MXPA02007728A - Method and apparatus for stimulation of multiple formation intervals. - Google Patents

Method and apparatus for stimulation of multiple formation intervals.

Info

Publication number
MXPA02007728A
MXPA02007728A MXPA02007728A MXPA02007728A MXPA02007728A MX PA02007728 A MXPA02007728 A MX PA02007728A MX PA02007728 A MXPA02007728 A MX PA02007728A MX PA02007728 A MXPA02007728 A MX PA02007728A MX PA02007728 A MXPA02007728 A MX PA02007728A
Authority
MX
Mexico
Prior art keywords
drilling
borehole
sealing
bha
fluid
Prior art date
Application number
MXPA02007728A
Other languages
Spanish (es)
Inventor
Lawrence O Carlson
Original Assignee
Exxonmobil Upstream Res Co
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Priority to US18268700P priority Critical
Priority to US24425800P priority
Application filed by Exxonmobil Upstream Res Co filed Critical Exxonmobil Upstream Res Co
Priority to PCT/US2001/004635 priority patent/WO2001061146A1/en
Publication of MXPA02007728A publication Critical patent/MXPA02007728A/en

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Classifications

    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/11Perforators; Permeators
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B23/00Apparatus for displacing, setting, locking, releasing, or removing tools, packers or the like in the boreholes or wells
    • E21B23/001Self-propelling systems or apparatus, e.g. for moving tools within the horizontal portion of a borehole
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B23/00Apparatus for displacing, setting, locking, releasing, or removing tools, packers or the like in the boreholes or wells
    • E21B23/14Apparatus for displacing, setting, locking, releasing, or removing tools, packers or the like in the boreholes or wells for displacing a cable or cable-operated tool, e.g. for logging or perforating operations in deviated wells
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00Sealing or packing boreholes or wells
    • E21B33/10Sealing or packing boreholes or wells in the borehole
    • E21B33/12Packers; Plugs
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/14Obtaining from a multiple-zone well
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25Methods for stimulating production

Abstract

The invention provides an apparatus and method for perforating and treating multiple intervals of one or more subterranean formations (86) intersected by a wellbore by deploying a bottom hole assembly having a perforating device (134) and at least one sealing mechanism (120) within said wellbore. The perforating device (134) is used to perforate the first interval to be treated. Then the bottom hole assembly is positioned within the wellbore such that the sealing mechanism (120), when actuated, establishes a hydraulic seal in the wellbore to positively force fluid to enter the perforations (230, 231) corresponding to the first interval to be treated. A treating fluid is then pumped down the wellbore and into the perforations (230, 231) created in the perforated interval. The sealing mechanism (120) is released, and the steps are then repeated for as many intervals as desired, without removing the bottom hole assembly from said wellbore.

