NL7906114A - METHOD FOR FORMING VERTICAL LINEAR BREAKS IN AN UNDERGROUND FORMATION. - Google Patents

Description

-1- 208Ó4 / CV / jb • Applicant: William Perlman, Houston, Texas, United States of America.

Short designation: Method for forming vertical linear fractions in an underground formation.

The invention relates to hydraulic fracturing of earth formations and more particularly to hydraulic fracturing of hydrocarbon-containing formations, ie oil and gas-containing sand layers and the like, with a view to increasing the production value and total amount of hydrocarbons to be recovered from a well disposed in such a formation.

Hydraulic fracturing techniques for hydrocarbon containing formations are well known and have been widely used to enhance the recovery of oil and gas from hydrocarbon containing formations. These techniques include. injecting a fracturing fluid down the well bore in contact with the fractions to be fractured. Sufficiently high pressure is applied to the fracturing fluid to initiate and continue a fracture in the formation. Support materials are generally entrained in the fracturing fluid and deposited in the fracture to keep the fracture open during production. The function of fracturing is to overcome the lack of permeability of the formation near the well bore "by creating a highly conductive path extending" into the producing formation consisting of sand and / or rock, that the well bore surrounds.

In accordance with conventional practice, a fluid such as water, oil, an oil-water emulsion, gelled water or oiled oil is pumped down into a well bore with sufficient pressure to open a fracture in the formation. The fracturing fluid may entrain a suitable support means such as sand, glass beads, etc. with a view to keeping the fracture open after the fracturing fluid has been recovered, ie permitting flow of the well. wells, ie wells under a millidarcy permeability, the known 30 'fracture forming methods have produced results which are only temporary in terms of increasing the flow rate. After perhaps a short period of accelerated flow, production speeds may drop to near the original value. Repeated stimulation with the same or a similar procedure can only yield a temporary gain again.

• 79 0 6 1 1 4 jtk -2- 20804 / CV / jb •. One reason for such a defective result in a low permeability formation is that: at the depths encountered, most formations have a vertical preferred fracture, orientation that exists due to naturally occurring weak planes in the formation when the fracture is formed, and continue along these weak areas. These vertical fractures have been found to be particularly advantageous in formations with a relatively wide economically productive zone and a permeability of the order of 10-20 milidarlys.

Unfortunately, many geological oil and gas containing formations, including some formations in W-Texas, which are at least primarily gas formations, include multiple vertically spaced narrow productive zones, ie, 10-30 foot productive zone formations each Generally separated by a clay-shale layer, the productive zones are sandstone formed and have very low permeability of the order of 10-0.10 milidarcy or less. To further complicate, the productive zones contain impurities, such as water-sensitive clay and iron, which undesirably react with acids commonly used to treat the formations.

Vertical fractures, as described above, often occur using a conventional fracturing process. In a gas well of the above-described multiple production zones, this results in radial vertical fractures which extend between the production zones and due to the intermediate zones of clay shale. As a result, fracturing fluid is lost in the zones of clay shale with none of them. resulting utility for breaking the hydrocarbon producing zones.

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Furthermore, only small vertically oriented vertical orientations are formed in the producing zones and, due to the deep vertical orientation, not much radial horizontal penetration is allowed in the producing zones themselves. A temporary increase in production produced in the fracture is likely the result of the fracture which allows connection between 30.

the well bore in a small portion of a common system between the matrix elements of the formation and with a small portion of the reservoir matrix. However, once this low volume space is drained, the productivity drops to that controlled by the low permeability reservoir matrix and since the formation surface exposed to such matrix 35 by the short radial vertical fractures is small, the productivity is low.

7906114 <c -3- 20804 / CV / jb. The object of the invention is to overcome the drawbacks of the prior art by providing a method of fracturing the producing formation for producing long vertical linear fractures which extend outwardly from a borehole within the zone of interest with minimal radically vertically oriented fractures and which occur above and below the zone of interest. producing zones.

