percarbonate sodium coated silicate, and uncoated granules percarbonate sodium, and the liquid contains a linear gel (unstitched) Guara; and

6 graphically illustrates the viscosity of a liquid at 150°F as a function of time for granules percarbonate sodium coated silicate, and uncoated granules percarbonate sodium, and the liquid contains a gel crosslinked with boron Guara.

Disclosure of inventions

The present invention mainly aims at creating liquids for treatment of wells containing composition percarbonate sodium delayed release for use in the oil industry. In accordance with the use in the description, the term "delayed release" refers to the dissolution profile, which delays the release of the oxidizer in the liquid for treatment of wells. For example, coatings that slow release granules percarbonate sodium, can provide the time of the dissolution of from about several minutes to about 5 hours at neutral pHs (i.e. pHs of about 6-8) depending on the intended application. Slow release percarbonate sodium may be used during drilling, the opening of the oil reservoir and process under which mnih layers and the like, at operating temperatures of about 0-400°F.

The fluid for the well treatment is an aqueous liquid containing at least one gidratiruyuschimi polymer, optionally a crosslinker and composition with delayed release of percarbonate sodium. In addition, if necessary, the liquid can be added proppants depending on the intended application in the oil field. During the application liquid is pumped into the subterranean formation with a first viscosity and then allow her to liquefied to collapse (i.e. the effect of reducing the viscosity) after dissolution of the coating delayed-release granules percarbonate sodium. Then, if necessary, the liquid for treatment of wells with reduced viscosity can be extracted. The planned end use will dictate the required viscosity of the fluid, for example, gels for cleaning the inner surface of the well may require more than a high viscosity, whereas the frac fluid may have a relatively low viscosity.

Water based, used in liquids for treatment of wells is not limited and may include water, salt water, brine, sea water, etc. In General, water can be from any source, processed or unprocessed, if it does not contain any components that can affect stabilnosti any of the other components of the fluid processing wells. pH of the aqueous liquid can be adjusted to make the liquid is compatible with the stapler. In one implementation, the materials that regulate the pH, is added to the aqueous liquid after adding thereto water-soluble polymer. Typical materials for adjusting the pH are bases, acids and buffers. For example, sodium bicarbonate, potassium carbonate, sodium hydroxide, potassium hydroxide and sodium carbonate are typical reagents for pH adjustment. In one implementation, the pH value of the fluid can be about 5-14. In other implementations pH of about 7-14 and in some other implementations pH of about 8-12.

Suitable hydratious polymers include those that are capable of forming a gel in the presence of the stapler. Suitable hydratious polysaccharides include, but are not limited to, galactomannan gum, guar derivatives of guar, katana, deutekom, scleroglucan and their derivatives. Specific examples include guar gum, derivatives of the guar gum, resin podrostkovogo tree, gum karaya, etc. Suitable hydratious polymers can also include synthetic polymers such as polyvinyl alcohol, polyacrylamides, poly-2-amino-2-methylpropanesulfonic acid and various other synthetic polymers and copolymers. Other suitable polymers known JV is the specialists in this field of technology. Also provided by a mixture of polymers.

The number hydratious polymer in the liquid is not limited. Usually gidratiruyuschimi polymer may be present in a liquid with a concentration of about 0.10 to 5.0% of the weight of the aqueous fluid. The preferred range of the content hydratious polymer about 0,20-0,80 wt.%.

A suitable binder may be any compound that increases the viscosity of the liquid chemical curing, physical stitching or any other mechanisms. In accordance with the use in the description of the term cross-linked usually refers to the formation of ties between the two molecules. For example, suitable staplers include borates such as boric acid, metaboric sodium, sodium tetraborate and the like; titanates, such as chelate esters of titanium; dialdehyde; compounds containing zirconium; zinc; various mixtures thereof; and the like, Other suitable suturing can be selected by a person skilled in the art. Selecting the appropriate staple usually depends on the type of planning process and used hydratious polymer. The number of stapler also depends on the conditions in the well and the type of planned treatment, but is usually in the range of about 10-1000 parts per million (ppm) of metal ions staple in liquid hydratious polymer. In some applications, water rest the R polymer crosslinks immediately after addition of the crosslinker with the formation of a very viscous gel. In other applications, the reaction of the crosslinker can be slowed so that the formation of a viscous gel does not occur until the desired moment.

Gidratiruyuschimi polymer alone or in combination with a crosslinker is present in a liquid with a concentration sufficient to provide a first viscosity of more than 1000 CPS (at of 3.77 with-1.

Composition with delayed release of percarbonate sodium is obtained from granules percarbonate sodium. In the present invention, the granules are essentially spherical particles with a normal distribution by size in the range of 0.3 to 1.5 millimeters (mm) core percarbonate sodium (Na2CO3: 1,5 H2About2and coated, slow release. Can be used sieves to separate a certain size, which may be desirable in various applications. Granules percarbonate sodium can be covered with an inorganic or polymeric material depending on the intended application. Suitable inorganic materials include silicates of alkali and/or alkaline earth metals. If necessary, granules percarbonate sodium can first be covered with a sulfate such as sodium sulfate, magnesium sulfate, and the like, coating Themselves preferably are uniform and homogeneous on the granules percarbonate sodium. The function of the coating layer comprised the t in the protection of percarbonate sodium from contact with moisture and/or water environment, which enhances the decomposition of the core material.

In one implementation of the inorganic material is a silicate of an alkali metal deposited in the amount of 15-37% by weight of the granules percarbonate sodium and in some other implementations 22-37 wt.%. It was found that the quantities of less than 15 wt.%, the slow dissolution of percarbonate in the liquid for treatment of wells is minimal at temperatures up to 150°F. a Similar result is observed when the content of silica is less than 22 wt.% at temperatures of 150-180°F. In quantities of more than 37 wt.% particles tend to agglomerate and clots. As soon as clots, floor asymmetrically breaks down during processing of wells, leading thus to a premature impact on gidratiruyuschimi the polymer percarbonate sodium, leading to oxidative dilution of the polymer and viscosity reduction. Because of this, the dissolution profile is very difficult to predict and it is often uneven. Typical alkali metal silicate is sodium (Na2SiO3).

