RU2851270C1 - Method for reinforcement of weakly cemented rocks of well formation - Google Patents

Abstract

FIELD: mining.

SUBSTANCE: invention relates to the gas industry, in particular to methods for strengthening the formation of gas and gas condensate wells, the collector of which is represented by low-cemented rocks. Method for reinforcement of weakly cemented rocks of well formation includes successive injection into formation of inert spacer fluid in amount of 0.5 m³, then binding fluid with relative viscosity equal to 18-30 s, in amount of not less than 0.05 m³ per one running meter of perforation interval, then inert buffer liquid in the design volume, but not less than 0.2 m³ and the fixing liquid in the amount of not less than 0.05 m³ per one running meter of the perforation interval, followed by forcing into the formation with a gaseous agent. Diesel fuel or stable gas condensate is used as inert spacer fluid. As a binding liquid, a solution is used, which includes a “SendStop” modifying reagent, containing in its composition a powdered inorganic silicate and an organic polymer – dextrin, as well as an additional inhibitor of alkaline decomposition of dextrin – sodium pyrosulfite and water in following ratio of components, wt. %: reagent-modifier “SandStop“ 15-40; sodium pyrosulfite 0.5-1.0; water – balance. Fixing fluid is a solution containing a modifier for process fluids "SoltPlast" based on a salt of a polyvalent metal, as well as an initiator of formation of colloidal aggregates – potassium acetate and water in following ratio of components, wt. %: modifier for process liquids "SoltPlast" 32-42; potassium acetate 0.5-1.0; water – balance.

EFFECT: improving reinforcement efficiency of weakly cemented rocks of the bed, maintaining its filtration-capacitance properties and increasing uniformity of the bed treatment.

1 cl, 1 tbl, 8 ex

Description

The invention relates to the gas production industry, in particular to methods for strengthening the formation of gas and gas condensate wells, the reservoir of which is represented by weakly cemented rocks.

An analysis of the existing state of the art showed the following:

- a method for strengthening a rock mass and an organomineral two-component composition for its implementation are known, which consists in the fact that the organomineral two-component composition is obtained directly in the rock mass by sequentially injecting first component A, then component B in a volume ratio of 1:1, component A contains, by weight %: sodium liquid glass 76; glycerin 9.5; distilled water 9.5; an adsorbent that promotes the formation of a film of component A on the surface of discontinuities and grains of rock and soil - a micelle-forming surfactant mSAV ML-80 5; a polymerization catalyst - dimorpholinodiethyl ether 0.3-0.8 in excess of 100 wt %; component B contains, by weight %: polyisocyanate 62; plasticizer - dibutyl phthalate 38 (see Russian patent No. 2785877 dated 01/26/2022 under class E21B 33/138, C09K 8/575, published 12/14/2022).

The disadvantage of this method is the following.

This method does not involve injecting any fluid to displace the wellbore fluids into the formation before applying component A. This has several consequences. First, component A is diluted by the wellbore fluid, changing the concentration of its active components. Second, chemical reactions may occur when mixing component A with the wellbore fluid. This may alter the chemical composition of component A, form a solid phase, and harden component A before introducing component B. This undoubtedly reduces the effectiveness of strengthening poorly cemented formation rocks and may lead to significant contamination and deterioration of the reservoir properties.

- a method is known for lining the bottomhole zone of sand-producing wells, which includes creating a filter by preparing and pumping a polymer composition and hydrochloric acid, followed by holding until the polymer composition hardens. In this case, the polymer composition is first pumped, and then hydrochloric acid in the form of a 10-15% aqueous solution in a ratio of 1:1 to the polymer composition with a diameter of the bottomhole zone coverage of at least 1.8 m each, and the polymer composition is prepared by mixing urea-formaldehyde resin with acetone-formaldehyde resin in a ratio of 4:1, respectively, and aluminum powder in an amount of 0.05÷0.2% of the weight of the polymer composition (see Russian patent No. 2387806 dated 03.04.2009 under class E21B 33/138, published on 27.04.2010).