The present invention relates to a method of forming long vertical linear fractures extending from the borehole outwardly into a production zone with minimal radial vertical fractures minimizing penetration into the intervening clay. shale layers.

The method involves several fracture phases in which a fine sand backing between the 60-140 mesh size (average 100 mesh) in a high sand to fluid ratio mixture but that is - 4 lbs / gallon or higher is included. each carrier phase is immediately followed by a corresponding spacer formation phase in which the fracturing fluid is utilized without an added support. Immediately following the last support phase and corresponding spacing phase, a final phase is performed in which an average backing sand of 20-40 mesh size is injected followed by a breaking fluid rinse of the pipe string.

A Furthermore, the fracturing fluid can be made up to 70 volume percent from alcohol to reduce the water volume of the fracturing fluid * which can adversely interact with water-sensitive clays in the formation. Furthermore, 20 weight percent liquefied co (carbon dioxide) can be combined with the water / alcohol mixture of the fracturing fluid to further reduce the water volume for the above reason in addition to the "wet" to reduce liquid injected into the formation.

As noted above, most formations have a preferred vertical fracture orientation along naturally occurring weak surfaces. As a result, it is generally expected that vertical fracturing in the formation will occur. Although a "fracture" will generally have "a vertical" orientation, the planar angle of the propagating fracture can vary widely in the formation, and the planes of the formation vary weakness. A fraction can collect 3 ^ s. an at least substantially vertical fracture and end as one. at least essentially - horizontal fracture, 79 0 6 1 1 4 a -4- 20804 / CV / jb • or start as a horizontal "pancake" fracture and dive or rotate to a more vertical orientation at a further radial distance from the borehole Accordingly, in the present specification, the term "vertical", when referring to vertical sign, will include all other possible fracture orientations in addition to the preferred vertical orientation.

It is a feature of the present invention to provide a method for producing long vertical linear fractures in relatively thin hydrocarbon formations while significantly radial vertical fractures in the above and below clay shale layers or other producing formations are avoided.

It is a further feature of the present invention to obtain a fracturing flux which contains a minimal water content which will disadvantageously interact with water sensitive clays contained in the productive formations.

It is a still further feature of the present invention to provide a method for creating vertical linear fractions within a thin producing formation which are considerably wider than those produced by known methods thereby creating a significantly larger vertical area of the formation exposed.

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It is yet a further feature of the present invention to provide a method of inserting several times the amount of solids into the formation for use as "support" agents than hitherto injected using conventional crushing techniques.

These and other features and advantages of the invention will become further apparent from the description below! accompanied by the accompanying drawings.

In order that the manner in which the above-mentioned advantages and features of the inventions can be obtained can be understood in detail and a more detailed description of the invention can be obtained with reference to a particular exemplary embodiment thereof in comparison with an exemplary embodiment. the prior art are both shown in the drawings forming part of the application. It should be noted, however, that the accompanying drawings show only a typical exemplary embodiment of the invention and should not be

79 0 6 1 H

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-5- 20804 / CV / jb fc • considered as limiting the scope of protection.

Figure 1 shows a cross section of an oil or gas containing formation penetrating borehole for introducing a fracturing fluid into contact with the formation and more particularly shows the radial vertical fracture orientation of multiple productive zones and non-producing formations therebetween as a result of conventional breaking techniques.

Figure 2 shows a cross section through a borehole extending into a multi-hydrogen producing zones containing formation, and shows the long vertical linear fractures generated using the present invention.

Figure 3 shows a cross-section through a vertical linear fracture in the productive zone depicted in Figure 2, seen along line 3-3 in Figure 2.

Figure 4 shows a vertical cross section through a conventional radial vertical fracture produced using known methods, taken along the line 4-4 in Figure 1.