Suitable polymers to create a slow release coating include polystyrenes, polyacrylates, polysiloxanes and mixtures thereof.

The coated granules percarbonate sodium typically includes spraying the desired coating on the granules percarbonate sodium fluid SL is E. Typical floor-based silicate will be performed by the air flow 120-155 cubic meters per hour (m3/h) at a temperature of 110-135°C. as an example, a layer of 2-3 kilograms (kg) percarbonate at a temperature of 80-105°C is sprayed at a rate of 0.5 to 2.5 kilograms per hour (kg/h) of the coating solution, diluted to about 30-40 wt.%. Typical polymeric coating can be carried by the air flow 125-140 m3/h at a temperature of 0-70°C. as an example, a layer of percarbonate about 3 kg at a temperature of 19-55°sprayed With the polymer solution at a rate of 0.2-0.7 kg/hour, a Coating of granules percarbonate sodium can be performed in AGT 150 system fluidized bed, commercially supplied Glatt (Germany).

The internal resistance of the granules percarbonate sodium can be monitored by analysis of the content of active oxygen in the time dimension values THERE (control thermal activity), and the value THERE is reduced with increasing resistance. Good storage life expressed low value THERE. For some applications it is THERE preferably should be below about 15 μw/g, and particularly below about 10 μw/g for percarbonate sodium. Is THERE microcalorimeter is the definition of energy emitted during the storage of measured THERE® Thermal Activity Monitor supplied Thermometric AB (Sweden). Decomposition lane is carbonate sodium it generates heat. The flow of this heat is measured by the amount THERE in µw/year

Liquid compositions for the initiation and completion (processing) of the present invention can optionally contain other additives. Additives are typically included to increase the stability of the liquid composition, prevent delamination caused by exposure to oxygen, temperature changes, traces of metals, components of the water, which is added to the liquid composition, prevent sub-optimal reaction kinetics of crosslinking, protection of oilfield equipment and prevent the growth of bacteria. The choice of components used in the liquid compositions, to a large extent dictated by the properties of hydrocarbon reservoir, in which they will be applied. Such additives can be selected from the group including oils, salts (including organic salts, biocides, corrosion inhibitors and solvents, pH modifiers (e.g., acids and bases), metallogenica, chelating agents, antioxidants, wetting agents, polymer stabilizers, clay stabilizers, inhibitors and solvents sediments, inhibitors and solvents formation of paraffin sediments, inhibitors, asphaltene precipitation inhibitors of the inflow water, additives from loss of liquid, chemical liquid solutions, flow-deflecting materials, reagents for artificial sand consolidation, RAS is linevalue fillers, the permeability modifiers, viscoelastic liquids, gases (such as nitrogen and carbon dioxide), blowing agents, etc.

The following examples are provided for illustrative purposes only and are not intended to limit the scope of the claims of the invention.

EXAMPLES

Percarbonate sodium following examples acquired from Kemira Kemi AB under the trademark Each. Sodium silicate with a molar ratio of 3.28 purchased from Askania (Sweden). The styrene-acrylate polymer and the polymer is a butyl acrylate/styrene purchased from the manufacturer of the paint Beckers (Sweden).

Stability is determined by analysis of the content of active oxygen freshly prepared samples and compared with the content of active oxygen in 2 months. The content of active oxygen or hydrogen peroxide is determined by titration with potassium permanganate (0,2 N) in acidic solution (10% sulfuric acid). A sample of 5 grams (g) are dissolved in 75 milliliters (ml) of 10% solution of H2SO4. From this sample, 3 g of the solution is titrated with a solution KMPO4using the combined Pt electrode; Metrohm 794 Basic Titrino and Metrohm 665 Dosimat.

The time of dissolution is determined by the conductivity, measured Cond 340i, WTW with 2 g of the sample in 1 liter (l) of deionized water at 20°C. the Sample was stirred at 750 revolutions per minute (rpm) during the measurement. The dissolution rate is determined graphically as the time (in minutes)for which the achieved 90% of maximum conductivity. To assess the contribution of the coating to the conductivity in the case of granules, coated with silicate of percarbonate covered Na2SiO3analyze1H-NMR. Spectra1H-NMR recorded on a Bruker Avance 500 spectrometer in D2O solutions at room temperature. The time of dissolution of the coating of sodium silicate measure to increase the peak of 4.8 ppm, which corresponds to the water produced during the decomposition of hydrogen peroxide (H2About2), and its release from the coating.

Example 1

In this example, granules percarbonate sodium covered with various types of coating materials with different thickness. Measure the time of dissolution and stability. Stability is determined by the content of active oxygen (AO) per 2-month period of time. The results are presented in table 1.

The obtained values of the content of active oxygen are used to compare the relative stability of the samples. The value for 24 hours is a standard benchmark uncovered percarbonate sodium as granules uncovered percarbonate sodium usually reach stable values after this time period.

6
Table 1
SampleFloor
Calculate the weight fraction of the coating (nide what about the %)
Dissolution (min)Source AO, %AO 2 months, %
ControlWithout coating (comparison)68 (s)32-
ControlWithout coating (comparison)51 (s)31-
1Na2SiO310%.332828
2Na2SiO330%1802121
3Styrene-acrylate 0,9%233130
4Styrene-acrylate of 1.7%683030
5The acrylate 8%122826
The butyl acrylate 30%262121
7Styrene-acrylate 2% + butyl Acrylate 3%1753030

The time units of dissolution for control are second. The results indicate that the time of the dissolution of percarbonate sodium retarded by the application of a coating of polymer or inorganic material. When a single coating granules percarbonate sodium coated silicate, show a very good effect of time of dissolution at room temperature and also give a very stable product. Although coating of the polymer of one type of acrylate usually less effective, it seems that the combination of polymers has a synergistic effect and is very effective even for very thin coatings. It seems that the polymer coatings also have a positive effect on stability.