A disadvantage of this method is the poor filtration properties of the injected polymer composition. This is due to the following: The aluminum powder in the polymer composition is suspended. Depending on the size of the pore channels, its particles can form filtration structures in the near-wellbore zone (BWZ). This means that only a portion of the pores will be treated with the aluminum-containing polymer composition. The rest of the formation will be saturated with aluminum-free filtrate. Since this component facilitates the curing of the polymer composition, the effectiveness of formation strengthening will be quite low.

Another significant drawback is the need to use a 10-15% aqueous hydrochloric acid solution to cure this polymer composition. A solution of this concentration is quite aggressive to the formation rocks. Using such a hardener can lead to the destruction of the formation cement and subsequently increase sand production.

The closest to the claimed invention is a method for strengthening the bottomhole zone of a well, which includes pumping isopropyl alcohol, phenol-formaldehyde resin mixed with isopropyl alcohol into the bottomhole zone of the well in a ratio of components, vol. %: phenol-formaldehyde resin - 90-95, isopropyl alcohol - 5-10, then an aqueous solution of hydrochloric acid of 12-24% concentration, after pumping isopropyl alcohol and after pumping phenol-formaldehyde resin mixed with isopropyl alcohol, hold for at least 8 hours, all reagents are pumped in a volume sufficient to create a screen in the bottomhole zone with a coverage diameter of at least 1.8 meters, and the injection of an aqueous solution of hydrochloric acid is carried out at a maximum flow rate that does not lead to an increase in the injection pressure above the permissible pressure on the production string of the well and the formations located in the bottomhole zone of the well (see Russian Federation Patent No. 2387803 dated 03.04.2009 under class E21B 33/13, C09K 8/44, published. (27.04.2010).

The disadvantages of this method include low efficiency in strengthening weakly cemented rocks, a significant reduction in the reservoir properties of rocks after treatment, and uneven formation treatment. This is due to the following.

Phenol-formaldehyde resin is an organic substance. It exhibits a relatively low affinity for rock surfaces, which are typically inorganic silicates. As a result, the phenol-formaldehyde resin film will have insufficient adhesion to the rock. This will lead to disruption of the film's integrity, cracking, and delamination, resulting in the separation of fixed pellite particles and their removal with the formation fluid. Therefore, the use of phenol-formaldehyde resin will not effectively strengthen poorly cemented rocks.

Furthermore, a phenol-formaldehyde resin solution in isopropyl alcohol has low viscosity. When injected into a formation, it primarily treats large, highly conductive pore channels. Low-permeability sections of the formation will remain virtually untreated, meaning the uniformity of formation treatment will be very low. This method uses a 12-24% hydrochloric acid solution to cure the phenol-formaldehyde resin. Exposure of the rock to such a concentration can lead to intense destruction. This is especially significant for low-permeability channels not protected by a phenol-formaldehyde resin film. This can result in partial destruction of the formation matrix, creating conditions conducive to sand production.

Another significant drawback of this method is that the formaldehyde resin solution in isopropyl alcohol and the curing agent—hydrochloric acid—are injected sequentially without any spacer fluids. This creates conditions in the formation pores for the bulk curing of the phenol-formaldehyde resin. This not only leads to unnecessary consumption of the resin but also to the formation of solid-phase particles in the pore channels, which can significantly reduce the reservoir properties of the treated rock.

The technical objective of the invention is to increase the efficiency of gas and gas condensate wells, the reservoir of which is represented by weakly cemented rocks, and to extend their service life.

The technical result that can be obtained by implementing the proposed invention consists of increasing the efficiency of strengthening weakly cemented formation rocks, preserving its filtration-capacitive properties and increasing the uniformity of formation processing.