Description

J METHOD AND APPARATUS FOR THE STIMULATION OF INTERVALS OF MULTIPLE TRAINING FIELD OF THE INVENTION This invention is generally concerned with the field of drilling and treatment of underground formations to increase oil and gas production thereof. More specifically, the invention provides apparatus and a method for multiple perforating and treating intervals without the need to remove equipment from the sweeper between tiers or steps.
BACKGROUND OF THE INVENTION When a hydrocarbon-bearing underground deposit formation does not have sufficient flow permeability for hydrocarbons to flow to the surface in economic quantities or at optimum rates, hydraulic fracturing or chemical stimulation (usually acid) is often used to increase the capacity of the hydrocarbon. flow. A hole penetrating an underground formation commonly consists of a metal tube (ademe) cemented to the original drill hole. The holes (perforations) are placed to penetrate through the cement wall and envelope surrounding the ademe to allow the hydrocarbon to flow into the hole and, if necessary, allow treatment fluids to flow from the borehole to the formation.
Hydraulic fracturing consists of injecting fluid (usually gels or slimming, non-Newtonian viscous slimming emulsions) into a formation at such high pressures and velocities that the deposit rock -falla forms a flat, usually vertical fracture (or fracture network). ) very similar to the fracture that extends through a log of wood as a wedge and driven to it. Granular support material, such as sand, ceramic beads or other materials, is generally injected with the last portion of the fracture fluid to maintain the open fracture (s) after the pressure is released. The increased flow capacity of the tank results from the easiest flow path left in the grains of the propellant material within the fracture (s). In chemical simulation treatments, the flow capacity is improved by dissolving materials in the formation or in another way, changing the training properties. The hydraulic billing application as described above is a routine part of oil industry operations, as they are applied to individual target zones of up to 60 meters (200 feet) of thick vertical thick underground formation. When there are multiple deposits or stratified deposits to be hydraulically fractured or a very thick hydrocarbon carrier formation (more than about 60 meters) then alternative treatment techniques are required to obtain treatment of the entire area. The methods to improve treatment coverage are commonly known as methods of "diversion" in the terminology of oil industry. When multiple hydrocarbon carrier zones are stimulated by fracturing, hydraulics or chemical stimulation treatment, technical economic gains are realized by injecting multiple stages of treatment that can be diverted (or separated) by various means, including mechanical devices such as bridge plug, shutters, bottomhole valves sliding sleeves and ball deflector / plug combinations; particulate materials such as sand, ceramic material, support agent, salt, waxes, resins or other compounds or by alternative fluid systems, such as viscous fluids, gelled fluid, foams or other fluids formulated chemically using limited input methods . All of these other methods and devices for temporarily blocking fluid flow in or out of a given set of perforations will be referred to herein as "deviation agents". In the deviation of mechanical bridge plug, for example, the deepest interval is perforated first and the stimulated fracture, then the interval is isolated by a set of wired bridge plug and the process is repeated in the next upward interval. Assuming ten target drilling intervals, the treatment of 200 meters (1,000 feet) of training this way would commonly require ten days in a time interval of ten days to two weeks not only with multiple fracture treatments, but also multiple operations of run of bridge stopper and drilling. At the end of the treatment process, it would require a hole cleaning to remove the bridge plugs and put the production well. The main advantage of using bridge plugs or other mechanical deviation agents is the high confidence with which the entire target area is treated. The main disadvantages are the high cost of treatment resulting from multiple trips in and out of the hole and the risk of complications resulting from so many operations in the well. For example, a bridge plug can stick to the wall and needs to be drilled to a larger gast. , An additional disadvantage is that the required cleaning operation of the blasthole can damage some of the successfully treated intervals. An alternative to using bridge plugs is to fill the portion of the hole associated with the fractured fresh fracture interval, commonly referred to as the Isle of Pines technique. The sand column in the hole essentially blocks the already fractured interval allowing the next interval to be perforated and fractured independently. The main advantage is the elimination of the problems and risks associated with bridge plugs. The disadvantages are that the sand plug does not provide a perfect hydraulic seal and it can be difficult to remove the hole at the end of all fracture simulations. Unless the production of well fluid is sufficiently strong to transport the sand from the borehole, the well may still need to be cleaned with a reconditioning platform or coiled tubing unit. As before, additional drilling operations increase costs, mechanical risks, risks of damage to fractured intervals. Another method of deviation involves the use of particulate matter, granular solids