EA010638B1 - Water-based drilling fluids using latex additives - Google Patents

Water-based drilling fluids using latex additives Download PDF

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Publication number
EA010638B1
EA010638B1 EA200600154A EA200600154A EA010638B1 EA 010638 B1 EA010638 B1 EA 010638B1 EA 200600154 A EA200600154 A EA 200600154A EA 200600154 A EA200600154 A EA 200600154A EA 010638 B1 EA010638 B1 EA 010638B1
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EA
Eurasian Patent Office
Prior art keywords
drilling fluid
latex
water
pressure
characterized
Prior art date
Application number
EA200600154A
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Russian (ru)
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EA200600154A1 (en
Inventor
Калвин Дж. II Стоуи
Роналд Г. Бланд
Деннис Клаппер
Тао Сян
Саддок Бенаисса
Original Assignee
Бейкер Хьюз Инкорпорейтед
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Priority to US49168503P priority Critical
Priority to US10/634,334 priority patent/US7393813B2/en
Application filed by Бейкер Хьюз Инкорпорейтед filed Critical Бейкер Хьюз Инкорпорейтед
Priority to PCT/US2004/024804 priority patent/WO2005012456A1/en
Publication of EA200600154A1 publication Critical patent/EA200600154A1/en
Publication of EA010638B1 publication Critical patent/EA010638B1/en

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Abstract

The invention describes a water-based drilling fluid containing a polymer latex capable of forming a deformable latex film, at least in a portion of the formation (downhole section), which allows filtering of pressurized drilling fluid when drilling wells for gas or oil in clay shale Preferably, a precipitating agent is used in conjunction with the polymer, for example, a silicate or an aluminum complex (for example, sodium aluminate). Water present in the drilling fluid usually contains salt, forming a brine, often saturated, although the invention is also feasible with the use of fresh water. When using salt, it is often advisable to additionally use a surfactant, such as betaine.

Description

The present invention relates to water-based drilling fluids used in the practice of oil production, and, in particular, relates in one of its variants to the use of water-based drilling fluids containing additives that prevent the penetration of the liquid phase of the drilling fluid into the formation rock through the borehole walls .

State of the art

Known drilling fluids used in the drilling of underground oil and gas wells and other works requiring the use of such fluids and works related to drilling. In the case of rotary drilling, drilling fluids, also known as flushing fluids, must have certain functions and characteristics. The drilling fluid must remove the cuttings (cuttings) from the drill bit (rock cutting tool), raise them along the annular space to separate them on the surface, while cooling and cleaning the drill bit. The drilling fluid is also designed to reduce friction between the drill string and the side walls of the borehole while maintaining the borehole in open-air sections in a steady state. The composition of the drilling fluid is selected in such a way as to prevent undesirable inflows of formation fluids from permeable rocks through which the well passes, and often to form a thin clay cake with low permeability, which temporarily clogs pores and other voids and rocks drilled by the drill bit. Drilling fluid can also be used to collect and interpret information obtained from the study of cuttings, cores, and electrical logs. It should be noted that in the context of the present invention, the concept of drilling fluid also includes solutions for the opening of productive formations (άτίΐΐ-ίη Πιιίάδ).

Drilling fluids are usually classified by the substance of their fluid base. In water-based solutions, solid particles form a suspension in water or brine. Oil or oil can be emulsified in water or brine. The dispersion phase in this case is water. Hydrocarbon-based drilling fluids (CBF) are the opposite. Solids are suspended and water or brine is emulsified in the oil product, i.e. the dispersion phase is the oil product. Hydrocarbon-based drilling fluids are water-in-oil emulsions and are also called invert emulsions. Brine-based drilling fluids, of course, are water-based muds in which the brine is an aqueous component.

The optimization of the composition of highly effective water-based solutions is currently the most important task of many service and oilfield companies in connection with various disadvantages of invert emulsion solutions. Invert-emulsion fluids based on traditional diesel fuel and mineral oils or more modern synthetic oils are the most effective drilling fluids in terms of clay inhibition, stabilization of the wellbore (ensuring its stability), as well as lubricating properties. However, a number of drawbacks inherent in these solutions, such as problems in terms of environmental safety, low profitability indicators, the tendency to absorb porous layers, the inability to indicate manifestations, as well as the problems created during the geological assessment, contribute to maintaining a steady demand for highly effective solutions in water basis. Due to the tightening of environmental requirements and environmental responsibilities, the industry still needs water-based drilling fluids as a complement to the leading invert emulsion fluids or to replace the latter.

A specific problem when drilling wells in shale using water-based drilling fluids is an increase in pore pressure and swelling of shale from the liquid that penetrates into them. To counteract these phenomena and stabilize shale under conditions of fluid exposure, shale stabilizers are usually added to the mud.

Reducing the penetration of drilling fluid pressure into the walls of the well is one of the most important factors for ensuring the stability of the wellbore. It has been established that a sufficiently high pressure in the wellbore stabilizes shale while maintaining the integrity of the wellbore. As the drilling fluid or fluid enters the shale, the pressure in the pores increases, and the pressure difference between the mud column and the surface of the shale decreases. Due to the drop in pressure difference, the solution ceases to support shale, and they easily collapse into the wellbore. Similarly, water seeping into the shale matrix increases the hydration or wetting of the partially dehydrated shale base, causing it to soften and lose its mechanical strength. The ability of shales to enter into chemical reactions can also lead to their loss of stability. Therefore, there is a need for a drilling fluid composition and method for stabilizing formations represented by shales.

When drilling in formations including depleted reservoir rocks (sand formations or sandstones), it is also necessary to prevent the penetration of drilling fluid through the wellbore into the formation rock. In this case, the main problem is not ensuring rock stability, but the loss or absorption of drilling fluid, leading to an increase in production costs. Therefore, it is desirable to be able to reduce drilling fluid absorption by depleted rocks.

- 1 010638 collectors.

It is obvious to the specialists involved in the selection or use of drilling fluids during oil and gas exploration that the precisely balanced composition ensuring the achievement of all the characteristics necessary in each particular case is an essential component of the success of the choice of a particular fluid. Since drilling fluids are designed to simultaneously solve a number of problems, achieving such a balance is not easy.

Therefore, it is desirable to develop such compositions and methods that would increase the ability of drilling fluids to simultaneously solve these problems.

Summary of the invention

Accordingly, it is an object of the present invention to provide methods for stabilizing shale and preventing absorption of solutions by depleted reservoir rocks (sandstones) during drilling using water-based drilling fluids.

Another objective of the present invention is the creation of water-based drilling fluids, providing a decrease in the rate of penetration of the pressure of the drilling fluid into the wall of the wellbore.

Another objective of the invention is to provide a drilling fluid composition and a method for increasing the degree and reliability of rock isolation from pressure and pore size, which can be plugged using water-based drilling fluids designed to stabilize shale.

To solve these and other problems, in one embodiment of the invention, there is provided a water-based drilling fluid containing water and polymer latex capable of forming a deformable latex film or deformable latex seal in at least a portion of the formation, thus at least , partially isolating the formation rock.

Brief Description of the Drawings

In FIG. Figure 1 shows the graphs of changes in reservoir pressure over time obtained during tests to study the penetration of pressure of the drilling fluid into the reservoir using a number of intermediate experimental compositions.