The technical result is achieved using the proposed method for strengthening weakly cemented rocks of a well formation, according to which an inert spacer fluid is sequentially pumped into the formation in a volume of 0.5 ^m3 , then a binding fluid with a conditional viscosity equal to 18-30 s in a volume of at least 0.05 ^m3 per linear meter of the perforation interval, then an inert spacer fluid in a volume calculated using the formula:

where V _b is the volume of inert buffer liquid, m ³ ;

h – length of perforation interval, m;

m is the effective porosity coefficient of the formation;

r _c is the wellbore radius within the productive formation interval, m, but not less than 0.2 m ³ , and a consolidating fluid in a volume of at least 0.05 m ³ per linear meter of the perforation interval, followed by squeezing into the formation with a gaseous agent. Diesel fuel or stable gas condensate is used as an inert spacer fluid, and a solution containing the SandStop reagent-modifier, containing powdered inorganic silicate and an organic polymer - dextrin, as well as an additional inhibitor of alkaline dextrin degradation - sodium pyrosulfite and water in the following ratio of components, wt.%, is used as a binding fluid:

reagent-modifier "SandStop" 15-40 sodium pyrosulfite 0.5-1.0 water rest,

and as a fixing liquid - a solution including a modifier for process fluids "SoltPlast" based on a polyvalent metal salt, as well as an initiator for the formation of colloidal aggregates - potassium acetate and water in the following ratio of components, mass%:

modifier for technology SoltPlast liquids 32-42 potassium acetate 0.5-1.0 water rest.

When implementing the claimed method for strengthening weakly cemented well formation rocks, the following chemical reagents are used to prepare the binding and consolidating liquids.

The SandStop reagent-modifier according to TU 20.59.59-195-31323949-2023 is an inorganic polymer reagent with the addition of natural and synthetic organic polymers, containing powdered inorganic silicate, dextrin.

Sodium pyrosulfite (GOST 10575-76) is the sodium salt of pyrosulfurous acid, a white or yellowish crystalline powder with a pungent odor. It is registered as food additive E223 _and has the chemical formula ( _{Na2S2O5 )} .

Modifier for process fluids "SoltPlast" according to TU 20.59.59-196-31323949-2023, which is a dry mixture based on calcium chloride with the addition of alkali and alkaline earth metal salts.

Potassium acetate (GOST 5820-78) is an anhydrous potassium salt of acetic acid, a colorless crystalline powder that is highly soluble in water. It has the chemical formula ( _CH3COO )K.

The operation of gas and gas condensate wells with productive formations composed of poorly cemented rock formations is typically associated with significant sand production. This leads to the formation of sand plugs in the wellbore, necessitating repairs (bottomhole normalization, wellbore flushing), as well as accelerated abrasive wear of downhole and wellhead equipment. To prevent sand production, it is necessary to consolidate the pelitic particles (sand) within the formation pores using film structures created on their inner surfaces. According to the proposed method, this is accomplished by injecting a spacer fluid into the formation, as well as special fluids—a binder and a fixing fluid. The volume of the latter should be at least 0.05 ^m³ per linear meter of perforation interval. This will ensure the fixation of pelitic particles in the BZP and the adjacent zone of the formation, regardless of their permeability, and will thereby contribute to increasing the efficiency of strengthening weakly cemented formation rocks.

The function of the spacer fluid is to separate the binding and consolidating fluids used in the proposed method from each other and prevent their mixing with the wellbore and formation fluids. This is achieved through the use of hydrophobic, chemically inert fluids such as stable gas condensate or diesel fuel. Injecting 0.5 ^m³ of spacer fluid into the well ahead of the binding fluid displaces the wellbore and formation fluids into the formation, thereby preventing mixing with the latter and changing its chemical composition. This prevents the active substance of the binding fluid from being consumed by secondary (non-target) chemical reactions and, accordingly, helps achieve the required level of formation treatment and, overall, improves the effectiveness of strengthening weakly cemented formation rocks.