The time required for a pressure disturbance, ie a pressure drop initiated by a producing source, to be propagated from the wellbore through a low permeability earth formation may include a period of 20 years for tapping the 14, 6-acre area reached by the shock wave front. Further expansion will demonstrate that it will take the compression wave 21.5 years to reach the perimeter of a 320-acre square relative to the well bore while the volume extends horizontally. about such an area will be tapped in 430 years. The printing plot will take 34 years in the case of 640-acre area (1 square mile), which would be drained in 680 years.

From the above it will be clear that in order to exploit a low permeability field within a period of 20 to 30 years, the distance between the wells must be approximately 900 feet. However, many states have legal regulations regarding well densities in oil and gas fields. It will be appreciated that it will be impractical to exploit a well economically in such a low permeability formation without special production techniques.

To accelerate the recovery of hydrocarbons from such 79 0 6 1 1 4 Λ -6- 20804 / CV / jb, / · * low permeability fields, techniques have been developed to generate radial fractures in the formation which fractures work as drains to allow the fluid to be recovered to flow to the well. Generally, a large volume of fracture fluid, on the order of 5000 or more gallons per phase, is pumped into the formation at a high feed rate in the range of 25 to 50 barrels per minute.

In addition, various support agents have been used to hold the formed fractures in an open position after releasing the fracture pressure. For purposes of establishing terms in the present specification, a reference to an "average" size support means is meant to mean a mesh size support means falling within the range of 20 to 40. Further, a reference to " fine "size of the support means means a support means with a mesh size falling within the range of 60-140. The above descriptions should not be construed as limitations of the invention as other support means dimensions may be equally effective in realizing the objects of the invention. Among such support means used in the prior art is "medium" sand (20-40 mesh), which is preferably used instead of * "fine" sand (60-140 mesh), since the fine sand is assumed will pack too tightly and in fact cause the fracture support agent volume to have a permeability lower than that of the formation. In general, a low ratio of the proppant to the fracturing fluid (such as 1/2 - 21bs sand per gallon of fluid) was used.

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When used with a single. comparatively thick producing zone having a medium permeability, the usual crushing techniques developed in the prior art have proven suitable. However, if the conventional fracturing techniques are used to fracture relatively permeability relatively thin formations, such as e.g. found in various gas-sand areas in W-Texas, the resulting production is considerably less than expected, as will be described below.

As shown in Figure 1, conventional hydraulic crushing techniques utilize a well equipped with a jacket 35 7906114 -7- 20804 / CV / jb • 12, which extends through a coating 14 in multiple gas-sand-producing zone areas where the productive zones 16 are separated by layers containing no oil or gas, such as clay shale layers 18.

A plurality of perforations 20 are generally formed in the jacket 12 extending in the producing zones 16. further, a pump 22, which is connected via a pipeline 24 to a source of sand and fracturing fluid mixture 26, pumps the fracturing fluid mixture into the jacket 12 through the tube 28, where, if a pressure builds up in the jacket 12, the fluid is forced out through the perforations 20 into the producing formations, thereby forming fractures 30. As a result of 10 dg high feed rate, the pressure builds up rapidly causing the radial vertical fractures 30 to extend into the producing zones through the non-producing formations 18 therebetween. As a result, a large amount of the fracturing fluid and sand is applied in fractures in areas and layers where there is no oil or gas. Furthermore, the vertically extending fracture formation in upper and lower formations tends to limit the radial length of the vertical fractures to an average length "X". As a result, the short radial vertical fractures in the producing formation only expose a limited surface of the formation 16, resulting in production for only a relatively short period of time and further production must depend on the slow natural drainage through / low permeability formation in the fracture and then to the well bore.

According to the present invention, long vertical linear fractions extending outwardly from the well casing and in a desired producing formation with substantially no vertical fractures extending in the above or below non-producing fractions are obtained as described below. will be described.