In FIG. 2 is a diagram illustrating the effect of the addition of surfactants on the particle size of CEXCAL 7463 in a drilling fluid of the following composition: 20% NaCl solution; 1 lb / bbl (2.86 g / l) ΝΕνΌΚΙΕΕ Pb8; 1 lb / bbl (2.86 g / l) ΧΑΝ-PEX Ό; 0.5 lb / bbl (1.43 g / l) sodium gluconate; 3 lb / bbl (8.58 g / l) ΝαΑ1Ο 2 ; 5 vol.% SEXAX 7463.

In FIG. 3 is a diagram illustrating the effect of adding polymer resins (in the amount of 3 lb / bbl., 8.58 g / l) on the SEXCAL 7463 particle size distribution after being processed in a rotary roller furnace for 16 hours at 150 ° E (66 ° C) in drilling mud of the following composition: 20% solution No. 101; 0.75 lb / bbl (2.15 g / l) ΧΑΝ-PEX Ό; 0.5 lb / bbl (1.43 g / l) sodium sodium gluconate; 0.4 lb / bbl (1.14 g / l) XEO-OK1 Pb8; 2 lb / bbl (5.72 g / l) ΒΙΟ -AC; 3 lb / bbl (8.58 g / l) \ aA1O <3% SEX.AP 7463; 1 lb / bbl (2.86 g / l) EXP-152.

In FIG. Figure 4 graphically presents the results of comparing the effects of EXP-154 and APEX on the properties of a drilling fluid with a density of 12 pounds per gallon (1.44 kg / l) of the following composition: base 20% solution No. 1Cl; 0.5 lb / bbl (1.43 g / l) XAX-REX Ό; 2 lb / bbl (5.72 g / l) VU-LO8E; 1 lb / bbl (2.86 g / l) \ E \\ '- 1) IP.P Pb8; 3% EXP-155; 150 lb / bbl (429 g / l) M1-BAC; 27 lb / bbl (77.2 g / l) Neu Piy.

In FIG. Figure 5 graphically presents the results of pore pressure transfer tests (PPS) for drilling fluids with the addition of ALPEX, EXP-154 / EXP-155 and ΙδΟ-TEC.

In FIG. Figure 6 graphically shows the effect of circulation on the efficiency of a drilling fluid with the addition of EXP-154 and EXP-155 according to tests for PPD.

In FIG. 7 graphically illustrates the effect of latex addition on the properties of a drilling fluid with a density of 9.6 pounds per gallon (1.15 kg / l) after processing it in a rotary roller furnace for 16 hours at 250 ° E (121 ° C); composition of the base: 20% solution No. 1C1; 1 lb / bbl (2.86 g / l) XAX-REX Ό;

O, 4 lbs / bbl. (1.14 g / l) XEO-OK1 Pb8; 2 lb / bbl (5.72 g / l) ΒΙΟ-pAC; 5 lb / bbl (14.3 g / l) EXP-154; 10 lb / bbl (28.6 g / l) M1-SAKV; 27 lb / bbl (77.2 g / l) Neu Peak !.

In FIG. Figure 8 graphically shows the effect of latex on the properties of a 12 pound per gallon drilling fluid after treatment in a rotary roller kiln for 16 hours at 250 ° E (121 ° C); composition of the base: 20% solution No. 1C1; 0.75 lb / bbl (2.15 g / l) XAX-REX Ό; 0.4 lb / bbl (1.14 g / l) HEU-ESH RI8; 3 lb / bbl (8.58 g / l) ΒΙΟ -AC; 5 lb / bbl (14.3 g / l) EXP-154; 150 lb / bbl (429 g / l) MSH-SARV; 27 lb / bbl (77.2 g / l) Neu Peak !.

In FIG. 9 graphically presents the results of a 96-hour range test of samples of experimental products in drilling fluids with a density of 12 pounds per gallon (1.44 kg / l) using shrimp Μνκίάορκίκ bа1ia; composition of the base: 20% solution No. 1C1; 0.5 lb / bbl (1.43 g / l) XAX-REX Ό; 0.4-1 lb / bbl (1.14-2.86 g / l) \ E \\ '- 1) IP.P Pb8; 2 lb / bbl (5.72 g / l) MP.-RAS LU (or ΒΙΟP. AC); 150 lb / bbl (429 g / l) MI ^ -ΒΑΚ.

In FIG. 10 shows a graph of the filtration rate of a mud with latex polymer in coli

- 3 010638, 3% on a 50 mD cement disk under high pressure and high temperature (HPH) conditions after its treatment in a rotary roller furnace for 16 hours at 250 ° Р.

In FIG. 11 is a photograph of an inner filter cake formed by the process of the invention.

DETAILED DESCRIPTION OF THE INVENTION

It has been found that adding polymer latex to a water-based drilling fluid can reduce the rate at which the pressure of the drilling fluid penetrates into the walls of the well passing through the subterranean formation while drilling the well. Polymer latex is preferably capable of forming a deformable latex film or seal at least in a portion of the formation. In the context of the present invention, the concepts of film and sealing should not be interpreted as meaning a fully impermeable layer. Such a seal, or insulating layer, is considered to be semi-permeable, but at least partially blocking the transfer of fluid, which as a result brings a significant increase in osmotic efficiency. In one possible embodiment of the invention, the addition of submicron-sized polymer latex in a highly mineralized aqueous solution containing an optional, but preferred binder / precipitating agent, such as an aluminum complex, significantly reduces the rate of penetration of drilling fluid pressure into shale. Thanks to the addition of latex, the degree of isolation of pressure increases, the reliability of clogging and the size of clogged pores. Slowing the penetration of drilling fluid pressure into the borehole wall is one of the most important factors in maintaining wellbore stability.

The main components of the inventive water-based drilling fluids are polymer latex and water, which makes up the bulk of the drilling fluid. Of course, other well-known additives or reagents can be used to bring the properties of the drilling fluid in line with its tasks.

In a preferred, but not exclusive, embodiment of the invention, the polymer latex is a carboxylated styrene butadiene copolymer or a sulfonated styrene butadiene copolymer. An example of a carboxylated styrene-butadiene copolymer that does not limit the scope of the invention is the SEXL 7463 polymer manufactured by Οtηονа δο διιΐίοη 1 ps. An example of a sulfonated copolymer of styrene with butadiene, not limiting the possibility of carrying out the invention, is SEXEL 8100 manufactured by ηtηονа δοϊιιΐίοη 1 ps. Other suitable polymeric latexes include, in particular, polymethyl methacrylate, polyethylene, a copolymer of polyvinyl acetate, a copolymer of polyvinyl acetate, vinyl chloride and ethylene, a copolymer of polyvinyl acetate and ethylene, natural latex, polyisoprene, polydimethylsiloxane and mixtures thereof. A somewhat less preferred latex is based on a polyvinyl acetate copolymer, namely a copolymer of ethylene vinyl chloride with vinyl acetate. Although latexes based on polyvinyl acetate copolymers are applicable in the proposed methods, they are generally inferior to carboxylated styrene butadiene copolymers. The average particle size in the polymer latex is preferably less than 1 μm, but it is most preferred that their diameter is about 0.2 μm or 0.2 μm or less. It is possible that other polymers in the dispersed phase will also work. It is contemplated that more than one type of polymer latex can be used simultaneously. The volume fraction of polymer latex in the drilling fluid with respect to the total volume of the fluid may be from about 0.1 to 10%, preferably from about 1 to 8%, and most preferably from about 2 to 5%.