In addition, the injection of the specified buffer fluid in a volume calculated using the formula:

where V is the volume of inert buffer liquid, ^m3 ;

h – length of perforation interval, m;

m is the effective porosity coefficient of the formation;

r _c is the wellbore radius within the productive formation interval, in m, but not less than 0.2 ^m3 . The separation between the binding and consolidating fluids ensures reliable separation of the latter. Moreover, the separating layer in the pore space will have a thickness of approximately 10-15 cm. This thickness is sufficient to completely eliminate volumetric interaction between the binding and consolidating fluids in the formation pores, preventing the formation of massive structures (solid-phase particles) within them, which significantly reduce their flow cross-section. This helps maintain the reservoir properties of the treated formation and prevents the misuse of active substances in the binding and consolidating fluids and the resulting reduction in the quality and thickness of the film, which ultimately ensures the strengthening of weakly cemented rocks.

Furthermore, since the proposed method uses stable gas condensate or diesel fuel as a spacer fluid, which is immiscible with the binding fluid, the movement of the spacer fluid through the pore space displaces the latter from the reservoir pore volume to its inner surface. This also increases the effectiveness of formation treatment with the binding fluid.

The binding fluid used in the proposed method creates an adsorbed film layer on the internal surface of the formation's pores and on the surface of the clay particles. This film layer is formed by silicic acid molecules and serves as the basis for creating an artificial cementing material that strengthens weakly cemented formations.

The appearance of silicic acid molecules in the solution is due to hydrolysis of the sodium silicate anion contained in the SandStop modifier reagent, which can be described by the following chemical reaction equation:

Na ₂ SiO ₃ + 3H ₂ O → 2NaOH + Si(OH) ₄ ,

The reaction of the binding liquid medium is alkaline. This is due to the dissociation of sodium hydroxide according to the chemical reaction equation:

2NaOH → 2Na ⁺ + 2OH ^- ,

The high concentration of hydroxyl ions OH ^- stabilizes the Si(OH) ₄ molecules, preventing their polymerization. Thus, the silicic acid molecules in solution exist in a highly active monomeric state.

When treating the surface of rocks with a binding liquid, chamosorption of Si(OH) ₄ molecules occurs with the formation of siloxane bonds with the surface atoms of the rock:

Since such structures are thermodynamically unstable and have excess surface energy, the system is stabilized by polymerization of the adsorbed layer with the splitting off of water molecules:

Moreover, since the processes described above do not occur instantaneously, and the rock surface contains a significant number of sites capable of chemisorbing silica molecules, the uniformity and density of surface population, and ultimately the effectiveness of the treatment, significantly depend on the rate of movement of the binding fluid through the pore space and the volume of the reaction zone (the thickness of the liquid layer at the surface of the pore channels). Both of these parameters are largely determined by its viscosity.

The nominal viscosity of the binder fluid used to implement the claimed method ranges from 18 to 30 s, which is 1.2-2.0 times greater than that of water. This viscosity range, when the binder fluid is displaced by a spacer fluid, ensures the formation of a thick liquid layer containing a large number of silicic acid molecules within the inner surface of the pore channels. These molecules are sufficient to populate all chemisorption sites on the rock surface, resulting in improved processing quality. At the same time, this viscosity is not so high as to significantly slow the movement of the binder fluid within the porous medium, reduce its ability to penetrate small pore channels, or prevent the filling of voids between the pore channel surface and the cemented pelitic particles.

Achieving the required viscosity, which ensures uniform and dense population of the treated surfaces with adsorbed silicic acid molecules, is due to the fact that the SandStop modifying reagent, in addition to sodium silicate, also contains dextrin.