Example 2

In this example analyzes the stability of percarbonate sodium coated with sodium silicate, and its capacity for destruction Guara during the test injection into an oil well. A 2-liter vessel 1000,0 g deionized water is added to 10.0 g of anionic carboxylate is hydroxypropylamino, purchased from Hercules, Incorporated under the trademark Aqualon Galactasol 651 and stirred for about 30 minutes at 3000 rpm to obtain a stock solution. To 175,0 g stock solution add 0.8 g of crosslinker, based on titanium, commercially supplied by E.I. du Pont de Nemours and Company under the trademark Tyzor®131, stirred at 1500 rpm for about 2 minutes and left to heliroute for about 30 minutes. Using a rotational viscometer Grace M3500A r, equipped with a rotor R1 and disk B2, the pre-gel is subjected to shear 75,4 with-1at a given temperature for 30 minutes and then subjected to shear for 30 s at of 3.77 with-1to measure the initial viscosity of the gel. Then add the specified amount of thinner and the gel is subjected to shear 75,4 with-1within 60 minutes, with 30-second intervals when of 3.77 with-1for measuring the viscosity after 1, 3, 5, 7, 10, 15, 20, 25, 30, 35, 40, 45, 50, 55 and 60 minutes. The parameters of each test are presented in table 2.

Table 2
The concentration of thinner (wt.% active percarbonate sodium)Temperature. (°F)Na2SiO3(% wt.)
1 0,0575Without coating
20,575Without coating
30,275133Without coating
40,05190Without coating
50,5190Without coating
60,2757510
70,057530
80,57530
90,27513330
100,0519030
110,5190 30

Figure 1-3 graphically illustrates the viscosity as a function of time with all the data for the above samples percentage of the initial viscosity. Data obtained at room temperature are presented in figure 1, show that both samples with silicate coating excellent stability regarding percarbonate sodium without coating, tested at the same temperature. Granules percarbonate sodium with 30 wt.% coating of sodium silicate show less release time than, granules percarbonate sodium with 10 wt.% coating of sodium silicate. However, at higher temperatures percarbonate released in the gel faster, which proves a more rapid decrease in viscosity and measurements at 190°F, there are small differences between the samples of coated and uncoated.

Example 3

In this example is the destruction of the guar polymer in the absence of shear for different granules percarbonate sodium coated and uncoated. A 2-liter vessel add 1 500.0 g of deionized water to 15.0 g of Aqualon Galactasol 651 polymer Guara and stirred for 30 minutes at 3000 rpm to obtain a stock solution of polymer is guar. The guar polymer is not crosslinked. of 300.0 g of the mother liquor is poured into 400 ml vessel. Half of this solution (150,0 ml) is poured into the autoclave to study thermal stability of the Boers is x solutions supplied Fann Instrument Company, and add different amounts of percarbonate sodium coated and uncoated, as shown in table 3. The remaining polymer solution Guara (150,0 ml) is added to the autoclave to study thermal stability of the drilling mud, which is then sealed, and create an increased pressure. The autoclave to study thermal stability of drilling fluids is shaken out three times to distribute the granules percarbonate sodium and placed in an oven for the time specified in table 4. Then measure the viscosity at of 3.77 with-1and 75°F rotary viscometer Grace M3500a equipped with a rotor R1 and disk B2. The temperature and pressure chosen to simulate depth 500-2500 feet, and time is 4-28 hours. The temperature and pressure to simulate different depths of the oil wells are presented in table 3, while table 4 presents the experimental conditions and results for each sample.

Table 3
Depth (ft)Temperature (°F)Pressure (psi)
50082250
2500113 1250

Table 4
Concentration (wt.%, active percarbonate sodium)Depth (ft)Time (h)Na2SiO3(wt.%)Viscosity at of 3.77 with-1(SP ± 80 JV)
10,055004Without coating4395
20,55004Without coating2996
30,0550028Without coating3271
40,550028Without coating859
50,0525004 Without coating3291
60,525004Without coating1521
70,05250028Without coating1576
80,5250028Without coating920
90,055004305304
100,55004304827
110,0550028303835
120,550028 302630
130,052,5004303375
140,52,5004302956
150,052,50028301967
160,52,5002830947

The results indicate that percarbonate sodium with 30 wt.% coating of sodium silicate interesting profile of destruction Guara. At shallow depths and in a shorter time percarbonate with a coating of sodium silicate much more slowly destroyed than percarbonate sodium without a cover, but in greater depth and for a longer time it destroys guar as well as percarbonate sodium without coating. A higher rate of destruction of guar follows from the increased rate of decomposition of percarbonate sodium at elevated temperatures. This would cause the three pressure increase inside the cover, ultimately, the destruction from the inside and the release of percarbonate sodium guar to dissolve the coating. However, the temperature Guara rises slowly from the surface temperature at the injection well and then heated at the bottom of the wellbore.

Example 4

In this example, evaluate the following thinners in the solution of polymer 4 pounds per 1000 gallons (lb/gallon) at 75°F: control without thinner; percarbonate sodium without coating; percarbonate sodium, covered with 22 wt.% sodium silicate; and percarbonate sodium, covered with 28 wt.% sodium silicate.

The polymer solution is prepared by adding 0,441 grams (g) copolymer of ultra-high molecular weight acrylic acid and acrylamide, commercially supplied under the trade mark Callaway A-4330, to 1000 g of deionized water. The solution is stirred for 30 minutes at 600 rpm, a polymer Solution (175 g) is poured into the container for the sample and placed in the viscometer Grace 3500 equipped with a rotor R1 and disk B1. Rotor machines fluid shear deformation under 100-1and immediately add the thinner (0,012±0.004 g). The viscosity is measured as a function of time within 90 minutes.

