EA004100B1 - Method and apparatus for stimulation of multiple formation intervals - Google Patents

Abstract

1. A method for perforating and treating multiple intervals of one or more subterranean formations intersected by a wellbore, said method comprising: (a) deploying a bottom-hole assembly (BHA) from a tubing string within said wellbore, said BHA having a perforating device and a sealing mechanism; (b) installing BHA using deploying means in said position within a wellbore using depth control device; (c) using said perforating device to perforate said interval; (d) activating said sealing mechanism so as to establish a hydraulic seal in said wellbore; (e) pumping a treating fluid in said wellbore and into the perforations created by said perforating device, without removing said perforating device from said wellbore; (f) releasing said sealing mechanism; and (g)repeating steps (b) through (e) for at least one additional interval of said one or more subterranean formations. 2. The method of Claim 1 wherein said deployment means is selected from the group consisting of a wireline, a slickline, and a cable. 3. The method of Claim 1 wherein said deployment means is a tubing string. 4. A method for perforating and treating multiple intervals of one ox more subterranean formations intersected by a wellbore, said method comprising: (a) deploying a bottom-hole assembly (BHA) using a deployment means selected from the group consisting of a wireline, a slickline and a cable within said wellbore, said BHA having a perforating device and a sealing mechanism; (b) using said perforating device to perforate said interval; (c) actuating said sealing mechanism so as to establish a hydraulic seal in said wellbore; (d) pumping a treating fluid in said wellbore and into the perforations created by said perforating device, without removing said perforating device from said wellbore; (e) releasing said sealing mechanism, and (f) repeating steps (b) through (e) for at least one additional interval of said one or more subterranean formations. 5. The method of Claim 3 wherein said tubing string is selected from the group consisting of coiled tubing and jointed tubing. 6. The method of Claim 3 wherein said BHA is positioned within said wellbore using a depth-control device selected from the group consisting of a casing collar locator and a surface measurement system. 7. The method of Claim 1 or 4 wherein said perforating device is a select-fire perforating gun containing multiple sets of one or more shaped-charge perforating charges; each of said sets of one or more shaped-charge perforating charges individually controlled and activated by electric or optic signal transmitted via a cable deployed in the wellbore. 8. The method of Claim 3 wherein said perforating device is a jet cutting device that uses fluid pumped down said tubing string to establishing hydraulic communication between said wellbore and said one or more intervals of said one or more subterranean formations. 9. The method of Claim 3 wherein treating fluid is pumped down the annulus between said tubing string and said wellbore. 10. The method of Claim 9 wherein treating fluid is also pumped down said tubing string, through flow ports in said BHA, and into said perforations. 11. The method of Claim 9 wherein a second treating fluid is pumped down said tubing string, through flow ports is said BHA, and into said perforations. 12. The method of Claim 11 wherein second treating fluid is nitrogen. 13. The method of Claim 1 or 4 wherein sealing mechanism, is a resettable packer. 14. The method of Claim 1or 4 wherein treating fluid is selected from the group consisting of an acid solution, an organic solvent, and a slurry of a proppant material and of a carrier fluid. 15. The method of Claim 1 or 4 wherein said method further comprises the step of, prior to releasing said sealing mechanism, deploying at least one diversion agent in said wellbore to block further flow of treating fluid into said perforations. 16. The method of Claim 16 wherein said diversion agent deployed in said wellbore is selected from the group consisting of particulates, gels, viscous fluids, foams, and ball sealers. 17. The method of Claim 1 or 4 wherein sealing mechanism is actuated by hydraulic pressure transmitted from the surface through an umbilical. 18. The method of Claim 1 or 4 wherein perforating device is actuated by hydraulic pressure transmitted from the surface through an umbilical. 19. The method of Claim 1 or 4 wherein perforating device is actuated by hydraulic pressure transmitted from the surface through s wellbore. 20. The method of Claim 3 wherein perforating device is actuated by hydraulic pressure transmitted from the surface through said tubing string. 21. The method of Claim 1 or 4 wherein BHA its repositioned within said wellbore before activating said sealing mechanism. 22. A stimulation treatment system for use in perforating and treating multiple intervals of one or more subterranean formations intersected by a wellbore, said system comprising; (a) a treating fluid; (b) a deployment means selected from the group consisting of a wireline, a slickline and a cable deployed within said wellbore; (c) a bottom-hole assembly (BHA) adapted to be deployed in said wellbore with said deployment means, said BHA having at least one conventional perforating device, for sequentially perforating said multiple intervals, and at least one sealing mechanism, said BHA capable of being positioned within said wellbore, to allow actuation of said perforating device and said sealing mechanism; (d) said sealing mechanism capable of establishing a hydraulic seal in said wellbore, and further capable of releasing said hydraulic seal to allow said BHA to move to a different position within said wellbore, thereby allowing each of said multiple treatment intervals to be treated with said treating fluid separately from said other treatment intervals. 23. A stimulation treatment system for use in perforating and treating multiple intervals of one or more subterranean formations intersected by a wellbore, said system comprising; (a) a treating fluid; (b) a deployment means deployed within said wellbore; (c) a bottom-hole assembly (BHA) adapted to be deployed in said wellbore with said deployment means, said BHA having at least one conventional perforating device, for sequentially perforating said multiple intervals, and at least one sealing mechanism, said BHA capable of being positioned within said wellbore using a depth control device, to allow actuation of said perforating device and said sealing mechanism; (d) said sealing mechanism capable of establishing a hydraulic seal in said wellbore, and further capable of releasing said hydraulic seal to allow said BHA to move to a different position within said wellbore, thereby allowing each of said multiple treatment intervals to be treated with said treating fluid separately from said other treatment intervals. 24. An apparatus for use in perforating and treating multiple intervals of one or more subterranean formations intersected by a wellbore, said apparatus comprising: (a) a bottom-hole assembly (BHA), adapted to be deployed in said wellbore by a deployment means, said BHA having at least one conventional perforating device for sequentially perforating said multiple intervals and at least one sealing mechanism; and (b) said sealing mechanism capable of establishing a hydraulic seal in said wellbore, and further capable of releasing said hydraulic seal to allow said BHA to move to a different position within said wellbore, thereby allowing each of said multiple treatment intervals to be treated separately from said other treatment intervals. 25. An apparatus for use in perforating and treating multiple intervals of one or more subterranean formations intersected by a wellbore, said apparatus comprising: (a) a bottom-hole assembly (BHA), adapted to be deployed in said wellbore by a deployment means selected from the group consisting of a wireline, a slickline and a cable, said BHA having at least one perforating device for sequentially perforating said multiple intervals and at least one sealing mechanism; and (b) said sealing mechanism capable of establishing a hydraulic seal in said wellbore, and further capable of releasing said hydraulic seal to allow said BHA to move to a different position within said wellbore, thereby allowing each of said multiple treatment intervals to be treated separately from said other treatment intervals. 26. An apparatus for use in perforating and treating multiple intervals of one or move subterranean formations intersected by a wellbore, said apparatus comprising: (a) a bottom-hole assembly (BHA), having at least one perforating device for sequentially perforating said multiple intervals and at least one sealing mechanism; (b) tractor device being adapted to move BHA on different positions in wellbore; (c) said sealing mechanism capable of establishing a hydraulic seal in sand wellbore, and further capable of releasing said hydraulic seal to allow said BHA to move to a different position within said wellbore, thereby allowing each of said multiple treatment intervals to be treated separately from said other treatment intervals. 27. The apparatus of Claim 25 wherein said deployment means is tubing string. 28. The apparatus of Claim 27 wherein said tubing string is selected from the group consisting of coiled tubing and jointed tubing. 29. The apparatus of Claim 5 wherein said deployment means is selected from the group consisting of a wireline, a slickline, anal a cable. 30. The apparatus of Claim 24-26 further comprising depth-control means for positioning said BHA in said wellbore selected from the group consisting of a casing collar locator and a surface measurement system. 31. The apparatus of Claim 24-26 wherein said sealing mechanism is a resettable packer. 32. The apparatus of Claims 24-26 wherein said perforating device is a select-fire perforating gun containing multiple sets of one or more shaped-charge perforating ch

Description

Field of Invention

The present invention relates to the field of perforation and technological processing (preparation) of underground geological formations to increase the production of oil and gas from them. More specifically, the present invention relates to a device and method for perforating and processing a plurality of intervals without having to remove equipment from the wellbore between operations of the method.

BACKGROUND OF THE INVENTION

In the event that the hydrocarbon containing underground production reservoir does not have sufficient permeability or throughput to allow hydrocarbons to flow to the surface in economically advantageous quantities or at optimal speeds, hydraulic fracturing or chemical (usually acidic) stimulation (excitation) is often used to increase throughput. ) A wellbore extending into an underground formation typically comprises a metal pipe (casing) cemented into the original borehole. Holes (perforations) pass through the casing and cement coating surrounding the casing to pass a hydrocarbon stream into the wellbore and, if necessary, to pass a fluid flow to process the formation from the wellbore into the formation.

Hydraulic fracturing of a formation involves the injection (injection) of fluids (usually a viscous means of thinning a slice, non-Newtonian gels or emulsions) into a formation, at such high pressures and speeds that the formation rock cracks and forms a flat, usually vertical, crack (or a network of cracks) , in many ways similar to a crack that develops in a log when a wedge is inserted into it. Granular proppants, such as sand, ceramic balls, or other materials, are typically pumped with the last portion of the fracturing fluid to hold the crack (s) open after pressure has been reduced. The increased throughput from the reservoir is the result of facilitating the path of fluid between the grains of proppant in the crack (s). In chemical treatments for intensification, throughput is improved by dissolving materials in the formation or by otherwise changing the properties of the formation.

The use of hydraulic fracturing in accordance with the above is a common part of oil production operations, which are used for individually defined zones with dimensions of up to about 60 m (200 ft) of the underground formation of large vertical thickness. In the case where a plurality of collectors, a layered collector, or a very thick hydrocarbon-bearing formation (with a thickness of more than about 60 m) are hydraulically fractured, then alternative processing technologies are required to ensure processing of the entire specified zone. The methods used to improve the processing are widely known in the oil industry as methods with deviation (bypass, retraction).

In the case when many hydrocarbon-bearing zones are excited by hydraulic fracturing or by chemical stimulation treatments, economic and technical gains are realized through the use of multiple processing steps that can be rejected (or separated) by various means containing mechanical devices such as packer plugs, packers, downhole valves, sliding sleeves, as well as combinations of baffles and plugs; sealing balls, powder materials such as sand, ceramic material, proppant, salt, paraffins, resins or other compounds; or using alternative fluids, such as viscous fluids, gel-forming fluids, foamed materials or other chemically formed fluids; or through the use of intake restriction methods. These and all other similar methods and devices that temporarily block the flow of fluids into or from a given set of perforations will hereinafter be referred to as deflection agents.

In case of deviation, for example, by means of a mechanical packer plug, the deepest interval is perforated first and a crack (break) is excited, and then this interval is usually isolated by the packer plug installed with the hoist rope, and the process is repeated for the next interval from above . If we take 10 predetermined perforation intervals, then to process 300 m (1,000 ft) of the formation in this way usually requires ten technological operations carried out over a period of time from 10 days to two weeks, and it is necessary to carry out not only many treatments to create cracks, but also to produce multiple punching and packer movement operations. At the end of the processing process, a wellbore cleaning operation is required to remove the packer plugs and start production from the well. The main advantage of using packer plugs and other mechanical deflection agents is the high confidence that the entire specified zone is processed. The main disadvantages are the high cost of processing associated with many operations input into and withdrawal from the wellbore, and the risk of complications associated with the presence of many operations performed in the well. For example, a plug packer can get stuck in the casing and then it is necessary to drill it, which leads to high costs. Another disadvantage is that the required wellbore cleanup operation can damage some of the intervals with successfully formed cracks.

One of the alternatives to using packer plugs is to fill a portion of the wellbore, combined with the interval with the newly formed cracks, using sand to break the formation, which is commonly known as Rsche 1k1ai technology. A column of sand in the wellbore essentially clogs the interval with already formed cracks and allows for independent perforation and formation of cracks in the next interval. The first advantage of this is the elimination of problems and risks associated with packer plugs. The disadvantages are that the sand plug (pillar) does not provide a perfect hydraulic seal and is difficult to remove from the wellbore at the end of all crack initiation operations. Unless the flow rate of the fluid from the well is so powerful that it allows sand to be removed from the wellbore, the well may still need to be cleaned using a well repair facility or a coiled tubing unit. As before, additional operations in the wellbore increase costs, mechanical risks and the risks of damage to intervals with formed fractures.

Another deflection method involves the use of powder materials (granular solids) that are introduced into the treatment fluid to facilitate deflection. When the fluid is injected, the particles enter the perforations, and a temporary block is formed in the fluid receiving zone if the stream contains a sufficiently high concentration of particles. The resulting flow restriction leads to a deviation of the fluid to other zones. After the treatment, the powder material is removed using the produced formation fluid or using an injected flushing fluid due to fluid entrainment or dissolution. Among the conventional powder deflecting materials available, benzoic acid, naphthalene, rock salt (sodium chloride), resins, paraffins and polymers can be mentioned. Alternatively, sand, proppant, and ceramic materials may be used as deflection powders. Other special powder materials that precipitate and form during processing can also be used.

Another method of deflection involves the use of agents as a deflection fluid with a high viscosity, viscous gels or foamed materials. This method involves injecting a deflecting fluid through a perforated interval and / or into it. These fluids are designed to temporarily block the flow to perforations by increasing the viscosity or reducing the relative permeability of the formation; moreover, these fluids are designed in such a way that at a desired time, this medium is destroyed, degraded or dissolved (with or without chemicals or other additives to trigger such destruction or dissolution), so that flow in or from perforations can be restored . These fluids can be used to deflect matrix intensification chemical treatments and cracking treatments. Sometimes, deflection powder means and / or sealing balls are introduced into these fluids to enhance deflection.