Sulfonated latexes used in accordance with the present invention have the additional advantage that they can often be used in the absence of a surfactant. This can simplify the preparation and transportation of drilling fluid additives to the field development site. In some applications, this can also reduce costs. When drilling in depleted reservoir rocks (sandstones), the need for the use of precipitating agents is often absent. In addition, depleted reservoir rocks often lack the need for surfactants for carboxylated styrene-butadiene copolymers in fresh water solutions.

The optional salt may be any salt commonly used in brine-based drilling fluids, including calcium chloride, sodium chloride, potassium chloride, magnesium chloride, calcium bromide, sodium bromide, potassium bromide, calcium nitrate, sodium formate, potassium formate , cesium formic acid, mixtures thereof and other salts. By highly mineralized solutions are meant solutions with a salt content of at least 20 wt.%, And in one embodiment of the invention, not limiting the possibilities of its implementation, it is preferable to use saturated brines. It is clear that it is impossible to predict in advance what the salt content in a particular saturated brine will be, since the saturation point depends on a number of factors, which include the types and ratios of various components of a water-based drilling fluid and other factors. Salt is an optional component, since the invention can be carried out without it, that is, using fresh water.

- 3 010638

An optional component is also a precipitating agent. Suitable precipitating agents include silicates, aluminum complexes, mixtures thereof, etc. Sodium aluminate No. A1O 2 may be mentioned as suitable aluminum complexes. sometimes written in the form of Na 2 OA1 2 O 3 , aluminum hydroxide, aluminum sulfate, aluminum acetate, nitric aluminum, potassium aluminate and the like, as well as mixtures thereof (especially at pH> 9, when these compounds are soluble in water). The proportion of precipitating agent in the drilling fluid relative to the total volume of the fluid may be in the range of about 0.25 to 20 lb / bbl. (from about 0.71 to 57.2 g / l), preferably from about 1 to 10 lb / bbl. (from about 2.86 to 28.6 g / l), and most preferably in the range of from about 2 to 7 lb / bbl. (approximately 5.72 to 20 g / l). Not limited to any particular theory, it is believed that the precipitating agent chemically binds to the clay surface in the wellbore to form a highly active polar surface.

Another optional component of the composition of the invention is a surfactant. In the presence of a surfactant, the latex treated by it moistens the surface well and accumulates, forming a film or coating that clogs cracks and flaws in shale. Suitable wetting surfactants include alkali metal alkylene acetate, sultaines, ether carboxylates, mixtures thereof, etc. It has been found that surfactants are especially useful when salts are present in the drilling fluid and are not equally preferred in drilling fluids based on fresh water.

The proportions of these components in terms of the total amount of water-based drilling mud are as follows: polymer latex - from about 0.1 to 10 vol.%, Salt (if present) - at least 1 wt.%, Precipitating reagent (if present) ) - from about 0.25 to 20 pounds per barrel. (from about 0.71 to 57.2 g / l), the surfactant (if present) is from about 0.005 to 2 vol.%, the rest is water. In a more preferred embodiment, the proportions of these components are as follows: polymer latex from about 1 to 8 vol.%, Salt (if present) at least 1 wt.%, Precipitating reagent (if present) from about 1 to 10 pounds / bbl (from about 2.86 to 28.6 g / l), a surfactant (if present) is from about 0.01 to 1.75 vol.%, the rest is water.

It is desirable that sodium aluminate or another precipitating agent is present in the drilling fluid in a metastable form, that is, in the form of a suspension or solution, but is deposited on the walls of the well. Typically, aluminum compounds are added to the drilling fluid in situ. If introduced into the drilling fluid in advance, they tend to lose stability by precipitating prematurely.

Since the pore pressure transfer test method (N11D) was developed, the effect of various chemical additives on the pore pressure transfer rate was investigated. The objects of research were primarily the characteristics of salts, glycols and precipitating agents, such as silicates and aluminum complexes. Improvements in the equipment and test methods for 11D accompanied the general interest in these studies, the aim of which was to obtain more efficient water-based drilling mud systems that would be closer invert emulsion drilling fluids to the characteristics of the 11D tests. 1, while a number of researchers found that silicate drilling fluids are especially effective in reducing the transmission rate of pore pressure, silicate fluids have not been widely used due to their inherent disadvantages. Although lower pore pressure transfer rates have been demonstrated for salts, glycols, and reagents based on aluminum complexes, these compounds still do not achieve the effectiveness of invert emulsion drilling fluids.

The new principle of formation of drilling fluid compositions in combination with the improvement of the test method for 11D was used to demonstrate the effectiveness of an alternative approach to improving the performance of water-based drilling fluids. Water-dispersible polymers were selected as the source of small deformable particles to provide a sealing and blocking effect on shales. The first of these polymers participated in 11D tests in drilling mud along with the rest of the compounds.

Below the invention will be considered in the following examples, which are illustrative only, in no way limiting the possibilities of carrying out the invention.

1 example 1. 1 the preparation of the intermediate composition of the drilling fluid.

The following example is the first experience in the preparation of intermediate compositions used in accordance with the present invention. Unless otherwise indicated, latex grade 728, which is a polyvinyl acetate latex, is used as latex in all examples.

- 4 010638

Component

Tap water

Sodium Aluminate

YOSO

ΑΙΒΈΙΈΧ 728

Gram per barrel (159 L)

310

10.5

Gram on 7 barrels (on And 13 l)

2170

73.5 (75 cm 3 )

The mixture was processed in a rotary roller furnace. After 6 days, the pH value was 11.51. The bottom of the vessel was 75% coated with small particles of 1/32 inch (0.79 mm) size. Then the following components were added in the quantities indicated below, again given in grams per barrel and 7 barrels, respectively:

ΝΕλνοΚΙΕί riz 0.42.8

NaC1 (20%) 77.5540

M1PAC LU 214

The solution with latex and ΝΕΑΩΒΙΕΕ + was light brown in color. Контроля8 was added to control foaming. The resulting mixture was kept in a rotary roller furnace for 4 hours at 150 ° E (66 ° C). The final pH was 10.75.

Example 2. Determination of the penetration of pressure into shales.

The installation for testing the PPD is made on the basis of the Hassler core holder, which withstands a pressure of 1,500 psi. inch (10300 kPa) and designed for core samples with a diameter of 2.5 cm and a length of 2.5 to 7.5 cm. Hassler core holder is a cylinder with pistons at both ends. The core is mounted between the pistons. Around the circumference, the core and pistons are enclosed in a rubber sleeve that provides core compaction and prevents fluid from flowing around its circumference. To ensure proper tightness, the sleeve is crimped from the outside. Tests are conducted on core samples with a diameter of 25 and a length of 25 mm.

To provide back pressure from the core side corresponding to the low pressure (rock side), a 1 liter stainless steel battery is installed, generating a pressure of 2000 psi (13800 kPa). The high-pressure side of the core is connected to two similar accumulators, one of which is intended for pore fluid, and the second for the test solution. The pressure in each of the batteries is controlled by a manual regulator connected to a nitrogen cylinder at 2200 psi (15,200 kPa).