The results of these experiments are presented in figure 4. The viscosity of the control sample remains constant during the test, as the fluid processed by percarbonate sodium, covered with 28 wt.% silicate is the atrium. The sample percarbonate sodium with 22 wt.% coverage no release within the first 20 minutes, and then the polymer is slowly destroyed, as evidenced by the decrease of viscosity. However, percarbonate sodium without coating reacts quickly and immediately destroys the polymer solution. Thus, the presence of a coating of sodium silicate effectively delaying the release of percarbonate sodium. In addition, it seems that the thicker coating is correlated with a slower release of percarbonate sodium in liquid.

Example 5

In this example, evaluate the following thinners in a solution of 40 pounds per 1000 gallons (lb/gallon) gel linear Guara at 120°F: control without thinner; percarbonate sodium without coating; percarbonate sodium, covered with 22 wt.% sodium silicate; and percarbonate sodium, covered with 28 wt.% sodium silicate.

Gel linear guar prepared using the mixer Waring attached to the rheostat set at 55%. In a mixer add deionized water (800,0 g) and then the mixer running on low speed. Then add guar (3,841 g), commercially supplied Benchmark Performance Group under the trade mark HR71-5 ID, when operating the mixer and the solution is stirred at low speed for 30 minutes. Finally, the solution is kept for 30 minutes without shearing strain.

Tests issue is lnewt viscometer with Grace 3500, equipped with a rotor R1 and drive. For test, part (175,0 g) solution of guar is poured into the container for the sample, which is placed in the viscometer. Add thinner (0.104 g±0.003 g) and then the rotor exposes the sample to shear deformation at 511-1when this temperature is changed to 120°F. the Viscosity was measured as a function of time within 90 minutes.

Figure 5 illustrates the results. Percarbonate sodium without coating causes an immediate and rapid decrease in solution viscosity of guar, whereas two samples with coating reduce the viscosity more slowly. In addition, the sample with 28 wt.%, coating of sodium silicate thins the solution of guar slower than the sample with 22 wt.% coating of sodium silicate. Floor, slow release, slows down razzhiganie gel linear Guara compared to the dilution caused by percarbonate sodium without coating. In addition, it seems that the thicker coating is correlated with a slower release of percarbonate sodium in liquid.

Example 6

In this example, evaluate the following thinners in solution gel, crosslinked with boron linear Guara 40 pounds per 1000 gallons (lb/gallon) at 150°F: control without thinner; percarbonate sodium without coating; percarbonate sodium, covered with 22 wt.% sodium silicate; and percarbonate sodium, covered with 28 wt.% sodium silicate

Stitched boron gel guar prepared using the mixer Waring attached to the rheostat set at 55%. In a mixer add deionized water (800,0 g) and then the mixer running on low speed. Then add guar (3,8425 g), commercially supplied Benchmark Performance Group under the trade mark HR71-51D, when operating the mixer and the solution is stirred at low speed for 30 minutes. Then add buffer (0.5 ml), commercially supplied under the trademark S-166, and boron crosslinker (2.4 ml), commercially supplied Benchmark Performance Group under the trademark I-1, and the mixer run for 1 minute. Then the solution is left for 30 minutes without shearing strain.

Tests carried out with a viscometer Grace 5600, equipped with a rotor R1 and disk B5. For each test part (31,7±1.6 g) solution crosslinked guar is poured into the container for the sample, which is placed in the viscometer, and then the rotor exposes the sample to shear deformation at 100-1while the temperature ranges to 150°F. the Viscosity was measured as a function of time for 60 minutes. The results are shown in Fig.6.

It is established that percarbonate sodium uncoated quickly reduces the viscosity and causes complete liquefaction after 48 minutes. Percarbonate sodium with 28 wt.% coating of sodium silicate causes a small decrease in viscosity after 60 minutes, whereas obrazets 22 wt.% coating of sodium silicate leads to a slightly greater decrease in the viscosity of the crosslinked gel during testing. Thus, it is shown that encapsulated sodium silicate percarbonate sodium slows the rate of decrease of viscosity.

This description provides examples to disclose the invention, including the best option, it enables any person skilled in the art to make and use the invention. The amount of the claims of the invention are defined by formula and may include other examples that can imagine a specialist in this field of technology. Such other examples should include in the scope of claims of the claims if they have structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements with minor differences from the literal language of the claims.

1. The liquid for the processing of wells, including:
water;
at least one gidratiruyuschimi polymer; and
granules percarbonate sodium coated, slow-release, in which the floor, slow-release, is an inorganic material.

2. The fluid for the well treatment according to claim 1, in which the inorganic material is a silicate of an alkali metal.

3. The fluid for the well treatment according to claim 2, additionally comprising sodium sulfate between percarbonate sodium and the alkali silicate m is metal.

4. The fluid for the well treatment according to claim 2, in which the alkali metal silicate is contained in the number 15-37 wt.% with respect to the total weight of percarbonate sodium and silicate of an alkali metal.

5. The fluid for the well treatment according to claim 2, in which the alkali metal silicate is contained in the number 22-37 wt.% with respect to the total weight of percarbonate sodium and silicate of an alkali metal.

6. The fluid for the well treatment according to claim 1, in which at least one gidratiruyuschimi polymer comprises a polysaccharide, polyacrylamide, polyvinyl alcohol and mixtures thereof.

7. The fluid for the well treatment according to claim 1, further comprising a stapler, the stapler includes a titanate, a borate, a compound containing zirconium, dialdehyde, and mixtures thereof.

8. The fluid for the well treatment according to claim 1, the pH of which is 5-12.

9. The fluid for the well treatment according to claim 1, in which granules of percarbonate sodium slow release coating are formed in such a way as to ensure the dissolution rate of up to about 3 h at neutral pH near room temperature.