Another possible method is a method of limited input deviation, which involves perforating the entire predetermined zone of the formation to be processed using a very small number of perforations, usually of small diameter, so that the pressure loss through these perforations during injection contributes to high internal pressure in the wellbore. The internal pressure in the wellbore is chosen high enough to cause the simultaneous formation of cracks in all perforated intervals. If the pressure is too low, then cracks form only in the weakest parts of the formation. The first advantage of a limited input deviation is that inside the casing there are no obstacles like packer plugs or sand, which later cause problems. The disadvantage is that a limited input gap often does not work well at large intervals, since the resulting fracture is often too narrow (the proppant cannot be completely pumped out through the narrow fracture and remains in the wellbore), and the initial high pressure in the wellbore may disappear. When sand is injected, the diameter of the perforations often undergoes erosion and increases, and the increased size of the perforations reduces the internal pressure in the wellbore.

The end result of this may be the lack of excitation of all given zones. Of additional concern is the potential limitation of throughput in the wellbore due to the small number of perforations.

Some of the problems associated with the impossibility of exciting the entire specified zone or using mechanical methods that require many operations5 in the wellbore and entries into the wellbore, which pose a high risk and lead to high costs, which are described here above, can be solved through the use of limited concentrated perforated intervals deflected by means of sealing balls. The zone to be treated can be divided into subzones with perforations approximately in the center of each such subzone, or the subzones can be selected based on the formation analysis at which the desired desired fracture locations are found. After that, injection (injection) can be carried out in the crack stages (sections), with deviation by means of sealing balls at the end of each stage. In particular, 300 m (1,000 ft) of the large formation can be divided into 10 subzones of approximately 30 m (about 100 ft) each. In the center of each 30-meter (100-foot) subzone, 10 perforations can be punched at a density of 3 holes per meter (one hole per foot) of the casing. After that, a fluid with a proppant is pumped into the crack stage, and then 10 or more sealing balls are introduced, at least one in each open perforation in one set of perforations or in one interval. The process is repeated until all sets of perforations are cracked. Such a system is described in more detail in US Pat. No. 5,890,536 of April 6, 1999.

Historically, all zones to be processed in a particular process operation in which the sealing balls are used as a deflection agent are perforated before injection of the treatment fluid, and the sealing balls are used to deflect the treatment fluid from zones with already formed cracks or from zones that might otherwise perceive a large part of the fluid flow, while other zones accept a smaller part of the fluid or do not accept it at all until Waiting for sealing balls. The processing and compaction theoretically is carried out zone by zone depending on the relative fracture (rupture) pressures or on permeability, however, problems often arise associated with premature entry of balls into one or more open perforations outside a given interval, and with two or more zones that undergo processing at the same time. Moreover, this technology assumes that each perforation interval or subzone will collapse and crack at sufficiently different pressures, so that each processing step will be used for only one set of perforations.

The primary benefits of deflection with sealing balls are low costs and low risk of mechanical problems. Costs are low because the process can usually be completed with one continuous operation, usually within a few hours of one day. In the wellbore, only sealing balls remain, which either go outside with the extracted hydrocarbons, or fall to the bottom of the well, in the area called a square pit. The first drawback is the lack of confidence in the simultaneous formation of cracks in only one set of perforations, when the exact number of sealing balls falls at the end of each stage of processing. In fact, the advantages of the process depend on one stage of a crack entering the formation through only one set of perforations, and all other open perforations remain mainly unused during this stage of processing. Other disadvantages are the lack of confidence that all perforated intervals will be processed, and that the processing sequence of these intervals during processing operations will be preserved. In the case where the processing order of the zone is unknown or uncontrolled, it is impossible to ensure the processing of each individual zone or the optimal design of an individual stage of processing intensification for a given zone. In some cases, it is impossible to carry out such a processing control in which individual zones undergo processing at a single processing stage.

To overcome some of the drawbacks that may occur during stimulation treatments, when many zones are perforated prior to injecting fluids for treating the formation, an alternative method of mechanical deflection has already been developed, which involves the use of an intensification system with coiled pipes, which allows sequentially exciting many intervals during separate processing. As with normal deflection using a sealing ball, all of the intervals to be processed are perforated before the injection of formation fluid. Then, the wound pipes are run through the wellbore using a mechanical deflection means similar to a packer on both sides attached to the end of the pipe. This deflection means, when properly installed and driven through perforations, allows for hydraulic isolation above and below said deflection means. After installing and actuating the deflection means to isolate the deepest set of perforations, the stimulation fluid is pumped down into the wound pipes, which exits through the channels provided in the deflection means between the upper and lower sealing elements. After completion of the first processing stage, the sealing elements provided on the deflection means are turned off or disconnected and the wound pipes are pulled upward to install deflection means across the second set of perforations from the bottom, and the process continues until all specified intervals are excited, or the process is terminated as a result of operational failure.

This type of coiled tubing stimulator and associated method is used to fracture multiple zones in wells at depths of up to about 8,000 feet. However, various technical obstacles, including frictional pressure losses, damage to sealing elements, depth control, passage speed and potential erosion of coiled pipes, currently limit the use of this device in deeper wells.

Excessive frictional pressure is created when pumping fluids for intensification, especially with proppants, and / or having high viscosity fluids, at high speeds through long sections of wound pipes. Depending on the length and diameter of the wound pipes, the viscosity of the fluid, the maximum allowable working pressure of the equipment on the surface and the discharge rate can be limited to only a few barrels per minute; however, this, depending on the characteristics of a particular subterranean formation, may not allow the effective introduction of a proppant during hydraulic fracturing or the effective dissolution of formation materials during acid intensification.

The erosive wear of wound pipes can also be a problem when pumping a fluid with proppant down into the inside of the wound pipes at high speed, including in the portion of these pipes that remains wound on the drum on the surface. The risk of erosion increases when a proppant fluid encounters a continuous bend in a portion of coiled tubing wound onto a drum on a surface.

Most seal elements (for example, lip-type seal elements) that are currently used in the wound pipe intensification operations described above may have seal problems or seal failure in deeper wells, since seal elements pass through a large number of perforations at high boreholes temperatures inherent in deeper wells. Since the seal element moves in contact with the pipe wall or with a minimum clearance from it, the rough inner surfaces of the pipe and / or the perforation marks can damage the seal element. The sealing elements that are currently available in deflection means, such as a packer spanning both sides, are made of elastomers that may not withstand the high temperatures often found in deeper wells.

The running speed of existing systems with an assembly type seal is typically between 15 and 30 feet per minute when moving down the wellbore and from 30 to 60 feet per minute when moving up the wellbore. For example, when driving at the slowest speed, it would take approximately 13 hours to reach a depth of 12,000 feet, prior to the start of stimulation. Given the safety instructions for night work, when driving at low speed it will take many days to complete the intensification operation. If problems arise during the technological operation, lifting equipment from the well and lowering it into it can be very expensive, as it takes a lot of time due to low running speeds.

Controlling the depth of the coiled tubing system and the deflection means, such as a packer spanning on both sides, also becomes more difficult with increasing depth, and it may be difficult to properly set up the deflection means at the desired depth for a successful intensification operation. This problem is solved by performing perforations before introducing wound pipes into the well. When performing the punching operation, another depth measuring device is used (usually a location system for casing collar couplings), which is different from that used in the coiled tubing system.

In addition, the method described above with wound pipes requires that all perforations be performed in the wellbore by performing a separate punching operation before the pumping operation for intensification. The presence of many sets of perforations open above the deflection means can create operational difficulties. For example, if the propping crack from the current zone grows vertically and / or if there is poor quality cement behind the pipe, the crack can cross a set of perforations above the deflection means, so that the proppant can flow back into the wellbore from above the deflection means, which prevents further movement specified funds. In addition, circulation operations may be difficult if a plurality of perforation sets are open above the deflection means. For example, if the circulation pressures exceed the fracture pressures associated with the perforations open above the deflection means, then the circulation may not be maintained and the circulation fluid may inadvertently be lost in the formation.

A similar type of intensification operation can also be carried out using composite pipes and a well repair facility instead of a coiled pipe system. The use of deflection means deployed on composite pipes may allow the use of larger diameter pipes to reduce frictional pressure losses and increase discharge rates. In this case, the risk of erosion and damage to the integrity of the pipes is reduced compared to wound pipes, since composite pipes with a larger wall thickness can be used, while composite pipes will not experience plastic deformation when moving in the wellbore. However, the use of this approach can lead to an increase in the time of the operation and its cost due to lower pipe speeds compared to wound pipes.

To overcome some of the limitations associated with completion (completion) operations, which require multiple descents and ascents of equipment to and from the wellbore, for perforating and stimulating underground formations, methods are proposed with a single descent and ascension of the casing of a downhole tool, which allows conduct crack initiation in zones in combination with perforation. In particular, these methods use operations that minimize the number of operations required in the wellbore and the time required to complete such operations, thereby reducing the cost of stimulation processing. These proposals include the following: 1) the presence of a suspension of sand in the wellbore during perforation with non-equilibrium pressure, 2) the discharge of sand from the scoop simultaneously with the ignition of charges for perforation, and 3) the conclusion of sand in a separate container with explosive release. All these proposals provide only minimal penetration of the fracture into the environment of the wellbore and are not adapted to the needs of the multistage hydraulic fracturing described here.

In accordance with the foregoing, there is a need to develop an improved method and device for individual processing of each of the multiple intervals of the underground formation into which the wellbore passes, while maintaining the economic benefits of multi-stage processing. There is also a need for a method and apparatus that economically reduces the risks inherent in currently available intensification processing options for hydrocarbon-bearing formations with multiple reservoirs or with layered reservoirs, or with a thickness of approximately 60 m (200 ft), with optimal processing using a mechanical deflection agent that directs the processing steps to a desired location.

SUMMARY OF THE INVENTION

In accordance with the present invention, there is provided a device and method for perforating and processing a plurality of intervals of one or more subterranean formations intersected by a borehole.

The device comprises deployment means (for example, coiled pipes, composite pipes, electrical wire, wire line, a downhole tractor (tractor), etc.) with downhole equipment, which includes at least a punching device and a reusable mechanical sealing mechanism which can be driven independently by one or more means of signal transmission (for example, by electronic signals transmitted over a wired communication line; hydraulic signals transmitted through pipes through the annular space and composite hoses, by means of tensile or compression loads, by means of radio communications; by means of a fiber-optic communication line; by means of computer systems located on downhole equipment, etc.).

The proposed method includes the operation of deploying downhole equipment in the wellbore using deployment tools, which may be a string of tubing, cable or a downhole tractor. A perforating device is installed next to the interval to be punched and is used to perforate the specified interval. Downhole equipment is installed in the wellbore using deployment tools, and a sealing mechanism is activated to create a hydraulic seal that directs the fluid pumped down into the wellbore to enter the perforated interval, after which the sealing mechanism is released (turned off). The process can then be repeated without removing downhole equipment from the wellbore for at least one additional interval of one or more subterranean formations.

The deployment means may be a tubing string that includes coiled tubing or standard composite tubing, a wired communication line, a fine suspension line, or a cable. Instead of pipes or cable, the deployment tool may be a tractor system associated with downhole equipment. The tractor system can be a self-propelled computer-controlled system, on board of which there is a control unit, so there is no need to connect a cable or pipes to it to control and operate the downhole equipment and / or tractor system. Alternatively, the tractor system can receive control and power through the wires or pipes of the composite hose (umbilical), while the tractor system and downhole equipment are controlled and driven by signals transmitted to the well using the composite hose. There are many different embodiments of the invention, depending on the suspension means and the specific components of the downhole equipment.

In a first embodiment of the invention, when the deployment means is a tubing string, the downhole equipment can be moved immediately after perforating the interval and the sealing mechanism is actuated to create a hydraulic seal below the perforated interval. Processing fluid may then be pumped down into the annular space between the tubing string and the wellbore and into the perforated interval. A second treatment fluid, such as nitrogen, can also be pumped through the tubing string simultaneously with the first treatment fluid down into the annular space between the tubing string and the wellbore.

In the second embodiment, when the suspension means is a tubing string, immediately after hole punching, the downhole equipment can be moved and the seal mechanism activated to create a hydraulic seal above the perforated interval. Processing fluid can then be pumped down through the tubing string and into the perforated interval.

In the third embodiment, when the deployment means is a string of pumping pipes, the bottomhole equipment can be moved and the sealing mechanism activated to create a hydraulic seal above and below the perforated interval (in this case, the sealing mechanism contains two sealing elements offset by a sufficient distance from each other to cover the perforated interval on both sides). In the third version, the processing fluid can be pumped down through the tubing string itself, through the hydraulic system channel located between the two sealing elements of the sealing mechanism, and into the perforated interval.

In a fourth embodiment, when the downhole equipment is deployed in the wellbore using a wireline, a thin suspension line or a cable, the downhole equipment can be moved and the sealing mechanism activated to create a hydraulic seal below the perforated interval to be processed, and the processing fluid may be pumped down into the annular space between the wire line, the fine suspension line or the cable and the wellbore.

In a fifth embodiment of the invention, a composite hose is deployed as an additional means for actuating a downhole equipment component. In the most general case, the composite hose has the form of a pipe of small diameter or a plurality of pipes to provide hydraulic communication with downhole equipment components, and / or the composite hose may take the form of a cable or multiple cables to provide electrical or electro-optical communication with components of the downhole equipment.

In a sixth embodiment, when the deployment means is a tractor system associated with the downhole equipment, the downhole equipment can be moved and the sealing mechanism is actuated to create a hydraulic seal below the perforated interval. Processing fluid may then be pumped down into the wellbore and at the perforated interval.

In a seventh embodiment of the invention, abrasive fluid jet cutting technology is used for punching, and the downhole equipment is suspended by means of pipes so that the downhole equipment can be moved and the sealing mechanism activated to create a hydraulic seal below the perforated interval. Processing fluid may then be pumped down into the annular space between the pipes and the wellbore.

One of the primary advantages of the proposed device and method is that the downhole equipment, including the compaction mechanism and the perforating device, does not need to be removed from the well before processing using the processing fluid and between the treatment of multiple formation zones or intervals. Another of the primary advantages of the proposed device and method is that each stage (stage) of processing is rejected using a mechanical deflection agent, so that precise control of the process of rejection of the treatment is achieved and each zone can be optimally excited. The result is a significant reduction in cost by reducing the time it takes to perforate and process multiple intervals in the wellbore. In addition, in this case, an increase in flow rate is achieved due to the use of a mechanical deviation agent, which provides processing deviation with precise control when exciting multiple formation intervals in the wellbore. The proposed device and method have significant economic advantages compared to existing methods and equipment, since the device and method in accordance with the present invention allow perforation and excitation of many zones with a single entry into the wellbore, followed by the withdrawal of downhole equipment, which plays a dual role mechanical deflection agent and perforating device.