Dextrin has the chemical formula (C ₆ H ₁₀ O ₅ ) _n . It is a product of the partial breakdown of starch or glycogen. Dextrin is classified as a low-molecular-weight polysaccharide. Due to its polymeric structure and the presence of a large number of active hydroxyl groups, dextrin is capable of forming numerous hydrogen bonds with water molecules. This ensures the formation of supramolecular structures in the binding fluid, which contribute to increasing its viscosity to the required values. Furthermore, dextrin is not susceptible to salting out in concentrated silicate solutions, making it a preferred choice for use.

However, dextrin molecules are not stable enough in an alkaline environment in the presence of atmospheric oxygen. This can lead to dextrin depolymerization and a decrease in the viscosity of the binding fluid. This process can be described by the following chemical reaction equation.

,

where n and m are the degree of dextrin polymerization, n > m.

To prevent dextrin depolymerization _, the binding fluid used in the claimed method contains sodium pyrosulfite, an inhibitor _of alkaline _dextrin degradation. This reagent has the chemical formula _{Na2S2O5 and} is the sodium salt of pyrosulfurous acid. _Na2S2O5 contains sulfur atoms with an oxidation state of +4. Redox reactions involving _{S2O5 2-} ions neutralize free radicals formed in the solution when free oxygen interacts with polymer molecules. This significantly slows ^the destructive processes in the binding fluid and maintains its viscosity, which positively affects the continuity and quality of the adsorbed film layer and, ultimately, improves the effectiveness of formation strengthening.

To form an artificial cementing material in the formation based on the created adsorbed film layer, the claimed method uses a cementing fluid. Its action is due to the presence of calcium chloride, the main component of the SoltPlast process fluid modifier, and potassium acetate. This action involves neutralizing the hydroxyl groups of silicic acid molecules chemisorbed by the rock with calcium ions in the presence of the reaction products of calcium chloride and potassium acetate.

Calcium ions are formed in the solution as a result of the dissociation of calcium chloride in accordance with the chemical reaction equation

CaCl ₂ ↔ Са ²⁺ + 2Cl ^- .

The neutralization of hydroxyl groups of silicic acid chemisorbed on the surface of pore channels is due to the occurrence of processes that can be described by the following reaction:

.

The resulting cementing film is water-insoluble, highly adhesive to the rock surface, and thin, preventing the pore channel cross-section from shrinking and preserving the reservoir properties. However, this structure is thermodynamically unstable. Over time, this leads to a redistribution of the material within the film, the development of defective zones and mechanical stress, which can manifest as cracking and delamination. To prevent this, the cementing fluid in the claimed method contains potassium acetate along with calcium chloride. Its action is as follows.

Potassium acetate (CH ₃ COO)K is a strong electrolyte and completely dissociates into ions in an aqueous environment, which can be described by the following chemical reaction equation

(CH ₃ COO)K ↔ K ⁺ + CH ₃ COO ^- .

Since potassium acetate is a salt composed of a weak acid (acetic acid) and a strong base (potassium hydroxide), the acetate ions ( _CH3COO ⁾ formed as a result of dissociation undergo hydrolysis at the anion, forming a non-dissociating substance—acetic acid—and hydroxyl ions. This can be described by the following chemical equation:

CH ₃ COO ^- + H ₂ O → CH ₃ COOH + OH ^- .

Unlike potassium acetate, calcium chloride is subject to cationic hydrolysis. Moreover, given the chemical reactivity of calcium ions, hydrolysis occurs to a significant degree only in the first stage, which can be represented by the following chemical reaction equation:

Ca ²⁺ + H ₂ O → Ca(OH) ⁺ + H ⁺ .

Since the processes described above occur together and simultaneously, the Ca(OH) ⁺ ions, capturing the hydroxyl groups OH ^- , are transformed into molecules of poorly soluble calcium hydroxide, which can be described by the following reaction equation:

Ca(OH) ⁺ + OH ^- → Ca(OH) ₂ ↓.