10. The fluid for the well treatment according to claim 1, additionally including proppants.

11. The fluid for the well treatment according to claim 1, in which at least one gidratiruyuschimi polymer is a guar gum and/or derived from the guar gum.

12. The liquid for the processing of wells, including:
water;
at least one gidratiruyuschimi polymer; and
granules percarbonate sodium coated, slow-release, in which the coating that slows the release includes a mixture of a styrene-acrylate and butyl acrylate.

13. The method of hydraulic fracturing a subterranean formation, comprising:
the injection pressure water hydraulic fluid from the first viscosity to the well in which water hydraulic fluid comprises water; at least one gidratiruyuschimi polymer; and granules percarbonate sodium coated, slow release of inorganic material;
the formation of breaks in the underground reservoir with hydraulic fluid from the first viscosity and dissolution of the coating, slow release, leading to the effects of water on percarbonate after a certain period of time;
interaction percarbonate sodium, at least one hydratious polymer to reduce the first viscosity to a second viscosity; and
removing at least part of the hydraulic fluid from the second viscosity.

14. The method of hydraulic fracturing a subterranean formation according to item 13, in which the aqueous hydraulic fluid further includes a stapler for adjusting the first fluid viscosity.

15. The method of hydraulic fracturing p is zemnogo layer on item 13, in which the inorganic material is a silicate of an alkali metal.

16. The method of hydraulic fracturing a subterranean formation according to item 13 additionally comprising adding proppant for hydraulic fluid to discharge under pressure and in a quantity effective to prevent closing of the gaps.

17. The method of hydraulic fracturing a subterranean formation according to item 13, in which at least one gidratiruyuschimi polymer comprises a polysaccharide, polyvinyl alcohol, polyacrylamide and mixtures thereof.

18. The method of hydraulic fracturing a subterranean formation according to item 13, in which at least one gidratiruyuschimi polymer is a guar gum and/or derived from the guar gum.

19. The method of hydraulic fracturing a subterranean formation according to item 13, in which the dissolution of the coating, slow release, leading to the effects of water on percarbonate after a certain period of time, carry out such that the coating has been dissolved with the dissolution rate to about 3 h at neutral pH near room temperature.

20. The method of hydraulic fracturing a subterranean formation according to item 13, in which the stapler includes a titanate, a borate, a compound containing zirconium, dialdehyde and mixtures thereof.

21. The method according to item 15, in which the alkali metal silicate is contained in the number 15-37 wt.% in Rel is increased by the total weight of percarbonate sodium and silicate of an alkali metal.

22. The method of hydraulic fracturing a subterranean formation according to § 15, in which the alkali metal silicate is contained in the number 22-37 wt.% with respect to the total weight of percarbonate sodium and silicate of an alkali metal.

23. The method of hydraulic fracturing a subterranean formation according to § 15, additionally comprising sodium sulfate between percarbonate sodium and the alkali metal silicate.



 

Same patents:

FIELD: oil and gas industry.

SUBSTANCE: method of hydraulic fracturing (HF) of carbonate formation in well includes perforation of well walls in required well interval by channels with depth not less than length of stress concentration zone in rocks from well shaft, lowering of pipe string to HF zone with sealing of intertube space by packer above perforation interval and cyclic pumping of fracturing jelly-like liquid to well. Before HF performance well is filled with process liquid in the volume of 0.2-0.4 of well shaft volume, total volume of pumped fracturing jelly-like liquid is calculated by formula: Vj=k*Hp, where Vj - volume of pumped fracturing jelly-like liquid, m3; k=1.4÷1.6 - conversion factor, m3/m; Hp - opening interval length, m. Fracturing jelly-like liquid is pumped in equal portions in 3-5 cycles, after that acid portions are pumped in the volume of 0.7-0.75 of volume of fracturing jelly-like liquid, after completion of the last pumping cycle marketable oil or fresh water is pumped in one-and-a-half volume of pipe string with further exposure during 1-2 hours, after that products of acid reaction with rock are removed, packer is dismounted and removed from well with pipe string.

EFFECT: increasing efficiency of hydraulic fracturing in carbonate rocks under low pressure of formation by means of reducing fracturing pressure upon cracking with possibility to prevent flooding of wells after hydraulic fracturing even if water-bearing horizons are close, simplifying technical process.

FIELD: oil and gas industry.

SUBSTANCE: method involves pumping of fracturing fluid and fracturing fluid with proppant to formation, and namely through the well to the fracture created in underground formation. According to the invention, first, analysis of service water is performed, and gelling agent is tested for solubility in water and structure formation. If the result is satisfactory, gelling agent is dissolved in water and tested again for structure formation. If results are satisfactory, clay stabiliser, demulsifier and destruction regulating component is added to solution of gelling agent in water; the obtained solution is pumped to the well, and decomposer and cross-linking agent is added to the solution during pumping process, thus forming fracturing fluid. Volume of the well is replaced with fracturing fluid, pumping is stopped and pressure decay is recorded; pumping of fracturing fluid is restored with working flow rate per hydraulic fracturing; fracturing fluid blanket is pumped in the volume of 3 to 6 m3. Then, trial sequence of fracturing fluid with proppant is pumped, brought to perforation interval, initial wellhead pressure is marked, and after that, its behaviour is recorded as the sequence passes through perforation interval and moves along the fracture. The above sequence is forced through with fracturing fluid without proppant. Forcing-through is stopped and pressure reduction is recorded; intensity of wellhead pressure reduction is recorded and processed. The obtained data is processed; data on operating efficiency of fracturing fluid, value of pressure, formation stress gradient, time and pressure of fracture closing, pore pressure in manifold, hydraulic pressure losses at perforation interval and bottom-hole part of formation is obtained. Adaptation of design data on hydraulic fracturing process to the obtained test pumping processing data is performed on the basis of the obtained data. Updated data is used for re-calculation of three-dimensional model of hydraulic fracturing and performance of specified version of hydraulic fracturing. Initial plan of the main hydraulic fracturing process is changed by changing initial data on mining-and-geological coefficients for the one obtained with the programme after test pumping is performed; the main hydraulic fracturing process that was changed is performed. When the main hydraulic fracturing process that has been changed is performed on the basis of the made calculations, the required volume of service water is taken, gel is prepared and test is performed. If the test results are satisfactory, hydraulic fracturing process is performed in compliance with the changed plan, where volume of final forcing-through is determined as sum of volume of tubing string and zone under packer to the roof of perforation interval. Mixture of proppant and gel is pumped in two portions; proppant concentration in the first portion is up to 300 kg/m3. Proppant concentration in the second portion is more than 300 kg/m3. The well is left in order to wait for pressure reduction. When the time required for gel destruction elapses, bleeding of residual wellhead pressure to atmospheric one is performed; well head is depressurised; packer is removed, and underground equipment is lifted.