Brief Description of the Drawings

The foregoing and other characteristics and advantages of the invention will be more apparent from the following detailed description, given with reference to the accompanying drawings, in which the following is shown.

FIG. 1 depicts a possible typical example of a wellbore configuration with peripheral equipment that can be used to support downhole equipment used in accordance with the present invention. FIG. 1 also shows a typical example of storing downhole equipment in wellbores with surface wedges (wedge grips), wherein said wellbores can be used to store spare parts or emergency downhole equipment.

FIG. 2A depicts a first embodiment of downhole equipment deployed using coiled tubing in an unperforated wellbore and set at the depth of the perforation using the first set of selectively ignited perforation charges. FIG. 2A further depicts that the downhole equipment includes a punching device, an inflatable reusable packer, a reusable axial wedge grip, and auxiliary components.

FIG. 2B shows downhole equipment, coiled pipes and the borehole of FIG. 2A, after ignition of a first set of selectively ignited perforation charges resulting in perforations (holes) in the production casing and in the cement sheath extending into the first formation zone, so that a hydraulic connection is established between the wellbore and the first formation zone.

FIG. 2C shows downhole equipment, coiled pipes and the borehole of FIG. 2B after the displacement of downhole equipment and the excitation of the first formation zone using the first stage of a multistage hydraulic proppant fracturing operation, when the first stage of the fracturing operation is performed through the annular space of the wellbore existing between coiled pipes and production casing. In FIG. 2C, the sealing mechanism is shown inoperative, since it is accepted only to explain the invention that there are no other perforations other than those associated with the first zone, and therefore, insulation is not necessary for processing the first zone.

FIG. 3A shows downhole equipment, coiled pipes and the borehole of FIG. 2C after rearrangement of downhole equipment and ignition of a second set of selectively ignited charges for perforation, leading to the appearance of perforations in the production casing and in the cement sheath passing into the second formation zone, so that a hydraulic connection is established between the wellbore and the second formation zone.

FIG. SV shows downhole equipment, coiled pipes and the borehole of FIG. З And after moving the downhole equipment to a significant distance below the deepest perforation of the second set of perforations, with the possibility of small movement of the downhole equipment up to install a repeatedly set axial wedge grip while maintaining the location of the circulation channel below the lowest perforation of the second set of perforations.

FIG. ZS depicts downhole equipment, coiled pipes and the wellbore of FIG. З В after actuating a repeatedly set mechanical wedge grip to create resistance to the axial downward movement while ensuring the location of an inflatable repeatedly installed packer and a repeatedly set mechanical wedge grip between the first zone and the second perforation zone.

FIG. 3Ό shows downhole equipment, coiled pipes and the borehole of FIG. Z C after actuating the inflatable re-installable packer to create an obstruction to the flow between the section of the wellbore directly above the inflatable re-installable packer and the section of the wellbore directly below the inflatable re-installable packer.

FIG. 3E shows downhole equipment, coiled pipes and the borehole of FIG. 3Ό after the second formation zone is excited by the second stage of a multi-stage hydraulic proppant fracturing, the second stage of hydraulic fracturing is injected in the annular space of the wellbore existing between coiled pipes and production casing.

FIG. 3E shows downhole equipment, coiled pipes and the borehole of FIG. 3E after deactivating the inflatable reusable packer, thereby again establishing a pressure transfer between the portion of the wellbore immediately above the inflatable reusable packer and the section of the wellbore directly below the inflatable reusable packer, while the reusable mechanical wedge is still excited and continues to prevent moving wound pipes and downhole equipment down the wellbore.

FIG. 4A shows a modified downhole equipment similar to the downhole equipment shown in FIG. 2A-2C and FIG. 3A-3E, however, with the addition of a mechanical plug installed with a selectively ignited charge installation system located below the firing drill string. FIG. 4A also shows coiled pipes and the wellbore of FIG. 3E after an additional third perforation and a crack initiation operation. FIG. 4A shows only the second and third cracks and corresponding sets of perforations. FIG. 4A shows a modified downhole equipment suspended by coiled tubing so that the location of the packer plug is above the last perforated interval and below the next perforated interval.

FIG. 4B shows downhole equipment, coiled pipes and the borehole of FIG. 4A after installing a mechanical plug in the well using selective charge ignition, after moving the downhole equipment and igniting the first set of selectively ignited charges for perforation, resulting in perforations in the production casing and in the cement sheath passing into the fourth formation zone, thus that establishes a hydraulic connection between the wellbore and the fourth formation zone.

FIG. 5 shows a second embodiment of the invention in which the suspension means is a tubing string, whereupon immediately after perforation of the interval, the downhole equipment can be moved and the sealing mechanism activated to create a hydraulic seal above the perforated interval. Processing fluid may then be pumped down into the tubing string and into the perforated interval.

FIG. 6 shows a third embodiment of the invention, in which the suspension means is a tubing string, the downhole equipment can be moved and the sealing mechanism activated to create a hydraulic seal above and below the perforated interval (in this case, the sealing mechanism contains two sealing elements offset from each other sufficient distance from each other to cover the perforated interval on both sides), in this embodiment, the processing fluid may be injected and down through the column of pumping pipes, through the hydraulic channel located between the two elements of the sealing mechanism of the seal, and into the perforated interval.

FIG. 7 shows a fourth embodiment of the invention in which downhole equipment is suspended in a wellbore using a wireline (or fine suspension line or cable); downhole equipment is moved and the sealing mechanism is actuated to create a hydraulic seal below the perforated interval to be processed, after which the processing fluid is pumped down into the annular space between the wire line, the thin suspension line or the cable and the wellbore.

FIG. 8A and 8B show a fifth embodiment of the invention in which a composite hose deployed inside pipes used as deployment means is used to actuate a reusable seal mechanism.

FIG. 9 shows a sixth embodiment of the invention in which a tractor system connected to the downhole equipment is used, by which the downhole equipment is moved and the sealing mechanism is actuated to create a hydraulic seal below the perforated interval, after which the processing fluid is pumped down into the wellbore and in the perforated interval.

FIG. 10 shows a seventh embodiment of the invention in which the perforating device uses abrasive or erosive fluid cutting technology, the downhole equipment is suspended in the wellbore using composite pipes and includes a mechanical compression kit, a reusable packer, an abrasive or perforating device erosive jet of fluid, casing collar locator and auxiliary components. In this embodiment, the perforations are created by pumping the abrasive fluid down into the composite pipes, which exits through a jet perforator located in the downhole equipment, so that a high pressure and high speed jet of abrasive or erosive fluid is created, which is used to create perforations in production casing and cement sheath, through which a hydraulic connection is established between the wellbore and the desired formation interval. After installing the reusable packer below the zone to be excited, the treatment fluid may be pumped down into the annular space located between the tubing string and the production casing string.

DETAILED DESCRIPTION OF THE INVENTION

Further, the present invention will be described with reference to its preferred options, however, it should be borne in mind that specific options and specific uses of the invention are provided only for its better understanding and are not restrictive. On the contrary, the description of the invention is intended to cover all alternatives, modifications and equivalents that are included in the scope of the invention defined in accordance with the attached claims.

In accordance with the present invention, a new method, a new system and a new device for perforating and exciting a plurality of formation intervals, which allow the processing of each single zone using an individual processing step, which eliminates or minimizes the problems that are associated with the existing ones, are proposed intensification methods using coiled pipes or composite pipes, and therefore creates significant economic and technical advantages compared th with the existing methods.

More precisely, the invention proposes to suspend downhole equipment in the wellbore for individually and sequentially perforating and processing each of the many desired zones, with multi-stage intensification and with the deployment of a mechanical reusable sealing mechanism to provide controlled deviation for each individual processing stage. For the purposes of the present invention, the term wellbore is to be understood as a system that includes below-ground components of the well seal and all packed equipment below the ground, such as the wellhead, winding drum parts, blowout preventer and lubricator.

The new device includes deployment means (for example, coiled pipes, composite pipes, electrical wire, wire line, tractor system, etc.), the downhole equipment comprising at least a punching device and a reusable mechanical sealing mechanism, which can be independently powered from the surface using one or more means of generating signals (for example, using electrical signals transmitted over a wire line, hydraulic signals, transmitted through pipes through the annular space and composite hoses, using tensile or compressive loads; using radio communications, using fiber-optic communication lines, etc.), while downhole equipment is designed taking into account existing conditions in the wellbore and nature loading.

In the most general sense, the term downhole equipment is used here to refer to a combination of components, which at least includes a perforating device and a reusable sealing mechanism. Among the additional components, you can specify (but without limitation) fishing necks, sub adapters with shear pins, flushing accessories, circulation channel adapters, hydraulic system adapters, pressure equalization channel adapters, temperature sensors, pressure sensors, adapters for connecting a wire line, repeatedly installed mechanical wedge grip, casing collar locators, centralizer adapters and / or connecting adapters, which can also be used downhole equipment to facilitate other possible auxiliary or official operations and measurements, which may be desirable during intensification.

In the most general sense, a reusable mechanical seal mechanism has the function of creating a hydraulic seal, where a hydraulic seal is understood to mean sufficient restriction of flow or its blocking, due to which the fluid is forcibly directed to a different location from the location to which it would go if there would be no specified flow restriction. More precisely, this broad definition of the term hydraulic seal includes the concept of an ideal hydraulic seal, in which the entire flow is directed to a location different from the location to which it would be directed if there were no specified flow restriction, and includes the concept of An ideal hydraulic seal in which a substantial part of the flow is directed to a location different from the location to which it would be directed if there were no specified flow restriction. Although it is generally desirable to use a reusable mechanical seal providing an ideal hydraulic seal to achieve optimum excitation, a seal mechanism that creates an imperfect hydraulic seal can be used, and a cost-effective treatment can be provided even if there is no ideal deviation. when processing intensification.

In a first preferred embodiment of the invention, coiled pipes are used as a deployment tool, the new method comprising sequentially perforating and then exciting individual zones from the bottom up to the completion interval, wherein the stimulation fluid is pumped down into the annular space between the production casing and the coiled pipes. As discussed in more detail below, this version of the new device and method provides significant advantages over existing stimulation technologies that use coiled pipes and composite pipes, and this option can be used in a wide range of wellbore architectures and types of treatment for stimulation.

More precisely, in the first preferred embodiment of the new method and device, they use a deployment system, signal receiving means, downhole equipment and operations, which are described in more detail below, and the various components, their orientation and operation steps are selected only for explanation in such a way that they correspond to the components and operations that can be used to implement hydraulic proppant crack initiation at multiple intervals.

In a first preferred embodiment, a device for effecting hydraulic proppant fracture initiation includes downhole equipment that is deployed in a wellbore using coiled tubing. Downhole equipment includes a perforating device, a reusable mechanical sealing mechanism; casing collar joint locator, circulation channels and other auxiliary components (as described in more detail below).

Moreover, in this first preferred embodiment, the perforating device comprises a system of firing perforators with selective ignition of charges (in which cumulative charges are used to perforate), a reusable mechanical seal mechanism containing an inflatable reusable packer, a mechanical reusable wedge grip to prevent its installation, directed downward axial movement of the downhole equipment, and pressure equalization channels, Assumption above and below the inflatable packer is repeatedly installed.

In addition, in this first preferred embodiment, a wireline can be installed inside coiled tubing and used to transmit signals designed to drive selectively ignited charges for perforation, and to transmit electrical signals to the casing collar locator using depth measurements downhole equipment.

In FIG. 1 shows an example of a type of surface equipment that can be used in a first preferred embodiment. It includes a drilling rig, which contains a very long lubricator 2 with a pipe injector head 4, suspended high in the air using a crane boom 6 connected to the crane base 8. The wellbore typically comprises a segment of the surface casing 78 located partially or completely inside the cement sheath 80 and a production casing 82 located partially or completely inside the cement sheath 84, the inner wall of the wellbore being formed by the production casing 82. The wellbore preferably extends to a depth slightly greater than the depth of the lowest interval to be excited, which is necessary for the installation of downhole equipment connected to the end of the wound pipes 106. The pipes 106 are inserted into the wellbore using the injector head 4 and a lubricator 2. Blowout preventers 10 are also connected to the lubricator 2, which can be remotely actuated in the event of operational failures. The crane base 8, crane boom 6, injector head 4, lubricator 2, blowout preventers 10 (and associated auxiliary control and / or actuating components) are components of standard well equipment that allow well-known specialists in this field to carry out the processes of safe installation of downhole equipment, with wound pipes into the well under pressure, and then removing them from the well under pressure.

When using existing equipment that is easily accessible, the height of the injector head 4 from the ground is about 90 feet, with the 8-shaped bend 12 (where the pipe spiral is bent to vertically enter the hole down) has a height of about 105 feet from the ground. The base 8 of the crane and the boom 6 of the crane must withstand the weight of the head 4 of the injector, pipes 106, as well as any load during possible fishing operations (when releasing the downhole tool and equipment with the help of a box and removing it from the well).

Generally speaking, the lubricator 2 must have a length exceeding the length of the downhole equipment to allow the downhole equipment to be safely deployed in the wellbore under pressure. Depending on the requirements for the full length and in accordance with engineering calculations for a particular application, to ensure the stability of the head 4 of the injector and the lubricator 2, the cable strands 14 can be connected at various locations with the head 4 of the injector and the lubricator 2. The cable strands 14 must be firmly fixed to the ground to prevent unwanted movement of the head 4 of the injector and lubricator 2, so that the integrity of the pressure-resistant surface components is not violated. Depending on the requirements for the full length, alternative injector and lubricator head suspension systems can also be used (specialized drilling rigs with wound pipes or workover rigs).

In FIG. 1 also shows the various components of the wellhead, which can be used to control the flow rate of the well and hydraulic isolation during installation and dismantling of the drilling rig, as well as for stimulation (stimulation) of the formation. Crown valve 16 is used as a device to isolate the section of the wellbore that is above it from the section of the wellbore that is below the crown valve 16. The upper main valve 18 and the lower main valve 20 form a valve system to isolate the pressure of the wellbore above and below them relevant locations. Depending on the specifics of the work on the site and the technology of the intensification operation, in reality not all of the indicated isolation type valves may be required and will be used.