In Figure 2, the same reference numerals as in Figure 1 have been used to designate the corresponding parts. Accordingly, in Figure 2, a well 10 is provided which is provided with a jacket 12 which extends into the top layer 14 in a plurality of gas-sand-containing producing zones 16, which are separated from each other by clay-shale layers 18 located between them. pump 22 is connected to a source of sand and fracturing fluid mixture 26 using a tube 24 and pumps it 7906114

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20804 / CV / jb support means containing fracturing fluid in the tube not shown inside the jacket 12 through the pipeline 28. Conventional techniques are employed for perforating the jacket 12 near a single producing zone 16, as shown by perforations 20,

Thereafter, the perforated section of the jacket is insulated so that if fracturing fluid is injected it affects only this single producing zone. A relatively low volume of breaking fluid (2000-5000 gallons per phase) with a high ratio of solids (in this case sand), such as 4-10 lbs (or more) of sand per gallon of breaking fluid, is injected into the single producing zone 16. A low feed rate (such as 9-15 barrels per minute) is used, resulting in the possibility of using a 2 ~ 3 inch tube to inject the fracturing fluid as opposed to significantly larger casing, which should be used with conventional crushing methods due to the high feed rates. Furthermore, the pressure required to break the formation is limited to the tube and jacket near the formation, thereby reducing the surface area on which the pressure is to be maintained.

As will be described below, multiple phases of support-loaded fracturing fluids are alternated with corresponding 2® unloaded fracturing fluid phases injected thereby effecting vertically oriented fractures 50 extending linearly along a length "Y" with little or no vertical or radial fracture occurring outside the treated productive zones 16. The enlarged surface area of the formation 16 exposed to the longer fracture 50 significantly increases your production. Furthermore, by limiting the fracture to a single form, an increased useful effect of production from this producing zone is obtained without simultaneously attracting from other zones. Once a lower formation 16 has been exhausted, the mantle 12 will be closed to close this formation and a higher formation will be treated and put into production as described above.

As described above, known fracture process and applied to such thin multi-producing zones 16 formations only form fractions 30 with a radial length of "X" and a "supported" width b "35 ...

(Figure 4) of 0.10 inch or less, often in the range of 0.0625 inches 7906114 "-9-20804 / CV / jb * using an" average "support means 35. Using the method of the present invention, a fraction 50 of length "Y" (compared to "X") can be obtained with a "supported" width "A" (see Figure 3) of about 0.25 inches using a "fine" support means 37. As described above, as the linear fracture 50 can be lengthened, the vertical cross-sectional area of the producing zone 16 exposed to the fracture 50 will be required to form a low pressure channel to the jacket 12, thereby the productivity of the producing zone is increased As will be apparent from Figures 1 and 2, a given cross-sectional area of the formations 16 is exposed to fractures 30 and 50 The fracture 50 can often be 2-50 notches the length of the fracture 30 , making the total vertical The cross-sectional area exposed by the fracture is increased by at least 200-500% with corresponding increase in productivity. In a test well, where (1 million pounds) of a backing medium (fine) sand was introduced into a formation fracture using the method of the present invention, investigations indicate probable linear fracture above 2000 feet and entirely within the gas formation.

The method of the present invention can be carried out by any conventional device used for hitherto known hydraulic fracturing methods. Such suitable equipment is shown in both Figure 1 and Figure 2. The fracturing fluid may be injected through the well casing, tube or other suitable conduit and may be returned to a well or fluid reservoir for the fracturing fluid. The fluid can be injected through perforations in the shell extending through the cement and directly into the formation, limiting the injection to a selected horizontal thin formation using conventional isolation techniques.

Additionally, conventional mixing equipment and pumping equipment for the mixture of proppant and liquid can be used to perform the process.