Pressure monitoring is carried out by Neschet sensors. Sensor readings are automatically recorded by the computer at predetermined time intervals.

The core holder is placed in an insulated chamber, where the temperature is maintained using a 200 W heater. The heater is regulated by a temperature controller of the company O \\ ueg. actuating the control unit of silicon rectifiers Coi1to1 CoeerC with phase angle control. Temperature control is performed with an accuracy of ± 0.05 ° С.

Pressure is applied to one end of the core sample and fluid flow rate is measured when the solution is filtered through the sample. The piston space on the low pressure side is filled with liquid and locked, so it is not the flow rate that is measured, but the increase in the liquid pressure. Even a very small amount of liquid passed through the core causes a large increase in pressure, which makes the core holder sensitive enough to measure the volume of filtration through shale. Since the permeability of shale is very low, the filtration through it is very small. The graph shows the change in pressure over time. The results are expressed as reservoir pressure (PD). If the pressure increases over time, then pressure penetrates the sample, and if reservoir pressure decreases over time, then pressure does not penetrate, which is desirable.

The solution used had a composition corresponding to Example 1. The injection was carried out in three doses of 50 cm per 50% of the stroke during and immediately after heating the core holder. One cycle of displacement was performed at 100% of the stroke, but it turned out to be difficult to regulate the temperature, so we decided that it was better to start at 50%.

Temperature 155 ° E (68.3 ° C).

Pressure from the side of the wellbore (P well ) 250 psi (1720 kPa).

Limiting pressure (P ogr .) 370 psi (2550 kPa).

- 5 010638

Time, hours: minutes

Formation Pressure psi inch

48.1

1:30

2 a.m.

7:15 a.m.

47.9

47.6

50.9 kPa

332

330

328

359

In the end, 50 cm of the solution was displaced by a 50% working stroke with temperature deviations within 2 ° P (1.1 ° C). Pressure rose to 52.7 psi (363 kPa). The heating of the rock was stopped, and the temperature was 147 ° P (64 ° C). As a result of the displacement of the solution, the reservoir pressure dropped to 36 psi (248 kPa), then over the next two days it increased to 80.2 psi (553 kPa). An initial decrease in reservoir pressure showed that the composition of the invention slows the penetration of pressure into the sample.

Example 3. The preparation of the intermediate composition of the drilling fluid (quantities are given in grams, unless otherwise indicated).

Component per barrel (159 L) per Ί barrels (1113 L)

Tap water

2170 3

Sodium Aluminate 2 14

yoso 2 14 Latex ASTHYTECH 728 10.5 75 cm 3 ΝΕ’ΛΌΒ.ΙΕΙ. PY38 0.4 2,8 IAAS! (twenty%) 77.5 540 MLRAS 2 14

Sodium aluminate and latex AHKREX 728 were mixed and left for two days. Then the mixture was kept in a rotary roller furnace for 2 hours at 150 ° P (66 ° C). Next, salt and polymers were added. The sequence of adding sodium aluminate and latex to the mixture was as follows: PHPA (partially hydrolyzed polyacrylamide; ΝΕ ^ ΌΚΙΕΕ Pbu8), followed by stirring, followed by half the amount of salt, MlPAC LU, then the rest of the salt. The mixture was left overnight in a rotary roller oven.

Example 4. Determination of the penetration of pressure into shale.

Wellbore pressure is 250 psi (1720 kPa). The limiting pressure is 370 psi (2550 kPa).

Reservoir pressure

Time, hours: minutes pound per square meter inch kPa 0 46.3 319 5:49 2,3 sixteen 7:36 0.6 * 4.1 50:00 65.0 448

* The limiting pressure has risen to 410 psi (2830 kPa), and the pressure from the wellbore has risen to 300 psi (2070 kPa).

Examples 5 and 6, comparative examples AE.

Two more drilling fluid compositions were prepared and tested in accordance with the present invention (examples 5 and 6 and six comparative examples (AE). The results are shown in Fig. 1. As can be seen, both examples 5 and 6 of the invention gave the desired results — a decrease over time reservoir pressure. Comparative examples showed an undesirable increase in reservoir pressure over time. The interpretation of the compositions is shown in Fig. 1. Designation of the core: Pierre. II parallel. means that the core refers to the Pierre shale and is in parallel flax orientation.

These results confirm the need to use all three components: salt, latex and sodium aluminate (examples 5 and 6). Compositions using only latex (comparative example A), only salt (comparative example B), latex only with salt (comparative example C), sodium aluminate only with salt (comparative example D), sodium aluminate only with salt (comparative example D) and sodium aluminate with salt only (comparative example E) were found to be ineffective or at least not as effective as the composition of the present invention.

Further experimental data indicate the manifestation by some latex substances of synergism with aluminum complexes, which is manifested in an improvement in the transmission characteristics of pore pressure. Stable drilling fluid systems were obtained with latex, which remains dispersed and elastic in highly mineralized (high salt) drilling

- 6 010638 solutions. The drilling fluids used in the present invention are more efficient in transferring pore pressure closer to hydrocarbon-based drilling fluids than the efficiency of existing aluminate-based drilling fluids. It is believed that two factors of this system make the main contribution to the stabilization of shale. Firstly, the smallest deformable particles of latex (the preferred diameter of the order of 0.2 microns) mechanically clog microcracks in the shale and physically impede the further penetration of drilling fluids into susceptible zones in the shale. Secondly, co-precipitation of latex with precipitating reagents, such as aluminum complexes, if present in the solution, leads to the formation of a semipermeable membrane on the surfaces of shale, which chemically improves the osmotic efficiency of the interaction between the drilling fluid and the walls of the wellbore.

For the drilling fluids used in the present invention, three experimental additives EXP-153, EXP-154 and EXP-155 were found. The EXP-153 additive is a sulfonated polymer resin used in this system to combat mud filtration under high pressure and high temperature (HPH) conditions.

The EXP-154 additive is offered as an alternative to the aluminum complex - the ABRIEH product. Compared to ADBBEX, EXP-154 additive shows much better compatibility with latex drilling fluids. EXP-155 is a modified latex product. Compared with other commercially available latexes, EXP-155 exhibits less sensitivity to electrolytes and does not undergo flocculation in drilling fluids based on a 20% sodium chloride solution at temperatures up to 300 ° E (149 ° C). In addition, due to the large temperature interval between the glass transition point (T d ) and the melting temperature (T t ), EXP-155 particles retain the ability to deform and clog microcracks in shale at temperatures that correspond to most applications. The toxicity indices of all these products satisfy the requirements for waste drilling fluids discharged into the Gulf of Mexico.

Compositions and properties of drilling fluids.

Mixing of all drilling fluids was carried out according to the technologies established by the company GYTEC of the Wakeg Nidijek Corporation. The initial and final rheological characteristics of the Bingham plastic body — structural viscosity, yield strength, and static shear stress after 10 s and 10 min of rest (10-second gel and 10-minute gel) were measured on a Yeaia 35 viscometer at 120 ° E (49 ° C) . Initial and final pH and filtrate volume values were recorded by ANI. Filtration (water loss) under the conditions of HPH was measured at 250 ° E (121 ° C) after static and dynamic aging (aging) for 16 hours at 250 ° E (121 ° C).