In FIG. 1 also shows lateral outlet injection valves 22, which determine the location for pumping (injecting) fluids for stimulation into the wellbore. Pipes from surface pumps and reservoirs that are used to pump stimulation fluids are connected via appropriate fittings and / or connecting flanges to the side outlet injection valves 22, by which stimulation fluids are pumped into the wellbore. When other appropriate flow control equipment is installed, fluid can also be diverted from the wellbore using side outlet injection valves 22. It should be borne in mind that the interior of coiled tubing 106 can also be used as a channel for pumping fluid into the wellbore.

Shown in FIG. 1 trunks 24 wells are used to store spare parts for downhole equipment or emergency downhole equipment 27, or to store downhole equipment that has already been used in the course of previous operations. The trunks 24 of the borehole for storing downhole equipment may have a shallower depth, so that the bottomhole equipment, which may contain perforating charges, can be held firmly in place by means of surface wedge grippers 26, so that the perforating charges are below ground level, until the bottomhole equipment is removed and connected to the wound pipes 106. The trunks 24 of the well for storing downhole equipment may contain cemented or not cemented casing or may remain completely uncased. The actual number of shafts 24 of the well for storing downhole equipment, which is required for a specific operation, depends on the requirements for a complete technological operation. The trunks 24 of the well for storing downhole equipment should be located within reach with the help of a boom 6 of the crane in order to allow quick replacement of the downhole equipment during the intensification operation without the need to physically move the base 8 of the crane to another location.

In FIG. 2A shows coiled pipes 106 provided with a coiled pipe coupling 110 that can be connected to an adapter 112 of a shear pin and fishing neck assembly that includes both a shear mechanism of the shear pin and a fishing neck and allows fluids to be passed under pressure , and a wired communication line 102. The adapter 112 of the tube assembly with a shear pin and a fishing neck can be connected to a circulation channel 114, which comprises a circulation channel designed to pass washing wastes from anstva over repeatedly usta23 navlivaemym inflatable packer 120 or for fluid flow injected into the well using coiled tubing 106. The channel 114 comprises a circulation valve block that controls the circulation channel 114 and the upper pressure equalization conduit 116. The upper pressure equalization channel 116 may be in communication with the lower pressure equalization channel 122 through the pipes via an inflatable re-set packer 120. Both the circulation channel 114 and the upper equalization channel 116 are advantageously open in the operating position and allow pressure equalization inside the wound pipes and in the annular space casing string. In this description, the term operating position refers to a situation in which all the components of the downhole equipment are configured to allow axial movement up and down the wellbore unhindered. The lower alignment channel 122, which is located below the inflatable reusable packer 120, is always open, so the flow between the alignment channels is controlled by the upper alignment channel 116. Circulation and alignment channels can be closed at the same time when a small compressive load is applied to the downhole equipment. To prevent potential backflow into the coiled tubing when the circulation channel 114 is open in the operating position, such surface pressure should be applied to the coiled pipe 106 that the pressure inside the circulation channel 114 exceeds the pressure in the wellbore directly from the outside of the circulation channel 114. The reusable inflatable packer 120 is hydraulically isolated from the internal pressure of the wound pipes in the operating position. The inflatable reusable packer 120 can provide pressure transmission through internal valves controlled by the internal pressure of the wound pipes when a small compressive load is applied to the downhole equipment. Mechanically actuated, axially deployable locking devices or wedge grips 124 may be mounted below an inflatable multiple-installable packer 120 to prevent downward movement of the wellbore. Mechanical wedge grips 124 can be actuated using a continuous 1 mechanism due to the cyclic change in axial load between compression and tension. A wireline adapter 126 is located above the casing string locator 128 and a selective ignition punch charge system. A punch adapter 130 connects a casing locator 128 of casing collar couplings to a selective ignition charge head 152. A perforation system can be designed taking into account the number, location and thickness of hydrocarbon-bearing sands within a given zone. The perforation system may comprise one perforation unit (e.g. 134) for each zone to be treated. The first (lowest) perforation unit comprises a selective ignition head 132 and a perforator body 134, into which punch charges 136 are loaded and in which a selective ignition detonation system is mounted.

The indicated preferred variant of the new method includes the following operations, moreover, as a technological operation for explaining the invention, a multi-stage hydraulic proppant is selected.

1. Drilling and cementing the casing at intervals to be completed, as well as, optionally, drilling and completing one or more boreholes for storing downhole equipment.

2. Identification of predetermined zones within the completion intervals (usually due to a combination of the logs recorded in the open hole and the logs recorded in the cased hole).

3. Deployment of downhole equipment and blocks (assemblies) of firing perforators for each downhole equipment, which they intend to use during the intensification operation, taking into account the number, location and thickness of hydrocarbon-bearing sands within the specified zones.

4. Preparing a drum of coiled tubing for a preferred embodiment of the downhole equipment described above. The reel of coiled tubing should also contain a wireline, which is used to transmit signals to actuate the firing punchers. Preferably, the desired amount of spare or emergency downhole equipment is also prepared, which is stored in the wellbore (s) for storing downhole equipment. Coiled tubing may be pre-filled with fluid, before or after connecting downhole equipment to coiled tubing.

5. As shown in FIG. 1, wound pipes 106 with downhole equipment are introduced into the well through a lubricator 2, and the head 4 of the injector of the wound pipes is suspended using the crane jib 6.

6. Wound pipes and downhole equipment are injected into the well when choosing the depth of location of the downhole equipment using the locator 128 (Fig. 2A) of the casing collar joints.

7. Wound pipes and downhole equipment are passed below the lowest specified zone to ensure the wellbore depth is lower than the lowest perforations, sufficient to place the downhole equipment below the first set of perforations during fracturing operations. As shown in FIG. 2A, the inflatable reusable packer 120 and the reusable mechanically actuated wedge grips 124 are in the operating position.

8. As shown in FIG. 2B, the coiled pipes and downhole equipment are then lifted to a location in the wellbore where the first (lowest) set of perforating charges 136, which is contained in the first perforating unit 134 of the perforation system with selective ignition, is located directly opposite the lowest predetermined zone, moreover, accurate depth control can be obtained from the testimony of the locator 128 couplings of the casing string and the depth gauge system of wound pipes (not shown). The action of moving the downhole equipment up to the location of the first perforated interval puts the mechanical wedge grip in the form of a continuous 1 mechanism (not shown) in the pre-locked position, and the subsequent downward movement forces the repeatedly installed mechanical wedge grip 124 to the locked position, thereby preventing further movement down. It should be borne in mind that an additional cyclic change in the axial load of the wound pipes from compression to tension and vice versa will return repeatedly installed mechanical wedge grips to the working position. In this way, a mechanical wedge grip is used in the form of a continuous 1 mechanism, due to the use of compression and tensile loads transmitted by means of the suspension (wound pipes) to actuate and turn off the mechanical wedge grippers.

9. The first set of perforating charges 136 are selectively set on fire by remote actuation using a wireline 102 that communicates with the first selective ignition head 132, whereby perforations 230-231 are punched through the casing 82 and the cement sheath 84 that install hydraulic communication with the formation 86. It should be borne in mind that any set of perforations can be used, for example, if desired, a set with one perforation, however, usually many perforations provide better cuts. ltaty processing. It should also be borne in mind that you can set fire to several segments of the perforation unit when you want to get a given number of perforations, for example, to eliminate the actual or expected misfire, or simply to increase the number of perforations. It should also be borne in mind that the interval is not necessarily a single sand collector. Many sand intervals can be perforated and processed in a single processing step using other deflection agents suitable for simultaneous deployment at a given processing step in accordance with the present invention.

10. As shown in FIG. 2C, the wound pipes can be moved to the position of the circulation channel 114, immediately below the deepest perforation 231 of the indicated first predetermined zone, in order to minimize the potential for proppant to flow above the inflatable repeatedly installed packer 120 and to minimize the flow with the high speed of the proppant behind downhole equipment.

11. The first treatment step for generating cracks is initiated by circulating (feeding) a small volume of fluid downward into the wound pipes 106 through the circulation channel 114 (using a volumetric pump). After that, the pumping of the fluid to intensify down into the annular space between the wound pipes 106 and production casing 82 with the speeds of the excitation of cracks. The flow of a small volume of fluid down into the wound pipes 106 serves to maintain a positive pressure inside the pipes 106, which counteracts the reverse flow of the proppant fluid into the pipes 106 and counteracts the crushing load of the pipes 106 during fracturing operations. It should be borne in mind that alternative means of counteracting collapse of the wound pipes can be used, and an internal valve mechanism can be used to hold the circulation channel 114 in the closed position, while the positive pressure in the wound pipes 106 is created using a surface pump. In an example of a hydraulic fracturing for stimulating a 15-acre sandy lenticular body containing gaseous hydrocarbon, a first fracture step may be formed from the following steps: (a) 5,000 gallons of water with 2% KCl; (b) 2,000 gallons of reticulated gel containing 1 pound per gallon of proppant; (c) 3,000 gallons of reticulated gel containing 2 pounds per gallon of proppant; (d) 5,000 gallons of gelled mesh containing 3 pounds per gallon of proppant; and (e) 3,000 gallons of gel of a mesh structure containing 4 pounds per gallon of proppant, so that 35,000 pounds of proppant are introduced into the first zone.

12. As shown in FIG. 2C, all stages of the first hydraulic fracturing operation are completed by creating the first proppant 232.

13. At the end of the first stage of intensification, the proppant in the wellbore prevents the immediate movement of coiled pipes and downhole equipment; the fluid can be circulated through the circulation channel 114 to flush and clean the proppant, which is necessary to release wound pipes and downhole equipment to allow movement.

14. As shown in FIG. 3A, the wound pipes and downhole equipment are then pulled upward along the wellbore to a position slightly higher than the second lower from the depth of the predetermined zone, so that the second set of perforation charges 146 contained in the selective ignition punching system 144 is slightly higher second from the bottom in the depth of the specified zone, and again accurate control of the depth is obtained according to the testimony of the locator of the sleeve couplings of the casing 128 and the depth gauge systems of the wound pipes. The action of moving downhole equipment up the wellbore (to a position just above the second interval to be perforated) translates the mechanical wedge grip in the form of a continuous 1 mechanism to the pre-lock position. An additional cyclic change in compressive to tensile loads will return the mechanical wedge grip in the form of a continuous 1 mechanism to its working position. Wound pipes and downhole equipment are then lowered along the wellbore to the position of the perforating charges 146, which are contained in the selective ignition punching system 144 located directly opposite the second lower depth of the predetermined zone, and again, precise depth control is obtained according to the indications of the casing coupling locator 128 and coiled pipe depth gauge systems.

15. The second set of charges 146 for punching is selectively set on fire by remote actuation using the second selective ignition head 142, which allows punching the casing 82 and cement sheath 84 and establishing hydraulic communication with the formation 86 through the received perforations 240, 241.

16. As shown in FIG. 3B, coiled pipes can be moved down the wellbore to install downhole equipment several feet below the deepest perforation 241 of the second predetermined zone.

Subsequent movement of downhole equipment up the borehole to install the circulation channel 114 directly below the deepest perforation 241 of the specified second predetermined zone will translate the repeatedly set mechanical wedge grips 124 to the pre-locked position, and the subsequent downward movement will force the repeatedly installed mechanical wedge grippers 124 to the locked position, thereby preventing further downward movement.

17. As shown in FIG. 3C, a downward movement engages repeatedly mounted mechanical wedge grips 124 with a casing wall 82, thereby preventing further downward movement of the downhole equipment. Then, a compression load is applied to the coiled pipes, this load closing the circulation channel 114 and the upper equalization channel 116, and due to the communication, equalizes the pressure between the inflatable re-installed packer 120 and the interior of the coiled pipes. The compressive load also blocks the circulation channel 114 in the position immediately below the deepest perforation 241 of the specified second predetermined zone (to minimize the potential for the proppant to flow above the inflatable, repeatedly installed packer 120 and create a minimum proppant flow rate behind the downhole equipment), while the inflatable a reusable packer 120 is located between the first and second perforated intervals.

18. An additional compressive load is applied to the coiled pipes and downhole equipment for testing repeatedly mounted mechanical wedge grips 124 to ensure that the additional downward force does not cause additional downhole movement of the downhole equipment down the wellbore.

19. As shown in FIG. 3Ό, an inflatable reusable packer 120 is driven by pressurizing the wound pipes 106, thereby creating a hydraulic seal above and below the inflatable reusable packer 120. A compressive load continues to be applied to the downhole equipment to maintain pressure equalization between the interior of the wound pipes and the inflatable repeatedly installed by the packer 120 to keep closed the circulation channel 114 and the upper alignment channel 116, as well as to hold repeatedly installed Vai mechanical wedge grips at position 124 and the excitation block. The inflatable reusable packer 120 is maintained in operation by maintaining pressure in the wound pipes 106 by means of a surface pump system (it should be borne in mind that the inflatable reusable packer can also be maintained in operation due to the blocking pressure in its element, using an internal valve remotely controlled from the surface by means of a signal generator compatible with other downhole equipment components and other available means mi create signals).

20. The second treatment step for generating a crack is started by pumping fluid down into the annular space between the coiled tubing 106 and the production casing 82 at crack excitation rates while maintaining the compressive load applied to the bottomhole equipment to keep the circulation channel 114 and the top closed channel 116 alignment, and the pressure of the wound pipes is maintained at a level sufficient to prevent crushing of these pipes and hold the inflatable repeatedly setting emogo packer 120 in the inflated state, when it serves as a fluid seal between the annular pressure above the packer, before, during and after the fracturing pressure and the compacted wellbore below the inflatable packer installed repeatedly.

21. All hydraulic fracturing stages are inflated and only the minimum lower passage is left with the last approach loaded by the proppant in the wellbore, so as not to bias the excess hydraulic fracture. If during this treatment the seal of the inflatable reusable packer 120 is broken, the processing step can be temporarily suspended to check the quality of the packer seal above the highest (smallest) perforations (for example, perforation 240 in Fig. 3Ό), after installing the inflatable reusable packer 120 into the pipe without side openings. If it is necessary to conduct a seal integrity test, it is preferable to carry out a circulation and flushing operation prior to conducting such a test to remove any proppant that may be present in the wellbore from the wellbore. The indicated circulation and flushing operation can be carried out by opening the circulation channel 114 and then pumping the fluid for circulation down into the wound pipes 106 to remove the proppant from the wellbore.