The preferred breaking fluid used in the practice of the process of the invention is a 2-3% KCL (barium-Chloride) water containing conventional gels to increase its viscosity and is mixed with liquid carbon. dioxideC (X ^) in certain proportions preselected from the range of 10% - 20% CO ^

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j <1 * - · 4 ΐ -10 -20804 / CV / jb in volume. The CCl is held at -10U F until it is combined with the KCL water in the mixer 26 just before the fracturing fluid is pumped into the well 12. During injection, the CC ^ remains liquid since it is pressurized and only after the temperature reaches 85 ° F at the rupture pressures in the formation, the C0 is “over C ^, in the gaseous form. This change in gas has two advantages. advantage is the additional energy (if CCl becomes gas), which assists in removing fracture water from the wellbore. A second advantage is the reduction of "moist" fluid injected into the formation, which must be recovered.

Since many of the producing formations found in the multi-producing regions of W-Texas include water-sensitive clays, it is advantageous to keep the amount of water injected into the formation small. In addition to the conventional reduction of water by the above addition of the 02 02, water used in the crushing fluid can be further reduced by the addition of a suitable alcohol in predetermined proportions of up to 70% alcohol by volume of the total fracture fluid. A suitable alcohol for use in the method of the invention can be described as any alcohol which will reduce the surface tension of the residual water to promote pumping of the fracturing fluid and, equally importantly, is miscible with water. . For example, 57,000 Gallons of the preferred fracturing fluid can be made using 13,680 gallons of sand, 11,400 gallons of liquefied CO2, {8880 gallons of H90 and 23,040 gallons of methanol or 25 liters of iso-prophyl or other suitable alcohol. Furthermore, the use of fracturing fluid combined with alcohol and CO2 in the above ratios has resulted in the recovery of injected fluids of the order of 80-95%.

The injection time depends on the volume of fracturing fluid, which is 30.

must be injected, which is determined by how large a fraction is desired and calculated in advance, and the flow value which depends on the pressure and flow resistance. Furthermore, the total injection time will be the sum of the injection times for the different multiple stages.

The following is an example of an experimental well stimulation treatment conducted in accordance with the invention in a W-Texas gas field: sti-7906114 _n_ 20804 / CV / jb *:

EXAMPLE

^ Formation thickness 28 '

Depth: 7082 'to 7110'

Materials: 3% KCL water and 20 volume? , and provided with a base t 10 fluid gel with a density of 40 Wgal · gelling agent

Support agent: sand, average 100 mesh, 488,600 lbs. and 20/40 mesh 15 51,000 lbs.

jacket: 4-1 / 2 "O.D.

Tube: 2-7 / 8 "O.D.

20

Perforations: 22

Pressure on jacket 1500 lbs on average.

25 on tube 5500 lbs on average.

Used hydraulic horsepower: 2022

Average speed in barrels per minute: 15 30

Number of phases: 40

Volumes:

Pre PAD 10,000 gal.

35 PAD 7,000 gal.

Support medium containing fluid 66,000 gal.

7Ü ft 1 1 A Displacement 1,000 gal.

7 «U Ö I 4 Xotal fluid 84,000 -12-20804 / CV / jb

Event Speed- Volume Pressure (psi) Description of operation

No. barrel per min. (incremental '(Tube) (jacket) and materials.

Volume) 5 2 0-15 7000 0-5000 1500? omp leus sen® 3 15 3000 5200 1500 Start sand 4 ppg 4 15 500 5400 1500 Pump spacer 5 16 3000 5100 1500 Start sand at 6 ppg 6 10 500 5400 1500 Pump spacer 7 16 3000 5200 1500 Start sand at 8 ppg 10 g 500 * 5200 1500 Pump spacer 9: 15 3000 5200 1500 Start sand at 8 ppg 10 15 1000 5300 1500 Pump spacer 11 15 3000 5200 1500 ^ Start sand at 10 ppg 12 15 500 5400 1500 Pump. spacer 13 15 3000 "5200 1500 S £ aft sand" at fü ppg 14 15 500 5200 1500 PomP spacer