EFFECT: improving monitoring quality of hydraulic fracturing process and expedition of well placing on production.

1 tbl, 2 ex

FIELD: oil and gas industry.

SUBSTANCE: analysis of service water is performed, gelling agent is tested for solubility in water and structure formation. If the result is satisfactory, gelling agent is dissolved in water and tested again for structure formation; if results are satisfactory, clay stabiliser, demulsifier and destruction regulating component is added to solution of gelling agent in water. The obtained solution is pumped to the well, and decomposer and cross-linking agent is added to the solution during pumping process, thus forming fracturing fluid. Volume of the well is replaced with fracturing fluid, pumping is stopped and pressure decay is recorded. Pumping of fracturing fluid is restored with working flow rate per hydraulic fracturing. Fracturing fluid blanket is pumped with volume of 3 to 6 m3. Then, there performed is trial sequence of fracturing fluid with proppant in the volume of up to 1 m3 with concentration of 30 to 200 kg/m3 and again fracturing fluid without proppant in the volume of 1.5-1.8 m3. Fracturing fluid is forced through in the volume equal to the volume of tubing string, zone under packer to the roof at perforation interval and 2-4 m3 more. Forcing-through is stopped and pressure decay is recorded. Intensity of wellhead pressure reduction is recorded and processed. The obtained data is processed; data on operating efficiency of fracturing fluid, value of pure pressure, formation stress gradient, time and pressure of fracture closing, pore pressure in manifold, hydraulic pressure losses at perforation interval and bottom-hole part of formation is obtained. Adaptation of design data on hydraulic fracturing process to the obtained test pumping processing data is performed on the basis of the obtained data. Updated data is used for re-calculation of three-dimensional model of hydraulic fracturing and performance of specified version of hydraulic fracturing. Initial plan of the main hydraulic fracturing process is changed by changing initial data on mining-and-geological coefficients for the one obtained with the programme after test pumping is performed. The main hydraulic fracturing process that was changed is performed. When the main hydraulic fracturing process that has been changed is performed on the basis of the made calculations, the required volume of service water is taken, gel is prepared and test is performed. If the test results are satisfactory, hydraulic fracturing process is performed in compliance with the changed design, where volume of final forcing-through is determined as sum of volume of tubing string and zone under packer to the roof of perforation interval. When rise of wellhead pressure is detected during pumping of trial sequence of fracturing fluid with proppant by the value of 1 to 2.5 MPa, volume of pumped proppant of small and average fraction of 20/40, 16/30 and 16/20 mesh is increased for minimum concentrations of 30 to 120 kg/m3 to 800-1000 kg per stage, and efficiency of this activity is evaluated as per reduction of wellhead pressure as this sequence of proppant passes through perforation zone, and when pressure is decreased by 1 and more MPa, the conclusion is made that hydraulic connection with formation has been improved, and hydraulic fracturing process shall be performed according to the planned parameters. When there are no signs of recovery of connection with formation, hydraulic fracturing plan shall be changed until the required result is obtained.

EFFECT: improving monitoring quality of hydraulic fracturing process and expedition of well placing on production.

2 cl, 2 ex, 1 tbl

FIELD: oil and gas industry.

SUBSTANCE: hydraulic fracturing method of formation saturated with fluid medium involves the following stages: introduction of some quantity of fluid medium of formation hydraulic fracturing to well shaft, which is enough for hydraulic fracturing of formation; introduction of formation treatment substance containing liquid carbon dioxide to well shaft; and evaporation at least of some part of formation treatment substance; at that, stages of introduction of some amount of fluid medium of formation hydraulic fracturing to the well shaft and introduction of formation treatment substance containing liquid carbon dioxide to the well shaft include the following stages as well: pressure control in well shaft and formation so that at least some portion of formation treatment substance remains in liquid state after it is pumped to well shaft; lowering of tubing of some length to well shaft so that annular space is formed between tubing and well shaft; pumping of formation treatment substance via tubing; pumping of fluid medium of formation hydraulic fracturing to annular space; pumping of formation treatment substance to fluid medium of formation hydraulic fracturing in order to create the second fluid medium; collision of the second fluid medium with formation; creation at least of one hydraulic fracturing in formation; forcing-through of the second fluid medium to formation; and pressure discharge in well shaft.

EFFECT: increasing the efficiency of the method.

9 cl, 1 tbl, 3 dwg

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.