22. As shown in FIG. 3E, all steps of the second crack initiation operation are completed by creating a second proppant crack 242.

23. After completing the second crack initiation operation and stopping the pumping of the fluid to intensify down into the annular space formed between the wound pipes 106 and the production casing 82, a small tensile load is applied to the pipes 106 while maintaining the internal pressure of these pipes 106. Slightly stretched before it isolates the pressure of the inflatable repeatedly installed packer 120 from the pressure of the pipes 106, due to which the pressure in the inflatable is repeatedly fixed ohm packer 120 and thus maintains a tight seal with overpressure and creates substantial resistance to axial movement of the inflatable reusable packer 120. Applied tension can then open the circulation channel 114 and the alignment channel 116, whereby the pressure of the wound pipes 106 can be relieved the annular space formed by the pipes 106 and production casing 82, which simultaneously allows pressures above and below the inflatable repeatedly installed packer 120 balance off. The surface pumping system that creates the internal pressure of the pipes 106 can be turned off after balancing the pressure in the well.

24. After the pressure inside the wound pipes 106, in the annular space formed by the pipes 106 and the production casing 82, is higher than the inflatable packer 120, and in the annular space formed by the downhole equipment and the production casing 82, below the inflatable repeatedly installed packer 120 are balanced, the compression load applied to the pipes 106 closes the circulation channel 114 and the upper equalization channel 116, before the internal pressure is transferred from the packer 120 to the pipes 106. This ypusk internal pressure of the packer 120 allows to withdraw the packer 120 from the production casing wall, as shown in FIG. 3E, in the absence of an external pressure drop applied to the packer 120, which could create forces and movements that could damage the coiled tubing 106 or downhole equipment.

25. Immediately after returning to the initial state of the inflatable reusable packer 120, as shown in FIG. 3E, a tension applied to coiled pipes and downhole equipment can turn off repeatedly set mechanical wedge grips 124, which allows downhole equipment to move freely, so that downhole equipment can be installed higher in the wellbore.

26. If at the end of the second stage of intensification the proppant remaining in the wellbore does not allow immediate movement of the wound pipes and downhole equipment, fluid can be circulated through the circulation channel 114 to flush and clean from the proppant to release the wound pipes and bottomhole equipment and allow downhole equipment to be moved up after releasing the inflatable reusable packer.

27. The process described above is repeated until the individual excitation of all planned zones has been carried out (in Fig. 3L-3E, downhole equipment designed to excite three zones is shown).

28. After completion of the intensification process, the downhole equipment is returned to its working position and the wound pipe block and the downhole equipment are removed from the wellbore.

29. After all desired desired zones have been excited, production from the well can be immediately started.

30. If it is desired to excite additional zones, the reel of coiled pipes can be connected to slightly modified downhole equipment, as shown in FIG. 4A. In this system, the only change to the preferred embodiment of the downhole equipment described above is the addition of a mechanical plug 164 of the selective ignition kit or a packer plug 164 of the selective ignition kit installed below the lowest perforation block with selective ignition, as shown in FIG. 4A. Typically, a plug packer or crack baffle may be used as the mechanical plug 164 of the selective ignition kit. A crack baffle is usually preferred if one wants to simultaneously separate the resulting zones with a plug immediately after the intensification operation.

31. Shown in FIG. 4A, the modified downhole equipment comprises a perforation system with selective ignition (FIG. 4A shows a perforation system that includes firing guns 174, 184, 194 combined with charges 176, 186, 196, and with selective ignition heads 172, 182, 192), casing collar locator 128, hydraulic system channels 114, 116, 122, inflatable reusable packer 120, reusable mechanical axial wedge grip 124, and selective ignition packer 164 installed using selective ignition shafts 162. Modified downhole equipment is injected into the well using a lubricator and an injector head of coiled pipes suspended by a crane or a derrick above the wellhead.

32. Wound pipes and downhole equipment are injected into the well, choosing the depth using the sleeve joint locator.

33. As shown in FIG. 4A, coiled pipes and modified downhole equipment are inserted into the wellbore so as to set the mechanical plug 164 of selective ignition in position above the last previously excited zone 252.

34. As shown in FIG. 4B, the selective ignition head 162 is ignited to position the mechanical selective ignition plug 164 in a position above the last previously excited zone 252.

35. After the selective plug ignition head 162 has been actuated to install the selective plug packer 164, the wound pipes and modified downhole equipment are then lifted to a location in the wellbore in which the first (lowest) set of perforation charges 176, which contained in a perforation system with selective ignition, located directly opposite the next lower perforated zone to be perforated, moreover, the exact depth control can be half According to the testimony of the locator, 128 couplings of the casing string and wound pipe depth gauge systems are provided for in surface equipment. The action of moving the downhole equipment up to the location of the first perforated interval puts the mechanical wedge grips in the locked position, and the additional cyclic change in the axial load of the wound pipes from compression to tension and vice versa will return repeatedly installed mechanical wedge grips to the working position.

36. As shown in FIG. 4B, a first set of perforation charges 176 in a modified downhole equipment is selectively ignited by remote actuation using a second selective ignition head 172, punching the casing 82 and cement sheath 84 to obtain perforations 270, 271 through which hydraulic communication is established with formation 86.

37. If there is an insufficient gap between the previously made perforations 250, 251 and the location of the next set of perforations 270, 271, which does not allow the proper installation of downhole equipment for punching, isolation and intensification of the next set of perforations 270, then the packer plug 164 of selective ignition can be installed below the last previously excited perforations 250, 251, moreover, the inflatable repeatedly installed packer 120 can be used during the first intensification operation to isolate itself x upper perforations 270, 271 from previously excited perforations 250, 251.

38. The process described above is repeated until the individual excitation of all planned zones has been carried out (Fig. 4L-4E shows downhole equipment designed to excite three additional zones).

Those skilled in the art will readily understand that the preferred method of suspension, when using a fluid with a proppant, is conventional composite pipes or wound pipes, preferably with one or more circulation channels, allowing the proppant residue to be easily removed from the wellbore. However, for treatments such as acid fracturing or parent rock acid treatment, this may not be necessary, and they can easily be implemented with a deployment system using a cable, such as a thin suspension line or a wireline, or using a downhole tractor system.

Specialists will easily understand that, depending on the tasks of a particular technological operation, various pumping systems can be used, including: (a) pumping down into the annular space formed between the cable or pipes (if the cable or pipes are used in the deployment method) and the casing wall columns; (b) pumping down into the interior of coiled pipes or composite pipes, if the suspension method involves the use of coiled pipes or composite pipes, and excessive friction and erosion due to the proppant do not cause problems for the well of the considered depth; (c) simultaneous pumping down into the annular space formed between the pipes (if pipes are used in the deployment method) and the casing wall, and into the internal space of the pipes, if excessive friction and erosion due to the proppant do not create problems for the well of the considered depth.

In FIG. 5 shows a second embodiment of the invention in which coiled pipes are used as a deployment tool, where excessive friction and the use of a proppant are not a concern, or the proppant is not inflated during the process. In FIG. 5 shows that coiled pipes 106 are used to suspend downhole equipment and its components. In this embodiment, individual zones are processed in a sequence from the smallest locations in the wellbore to the deepest locations in the wellbore. As shown in FIG. In an embodiment, the circulation channel 114 is located below the packer 120, so that the formation fluid can be pumped down into the interior of the wound pipes 106, and then can exit through the circulation channel 114 and injected to enter predetermined perforations. As an example of the operation in FIG. 5 shows that the packer 120 can be powered and installed below the perforations 241, which are combined with the previous fracturing zone 242 of the formation. The inflatable reusable packer 120 provides such hydraulic isolation that upon subsequent pumping of the formation fluid down into the wound pipes 106, the processing fluid is forced to enter the previously performed perforations 230, 231 and creates new hydraulic fractures 232. The operations then continue and repeated accordingly for the desired number of formation zones and intervals.

In FIG. 6 shows a third embodiment of the invention in which coiled pipes are used as a deployment tool, where excessive friction and the use of a proppant are not a concern, or the proppant is not pumped during the process. In FIG. 6 shows that coiled pipes 106 are used to suspend downhole equipment and its components. In this embodiment, the processing of individual zones can be performed in any order. In this embodiment, as shown in FIG. 6, use an inflatable seal mechanism with a packer 125 spanning on both sides as a reusable seal mechanism, the circulation channel 114 being now located between the upper inflatable seal member 121 and the lower inflatable seal member 123. After actuating the upper inflatable seal member 121 and the lower inflatable seal member 123, the formation fluid may be pumped down into the interior of the wound pipes 106 and then may exit through the circulation channel 114 and pump to enter predetermined perforations. As an example of the operation in FIG. 6 shows that the upper inflatable seal member 121 and the lower inflatable seal member 123 are actuated and mounted opposite perforations 241, which are combined with the next zone to be torn. The inflatable reusable packer 120 provides such hydraulic isolation that upon subsequent pumping of the formation fluid down into the wound pipes 106, the processing fluid is forced to enter the previously performed perforations 240, 241 and creates new hydraulic fractures 242. The operations then continue and repeated appropriately for the desired number of formation zones and intervals.

In FIG. 7 shows a fourth embodiment of the invention in which a wireline 102 is used as a deployment tool to suspend downhole equipment and its components. In this embodiment, individual zones are processed in a sequence from the deepest locations in the wellbore to the smallest locations in the wellbore. In this embodiment, as shown in FIG. 7, the formation fluid may be pumped down into the annular space between the wireline 102 and the wall of the production casing 82, and then can be forced to enter predetermined perforations. In this embodiment, the inflatable reusable packer 120 also includes an internal electric pumping system 117, which is supplied with electric energy transmitted to the well via a wireline that allows inflatable re-installable packer 120 to be inflated or deflated (pumped out) using the wellbore fluid. In FIG. 7 shows that the packer 120 can be powered and mounted below the perforations 241, which are combined with the next fracture zone. Packer 120 provides such hydraulic isolation that upon subsequent pumping of the treatment fluid down into the annular space between the wireline 102 and production casing 82, the treatment fluid is forced to enter the perforations 240, 241 and creates new hydraulic fractures 242. The operations are then continued and repeated accordingly for the desired number of formation zones and intervals.

A fifth embodiment of the invention provides for the deployment of an additional string of tubing or cables, hereinafter referred to as integral hoses, inside and / or outside of the wound pipes (or composite pipes). As shown in FIG. 8A and 8B, the tubular composite hose 104 is located inside the wound pipes 106. In this embodiment, the tubular composite hose 104 is connected to a reusable seal mechanism 120, and in this embodiment, the re-installable seal mechanism 120 can be actuated by hydraulic pressure transmitted through composite hose 104. Generally speaking, a plurality of composite hoses can be deployed inside the coiled tubing and / or in the annular space between the coiled tubing and the production casing. Generally speaking, composite hoses can be used to perform many different operations, including (but not limited to) creating a (a) hydraulic connection for actuating individual downhole equipment components, including (but not limited to) the sealing mechanism and / or perforating devices;

(b) pipelines for pumping into the well or for circulating additional fluid;

(c) to collect data from downhole measuring devices. It should be borne in mind that, as shown in FIG. 8A, the downhole equipment also includes centralizers 201, 203, 205, which are used to keep the downhole equipment centered in the wellbore when its components are in working position.

The use of a composite hose (s) may allow hydraulic engagement and / or disengagement of a repeatedly mounted mechanical seal mechanism regardless of the amount of hydraulic pressure inside the wound pipes. This then allows you to expand the method for using repeatedly installed mechanical sealing mechanisms, requiring independent hydraulic actuation to perform operations. Punching devices that require hydraulic pressure for selective ignition can be actuated using a composite hose. This can then allow the use of a wired communication line, if it is deployed together with coiled pipes and downhole equipment, as a channel or channels for transmitting electrical signals, which may be desirable for collecting data from measuring instruments installed in the downhole equipment; or to drive other downhole equipment components, for example, electric downhole drive motors, which can generate rotation or torque for downhole equipment components. Alternatively, a composite hose may be used to turn on a hydraulic motor designed to actuate various downhole components (e.g., a hydraulic motor to turn on and off a repeatedly set seal mechanism).

The use of a composite hose (s) may allow pumping into the well or circulating any fluid to a variety of locations, desirable according to precise control. For example, to reduce the proppant's deposition on the seal mechanism during hydraulic proppant fracturing, a compound hose (s) can be used that allows continuous or periodic flushing and circulation to prevent the proppant from accumulating on the seal mechanism. For example, one composite hose may extend directly above a reusable mechanical seal mechanism, while another composite hose may extend directly below a reusable mechanical seal mechanism. Then, if desired, a fluid (e.g. nitrogen) can be introduced into the well for circulation at each or both locations to flush the proppant from the area surrounding the compaction mechanism, which reduces the potential risk of downhole equipment getting stuck as a result of the proppant build up. In the case of fluid circulation, the size of the composite hose and the type of fluid should be selected to provide the desired speed so that the fluid flow is not inhibited by frictional pressure in the composite hose.

In addition to composite hoses formed by a tubing string that provide hydraulic communication in the well, as a means of transmitting signals for driving components of the downhole equipment (or as a possible means of transmitting signals for registering data from downhole sensors on the surface), one or more wired communication lines or one or more fiber optic cables can be deployed in the wellbore to create an electrical or electro-optical cable with ligature in the well, as a means of transmitting signals for actuating components of the downhole equipment (or as a possible means of transmitting signals for registering data from downhole sensors on the surface).

In FIG. 9 shows a sixth embodiment of the invention in which a tractor system that includes an upper tractor drive unit 131 and a lower tractor drive unit 133 is connected to downhole equipment and is used to deploy and select this equipment in the wellbore. In this embodiment, individual zones are processed in a sequence from the deepest locations in the wellbore to the smallest locations in the wellbore. In this embodiment, the downhole equipment also includes an internal electric pumping system 117, which is supplied with electric energy transmitted to the well via a wireline 102, which allows inflating or lowering (pumping out) the inflatable reusable packer 120 using the wellbore fluid. In this embodiment, the formation fluid is pumped down into the annular space between the wireline 102 and the wall of the production casing 82, and forcibly pumped into predetermined perforations. In FIG. 9 shows that an inflatable reusable packer 120 can be driven and mounted below perforations 241 that are combined with the next fracture zone. The inflatable reusable packer 120 provides such hydraulic isolation that when the formation fluid is then pumped down into the annular space between the wireline 102 and production casing 82, the treatment fluid is forced into the perforations 240, 241 and creates new hydraulic fractures 242. The operations are then continued and repeated accordingly for the desired number of formation zones and intervals.