that are placed in the treatment fluid and aid in deviation. As the fluid is pumped and the particles enter the perforations, a temporary block is formed in the area accepting the fluid, if a sufficiently high concentration of particles is deployed in the flow stream. Then, the restriction of the flow deflects the fluid to the other zones. After the treatment, the particles are removed by the formation fluids produced or mediated injected washing fluid, either by fluid transport or by dissolution. Commonly available deviating materials and particles include benzoic naphthalene acid, rock salt (sodium chloride), resin materials, waxes, and polymers. Alternatively, sand, support agent and ceramic materials could be used as particle deviators. Other specialty particles can be designed to precipitate and form during treatment. Another method of deflection involves using viscous fluid, viscous gels or foams as deviation agents. This method involves pumping the fluid d deflection through and / or to the perforated interval. These fluid systems are formulated to temporarily clog the flow to the perforations due to the viscosity formation in relation as the permeability decreases and are also designed in such a way that at the desired time, the fluid system breaks down, degrades or dissolves. (with or without addition of chemicals or other additives to trigger such breaking or dissolution) in such a way that the flux can be restored to or from the perforations. This fluid systems can be used for the diversion of - treatments of chemical stimulation of matrix and treatment of fracture. Particulate deviating agents and / or ball seals are sometimes incorporated into these fluid systems, in efforts to improve deviation. Another possible process is the deviation of limited entry, in which the entire target area of the formation to be treated is drilled with a very small number of perforations, generally of small diameter, in such a way that the pressure loss through these perforation during pumping promotes a high internal borehole pressure. The internal pressure of the hole is designed to be high enough to cause all perforated intervals to fracture simultaneously. If the pressure were too low, only the weakest portions of the formation would fracture. The primary advantage of the limited input deviation is that there are no obstructions to the inside of the ademe as sand bridge plugs that cause problems later. The advantage that limited entry fracturing often works well for thick intervals because the resulting fracture is often too narrow (the support agent can not be pumped to the narrow fracture and remains in the hole) and the high pressure initiates of the hole may not last. As the sand material is pumped, the perforation diameters are often rapidly eroded to larger sizes that reduce the internal pressure of the borehole. The net result may be that not the entire target area is stimulated. An additional concern is the potential for the flow capacity to the borehole is limited by the small number of boreholes. Some of the problems that result from faults to stimulate the entire target area or to use mechanical methods that require multiple borehole and borehole operations that have higher risk and cost as described above can be alleviated by using limited perforated interval concentrates diverted by ball sealers. The area to be treated could be divided into sub-zones with perforations in approximately the center of each one of those subzones or subzones that could be selected based on the analysis of the formation to desired target fracture sites. Then, the fracture stages would be pumped with deflection by ball sealants at the end of each stage. Specifically, 300 meters (1,000 feet) of coarse formation would be divided into ten subzones of approximately 30 meters (approximately 100 feet) each. At the center of each 30-meter (100-foot) sub-zone, ten holes could be fired at a density of three shots per meter (one shot per foot) of ademe. Then a fracture stage would be pumped with fluid loaded with a support agent, followed by ten or more ball sealants, at least one for each perforation open in a single perforation interval. The process would be repeated until all sets of perforations were fractured. Such a system is described in more detail in U.S. Patent No. 5,890,536, issued on April 6, 1999. Historically, all the areas to be treated in a particular task using ball sealants as a diverting agent have been drilled prior to pumping. d treatment fluids and bolt sealers have been used to divert the treatment fluids from the already broken zones or otherwise leading the greater flow of fluid to other areas that carry less or no fluid before the release of the ball sealants . The treatment and sealing theoretically proceed from zone to zone, depending on the relative breakage permeability pressures, but frequently there were problems with balls that settle prematurely in one or more of the perforations open to the exterior of the target interval and with two or more zones They are treated simultaneously. In addition, this technique assumes that each perforation interval or sub-zone would break, fracturing at a sufficiently different pressure, so that each stage of treatment would only enter a set of perforations. The primary advantages of deviation by ball sealer are the low cost and low risk of mechanical problems. The costs are low because the process can be consummated commonly in a continuous operation, usually for only a few hours of a single day. Only the ball sealants are left in the hole, either to flow out with the hydrocarbons