SUBSTANCE: proposed method comprises exposing the reservoir by vertical or inclined borehole, perforating the reservoir in preset range of productive reservoir with injection of working fluid therein to produce slits therein and fracturing reservoir via formed slits. Note here that perforation in vertical or inclined borehole is performed in preset range of productive reservoir, not perforated earlier, by hydromechanical slit perforator to produce slits oriented in azimuthal direction. After producing said slot, perforator is withdrawn from borehole and tubing with packer is lowered therein. Directed fracturing is performed in preset range of productive reservoir via aforesaid slit. Then tubing with packer is withdrawn. Tubing with washing tool is lowered therein to wash borehole bottom. Then, isolating sand bridge is made to isolate produced fracture. Then tubing with washing tool is withdrawn. Tubing with slit perforator tool is lowered therein oriented in azimuthal direction. Another slit is produced as described above and fracturing is carried. Tubing with washing tool is lowered therein to wash borehole bottom down to current bottom. At larger thickness of productive reservoir, slits are produced and fractured in staggered order through 90 degrees with respect to each other, or slits are formed in pairs wherein slits are arranged through 180° and pairs are arranged through 90° with respect to each other. Every new slit is isolated by sand bridge.

EFFECT: higher efficiency of hydraulic fracturing.

4 cl, 6 dwg

FIELD: oil-and-gas production.

SUBSTANCE: proposed method comprises the following steps: a) forcing flooding fluid into deposit, and b) extracting oil from borehole in location other than that of forcing flooding liquid. Flooding liquid includes water and some amount of one or more specified viscoelastic nonpolymeric surfactants sufficient for interfacial surface tension approximating to 1 mNm or smaller, and viscosity of 10 sP or larger. Proposed invention is developed in dependent claims.

EFFECT: higher efficiency of tertiary oil extraction.

24 cl

FIELD: oil and gas industry.

SUBSTANCE: invention relates to the field of the oil and gas industry and may be used at the final stage of developing massive and bedded-massive accumulations with a cap of large thickness and underlaid with a bottom water actively introducing into a productive part of a reservoir, in particular, to increase a drained area of the bottomhole formation zone - BFZ. The concept of the invention is as follows: the method includes arrangement of a horizontal well, its perforation and formation of cracks with the help of reservoir hydraulic rupturing - RHR, subsequent operation of the horizontal well via cracks of the reservoir rupture. When operating an accumulation with an active bottom water and low oil and gas recovery coefficient in a horizontal well, one or more side shafts are drilled in parallel to the plane of a gas oil of an oil and water contact, where RHR is carried out. At the same time RHR in each interval of the side shaft is carried out from its minimum possible rated value in the farthest section from the horizontal shaft to the maximum possible value in the nearest section. Besides, the maximum rupture pressure is accepted as the value that does not exceed the permissible limit value for breakage of a rock skeleton in the area of this side shaft arrangement. Accumulation operation is carried out with depressions at a reservoir that do not permit tightening of a bottom water.

EFFECT: increased drained area of a productive reservoir BFZ and provision of maximum possible yield of oil or gas from a hydrocarbon accumulation.

1 dwg

FIELD: chemistry.

SUBSTANCE: proppant is a material in form of particles, where each particle contains a proppant particle base, a water-soluble outer coating deposited on said base, and microparticles of an insoluble reinforcing and filling agent, at least partially immersed in the water-soluble outer coating such that said microparticles are essentially released from the proppant particle base when the water-soluble coating dissolves or breaks down. The material in form of particles for improving operation and/or efficiency of a bore hole in an underground formation, having a particle base from the underground formation, a water-soluble outer coating on said base and a reinforcing agent from microparticles at least partially immersed in said coating such that it is essentially released when the water-soluble coating dissolves or breaks down. The method of improving operating characteristics of a bore hole in an underground formation, involving feeding said material into one or more objects selected from an underground formation, a well shaft in said formation or bore hole in said underground formation.

EFFECT: high strength and wear-resistance of the proppant and permeability of the filling made from said proppant.

18 cl, 1 ex, 1 tbl, 4 dwg

FIELD: oil and gas production.

SUBSTANCE: method of formation hydraulic breakdown (FHB) consists in descending the tubing casing (TS) into hydraulic breakdown zone, pressurisation of casing string annulus by packer, pumping of gas, breakdown agent under pressure through TS. Note that the gas is supplied together with the breakdown agent that is crude oil. Propping agent is supplied after breakdown agent pumping. Note that the gas is inert and it is pumped at 20-30% of breakdown agent volume at a pressure 8 MPa. As propping agent there used is acid-oil emulsion fluid with adding of inert gas at 20-30% of propping agent volume at a pressure 9 MPa. After that the pumping cycle of breakdown agent with gas and propping agent is repeated 3-6 times. Before development the process fluid with inert gas is pumped into tubing casing at 10 MPa in the volume of 20-30% of total volume equal to 1.5-fold inner volume of tubing casing with the following technological exposure for 2-3 h. Note that breakdown agent and propping agent are pumped by equal portions of total volume in each cycle.

EFFECT: simplification of FHB technological process.

1 dwg

FIELD: chemistry.

SUBSTANCE: invention relates to oil industry, particularly reagents for treating an oil reservoir and methods of extracting oil and can be used on oil deposits in a wide range of reservoir temperature (20-90°C), total content of salts in the stratal and injected water (0.034-24.0 wt %) with carbonate, terrigenous and mudded rocks. The reagent is a mother solution of ammonium sulphate from stripping aqueous acidic wastes from caprolactam production containing not less than 41 wt % dry residue, not less than 2.1 wt % amino organic acids in form of amino caproic acid and having pH higher than 4.4. The method of extracting oil involves pumping said reagent and aqueous solution of electrolyte and/or organic solvent.

EFFECT: high well productivity and high reservoir recovery.

2 cl, 4 tbl

FIELD: oil and gas industry.

SUBSTANCE: in formation permeability control method involving subsequent pumping to the well through separating bank of fresh water or oil, liquid wastes of produced zeolites and gel formation initiator, forcing-through of pumped reagents to formation with waste water or oil, the solution of by-product of produced polyethylenepolyamines - reagent of ammonium chloride is used as gel formation initiator.

EFFECT: reducing corrosive activity of composition; increasing technological efficiency for restriction of water and gas breakthrough.

4 ex, 2 tbl, 1 dwg

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

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.