As an alternative to this sixth embodiment, the tractor system may be self-propelled, controlled by on-board computer systems, and it may include on-board signal processing systems, so that there is no need to use a cable or pipes to select a position, to control and / or actuate tractor system. Moreover, the control of various components of the downhole equipment can also be carried out using on-board computer systems, and these components may contain on-board signal processing systems, so that there is no need to use a cable or pipes to control and / or actuate these components. For example, the tractor system and / or downhole equipment components can have on-board energy sources (e.g. batteries), computer systems, and data transmission and reception systems, so that the tractor and downhole equipment components can be remotely controlled from the surface using remote signal processing systems , or alternatively, various on-board computer systems may be preprogrammed on the surface to carry out the desired sequence of operations when deployed to well will.

According to a seventh embodiment of the present invention, abrasive (or erosive) fluid jets are used as a means for perforating a wellbore. Jet injection of an abrasive (or erosive) fluid is a common method widely used in oil production for cutting and perforating borehole tubing strings or other components of the wellbore and wellhead. The use of coiled pipes or composite pipes as a means of suspending downhole equipment creates a deployment pipeline for an abrasive fluid jet cutting system. For this, downhole equipment includes an inkjet tool. An inkjet tool allows injection of abrasive (or erosive) fluid or slurry into a well at high pressure and at high speed, through pipes and nozzles. Abrasive (or erosive) fluid cuts the wall of the production casing, cement sheath and penetrates into the formation, providing a path of fluid flow to communicate with the formation. A random distribution of holes and slots can be obtained using a jet tool over the entire completion interval during the intensification operation. Typically, abrasive (or erosive) fluid cutting and punching can be easily performed under a wide range of pumping conditions, using a wide variety of fluids (water, gel, oils and a combination of liquids and gas) and using a wide variety of hard materials (sand, ceramic materials, etc.) if the use of abrasive solid materials is required for specific perforation of the wellbore.

The inkjet tool allows you to replace the conventional selective ignition punching system used in the previous six versions. Since this inkjet tool has a length of approximately one to four feet, the requirements for the height of the surface lubrication system (lubricator system) are significantly reduced (which can have a height of up to 60 feet or more) compared to the height requirements when using conventional punching units with selective ignition as a perforating device. Reducing the height requirements of the surface lubrication system provides many benefits, including lower costs and reduced operating time.

In FIG. 10 shows in more detail a seventh embodiment of the invention in which an inkjet tool 310 is used as a perforating device, and composite pipes 302 are used to suspend downhole equipment in a wellbore. In this embodiment, a mechanical, compressible, reusable packer 316 is used as a reusable seal device; mechanical casing string locator 318 is used to control the depth of the downhole equipment and to select its position; a full opening unidirectional shutoff valve adapter from kid type 304 is used to prevent fluid from flowing upward through the composite pipes 302; an adapter 306 of the plug assembly with a shear pin and fishing neck is used as a safety release device; the adapter 308 of the circulation channel and the channel of equalization is used to circulate the fluid and to balance pressures above and below the mechanical, set by compression, repeatedly installed packer 316 in some circumstances, the adapter 314 unidirectional shut-off ball valve is used so that the fluid can flow up from the space below the mechanical, installed by compression, repeatedly installed packer 316 only through the adapter 308 channel compasses tion and alignment of the channel.

The inkjet tool 310 comprises jet channels 312 that are used to accelerate and direct abrasive fluid pumped downward into the composite pipes 302 so that the production casing 82 experiences a direct impact of the jet. In this configuration, the mechanical casing collar locator 318 is appropriately connected to the mechanical, compressible, multiple-set packer 316, so as to allow fluid to flow upward from below from the mechanical, compressible, multi-set packer 316 , to the adapter 308 of the circulation channel and the channel alignment. The cross-sectional area of the hydraulic pipelines that are inside the adapter 308 of the circulation channel and the alignment channel is chosen so that it exceeds the cross section of the jet channels 312, so that most of the flow inside the composite pipes 302 or downhole equipment mainly flows through the adapter 308 of the circulation channel and alignment channel, and not through the jet channels 312 when the adapter 308 of the circulation channel and the alignment channel is in the open position. The adapter 308 of the circulation channel and the alignment channel opens and closes by moving up and down the composite pipe 302.

In this embodiment, composite pipes 302 are advantageously used in conjunction with a mechanical, compression-set, multiple-set packer 316, since a mechanical, compressible, multiple-set packer 316 can be easily powered on and off (deactivated) by vertical movement and / or rotation applied through composite pipes 302. Vertical movement and / or rotation is applied through composite pipes 302 by means of a unit for feeding pipes into a high-pressure well down at the mouth provided in a small mobile installation for completing a drilled well, using a power swivel unit, which are used as surface means for connecting, installing in a wellbore and removing composite pipes 302 from the wellbore. It should be borne in mind that surface equipment , methods and procedures associated with the use of a block for supplying pipes to a well with a high pressure at the wellhead, provided in a small mobile installation for completing a drilled well ins and using a power swivel unit, are conventional and well known to those skilled in the compounds installation in the wellbore under pressure and removal from the wellbore pressure composite pipes. Alternatively, the use of a small mobile installation for completing a drilled well with a power swivel unit and with a dismantling head instead of a unit for supplying pipes to the well with high pressure at the wellhead also allows connection, installation in the wellbore under pressure and removal from the wellbore under pressure composite pipes; this is also common and well-known to those skilled in the art of connecting, installing into a well bore under pressure and removing composite pipes from the well bore under pressure. It should also be borne in mind that surface equipment includes appropriate manifolds, pipes and valves, which allow flow between all relevant surface components and equipment and the wellbore, including (but not limited to) through composite pipes, the annular space between composite pipes and production casing through pumps, fluid reservoirs and backflow wells.

Since a mechanical, compressible, reusable packer is driven by vertical movement and / or rotation of the composite pipes 302, fluid can be pumped downward into the composite pipes 302 without the use of additional control valves and / or isolation valves, which might be required if the inflatable packer was used as a reusable seal device. In this case, the interior of the composite pipes 302 is used to form an independent conduit between the surface and the jet tool 310 through which the abrasive fluid can be pumped downward through the composite pipes 302 to the jet tool 310. The jet channels 312 provided on the jet tool 310 create a jet abrasive fluid having a high speed, which is directed to perforate the production casing 82 and cement sheath 84 to establish a hydraulic connection with formation 86.

In FIG. 10 shows an inkjet tool 310 that is used to create perforations 320 leading to a first machined formation interval that is excited by hydraulic fractures 322. FIG. 10 also shows an inkjet tool 310 that has been reinstalled in the wellbore and which is used to create perforations 324 in the second processing interval of the formation, the mechanical, compressible, repeatedly installed packer 316 can be actuated to provide hydraulic compaction in the wellbore previous use of perforations 324 in the second stage of a multi-stage hydraulic proppant fracturing.

It should be borne in mind that the inkjet channels 312 can be located at a distance of approximately six inches to one foot from the mechanical, installed by compression, repeatedly installed packer 316, so that after the second proppant fracturing step, above the mechanical installed for due to the compression of the repeatedly installed packer 316, the proppant causing concern is accumulated; in this case, the non-abrasive and non-erosive fluid can be pumped down into the composite pipes 302 and can enter through the jet channels 312 and / or through the adapter 308 of the circulation channel and the alignment channel to remove the proppant from above the mechanical, established by compression, repeatedly installable packer 316. Moreover, the inkjet tool 310 can be rotated (when a mechanical, compressible, repeatedly installed packer 316 is not powered) using composite pipes 302, which can be rotated by means of a surface power swivel, to further facilitate the removal of the proppant from above the mechanical, compressible, repeatedly mounted packer 316. Since the perforations are created using a jet of fluid, the seizures of the perforations are not are formed. Since there are no burrs of perforations, which are potentially a source of additional wear of the mechanical elastomers, which are installed due to the compression of the repeatedly installed packer 316, the durability of the mechanical, which is established due to the compression, repeatedly installed packer 316 can be increased in comparison with those types of application which there may be bulging perforations.

It should also be borne in mind that flow control is provided by an adapter 314 of a unidirectional shut-off ball valve, and the adapter 304 of a unidirectional shut-off valve with a fully open hinged type is used only to balance pressures above and below the mechanical, set by compression, repeatedly installed packer 316, when the pressure is lower than the mechanical set by compression, repeatedly installed packer 316 exceeds the pressure above the mechanical, set due to compression, repeatedly installed packer 316. In cases where the pressure is higher than mechanical, established by compression, repeatedly installed packer 316 exceeds pressure below mechanical, established by compression, repeatedly installed packer 316, then the pressure is higher than mechanical, set beyond the compression of the repeatedly installed packer 316 can easily be reduced by conducting a controlled backflow in the newly excited zone using an annular of the space between the flexible pipes 302, and production casing string 82, or by circulating fluid of lower density (e.g., nitrogen) through the down tube component 302 and upward in the annulus between the flexible pipes 302, and production casing string 82.

The use of an adapter 304 of a unidirectional shut-off valve with a fully open hinged type is preferable, since its design allows pumping without restriction (free pumping) of abrasive (or erosive) fluid into the well, and also allows control balls to pass, which, depending on the specific parts of individual downhole equipment components may fall from the surface into the fluid flow for control or into the hydraulic system of individual downhole components equipment, or to ensure the safe release of this equipment. Depending on the specific design of the instrument, various configurations can be used to provide the functionality of the flow control valves (fountain valves) described in this embodiment.

As an alternative to the indicated seventh embodiment, an adapter may be used that contains a fitting (nipple) that allows for the suspension or retention of other measuring devices or components of the downhole equipment. This fitting, for example, can hold a conventional casing collar locator and a gamma ray tool that is deployed using a wired communication line and installed in the fitting, and which can be used to further diagnose the position of downhole equipment and the location of formation intervals of interest . Additionally, various abrasive inkjet tools can be deployed as part of the downhole equipment to control perforation cutting characteristics, such as hole (slit) size and cutting speed, which allow the use of various abrasive materials and / or provide redundancy of the system in case of premature component failure.

Specialists will easily understand that many different components can be used in downhole equipment. The downhole equipment may have a configuration that includes means for measuring reservoir, fluid, and wellbore parameters that are considered desirable for a given application. For example, temperature and pressure sensors can be used to measure the temperature and pressure of a well fluid during processing; a densimeter can be used to measure the effective density of the borehole fluid (which is especially useful for determining the distribution in the borehole and finding the location of the proppant during hydraulic proppant fracturing); and a radioactive detection system (e.g., gamma ray or neutron measurement systems) can be used to localize hydrocarbon-bearing zones or to identify or localize radioactive material in a wellbore or formation.

Depending on the presence of specific components of the downhole equipment and whether the punching device creates perforation holes with scuffs that can damage the sealing mechanism, the downhole equipment may have a tool to remove perforation scuffs that allows you to scrape and remove perforation scuffs from the casing wall.

Depending on the presence of specific components of the downhole equipment and whether excessive wear of the components of the downhole equipment can occur if it moves in contact with the casing wall, centralizer adapters can be used in the downhole equipment to mechanically select the position of the downhole equipment and eliminate or reduce the risk its damage when moving in contact with the casing wall.

Depending on the presence of specific components of the downhole equipment and on whether charges for punching can create strong shock waves and cause harmful vibrations when they are ignited, the downhole equipment may contain vibration and shock damping adapters that eliminate or minimize harmful effects on system parameters due to detonation of charge for perforation.

Depending on the deployment system used and the tasks of a particular technological operation, perforating devices and any other desired downhole equipment components may be installed above or below the reusable seal mechanism, and in a desirable order relative to each other. The deployment system itself, regardless of whether it is made in the form of a wireline, electrical wire, coiled pipes, conventional composite pipes, or a downhole tractor, can be used to transmit signals to actuate the compaction mechanism and / or perforating device. It is also possible to suspend such signal transmissions inside conventional composite pipes or coiled pipes which are used to suspend the sealing device itself and the perforating device. Alternatively, signal transmission means, whether electric, hydraulic or otherwise, can pass through a channel located outside the suspension means, or even located in one or more separate turns of wound pipes or conventional composite pipes.

When using highly viscous fluids in wells with a depth of approximately more than 8,000 feet, many significant technological and economic advantages can be obtained by applying the present invention. Reducing the frictional pressure allows fracturing in deeper wells and reduces the requirements for special fracturing fluid compositions. The reduction or elimination of frictional pressure occurs because a fluid with a high viscosity can be pumped down into the annular space between wound pipes or other means of suspension and production casing. Since there is a decrease in frictional pressure compared with high viscosity fluid pumping systems down into the inner space of coiled pipes, the depth of the wells in which such technology can be used is significantly increased. For example, in the case of deploying 1-1 / 2 inch wound pipes in a casing string of 17 pounds per foot with an outer diameter of 5-1 / 2 inches, the effective flow cross section is roughly equivalent to a casing string with an outer diameter of 5 inches. At the indicated effective flow cross sections, hydraulic fracturing can be carried out in wells up to 20,000 feet deeper and deeper, and higher injection rates (e.g., from about 10 to 30 barrels per minute or more) can be achieved to efficiently transport the proppant and for hydraulic fracturing using high viscosity fluids.

Since the annular space can usually have a larger equivalent cross-sectional area, a conventional fracturing fluid can be used instead of a special fluid with a low viscosity (such as Oosk fluid \\ 's11-Zc111itSgdsg'5 C1eagEgas ™), which is used to reduce frictional pressure drop through wound pipes. The use of technology with conventional fluid for fracturing allows the processing of formations at temperatures above 250 ° E, above which the currently available expensive special fluids can begin to degrade.