As a result, the cementing fluid is saturated with colloidal calcium hydroxide particles stabilized by K ⁺ and ^Cl- ions. Since their size does not exceed a few micrometers, they are able to easily penetrate and become anchored in the cavities between the structural elements of the formed artificial cementing material film, thereby stabilizing it and reducing its defects and the resulting mechanical stresses. This prevents cracking and delamination of the film and ensures increased effectiveness of strengthening the poorly cemented formation.

The essence of the claimed invention is described in more detail by the following examples.

Example 1 (laboratory).

To prepare the binding liquid, 150 g, which is 15 wt.%, of the SandStop modifying reagent and 5 g, which is 0.5 wt.%, of sodium pyrosulfite are successively dissolved in a container in 845 ml of water.

To prepare the fixing liquid, 320 g, which is 32% by weight, of the SoltPlast process fluid modifier and 5 g, which is 0.5% by weight, of potassium acetate are successively dissolved in a container in 675 ml of water.

Next, the process parameters are measured.

Example 2 (laboratory).

To prepare the binding liquid, 350 g, which is 35% by weight, of the SandStop modifying reagent and 8 g, which is 0.8% by weight, of sodium pyrosulfite are successively dissolved in a container in 642 ml of water.

To prepare the fixing liquid, 380 g, which is 38% by weight, of the SoltPlast process fluid modifier and 6 g, which is 0.6% by weight, of potassium acetate are successively dissolved in a container in 614 ml of water.

Next, the process parameters are measured.

Example 3 (laboratory).

To prepare the binding liquid, 400 g, which is 40 wt.%, of the SandStop modifying reagent and 10 g, which is 1.0 wt.%, of sodium pyrosulfite are successively dissolved in a container in 590 ml of water.

To prepare the fixing liquid, 420 g, which is 42% by weight, of the SoltPlast process fluid modifier and 10 g, which is 1.0% by weight, of potassium acetate are successively dissolved in a container in 570 ml of water.

Next, the process parameters are measured.

Example 4 (laboratory) - outside the concentration range.

To prepare the binding liquid, 140 g, which is 14 wt.%, of the SandStop modifying reagent and 4 g, which is 0.4 wt.%, of sodium pyrosulfite are successively dissolved in a container in 856 ml of water.

To prepare the fixing liquid, 310 g, which is 31% by weight, of the SoltPlast process fluid modifier and 4 g, which is 0.4% by weight, of potassium acetate are successively dissolved in a container in 686 ml of water.

Next, the process parameters are measured.

Example 5 (laboratory) - outside the concentration range.

To prepare the binding liquid, 410 g, which is 41% by weight, of the SandStop modifying reagent and 11 g, which is 1.1% by weight, of sodium pyrosulfite are successively dissolved in a container in 679 ml of water.

To prepare the fixing liquid, 430 g, which is 43% by weight, of the SoltPlast process fluid modifier and 11 g, which is 1.1% by weight, of potassium acetate are successively dissolved in a container in 559 ml of water.

Next, the process parameters are measured.

Example 6 (laboratory) - outside the concentration range.

To prepare the binding liquid, 350 g, which is 35% by weight, of the SandStop modifier reagent are successively dissolved in 650 ml of water in a container.

To prepare the fixing liquid, 380 g, which is 38% by weight, of the SoltPlast process fluid modifier are successively dissolved in a container in 620 ml of water.

Next, the process parameters are measured.

Testing using the proposed method is conducted under laboratory conditions. To determine the rock's filtration properties before and after treatment with binding and consolidating fluids using the proposed method, bench tests are conducted on a modernized UIPK-1M rig (core permeability testing unit) in accordance with GOST 26450.0-85 "Rocks. Methods for Determining Reservoir Properties." An example of this is described below.

For laboratory studies, a bulk model of the formation is used: a metal core holder 150 mm long and 30 mm in internal diameter, filled with compressed quartz sand, with an initial gas permeability in the range of 0.5-2 μm ² .