SUBSTANCE: proposed method comprises the following steps: a) forcing flooding fluid into deposit, and b) extracting oil from borehole in location other than that of forcing flooding liquid. Flooding liquid includes water and some amount of one or more specified viscoelastic nonpolymeric surfactants sufficient for interfacial surface tension approximating to 1 mNm or smaller, and viscosity of 10 sP or larger. Proposed invention is developed in dependent claims.

EFFECT: higher efficiency of tertiary oil extraction.

24 cl

FIELD: oil and gas production.

SUBSTANCE: method of bottom-hole zone treatment of low-permeable terrigenous formation according to the first version consists in flushing of killed well, sequential pumping of methanol, 18-20% solution of hydrochloric acid for acid bath installation, then the well is repeatedly pumped by 18-20% solution of hydrochloric acid and buffer-gas condensate, acid composition is squeezed into bottom-hole zone of formation by inert gas, then mud acid solution is pumped, gas influx from formation is caused and then reaction products are removed together with gas flow, the well is treated through flare line with removal of reaction products till it reaches design conditions and then the well is placed under production. Method of bottom-hole zone treatment of low-permeable terrigenous formation according to the second version consists in sequential pumping of methanol, 18-20% solution of hydrochloric acid and buffer-gas condensate into non-killed well through tubing casing, acid composition is squeezed into bottom-hole zone of formation by inert gas, then mud acid solution is pumped, gas influx from formation is caused and then reaction products are removed together with gas flow, the well is treated through flare line with removal of reaction products till it reaches design conditions and then the well is placed under production.

EFFECT: recovery of gas-hydro-dynamic connection of well with low-permeable and highly colmataged terrigenous productive formation in condition of abnormally low formation pressure.

2 cl

FIELD: oil and gas production.

SUBSTANCE: method of formation face zone development consists in pumping the gas-generating and acid-based reagents, where gas-generating reagent is the compound that includes, wt %: urea 28.4-38.4, sodium nitrite 18.2-27.6, water - the rest, and acid-based reagent is the compound that includes, wt %: inorganic acid 5.2-60.9, surface acting agent 2.4-3.5, ferrum inhibitor 1.4-2.3, flotation agent 7.0-11.4, water - the rest. Note that the proportion of gas-generating and acid-based reagents amounts 1:(1-3), after pumping of the reagents they are held.

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.

3 cl, 2 tbl, 2 ex, 1 dwg

FIELD: oil and gas industry.

SUBSTANCE: method for control of flooding area of oil formations includes oil extraction through production wells and pumping of margins of working agent and silicate in water phase with varying concentration of components trough injection wells. At that watering out of produced oil, capacity of injection wells, allowable pumping pressure and minimal pumping pressure are additionally checked. Pumping is started from injection wells of high capacity, connected hydrodynamicly to highly watered out production wells. At least one injection well is stopped till formation pressure is decreased by 6-24% from formation pressure in area of injection well. Pumping of working agent is started from composition of high-viscosity in quantity not less than 0.5 m3 per 1 m of productive formation with high capacity under pumping pressure exceeding minimal pumping pressure not more than by 20%, at which well accepts. Then margins of water solution of alkaline silicate and polymer are pumped in succession or jointly. Solution of alkaline silicate is used in quantity 0.1-15.0 wt %, and polymer is used in quantity 0.001-3.0 wt %, the other part of solution is water.

EFFECT: increasing oil recovery from formations.

4 cl, 3 ex

FIELD: oil and gas industry.

SUBSTANCE: method includes stages at which cloudy treating fluid with primary microbial population is provided. The fluid is placed in self-contained road mobile manifold of treatment by ultra-violet, which contains source of ultra-violet. Cloudy treating fluid is treated using source of ultra-violet in the presence of weakening reagent to form irradiated treating fluid. Then irradiated treating fluid is supplied to mixing system. Mobile system of treating fluid treatment by ultra-violet contains inlet device, source of treating ultra-violet, chamber for treatment by ultra-violet, weakening reagent, outlet device. At that system of treating fluid treatment by ultra-violet is transported using self-contained road mobile platform.

EFFECT: increasing efficiency of treating fluids disinfection.

12 cl, 2 tbl, 8 dwg

FIELD: oil and gas industry.

SUBSTANCE: well treatment method involves introduction to the well of treatment liquid containing polymer, binder, organic peroxide, soluble amine connection and functional dilution retarder, where soluble amine connection has chemical structure R3R4N((CR5R6)2-NR7)n-R8, in which n is equal to 2 to 8 and in which R3, R4, R5, R6, R7 and R8 are chosen independently from each other from hydrogen, alkyl, hydroxyalkyl and their combinations, where mass ratio of soluble amine to organic peroxide is approximately 1:1 to approximately 20:1; and treatment liquid dilution. Invention has been developed in dependent claims.

EFFECT: increasing monitoring efficiency of viscosity reduction.

16 cl, 15 ex, 15 dwg

FIELD: oil and gas industry.

SUBSTANCE: solid foaming agent for removal of liquid from bottom hole, which is obtained using ammonium carbonate and surface active substances - non-ionic- OP-10 or OP-7 and anionic - sulphanole by formation of mixture and its solidification, where at ratio of OP-10 or OP-7 and sulphanole of 3.3-5.2:1.0 the mixture also contains Kolamid K; at that, mixture is prepared by mixing of OP-10 or OP-7, sulphanole and Kolamid K, by heating of the obtained mixture of up to 40-60°C, by its mixing till sulphanole is diluted, and then, by adding ammonium carbonate, at the following component ratio, wt %: OP-10 or OP-7 33.0-52.0, sulphanole 10, ammonium carbonate 0.2-0.5, and Kolamid K is the rest.

EFFECT: improving foaming efficiency and carry-over of high-mineralised waters in presence of gas condensate from bottom holes of low temperature gas and gas-condensate wells, and improving the manufacturability of solid bars - sticks.

3 tbl, 3 ex

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