15 15 15 3000 5300 1500 Start sand at i0 PPS

16 15 500 5300 1500 Pump spacer

17 15 3000 5500 1500 Start sand at 10 PPS

18 15 500 5500 1500 Pump spacer 19 13 3000 5500 1500 Start sand at 10 PP8 20 13 500 6400 1500 'Pump spacer 21 13 3000 5400 1500 Start sand at 10 ppg 20 22 13' 500 6400 1500 Pump spacer 23 13-15 3000 6400 1500 Start sand at 10 ppg 24 15 500 5100 1500 Pump spacer 25 15 3000 5600 1500 Start sand at 10 ppg 26 15 500 5400 1500 Pump spacer 27 15 3000 5100 1500 Start sand at 10 ppg 28 15 500 5200 1500 Pump spacer 29 15 3000 5400 1500 Start sand at 10 ppg 23 3q 14 5Ö0 5700 1500 Pump spacer 31 14 3000 5700 1500 Start sand at 10 ppg 32 14 500 6400 1500 Pump spacer 33 13 500 6300 1500 Start sand at 10 ppg 34 14 500 6100 1500 Pump spacer 35 14 3000 5700 1500 Start sand at 10 ppg 36 14 500 5500 1500 Pump spacer 30 37 14 3000 '5500 1500 Sand sand' At ïö ppg 38 15 1000 5500 1500 Pump spacer

39 12000 5500 1500 20-40 sand bii 3 PPS

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The 488,600 lbs. on average, 100 mesh sand was injected at a rate of 10 lbs./gal, while the larger 20-40 mesh sand was injected at 3 lbs./gal.

79 0 6 1 1 4 -13- 20804 / CV / jb • In a conventional crushing treatment, it has been found desirable to use at least an 81b./gax solid component ratio of the "fine" support, referred to above as 60-140 knife ^ to maintain fracturing fluid. A solid particle ratio of 12 / lbs. / Gal has been achieved, but with re-mixing equipment, solid particle ratios of 15-20 lbs / gai should be possible. Of course, a support of any suitable size can be used if the objects of the invention are achieved. The final support applications were made using an "average" mesh zarid (20-40), but other dimensions of the final support may be used.

The preferred injection rate is in the range of 10-15 barrels per minute, however, a range of 2-15 barrels per minute has been used to obtain satisfactory results and rates of 25 barrels per minute or less can produce good results. depending on the geology of the production zone.

In field trials, the volume of support agent injected into the producing formation has varied from 200,000 lbs. up to 1,000,000 lbs. of a proppant in a single producing zone using fracturing fluid volumes from about 50,000 to 20 gallons, respectively. 200,000 gallons for total average solids ratios of 7 to 8 lbs / gal. Successful practice of the invention has shown that a ratio of at least 25,000 lbs. support per foot of net production zone is desired and can be achieved.

Although specific embodiments have been described and described above, it will be appreciated that the present invention is not limited thereto and many variations and additions are possible within the spirit and scope of the invention.

7906111

Claims (20)