The following indicators are determined: the initial gas permeability of the sample before and after treatment with binding and fixing liquids, and the permeability recovery coefficient.

The permeability of the sample K, µm ² , before and after treatment with binding and fixing liquids is calculated using the formula

,

where μ is the dynamic viscosity of air, Pa⋅s;

Р _atm - atmospheric pressure, Pa;

q – flow rate of pumped air (gas), ^m3 /s;

1 - sample length, m;

F – cross-sectional area of the sample, ^m2 ;

P ₁ and P ₂ – pressure at the inlet and outlet of the test sample, Pa.

The coefficient of gas permeability recovery K is determined as the ratio of the core permeability values before and after treatment with binding and fixing liquids and is calculated using the formula

where K ₁ is the initial gas permeability of the sample before treatment with binding and fixing liquids, µm ² ;

K ₂ - gas permeability of the sample after treatment with binding and fixing liquids, µm ² .

The content of the SandStop reagent-modifier in the binding liquid is less than 15 wt.%, sodium pyrosulfite is less than 0.5 wt.%, and in the fixing liquid the modifier for SoltPlast process fluids is less than 32 wt.%, potassium acetate is less than 0.5 wt.% is not advisable, since it does not provide the required conditional viscosity of the binding liquid, reduces the compressive strength and reduces the effectiveness of strengthening weakly cemented rock.

The content of the SandStop reagent-modifier in the binding liquid exceeding 40 wt.%, sodium pyrosulfite exceeding 1.0 wt.%, and the content of the SoltPlast process fluid modifier in the fixing liquid exceeding 42 wt.%, and potassium acetate exceeding 1.0 wt.% is not advisable, as it leads to an increase in the relative viscosity of the binding liquid above the permissible limit, does not ensure the preservation of the reservoir properties of weakly cemented rock, and reduces the effectiveness of strengthening weakly cemented rock.

Example 7 (industrial)

Initial data.

Well depth is 1105 m

The level of the upper perforations is 1072 m

The level of the lower perforations is 1092 m

Well radius (r _с ) - 0.11 m

Effective porosity coefficient of the formation (m) - 0.15

Tubing diameter - 0.073 m

Tubing descent depth: 1068 m

The diameter of the production casing is 0.168 m

1) Based on the length of the perforation interval, the volume of the binding liquid V _c is determined:

V _c = 0.05⋅(1092-1072) = 1 _m ³ .

2) Based on the length of the perforation interval, the volume of fixing liquid V ₃ is determined:

V ₃ = 0.05⋅(1092-1072) = 1 m ³ .

3) Prepare the calculated volumes of binding and fixing liquids using the method given in example 2.

4) Determine the volume _Vb of the inert buffer fluid—diesel fuel—injected between the binder and fixing fluids. To do this, calculate using the formula:

where V _b is the volume of inert buffer liquid, m ³ ;

h – length of perforation interval, m;

m is the effective porosity coefficient of the formation;

r _с is the well radius in the productive formation interval, m.

Based on the initial data, the length of the perforation interval h is equal to:

h = 1092-1072 = 20 m.

Next, substituting the values, we obtained:

V _b = 0.628⋅h⋅m⋅(0.1 + 2⋅r _s ) = 0.628⋅20⋅0.15⋅(0.1+0.11) = 0.4 m ³ .

Since 0.4 ^m3 is greater than 0.2 ^m3 , the calculated value is taken as the value of _Vb , i.e. _Vb = 0.4 ^m3 .

5) After piping the wellhead equipment, sequential injection is carried out with an inert buffer liquid in a volume of 0.5 ^m3 , a binding liquid in a volume of 1 ^m3 , prepared according to example 2, an inert buffer liquid in a volume of V = 0.4 ^m3 , and a fixing liquid in a volume of 1 ^m3 , prepared according to example 2.

6) Next, the consolidating liquid is forced into the formation using a gaseous agent.