As a sealing mechanism can be used: inflatable device; mechanical, installed by compression, repeatedly installed packer; mechanical, installed by compression, covering on both sides of the packer; plug-type seal devices, as well as any other alternative devices that can be deployed by means of a suspension and provide a reusable hydraulic seal or perform an equivalent function. There are both inflatable and compression-mounted devices that provide such a radial clearance between the sealing elements and the casing wall (for example, from about 0.25 to 1 inch for inflatable devices and 0.1-0.2 inches for installed due to compression of devices), that the wear of the sealing elements is significantly reduced or completely eliminated. According to a preferred embodiment of the present invention, there is a sufficient gap between the sealing mechanism in its inoperative state and the casing wall, which allows for quick movement of the borehole entry and exit from the wellbore without significant damage to the sealing mechanism or without pressure control associated with with pressure pulsations or with well swabbing as a result of tool movement. The increased clearance between the seal surface and the casing wall (when the seal mechanism is not actuated) also allows the introduction of wound pipes and downhole equipment into the well and withdrawal from it at substantially higher speeds than is possible using currently available systems with wound pipes. In addition, in order to minimize the possibility of unwanted wear, in accordance with a preferred embodiment, the perforating device allows such a perforation of the casing wall to produce a relatively smooth edge of the perforation. Alternatively, a mechanical, reusable seal mechanism may not create an ideal hydraulic seal and may, for example, leave a small gap around the perimeter of the device. The size of such a small gap can be chosen so as to create a sealing mechanism (if necessary) when the proppant closes this gap, and to eliminate the seal (if necessary) due to the circulation of the fluid. Moreover, depending on the specific type of application, it is possible to carry out cost-effective work on stimulation of the formation, even if the ideal hydraulic seal is not obtained using a mechanical, repeatedly installed seal mechanism.

Since the punching device is deployed simultaneously with a repeatedly installed sealing mechanism, the depth control of all components can be carried out at the same time (simultaneously) using the same measurement standard. This eliminates the problems of depth control that are inherent in existing methods when punching operations and intensification operations are carried out using two different measurement systems at different times and at different movements in the wellbore. Very precise depth control can be achieved through the use of a casing collar locator, which is used in the preferred depth control method.

The height of each of the individual perforated predetermined intervals in accordance with the present invention is not limited, which contrasts with the case of previously known pipe wound systems and using a packer spanning both sides in which the height of the perforated interval is limited to 15-30 feet.

Since the use of permanent packer plugs is not mandatory, the increase in cost and risk in the wellbore associated with drilling operations of packer plugs is excluded.

When using coiled pipes as a deployment tool, it is possible to use a string of coiled pipes used for the intensification operation as a production string of tubing suspended at the wellhead, which leads to a significant reduction in cost by eliminating the need to mobilize (move) the rig at the location of the well for installing a conventional tubing production string consisting of composite pipes.

Controlling the sequence of zones to be processed allows you to optimize individual processing steps based on the characteristics of each individual zone. Moreover, the probability of not optimal intensification due to the simultaneous processing of multiple zones is significantly reduced if there is only one open set of perforations for each processing step. For example, in the case of hydraulic fracturing, the present invention minimizes the likelihood of excessive flushing or insufficient introduction of the proppant into the fracture. In addition, in the event of a problem leading to the need to stop processing, the zones to be excited in the upper part of the well are not at risk, as they are not yet perforated. This contrasts with conventional intensification methods using a sealing ball or coiled tubing in which all perforations must be punched before the intensification is performed. In the event of failure during intensification using conventional coiled pipes, it is extremely difficult to efficiently deviate and excite in a long completion interval. In addition, if only one set of perforations is open above the seal element, then the fluid can circulate without the possibility of breaking down into a plurality of sets of open perforations above the upper part of the seal element, as can be the case in a conventional process using wound pipes. This can minimize or eliminate fluid loss and formation damage when the circulation pressure in the face exceeds the pressure in the pores of the formation.

Pumping for the entire treatment can be carried out by performing a single pass in the well, which leads to a significant reduction in cost compared to other technologies that require many movements of the wireline or other equipment into the well and back between the processing steps.

The invention can be used for multi-stage treatments in deviated or horizontal wellbores.

Typically, other conventional deviation technologies in deviated or horizontal wellbores are more promising given the nature of the fluid transporting the deflecting material at long intervals, which are typically found in deviated or horizontal wellbores.

If sand precipitation occurs during hydraulic fracturing, the invention provides a method for immediately pumping out a fluid containing sand in the annular space from the well, so that the intensification operation can be resumed without wound pipes and downhole equipment from the well. The presence of a coiled pipe system creates a means of measuring downhole pressure after perforation or during intensification operations, based on pressure calculations in the coiled pipe string when the well stops (or at a low flow rate).

The presence of a coiled pipe system or conventional composite pipes, if used as a deployment tool, makes it possible to pump fluid into the well regardless of the fluid pumped into the annular space. This can be used, for example, in such additional applications as: (a) cleaning the sealing mechanism of the downhole equipment and hydraulic system channels from the accumulation of proppant (which can cause a tool jam) by pumping fluid into the well at a nominal speed to clean the mechanism seals and hydraulic channels; (b) downhole mixing (which is discussed in more detail below); (c) pouring acid into the well during perforation to help clean the perforation and improve communication with the formation; and (d) independent excitation of two zones isolated from each other by means of a repeatedly set compaction mechanism. Essentially, if pipes are used as a deployment tool, then depending on the desired specific operations and the specific components of the downhole equipment, the fluid can circulate in the well all the time, or only when the sealing element is actuated, or only when the sealing element is turned off, or when the equalization (pressure) channels are open or closed. Depending on the specific components of the downhole equipment and the specific design of the downhole flow control valves, which can be used, for example, as integral components of the alignment channel adapters, circulation channel adapters or hydraulic system adapters, downhole flow control valves can be controlled using a wired communication line, due to actuation hydraulically, due to actuation by flow, due to actuation by _ ) valves, due to actuation by means of a sliding sleeve, or by many other means known to specialists in the field of actuation of downhole flow control valves.

The coiled tubing system also allows for controlled backflow in individual processing steps to facilitate cleaning and closing the gap. The backflow can flow up through the annular space between the coiled tubing and the production casing, or, alternatively, the backflow can even flow up through the coiled tubing if excessive backflow of proppant does not cause problems.

As a punching device, any commercially available punching system can be used. Among such systems, there are systems with so-called selective ignition, in which a single perforation unit contains many charges or sets of charges for perforation. Each individual set of one or more charges for perforation can be remotely controlled and ignited from the surface using telecommunications, radio communications, pressure, fiber optics or other means of actuation. Each set of charges for punching has design parameters (number of charges, number of holes per foot, hole size, penetration characteristics) that allow punching optimal perforations in an individual zone to be processed using an individual step. At the current level of technology, selectively ignited rotary hammers, there are commercially available punching systems that allow you to perforate sequentially from approximately 30 to 40 intervals with a single pass in the well. First you should choose such a design and a size of the punch, which allows you to punch many sets of perforations. Hammers can be located at any location on the downhole equipment, including above or below the mechanical, reusable seal mechanism.

Processing intervals can be grouped based on the properties of the collector, the processing parameters, or the limiting characteristics of the equipment. After creating each group of intervals (containing mainly approximately from 5 to 20 intervals), at the end of the working day (often determined by light conditions) or when difficulties arise when sealing one or several zones, a packer plug or other mechanical device is mainly used to isolate the group already processed intervals from the next group of intervals51 to be processed. One or more packer plugs installed by selective ignition or crack baffles can be inserted together with downhole equipment and installed during the completion operation to ensure mechanical isolation between the perforated intervals and eliminate the need for a separate wireline to install mechanical isolation devices or deviation agents between groups of break stages.

In general, the proposed method can easily be used in production casing strings with diameters from 4-1 / 2 inches to 7 inches, using existing punching systems and mechanical, repeatedly installed sealing mechanisms. The proposed method can be used in smaller or larger casing strings using mechanical, repeatedly installed sealing mechanisms designed accordingly for said smaller or large casing strings.

When using perforators with selective ignition, each individual perforator can have a length of approximately 2 to 8 feet and contain approximately 8 to 20 charges for perforation placed along the perforator pipe with a hole density of 1 to 6 holes per foot, and mainly from 2 to 4 holes per foot. According to a preferred embodiment, from 15 to 20 individual perforators can be stacked together, with the assembled perforator system having a total length of less than about 80-100 feet. A system with such a full length can easily be inserted into the wellbore using an existing surface system with a crane and a lubricator. Longer systems can also be used, however, they may require the use of additional or special surface equipment, depending on the total number of perforators forming a complete punching device. It should be borne in mind that in some unique applications, the length of the perforators, the number of charges in one perforator and the density of the holes can be more or less than those indicated above, since the final parameters of the perforation system depend on the specific characteristics of the formation crossed by the borehole to be excited .

To minimize the full length of the punch system and downhole equipment, it may be desirable to use a plurality (two or more) of charge carriers uniformly distributed and tied, welded or otherwise attached to wound pipes, or mounted below a mechanical, reusable seal mechanism. For example, if it is desirable to initiate 30 zones when each zone is perforated with a 4-foot punch, a single punch unit will have a total length of about 150 feet, which is impractical to control from the surface. Alternatively, two perforation units mounted opposite each other on wound pipes can be used, each unit containing 15 perforators, with a total length of approximately 75 feet, making it easy to control from the surface using existing crane and lubricator systems.

An alternative embodiment of the construction of a perforator or perforators provides for the installation of one or more perforators above a repeatedly installed mechanical sealing mechanism. Two or more separate perforation blocks are used, fixed so that the charges are oriented in the direction of removal from downhole equipment components or from wound pipes. A single unit with more densely loaded charges can also be used, and the ignition mechanisms provide for the simultaneous ignition of only one subset of charges in a given interval, possibly all charges for one given phase orientation.

Although the perforating device described in this embodiment uses remote ignition of charges or a jet of fluid to perforate the casing and cement sheath, alternative perforating devices may be used within the scope of the present invention, including (but not limited to) devices chemical dissolution or cutting devices for drilling and milling, allowing you to create a path of fluid movement between the wellbore and the surrounding formation. In the description of the present invention, the term perforating device is used in a broad sense and includes all previously mentioned and other existing devices that can be suspended in the wellbore to actuate charges or other perforating means that can be introduced using a casing string or using an external device relative to the bottomhole equipment, or using the method of suspension of the bottomhole equipment.

The downhole equipment may have a downhole motor or other mechanism for generating rotation or a moment of rotation for actuating mechanical sealing mechanisms requiring the creation of rotation or a moment of rotation for putting them into action. Such a device, in combination with an orientation device (for example, a gyroscope or a compass), allows oriented perforation in which perforations are made in the preferred direction. Alternatively, if conventional composite pipes are used, it is possible to transfer rotation or torque to the well due to the direct rotation of the composite pipes using a rotation drive, which is available in conventional well workover rigs. Downhole sensors can also be deployed as downhole equipment elements for measuring conditions in the well (casing collar locator, pressure sensors, temperature sensors, as well as other sensors) that allow real-time monitoring of intensification operation parameters, reservoir characteristics and / or well performance.

In addition to a reusable mechanical deflection device, other materials and deflection devices may be introduced into the well during processing, including (but not limited to) compaction balls or powder material such as sand, ceramic material, proppant, salt, paraffins , resins or other organic and inorganic compounds; or alternative fluids, such as viscosifying fluids, gel-forming fluids, foamed materials, or other chemically formed fluids, or other pumped deflection agents. Additional deviation material can be used to reduce the processing time of the intensification by reducing the number of settings of the mechanical deviation device, however, while maintaining the possibility of deviation in many zones. For example, in a 3,000 foot interval in which individual zones are processed at nominal intervals of 100 feet, it may be desirable to use a reusable mechanical deflection device operating in increments of 500 feet up the wellbore and then deflect each of the six steps with a deflection agent carried by processing fluid. Alternatively, entry restriction technology can be used for multiple intervals when it is desired to process a subset of a large interval. Each of these possibilities reduces the number of mechanical installations of a mechanical deflection device and, possibly, increases its effective durability.

If the tubing string is used as a deployment tool, then the pipes allow deployment of downhole mixing devices and apply downhole mixing technology. More precisely, the tubing string can be used to pump chemicals into the well and then through the channels of the hydraulic system into the downhole equipment, followed by mixing with the fluid, which is pumped into the pipes through the annular space of the production casing. For example, during hydraulic fracturing, it may be desirable to inject nitrogen or carbon dioxide into the borehole pipes and mix them in the borehole with a treatment fluid to produce a backflow with nitrogen or carbon dioxide.

The described method and device can be used to process vertical, inclined or horizontal boreholes. For example, the invention provides a method for generating a plurality of vertical (or substantially vertical) fractures to intersect horizontal or inclined wellbores. This technology allows cost-effective completion of multiple wells from a single work site. Processing can also be carried out for wells with many lateral branches, whereby the deepest branch is processed first, then a plug is inserted or a sealing sleeve is activated to isolate this lower branch, then the next branch upstream of the borehole is processed, then another a plug or drive another sealing sleeve to isolate this branch; and repeating the process for processing the desired number of branches in one wellbore.

If selectively ignited rotary hammers are used, although it is desirable to process the maximum number of intervals, the use of short rotary hammers (for example, with a length of 4 feet or less), in some cases limits the productivity of the well by creating an increased pressure drop in the areas closest to the well collector compared to using longer perforators. Well productivity can likewise be limited if only a short interval (for example, with a length of 4 feet or less) is perforated using an abrasive jet. At the same time, the likelihood of an excessive reverse flow of the proppant increases, which leads to a decrease in the intensification efficiency. The reverse flow should preferably have a controlled flow rate to limit the potential reverse flow of the proppant. Depending on the intensity of the reverse flow, a polymer coated proppant or alternative perforator configurations can be used to increase the intensification efficiency.

In addition, if the pipes or cable are used as a deployment tool, then, to direct potential impact of the proppant on the pipes or cable during direct impact of the fluid with the proppant, when it is pumped into the pumping channels with a lateral outlet, at the wellhead an isolation device should be formed. Such an isolation device may have a flange connected to a short length of pipe that is inserted down the center of the wellhead, several feet below the injection channels. Downhole equipment and pipes or cable pass inside the pipe insulation device. In this case, the pipe of the insulation device deflects the proppant and isolates the pipe or cable from a direct impact of the proppant. The specified insulation device has a pipe of appropriate diameter, allowing free passage of downhole equipment and pipes or cable of large diameter. The length of the isolation device is chosen so that in case of damage the lower main valve still remains closed and it is possible to carry out the corresponding dismantling of the wellhead to remove the insulation tool. Depending on the type of intensification fluids and the injection method, an isolation device may not be needed if there is no erosion problem. Despite the fact that field tests of insulation devices indicate that there are no erosion problems associated with the technology used, there is some risk of erosion damage to the pipes of the insulation tool due to obstructions in its removal. When using an insulating tool, it is preferable to maintain the collision rate of the erosive fluid with the insulating tool below approximately 180 feet per second, and even better, below approximately 60 feet per second.