Latex stability.

The stability of the latex samples was determined in 20% and 26% solutions No. 101 according to the following procedure.

1. Pour 332 ml of a 20% (or 26%) aqueous solution of IAl into a glass and begin to mix.

2. Slowly add 18 ml of the tested latex sample to the solution and install the Rppse SakPe agitator with an autotransformer and a speed indicator of 4000 rpm.

3. After stirring for 5 minutes, 3 g of ΝιΑ1Ο 2 is slowly added to the solution and stirring is continued for another 15 minutes. If foaming is observed during mixing, add approximately 5 drops of antifoam (BE-8).

4. The solution was transferred to a mug and kept under static conditions for 16 hours at 150 ° E (66 ° C).

5. Remove the mug from the oven and cool to room temperature. The solution is inspected for flocculation and stratification.

6. If delamination and flocculation are absent, the solution is passed through a 100 mesh sieve (mesh size 0.150 mm). Inspect the sieve to determine the amount of latex particles retained.

Subsequent determinations were carried out only for those samples that passed the screening test. To measure the particle size distribution (particle size distribution) of latex in the prepared drilling fluids, we used a particle size analyzer Layout Machegmheg RagBs1e δί / e Lpa1uheg. When determining the particle size distribution, a small element of the dispersion sample and a standard refractive index of 50NE were always used (particle refractive index = 1.5295, 0.1000, and dispersant refractive index = 1.3300). The pH of a 20% aqueous solution No. C1 was adjusted to 11.5.

Shale Inhibition Test.

Clay shale inhibition characteristics were determined in clay dispersion trials, which included a static layered substrate test and pore pressure transfer (PSD) tests. In the IPD test, a sample of a preserved core of Pierre slate II with a diameter of 1 inch and a length of 0.9 inches (2.54x2.29 cm) was placed between two pistons, as described above in Example 2. Around the circumference, the shale core and pistons were sealed with a rubber sleeve. Cylindrical image

- 7 010638 core samples were oriented by bedding planes in a parallel direction or a direction of high permeability. Drilling fluid at a pressure of 300 psi (2070 kPa) is pumped through the upper piston (side of the borehole wall), and sea water at a pressure of 50 psi (345 kPa) is pumped through the lower piston (rock side). Sea water in the space of the lower piston is held by a valve. As the drilling fluid filtrate arrives at the end of the core sample from the side of the wellbore, the water contained in the shale is displaced into the piston space located on the side of the rock.

Latex stability.

As noted above, initial experiments revealed a synergistic effect of some latex products (emulsion polymers) with an aluminum complex that improves the transmission characteristics of pore pressure of drilling fluids. These results have opened a new approach to the development of water-based drilling fluids with high inhibitory properties. Latex, however, is usually considered a metastable system. The large surface of the particles is thermodynamically unstable; therefore, any disturbance affecting the balancing forces that stabilize the polymer dispersion leads to a change in the kinetics of particle agglomeration. Most commercially available latexes designed for the production of synthetic rubber or for use in paints and coatings are sensitive to increasing electrolyte concentrations and temperature.

As shown in the table. I, from sixteen latex samples tested in 26% and 20% solutions of No. 1C1. none is stable in a 26% NaCl solution, and only ΑΙΚΕΈΕΧ 728 and NaCl 7463 are relatively stable in a 20% NaCl solution. It is clear that for the successful use of latex in drilling fluids it is necessary to increase its stability in highly mineralized environments and at elevated temperatures. To increase the stability of latex in electrolyte solutions, a common method is to add certain surfactants. In FIG. Figure 2 compares the effect of EXP-152 on the particle size distribution of ΑΙΚΕΈΕΧ 728 and ΟΕΝΟΑΕ 7463. The presented results show that a mixture of ΟΕΝί ΑΕ 7463 and EXP-152 can be a stable product for use in drilling fluids.

Table I

Study of the stability of latex products in a solution of Ν; · ιΟ1

% Stability after 16 hours of static aging Poimeo Latex sample ('FROM) 26% solution of IaCl: 3 <Lunt / bapo. 18.58 g / l) %ΛΟ 20% solution: 3 lb / bbl. (8.58 g / l)

Vinyl Acetate / Ethnlenvinyl LHLRRID 7 ASHEEKH 728 0 Flocculation, but passing through a 100 mesh sieve Flocculation / coagulation Vinyl Acetate / Ethylene 8 ASHGYEH 426 0 Flocculation / coagulation Flocculation / coagulation nine A1Y.GBEH 7200 0 Flocculation / coagulation Flocculation / coagulation 10 νίΝΑϋ XX-211 n / a * Flocculation / coagulation Flocculation / coagulation eleven EBUACE 40722- 00 n / a Flocculation / coagulation Floating / coagulation Carboxylated Styrene / Butadiene 12 ΟΕΝΟΑΕ 7463 thirteen Flocculation, but passing through a 100 mesh sieve Flocculation at 150 ° P (66 ° C), but stable at 75 ° P (24 ° C) thirteen ΟΕΝΟΑΕ 7470 n / a Flocculation / coagulation - 14 SEMRBO 576 n / a Flocculation / coagulation - fifteen TUEAS 68219 n / a Flocculation, but passing through a 100 mesh sieve Flocculation, but passing through a 100 mesh sieve sixteen TUBAS SR8 812 n / a Flocculation / coagulation - 17 TUSNEM 68710 n / a Flocculation / coagulation - eighteen ΚΟνΕΝΕ 9410 -56 Coagulation Coagulation nineteen ΚΟΥΕΝΕ 6140 • 27 Coagulation Coagulation Carboxylated Acrylic Copolymer twenty εΥΝΤΗΕΜυί CP8 401 n / a Flocculation / coagulation - 21 zumtnemi 97982 n / a Flocculation / coagulation Styrene / Butadiene 22 ΚΟΫΕΝΕ 4823B -51 Coagulation Coagulation

* there is no data

- 8 010638

Aluminum complex.

Although the results of the PID test confirmed the synergistic effect of APBEX and latex on the stabilization of shale, this system is short-lived and very sensitive to increased salt concentration and temperature. It was found that in a 20% solution of No. 1C1, the ACHEEX 728 additive in an amount of 3% or the CEXCAL 7463 additive in an amount of 3% underwent flocculation for several minutes after adding 4 lb / bbl. (11.4 g / l) LIREX. The preliminary hydration of LREEX with fresh water or the addition of some surfactant (for example, EXP152) improved the stability of this system at low temperatures, but the effect of LLEX on the particle size of the latex remained strong. Particles larger than 100 microns in drilling fluid containing LFLEX may partly be insoluble lignite (LLLEX component). A similar effect is observed in the case of SEXCAL 7463. The low solubility and slow dissolution rate of lignite with high mineralization is probably the main factor determining the reduced latex stability.

Additional studies have been conducted to find a polymer resin compatible with the latex system. In FIG. Figure 3 shows the effect of various polymer resins on the particle size distribution of EXP-155. Among the tested samples, EXP-153 showed the best compatibility with this latex system.