Method according to claim 1, characterized in that a final phase of the breaking fluid carries an average support material in a support to fluid ratio less than the finely measured support material to fluid ratio and is introduced into the fractures before precipitation medium sized support means material in the formation near the well bore. 25 3. Method according to claim 1 or 2, characterized in that the fine-sized support material is formed from 60-140 mesh sand. Method according to any one of the preceding claims, characterized in that the medium-sized support material is formed by sand 20-90 mesh. - 7906114 35 λ, -15- 20804 / CV / jb. A method according to any one of the preceding claims, characterized in that the fracturing fluid is a combination of KCL water gel and alcohol and the volume of alcohol combined with the KCL water to form: - the total volume of the fracturing fluid preselected in the range of 25 volume% - 70 volume% alcohol. 5 A method according to any one of the preceding claims, characterized in that the breaking fluid injection rate is selected within the range of 2-20 barrels per minute. A method according to any one of the preceding claims, characterized in that the ratio of the finely measured support material to the fluid is selected in the range of 8-20 support material per gallon of stretch fluid. 8. A method according to any one of the preceding claims, characterized in that the breaking fluid is a combination of KCL water, gel, alcohol and liquefied CO2. 9. A method according to claim 8, characterized in that the volume alcohol with the KCL water to form the total volume of the fracturing fluid is preselected in the range of 25 volume% -70 volume% alcohol and the volume of CO2 combined with the KCL water to form the total volume of fracturing fluid is preselected in the range of 10 volume% - 20 volume% liquefied CO2 · 25 Method according to claim 9, characterized in that the injection phase of the carrier phase is selected within the range of 2-20 barrels per minute. A method according to any one of the preceding claims, characterized in that the ratio of the finely sized support material to the fluid is selected in the range of 8-20 pounds of support per gallon of breaking fluid. 12. A method of forming vertical linear fractures in an underground producing formation extending outwardly from a formation-penetrating well without forming any significant radial vertical fractures from above or below 7. Q β 1 1 i A -16- 20804 / CV / jb / layers, characterized in that: a number of carrier phases of the breaking fluid are introduced, the breaking fluid carrying a finely sized support material in an average support to fluid ratio of at least 8 pounds per gallon at which this carrier phase fracturing fluid is injected at an injection rate of less than 25 barrels per minute and selected at a pressure to produce the fractures in the formation, introducing a number of intermediate phases of the breaking fluid alternating with the carrier phases at a selected pressure and velocity sufficient to carry the support material of the support phase in the fracture and facing away from the well, and applying an end phase of the breaking fluid containing a support material of average size entrains in a ratio of 2 ^ support to fluid less than the carrier phase ratio, the end phase being injected with a selected pressure and sn sufficient to bring the support material end-phase material into the fractures near the injection well bore. The method according to claim 12, characterized in that the finely sized support material is sand of 60-140 mesh. Method according to claim 12 or 13, characterized in that the support means is medium-sized sand material of 20-40 mesh · A method according to any one of the preceding claims 12-14, characterized in that the breaking fluid is a combination of KCL water, gel and alcohol, and the volume of alcohol combined with KCL water 30 to form the total volume of breaking fluid beforehand was selected from the range of 25 volume% - 70 volume% alcohol. 16. Method according to any one of the preceding claims 12-15, characterized in that the injection phase for the carrying phase is selected in the range of 2-20 barrels per minute. 79 0 6 1 1 4 -17- 20804 / CV / jb. A method according to any one of claims 12-16, characterized in that in the support phase the ratio of support agent to fluid is selected in the range of 8-20 pounds support agent per gallon of crushing fluid. 5 18. A method according to any one of the preceding claims 12-17, characterized in that the introduction of the support phase is continued to obtain a support volume of at least 25 pounds of the finely sized support material deposited in the fracture formation for each single foot of vertical net production zone of the formation. A method according to any one of the preceding claims 12-18, characterized in that the fracturing fluid is a combination of KCL water, gel, alcohol and liquefied CO2 20. Method according to claim 19, characterized in that the volume of alcohol combined with the KCL water to form the total volume of the breaking fluid is preselected in the range of 25 volume% - 70 volume% alcohol and the volume of CO2 combined with the KCL water to form the total volume of fracturing fluid is preselected within the range of 10 volume% - 20 volume% liquefied CO2 The method according to claim 20, characterized in that the injection phase of the carrier phase is selected in the range of 2-20 barrels per minute. 22. A method according to claim 20, characterized in that the ratio of support agent to fluid in the. bearing phase is selected in the range of 8-20 pounds of support medium per gallon of breaking fluid. 23. A method according to claim 22, characterized in that the introduction of the support phases is continued to obtain a support volume of 25,000 pounds 3 of the fine-sized support medium material deposited in the fracture formation for every single foot of vertical net production. zone of the formation. 7906114