As a result of the work, no sand removal with the extracted fluid is observed.

Example 8 (industrial)

Initial data.

The well depth is 1328 m

The level of the upper perforations is 1294 m

The level of the lower perforations is 1302 m

Well radius (r _с ) - 0.084 m

Effective porosity coefficient of the formation (m) - 0.13

Tubing diameter - 0.073 m

Tubing descent depth: 1280 m

The diameter of the production casing is 0.168 m

1) Based on the length of the perforation interval, the volume of the binding liquid V _c is determined:

V _c = 0.05⋅(1302-1294) = 0.4 m ³ .

2) Based on the length of the perforation interval, the volume of fixing liquid V ₃ is determined:

V ₃ = 0.05⋅(1302-1294) = 0.4 _m ³ .

3) Prepare the required volumes of binding and fixing liquids using the method given in example 2.

4) Determine the volume _Vb of the inert spacer fluid—a stable gas condensate injected between the binder and fixing fluids. To do this, calculate _Vb using the formula:

where V _b is the volume of inert buffer liquid, m ³ ;

h – length of perforation interval, m;

m is the effective porosity coefficient of the formation;

r _с is the well radius in the productive formation interval, m.

Based on the initial data, the length of the perforation interval h is equal to:

h = 1302-1294 = 8 m.

Next, substituting the values, we obtain:

V _b = 0.628⋅h⋅m⋅(0.1 + 2⋅r _s ) = 0.628⋅8⋅0.13⋅(0.1 + 0.084) = 0.12 m ³ .

Since 0.12 ^m3 is less than 0.2 ^m3 , 0.2 ^m3 was taken as the value of _Vb .

5) After piping the wellhead equipment, sequential injection is carried out of an inert buffer liquid in a volume of 0.5 ^m3 , a binding liquid in a volume of 0.4 ^m3 , prepared according to example 2, an inert buffer liquid in a volume of V = 0.2 ^m3 , and a fixing liquid in a volume of 0.4 ^m3 , prepared according to example 2.

6) Next, the consolidating liquid is forced into the formation using a gaseous agent.

As a result of the work, no sand removal with the extracted fluid is observed.

The technological parameters of the binding and fixing liquids for examples 1-6 are presented in the table.

Thus, the proposed set of essential features ensures the achievement of the claimed technical result.

The claimed technical solution meets the patentability requirements of “novelty, inventive step and industrial applicability”.

Claims (10)

A method for strengthening weakly cemented rocks of a well formation, which includes the sequential injection into the formation of an inert spacer fluid in a volume of 0.5 ^m3 , then a binding fluid with a conditional viscosity equal to 18-30 s, in a volume of at least 0.05 ^m3 per linear meter of the perforation interval, then an inert spacer fluid in a volume calculated using the formula: where V _b is the volume of inert buffer liquid, m ³ ; h – length of perforation interval, m; m is the effective porosity coefficient of the formation; r _с - well radius in the productive formation interval, m, but not less than 0.2 ^m3 , and a consolidating liquid in a volume of not less than 0.05 ^m3 per linear meter of the perforation interval, followed by forcing into the formation with a gaseous agent, with diesel fuel or stable gas condensate used as an inert buffer liquid, and a solution as a binding liquid, including the SandStop reagent-modifier, containing in its composition a powdered inorganic silicate and an organic polymer - dextrin, as well as an additional inhibitor of alkaline destruction of dextrin - sodium pyrosulfite and water in the following ratio of components, mass%: reagent-modifier "SandStop" 15-40 sodium pyrosulfite 0.5-1.0 water rest, and as a fixing liquid - a solution including a modifier for process fluids "SoltPlast" based on a polyvalent metal salt, as well as an initiator for the formation of colloidal aggregates - potassium acetate and water in the following ratio of components, mass%: modifier for technology SoltPlast liquids 32-42 potassium acetate 0.5-1.0 water rest