For the latex system, a new product was invented based on an aluminum complex, EXP-154 (a mixture of 45% XAA1O 2 , 45% EXP-153 and 10% sodium S-gluconate). In FIG. Figure 4 compares the properties of clay solutions with a density of 12 pounds per gallon (1.44 kg / l) containing EXP-154 and ALPEX based on the 20% solution of XaCl / XE \ Y-OXL / EXP-155. The experimental aluminum complex exhibits improved compatibility with latex and biopolymers. In addition, it was found that EXP-154 is better than ALPEX, it reduces filtering, both under the conditions of ANI and with airborne airborne engines.

Pore Pressure Transfer Test (PID).

The influence of the experimental latex system on the stability of the wellbore was determined on the above installation for testing for FID. A cylindrical sample of a preserved core of Pierre slate II with a diameter of 1 inch and a length of 0.9 inches (2.54x2.29 cm) was placed between the two pistons, as described above in example 2. Around the circumference of the shale core and pistons were sealed with a rubber sleeve. The cylindrical core sample was oriented by bedding planes in the parallel or high permeability direction. Drilling fluid at a pressure of 300 psi (2070 kPa) is pumped through the upper piston (side of the borehole wall), and sea water at a pressure of 50 psi (345 kPa) is pumped through the lower piston (rock side). Sea water in the space of the lower piston is held by a valve. As the drilling fluid filtrate arrives at the end of the core sample from the side of the wellbore, the water contained in the shale is displaced into the piston space located on the rock side. This intake of water compresses the water in the piston space, which leads to an increase in pressure. The increase in pressure of water located in the piston space from the side of the rock is measured as the increase in reservoir pressure (PD).

As shown in FIG. 5, drilling fluid with the addition of EXP-154 / EXP-155 gives at the moment the best results in PPD. The upper curve refers to the standard salt-polymer system. The next curve below corresponds to the composition with ALPEX additives, the next to the composition with EXP-154 / A1PEX 728 additives, even lower, to the composition with EXP-154 / EXP-155 additives and, finally, the lower curve represents the drilling fluid of the following composition 80 / 20 18 OTES. 25% CaCl 2 , 6 lbs / bbl. (17.2 g / l) SAVCO-SEV and 10 lb / bbl. (28.6 g / l) OMX1-MI. A possible explanation for the highest efficiency of drilling fluid with additives EXP-154 / EXP-155 can serve, at least in part, the small particle size of the latex in this system. As discussed above, EXP-152 dispersed CEXCAL 7463 more efficiently to produce a much larger percentage of particles smaller than one micrometer.

In these experiments, a synergistic interaction was also observed between the latex and the aluminum complex. Such results can be attributed to the co-precipitation of EXP-155 and EXP-154. It was found that at pH <10 EXP-1 54 becomes insoluble. Under these conditions, only EXP-155 is not precipitated. However, if EXP-154 is present in the system, EXP-155 is precipitated together with EXP-154. Due to the nature of their joint deposition, the particles forming a precipitate on the surface of shale contain both lipophilic and hydrophilic components. Such a multiphase system is capable of forming semipermeable membranes, which provides a significant increase in the efficiency of osmosis. Another characteristic feature of EXP-155 is that its smallest (ultrafine) particles remain elastomeric in a wide temperature range. Under the influence of the differential pressure, these ultrathin particles do not cut off and do not collapse, but become deformed and penetrate microcracks with the formation of an impermeable seal. At temperatures lying between T d (glass transition point) and T t (melting point), most polymers, like rubber, exhibit high elasticity. The glass transition temperature of EXP-155 is 52 ° E (11 ° C). According to the relationship between T, and T t , graphically constructed by Woeweg (1963) and given in the book by Vshteueg

- 9 010638

TehLook Og Ro1uteg Bsheise, 2nd ed., ^ Yeou-1p1eg8S1eise, Νον, New York, 1971, p. 230, can determine that the T m of EXP-155 is about 300 ° E (422 K). This temperature range covers most applications of drilling fluids.

It has been found that mud circulation is an important element in latex rock plugging. This element was investigated in experiments with EXP-155. Since the latex content in the composition was only 1.5 vol.% (EXP-155 active at 50%), the latex in the drilling fluid was not enough to clog the rock in static conditions. Under the conditions of circulation, latex accumulated on the surface and formed a clogging film. The standard method involves pumping the drilling fluid for about 7 hours, after which the solution was left in the static state overnight. In the morning, the test was started after 4-5 hours without circulation. This period of the static state eliminates the pressure movement caused by the influence of temperature, allowing, upon completion of the circulation, the temperature to go into equilibrium.

At the beginning of the experiment, the reservoir pressure dropped from 50 psi (345 kPa) to zero, and the pressure difference increased from 250 psig to 300 psi (from 1720 to 2070 kPa), as can be seen in FIG. 6. After about 30 hours, fluid seepage through the core began, and reservoir pressure increased. However, as a result of additional circulation for an hour, the leakage was stopped, and the pressure again dropped to zero. In previous experiments, circulation was stopped after an hour, and after another 30 hours the core began to flow again. In the same experiment, circulation was resumed after pressure increased to 60 psi (414 kPa) after 70 hours (FIG. 6). However, the circulation was maintained for 5 hours, not 1 hour, as before. As a result of circulation, which lasted several hours after the establishment of a larger pressure drop, the seal (insulating layer) turned out to be more stable. After 45 hours, pressure increased by only a few pounds per square meter. inch.

Microphotographs of the surface of the core face showed latex accumulation along microcracks in shale. Since the volume and rate of filtration in these slots are very small, filtration alone cannot be the cause of latex accumulation at the entrance to these slots. Inside these gaps, the ratio of the surface area of the shale to the volume of the filtrate is very large, which led to the intensive deposition of EXP-154. The reason for this, as mentioned above, may be the nature of the co-deposition of EXP-154 and EXP-155 without limiting the reason to any specific explanation. The precipitation of the aluminum complex at pH <19 clearly contributes to the accumulation of latex at the entrance to the slots. When the latex is deposited in sufficient quantity to block the slot opening, a crack becomes clogged and a certain pressure drop occurs on the latex jumper. Under the influence of this differential pressure, the latex sediment is compacted, creating a continuous seal. The increase in pressure drop, obviously, causes this seal to deform over time (about 30 hours in the case of the results of Fig. 6) and / or creates additional slots in the shale, and therefore the shale begins to let fluid through, although the inventors admit other reasons for this. However, additional circulation quickly eliminated leakage, restoring the seal. Pumping the solution after reaching the full value of the pressure drop led to the formation of a stable seal with a slight increase in pressure.

The effect of latex on the properties of the drilling fluid.

The previous results and their discussion related to the stability of latex in drilling fluids and its synergism with the aluminum complex in increasing the efficiency of the use of drilling mud in rocks composed of shale. In addition, the efficiency gains achieved by using latex products were affected. Two latex samples were evaluated: Latex A (a mixture of A1BEBEX 728 and EXP-152 in a ratio of 8: 1) and EXP-155 (a mixture of SEZH AB 7463 and EXP-152 in a ratio of 8: 1) in drilling fluids based on 20% solution No. C1, one with a density of 9.6 pounds per gallon (1.15 kg / l) and the other with a density of 12 pounds per gallon (1.44 kg / l). The effects of adding these latex products in an amount of 3% by volume are illustrated in FIG. 7 and 8. Without an obvious effect on the rheology of the fluids under the influence of Latex A and EXP-155, the filtration of the drilling fluid under high pressure and high temperature (HPH) at 250 ° E (121 ° C) decreased in the drilling fluid density of 9.6 pounds per a gallon (1.15 kg / l) by as much as 45 and 52%, and in a drilling fluid density of 12 pounds per gallon (1.44 kg / l) by 35 and 40%, respectively. Again, EXP-155 showed better results than EBEX 728. Additional experiments with EXP-155 are listed in Table. II.