Another concern with the use of this technology is the premature loss of sand from the sand carrier during hydraulic fracturing, which can occur with inaccurate measurement of the movement of the fluid during pumping, since it is difficult to initiate a break using fluid with proppant through the next zone to be perforated. It may be desirable to use KC1 fluid or other non-gel-forming fluid or fluid to create a pad, instead of a pad of gel-forming fluid, to better initiate fracturing in the next zone. Pumping at a higher speed of a non-gel-forming fluid between the steps to provide turbulent flushing and swirling of the casing minimizes the risk of proppant loss. In addition, emergency perforators, which are provided on the tool string, allow you to continue the technological operation after the corresponding waiting time.

Despite the fact that the above options are primarily associated with the advantages of the proposed method when applied to hydraulic fracturing processes, this does not limit the claimed invention, which can be used in any situation in which it is advantageous to perforate and perform other well operations with one the passage in the wellbore. Despite the fact that the preferred embodiment of the invention has been described, it is very clear that it will be modified and supplemented by those skilled in the art, which do not, however, go beyond the scope of the following claims.

Claims (44)

CLAIM 1. A method for perforating and processing multiple intervals of one or more subterranean formations intersected by a wellbore, comprising the following operations: (a) deploying downhole equipment using a deployment tool inside the wellbore, the bottomhole equipment having a punching device and a compaction mechanism; (b) installing downhole equipment at a predetermined position within the wellbore using a depth control device; (c) using a punching device to punch a spacing; (ά) actuating the sealing mechanism to create a hydraulic seal in the wellbore; (e) pumping a treatment fluid into the wellbore and in the perforations created by the perforation device without removing the perforation device from the wellbore; (ί) release of the sealing mechanism; (e) repeating operations (b) - (£) for at least one additional interval of one or several subterranean formations. 2. The method according to claim 1, in which the deployment tool is selected from the group, which includes a wired communication line, a thin suspension line and a cable. 3. The method according to claim 1, in which the deployment tool is a tubing string. 4. A method for perforating and processing multiple intervals of one or more subterranean formations intersected by a wellbore, comprising the following operations: (a) deploying downhole equipment using a deployment tool selected from the group consisting of a wired communication line, thin suspension line and cable inside the wellbore, moreover, said bottomhole equipment has a device for punching and a compaction mechanism; (b) using a punching device to punch a spacing; (c) actuating a seal mechanism to create a hydraulic seal in the wellbore; (6) pumping the treatment fluid into the wellbore and in the perforations created by the perforation device, without removing the perforation device from the wellbore; (e) release of the sealing mechanism; (ί) repeating operations (b) - (e) for at least one additional interval of one or more subterranean formations. 5. The method according to claim 3, in which the tubing string is selected from the group consisting of coiled tubing and composite tubing. 6. The method according to claim 1 or 4, in which the downhole equipment is installed at a predetermined position within the wellbore using a depth control device selected from the group comprising a casing coupling locator and a measurement system located on the surface. 7. The method according to p. using an electrical or optical signal transmitted through a cable deployed in the wellbore. 8. The method of claim 3, wherein the perforating device is a jet cutting device that uses fluid pumped down into the tubing string to establish hydraulic communication between the wellbore and one or more intervals of one or more subterranean formations. . 9. The method of claim 3, wherein the treatment fluid is pumped down into the annular space between the tubing string and the wellbore. 10. The method of claim 9, wherein the treatment fluid is also pumped down into the tubing string through the channels in the downhole equipment and further into the perforations. 11. The method of claim 9, wherein the second treatment fluid is pumped down into the tubing string through the channels in the downhole equipment and further into the perforations. 12. The method of claim 11, wherein the second treatment fluid is nitrogen. 13. The method according to claim 1 or 4, in which the sealing mechanism is a multiple installable packer. 14. The method according to claim 1 or 4, wherein the treatment fluid is selected from the group consisting of an acid solution, an organic solvent, a proppant suspension and a transporting fluid. 15. The method according to claim 1 or 4, which further comprises an operation to deploy at least one deflection agent in the wellbore to block additional fluid flow for the perforation treatment, prior to the release of the sealing mechanism. 16. The method according to claim 15, wherein the deflection agent deployed in the wellbore is selected from the group consisting of powders, gels, viscous fluids, foams and sealing balls. 17. The method according to claim 1 or 4, in which the sealing mechanism is driven by hydraulic pressure transmitted from the surface through a composite hose. 18. The method according to claim 1 or 4, in which the device for perforating is driven by the hydraulic pressure transmitted from the surface through the composite hose. 19. The method according to claim 1 or 4, in which the device for perforating is driven by hydraulic pressure transmitted from the surface through the borehole. 20. The method according to claim 3, in which the device for perforating is driven by the hydraulic pressure transmitted from the surface through the tubing string. 21. The method according to claim 1 or 4, in which the face equipment is moved to a different position within the wellbore before actuating the sealing mechanism. 22. An intensification system for use in perforating and processing multiple intervals of one or more subterranean formations intersected by a well bore, containing the following components: (a) treatment fluid; (b) deployment tool, selected from the group consisting of a wired communication line, a thin suspension line and a cable, deployed inside the wellbore; (c) downhole equipment, capable of being deployed in the wellbore by means of a deployment tool and having at least one device for perforating, allowing for sequential perforation of a plurality of intervals, and at least one sealing mechanism, while the bottomhole equipment is adapted to installation in a predetermined position within the wellbore, which allows you to actuate the device for punching and sealing mechanism; (d) moreover, the sealing mechanism is designed to create a hydraulic seal in the wellbore and depressurize the hydraulic seal, which allows the bottomhole equipment to be rearranged to a different position inside the wellbore, thereby allowing each of the multiple intervals to be treated to be treated with the treatment fluid separate from other processing intervals. 23. An intensification system for use in perforating and processing multiple intervals of one or more subterranean formations intersected by a well bore, containing the following components: (a) treatment fluid; (b) deployment tool deployed within the wellbore; (c) downhole equipment, configured to be deployed in the wellbore using a deployment tool and containing at least one punching device to enable sequential punching of multiple intervals, and at least one compaction mechanism, the downhole equipment being configured to to a predetermined position inside the wellbore using a depth control device, which allows actuating the device for punching and mechanics zm seals; (d) moreover, the sealing mechanism is designed to create a hydraulic seal in the wellbore and depressurize the hydraulic seal, which allows the bottomhole equipment to be rearranged to a different position inside the wellbore, thereby allowing each of the multiple intervals to be treated to be treated with the treatment fluid separate from other processing intervals. 24. A device for use in perforating and processing multiple intervals of one or more subterranean formations intersected by a well bore, comprising the following components: (a) a downhole equipment adapted to be deployed in a wellbore using a deployment tool selected from the group consisting of a wired communication line, a thin suspension line and a cable, and containing at least one punching device for sequentially punching a plurality of intervals, and at least one sealing mechanism; (B) moreover, the sealing mechanism is designed to create a hydraulic seal in the wellbore and depressurize the hydraulic seal, which allows the bottomhole equipment to be rearranged to another position within the wellbore, thereby allowing each of the multiple intervals to be processed to be processed separately from other intervals processing. 25. A device for use in perforating and processing multiple intervals of one or more subterranean formations intersected by a well bore, containing the following components: (a) downhole equipment adapted to be deployed in the wellbore using a deployment tool and installed at a predetermined position within the wellbore using a depth control device and containing at least one perforating device for sequentially perforating a plurality of intervals, and at least least one sealing mechanism; (b) wherein the sealing mechanism is designed to create a hydraulic seal in the specified wellbore and with the possibility of depressurization of the hydraulic seal, which allows the bottomhole equipment to be rearranged to another position inside the wellbore, thereby making it possible to process each of the multiple intervals to be processed separately from other processing intervals. 26. A device for use in perforating and processing multiple intervals of one or more subterranean formations intersected by a well bore, comprising the following components: (a) a downhole equipment having at least one punching device for sequentially punching a plurality of intervals, at least one compaction mechanism and at least one tractor device; (b) wherein the tractor unit is adapted to rearrange the face equipment to different positions in the wellbore; (c) wherein the sealing device is adapted to create a hydraulic seal in the wellbore and allows depressurization of the hydraulic seal, which makes it possible to rearrange the bottomhole equipment to a different position within the specified wellbore, thereby ensuring that each of the multiple intervals to be processed can be processed separately from other intervals processing. 27. The device according to claim 25, wherein the deployment means is a tubing string. 28. The apparatus of claim 27, wherein the tubing string is selected from the group consisting of coiled tubing and composite tubing. 29. The device according to claim 25, wherein the deployment means is selected from the group consisting of a wired communication line, a thin suspension line and a cable. 30. Device according to one of claims 24 to 26, which further comprises a depth control means for installing the downhole equipment at a predetermined position in the wellbore and selected from the group consisting of a casing joint coupling locator and a measurement system located on the surface. 31. The device according to one of p-26, in which the sealing mechanism is a multiple installer packer. 32. Device according to one of claims 24 to 26, in which the device for perforating is a firing gun with selective ignition, containing a plurality of sets having one or more shaped charges for perforating, each of these sets being configured to individually control and cast into action with the help of an electrical signal transmitted through a wire line, deployed in the wellbore. 33. Device according to one of claims 24 to 26, in which the device for perforating is activated by means of hydraulic pressure transmitted from the surface through said borehole. 34. The device according to claim 27, wherein the device for perforating is activated by means of hydraulic pressure transmitted from the surface through the tubing string. 35. The device according to claim 27, wherein the punching device is a jet cutting device that uses fluid pumped down into the tubing string to establish hydraulic communication between the wellbore and one or more intervals of one or more subterranean formations . 36. The method according to claim 1 or 4, in which the sealing mechanism is actuated in such a way as to set the hydraulic seal below the perforated interval. 37. A method of perforating and processing multiple intervals of one or more subterranean formations intersected by a wellbore, comprising the following operations: (a) deploying downhole equipment within the wellbore, comprising a device for perforating, a sealing mechanism and at least one pressure equalization means; (b) using a punching device to perforate an interval in one or more subterranean formations; (c) actuating a seal mechanism to create a hydraulic seal in the wellbore; (b) pumping the treatment fluid into the wellbore and in the perforations created by the perforation device without removing the perforation device from the wellbore; (e) equalizing the pressure between the wellbore sections above and below the compaction mechanism using at least one pressure equalizing means; (D) release of the sealing mechanism; (e) repetition of operations (b) - (D) for at least one additional interval of one or several subterranean formations. 38. A method of perforating and processing multiple intervals of one or more subterranean formations intersected by a well bore, comprising the following operations: (a) deploying downhole equipment within the well bore, comprising at least one punching device and at least one compaction mechanism, the punching device being installed below the compaction mechanism; (b) using at least one punching device to perforate the interval in one or more subterranean formations; (c) actuating at least one compaction mechanism to create a hydraulic seal in the wellbore; (b) pumping the treatment fluid into the wellbore and in the perforations created by the perforation device without removing the perforation device from the wellbore; (e) release of the sealing mechanism; (D) repetition of operations (b) - (e) for at least one additional interval of one or several subterranean formations. 39. The method of claim 38, wherein the perforation device does not have a channel for flushing fluid. 40. A method according to one of claims 37 to 39, in which the bottomhole equipment is repositioned to a different position in the well bore and the sealing mechanism is activated to create a hydraulic seal below the perforated interval. 41. A method of perforating and processing a plurality of intervals of one or more subterranean formations intersected by a wellbore, the plurality of intervals including the deepest predetermined interval and successively smaller predetermined intervals and the method comprises the following operations: (a) deploying inside the wellbore downhole equipment comprising a punching device and a compaction mechanism, the punching device being installed below the compaction mechanism; (b) using a punching device to punch the deepest predetermined interval of one or more subterranean formations; (c) pumping the treatment fluid into the wellbore and in the perforations created in the deepest interval with a perforation device, without removing the perforation device from the well bore; (6) installing the downhole equipment at a predetermined position in the wellbore and using a device for perforating to perforate the next successively smaller, predetermined interval of one or more underground formations; (e) repositioning the downhole equipment in the wellbore and activating a seal mechanism for hydraulic isolation of the perforations created in the next successively smaller predetermined interval from the perforated deepest predetermined interval; (!) pumping fluid for processing into the wellbore and in perforations created in the next successively smaller predetermined interval using a device for punching, without removing the device for punching from the well bore; (e) release of the sealing mechanism; (11) repeating operations (6) - (d) for at least one additional successively smaller specified interval of one or several subterranean formations, moreover, perforations created in at least one additional successively smaller predetermined interval are hydraulically isolated from the perforated below intervals . 42. A device for use in perforating and processing multiple intervals of one or more subterranean formations intersected by a well bore, comprising bottomhole equipment adapted to be deployed in a well bore using a deployment means and containing at least one perforating device intended for sequentially perforating a plurality intervals, at least one seal mechanism and at least one pressure equalization means, the seal mechanism being made with the ability to create a hydraulic seal in the wellbore; the pressure equalization means is arranged to equalize the pressure between the wellbore sections above and below the seal mechanism and the seal mechanism is additionally configured to depressurize the hydraulic seal to enable the downhole equipment to move to another position in the wellbore to allow each of the multiple intervals to be processed separately from other intervals about work 43. A device for use in perforating and processing multiple intervals of one or more subterranean formations intersected by a well bore, comprising bottomhole equipment adapted to be deployed in a well bore using a deployment means and containing at least one perforating device intended for sequential perforating a plurality intervals, and at least one sealing mechanism, and the device for punching is set below the sealing mechanism tions; the sealing mechanism is designed to create a hydraulic seal in the wellbore and to depressurize the hydraulic seal to move the bottomhole equipment to a different position in the wellbore to allow each of the multiple intervals to be processed separately from other processing intervals. 44. The device according to item 43, in which the device for punching does not have a channel for flushing fluid.