- 10 010638

Table II Typical characteristics of drilling fluids with a density of 12 pounds per gallon based on a 20% ΝαΟΙ mud with the addition of EXP-155

Composition Example 23 24 Water, barrels. (l) 0.89 0.89 (141) ΧΑΝ-REX ϋ, lb / bbl. (g / l) 0.5 (1.43) 0.5 (1.43) ΒΙΟ-ΡΑΟ, pound / barrel (g / l) 4 (11.4) - ΒΙΟ-ίΟ8Ε, pound / barrel (g / l) - 4 (11.4) ΝΕΑ OKZIER REVE, lb / bbl. (g / l) 1 (2.86) 1 (2.86) EXP-154 lb / bbl (g / l) 5 5 (14.3) MaCl, lb / bbl (g / l) 77.5 (222) 77.5 (222) EXP-155. % vol. 3 3 ΜΙί, -ΒΑΚ, pound per barrel without weights (g / l) 150 (429) 150 (429) Ksu-0iz1, pound / barrel. (g / l) 27 (77.2) 27 (77.2) Initial Properties Plastic viscosity, cP 22 21 Yield strength, pound per 100 square meters. ft (kPa) 26 (179) 20 (138) Static shear stress after 10 s of rest, pounds per 100 square meters. ft (kPa) 5 (34) 4 (28) Static shear stress after 1 0 min rest, pound per 100 square meters. ft (kPa) 10 (69) 8 (56) ANI filtering, cm ’/ ZO min 2,5 1.4 pH 10.6 10.7 Density, pounds per gallon 12,2 12,2

After 16 hours of aging in a rotary roller furnace with: ] 50 ° P (66 ° C) 250 ° P (121 ° C) - 150 ° P (66 ° C) 250 ° P (12 GS) - After 16 hours of aging in a static state with: - - ZOO’R (149 ° C) - - 300 ° P (149 ° C) Plastic viscosity, cP twenty 21 22 26 24 23 Yield strength, pound per 100 square meters. ft (kPa) 24 (165) 29 (200) 34 (234) 17 (117) 21 (145) 22 (152) Static shear stress after 10 s of rest, pounds per 100 square meters. ft (kPa) 6 (41) 7 (48) 10 (69) 4 (28) 5 (34) 5 (34) Static shear stress after 10 minutes of rest, pound per 100 square meters. ft (kPa) 9 (62) 10 (69) 13 (90) 7 (48) 7 (48) 7 (48) ANI. ml 2,8 3,7 2,8 2.2 2.6 1.8 pH 10,4 9.7 9.7 10.5  9.7 10.1 Filtering index at HPHT, cm3 / min LP 9,4 16,4 12 8.4 thirteen 10.8

Toxicity test.

Results of a 96-hour biological analysis (range test) of additives AZHEEX 728, SEISAY 7463, EXP-152, EXP-154 and EXP-155 in drilling fluids with a density of 12 pounds per gallon (1.44 kg / l) of the composition 20% solution ΝηΟΙ / ΝΕΧνΟΕΙΕΤ using are shown in FIG. 9. All of these products meet the requirements for discharging spent drilling fluid into the Gulf of Mexico (concentration

- 11 010638 fraction of 30,000 ppm), and their toxicity is reduced after mixing with the solid phase of the drilling fluid.

Example 7

Since latex polymers contain deformable colloidal particles, they have an excellent ability to block and plug voids, thereby reducing the permeability of rocks in which drilling fluid absorption may occur. In the table. III shows a typical composition for studying the ability of latex polymers to plug permeable rock. In the absence of a latex polymer, the filtration (absorption) of this drilling fluid cannot be controlled. However, when a 3% vinyl acetate / ethylene / vinyl chloride-based latex polymer commercially available under the trade designation AiT1ex 728 is added to this drilling fluid, there is a sharp decrease in filtration per unit time, as shown in FIG. 10. In the table. 1U-U1 presents the data of FIG. 10.

In FIG. 11 shows a cross section of a fractured disk with a permeability of 50 mD after a 4-hour test at 300 ° Ρ with a drilling fluid containing 3% latex polymer. ΌΡΕ-245 is a mixture of OeiCa1 7463 and MDET BET-030 with a volume ratio of about 9: 1. It is clearly seen that an internal filter cake formed inside the disk with a permeability of 50 mD.

Table III The composition of the drilling mud to study the effect of latex on the filtration of the drilling fluid at high pressure

Composition number 1094-52-1 Water, barrels. 0.89 ΝΕ \ ν-ΟΚ.Ι1Χ ® РЫ13, lb / bbl. 0.4 Μΐί-RAS LU, pound / barrel. 2 MAX RECH, lb / bbl. 4 No. € 1, pound / barrel. 77.5 AgShekh 728 (latex polymer), vol.% 3 Tycoon VET-OZO, pound / barrel. one

Table IV Filtration of the drilling fluid under high pressure and high temperature (HPHT) conditions - 500 psi and 75 ° м - on a disk with a permeability of 50 mD for a drilling fluid containing 3% A1gieh 728

Time interval, min Filtration of a solution at HPH, ml The average rate of filtration of the solution at HPH, ml / min 0-1 4,5 4,50 1-10 2 0.22 10-30 E5 0.08 30-60 1,5 0.05 60-120 2,5 0.04

Table v

Filtration of the drilling fluid under high pressure and high temperature (HPHT) conditions 500 psi and 250 ° Ρ on a 50 mD permeability disk for a drilling fluid containing 3% AIT1ex 728

- 12 010638

Table VI Loss of drilling fluid at high temperature and pressure (HPHT) 500 psi and 300 ° P on a 50 mD disk for a mud containing 3% Lhtjeh 728

Time interval, min Loss of HPHT solution, ml The average rate of filtration of the solution at HPH, ml / min 0-1 10 10 1-10 thirteen 1.44 10-30 8 0.4 30-60 6 0.20 60-120 10 0.17 120-180 5 0.08

Above, the invention was examined with specific examples of its implementation and it was shown that it proposed a water-based drilling fluid, which is able to effectively reduce the rate of penetration of a drilling fluid pressure under pressure into a borehole wall. However, the specialist should be obvious possibilities of carrying out the invention and in other, modified, variants that fall under the patent claims set forth in the attached claims. Accordingly, this description should be considered as illustrating the possibilities of using the invention, and not limiting them. It is intended, for example, that patent claims will cover specific combinations of brines and latexes with precipitating agents and / or wetting surfactants or salts that are within the scope of the claimed parameters, but not specified in the description or not tested in a specific composition to reduce the penetration of drilling pressure mortar in shales, sand and other rocks.

4025-70

APORJEH 728

A1KTEX 426

ASHET.EX 7200

Glossary

Atoso low molecular weight amphoteric polymer; found ineffective (also denoted 4025).

Dispersion of polyvinyl acetate latex (in particular, a copolymer of ethylene-vinyl chloride and vinyl acetate) manufactured by Αίτ Рго4ис1з

A copolymer of vinyl acetate and ethylene manufactured by Αίτ RgoisGz.

A copolymer of vinyl acetate and ethylene manufactured by Ai RgoOtsy.

APREX® The patented aluminum complex manufactured by Wakeg Niigkez ΙΝΤΕ (). AC8 Abbreviation for AOIAASO-8, glycol production ________________ and ___ 1 ___ т> .тт “T2gl kishshnpn oixx are written Vu-bo5e Modified starch produced by Wakeg Nimfey ΙΝΤΕί). WURAF Additive to combat the absorption of drilling fluid based on modified starch, manufactured by Wakeg Nschfez STE (). SAKVO-OE Amine-treated clay manufactured by Wakeg Nschfez PChTE <E. SAK.VO-MI Emulsifier for inverse emulsions manufactured by Wakeg Nidiyes ΙΝΊΈρ. EYUACE 40722-00 Latex copolymer of vinyl acetate and ethylene manufactured by Ke1sY1o1s1. EXP-152 Surfactant oleamidopropyl betaine.

- 13 010638

EXP-153 Sulfonated polymer resin (or sulfonated humic acid with resin) manufactured by Wakegnergieff. EXP-154 A mixture of 45% No.AU 2 , 45% ΕΧΡ-153 and 10% sodium β-gluconate. EXP-155 A mixture of CEMCAN 7463 and EXP-152 in a volume ratio of 8: 1. ΙΕΟΆ'ΖΑΝ Biopolymer produced by the company βπΐΐϊης 8res1a1111ez. ET-1 A BIGGAT, a dispersion of water-soluble 90% sulfonated asphalt manufactured by Wakeg Niigz ΙΝΤΕβ. ΟΕΝΓ.ΑΕ 7463 Carboxylated copolymer of styrene and butadiene manufactured by Oshpoe 8o1i6op 1is. SEC1CAE 7470 Carboxylated styrene-butadiene copolymer manufactured by Otpowa 8ο1ιιΐίοη 1ps. ΟΕΝΕίΟ 576 Reagent production company Otpoua δοϊυΐίοη 1 ps. BO8 Defoamer manufactured by Baker Ni§ez ΙΝΤΕ <2. EUSO Lignite production company Wakeg Nee ^ kes ΙΝΤΕ (). M1B-VAK Barite Drilling Fluid Weighting Agent manufactured by Wakeg Nigz ΙΝΤΕρ. MI.-SAV.V Calcium carbonate-based drilling fluid weighting agent manufactured by Wakeg Nike ^ kes ΙΝΤΕφ. M1ERAS 1.U Low-viscous polyanionic cellulose manufactured by the company Wakeg Nigz ΙΝΤΕ (2 (sometimes referred to as RasBU). MAX RECH Aluminum complex for stabilization of shale by Wakeg Ni§gez ΙΝΤΕ (}. ΜΙΚ.ΑΤΑΙΝΕ BET-O-ZO Betaine surfactant manufactured by Biogia. ΝΕχνοκίΕί riz Partially hydrolyzed polyacrylamide manufactured by Wakeg Nick ев (.).

- 14 010638

Κ, ΟνΕΝΕ 4823B A copolymer of styrene and butadiene manufactured by MaPagb Sgeek. Κ, ΟνΕΝΕ 6140 A copolymer of styrene and butadiene manufactured by MaPagb Sgeek. ΚΟνΕΝΕ 9410 A styrene-butadiene copolymer manufactured by MaPagy Szheek. 8A Short for sodium aluminate. EVERYTHING 97982 Carboxylated acrylic copolymer manufactured by KeiYuu. OPERATION CP8 401 Carboxylated acrylic copolymer manufactured by K.е1сЫю1 <1. TUSNEM 68710 Carboxylated styrene-butadiene copolymer manufactured by Kekuyu. TUIAS 68219 A carboxylated copolymer of styrene and butadiene manufactured by Ke1cYu1c1. TUYAS SRZ 812 Carboxylated copolymer of styrene and butadiene manufactured by NEGSVCOI. USHAS XX-211 A copolymer of vinyl acetate and ethylene manufactured by Ai Rgoisi18. Р-REX Biopolymer manufactured by Wakeg N. and §11ez ΙΝΤΕφ. CLAIM

1. A method of slowing down the filtration of a drilling fluid through a wall of a wellbore while drilling a well in a rock stratum, including a depleted sand formation, using a water-based drilling fluid, the method comprising introducing plugging material into the drilling fluid and pumping the drilling fluid with plugging material into contact with the wall of the wellbore in the area of the depleted sand formation, characterized in that mainly polymer latex with an average hour size is used as a plugging material less than 1 μm, which is injected into the drilling fluid without a precipitating reagent, and at least in a section of rock strata, including a depleted sand formation, the clogging material forms a deformable insulating latex film that reduces formation pressure over time.

Claims (9)

1. A method of slowing down the filtration of a drilling fluid through a wall of a wellbore while drilling a well in a rock stratum, including a depleted sand formation, using a water-based drilling fluid, the method comprising introducing plugging material into the drilling fluid and pumping the drilling fluid with plugging material into contact with the wall of the wellbore in the area of the depleted sand formation, characterized in that mainly polymer latex with an average hour size is used as a plugging material less than 1 μm, which is injected into the drilling fluid without a precipitating reagent, and at least in a section of rock strata, including a depleted sand formation, the clogging material forms a deformable insulating latex film that reduces formation pressure over time.
2. The method according to claim 1, characterized in that as a polymer latex use a copolymer of styrene and butadiene.
3. The method according to claim 1 or 2, characterized in that use clogging material, essentially not containing a surfactant.
4. The method according to any one of claims 1 to 3, characterized in that carboxylated copolymers of styrene and butadiene are used as polymer latex.
5. The method according to any one of claims 1 to 3, characterized in that sulfonated copolymers of styrene and butadiene are used as polymer latex.
6. The method according to claim 4 or 5, characterized in that the plugging material is introduced in an amount sufficient to obtain a water-based drilling fluid with a styrene-butadiene copolymer content of from about 0.1 to 10 vol.%.
7. The method according to any one of claims 1 to 5, characterized in that the plugging material is introduced into the water-based drilling fluid containing salt.
8. The method according to any one of claims 1 to 5, characterized in that the plugging material is introduced into the water-based drilling fluid containing saturated brine.
9. The method according to any one of claims 1, 4 and 5, characterized in that it further uses a plugging material consisting essentially of a surfactant selected from the group consisting of betaines, alkali metal alkylene acetate, sultaines, simple carboxylates esters and mixtures thereof, the surfactant comprising from about 0.005 to 2% of the total volume of water-based drilling mud.
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US10457848B2 (en) 2010-08-17 2019-10-29 Schlumberger Technology Corporation Self-repairing cements
RU2613709C2 (en) * 2015-06-11 2017-03-21 Федеральное государственное бюджетное образовательное учреждение высшего профессионального образования "Ухтинский государственный технический университет" Drill fluid processing method

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