produced or to fall to the bottom of the well in an area known as the rat hole (or rush). The main disadvantage is the inability to be sure that only one set of perforations will fracture at the same time, so that the correct number of ball sealants will drop at the end of each treatment stage. In effect, the optimum benefit of the process depends on a fracture stage entering the formation through only a set of perforations all other open perforations remain substantially unaffected during that stage of treatment. Additional disadvantages are the lack of certainty that all perforated intervals will be treated and the order in which these intervals are treated while the work is in progress. When the order of zone treatment is not known or controlled, it is not possible to ensure that each individual zone will be treated or that such an individual stimulation treatment step has been optimally designed for the target area. In some instances, it may not be possible to control the treatment, such that individual zones are treated with individual treatment steps.
To overcome some of the disadvantages that may occur during stimulation treatments, when multiple zones are drilled before the treatment fluid is pumped, an alternate mechanical deviation method has been developed that involves the use of a helical piping stimulation system. sequentially stimulates multiple intervals with separate treatment. As with the deviation of conventional ball sealant, all the intervals to be treated are perforated before the pumping of the stimulation treatment. Then the helical pipe is run into the hole with a mechanical deflection tool "resembling a saddle plug" attached to the end. This deflection tool, when properly positioned and driven through the perforations, allows hydraulic isolation to be obtained above and below the deflection tool. After the deflection tool is positioned and actuated to isolate the deepest set of perforations, the stimulation fluid is pumped into the helical piping and exits through the exit holes placed in the deflection tool between the top sealing elements and lower. After the completion of the first stage of treatment, the sealing elements contained in the deflection tool are deactivated or separated and the helical pipe is pulled up to place the deflection tool through the second deeper set of perforations the process is continued until all target ranges have been stimulated or the process is canceled due to process alterations. This type of helicoidal pipe stimulation method and apparatus has been used to hydraulically fracture multiple well zones with depths of up to 243 meters (8,000 feet). However, several technical obstacles, which include friction pressure losses, damage to sealing elements, depth control, operating speed and potential erosion of helical pipe, currently limit their deployment in deeper wells. Excess pressure is generated when stimulating fluids, particularly fluids laden with support agent and / or high viscosity fluids, are pumped at high speeds through longer lengths of helix pipe. Depending on the length and diameter of the helical pipe, the viscosity of the fluid and the maximum allowable pressures of the surface tooling, the pump speeds could be limited to only one • few barrels per minute that, depending on the characteristics of a specific underground formation, may not allow the effective placement of the support agent during hydraulic fracture treatments effective dissolution of the formation materials during acid stimulation treatments. Erosion of the helical pipe could also be a problem, as the fluid loaded with carrier agent d is pumped into the high velocity helical pipe, which includes the portion of the helical pipe which is still wound on the pipe. surface reel. Corrosion concerns are exacerbated as the fluid loaded with the support agent collides with the "continuous bending" associated with the portion of the helical pipe placed on the surface reel. Most of the sealing elements (eg, "cup" seal technology) currently used in the helical piping stimulation operations described above could experience seal failure problems-from seals in the deepest wells, as the Seals are operated beyond a large number of boreholes at the highest well temperatures associated with the deepest wells. Since the seals run in contact with or at a minimum clearance from the tube wall, the rough surfaces of the tube interior and / or burrs "Drilling can damage sealing elements." Seals currently available on saddle shutter-like deflection tools are also constructed of elastomers that may be unable to withstand the higher temperatures frequently associated with deeper wells. operating speed of existing systems co-sealing cups is generally in the order of 4.6 to 9 meters per minute (15 to 30 feet per minute) that run downhole at 9 to 18 meters per minute (30 to 60 feet per minute) from the top of the well, for example, at the lower operating speed, it would take approximately 13 hours to reach a depth of 3657 meters (12.00 feet) before starting the stimulation. night operations, this slow operating speed could result in s requiring several days to complete a stimulation task. Any problems during the task, the inward and outward displacement of the hole could be very expensive due to the total operation times associated with the slow operating speeds. The control of the depth of the helical pipe system and the similar deviating saddle shutter tooling also becomes more difficult to "As the depth increases, so that the placement of the tooling at the correct depth to execute the stimulation operation can be difficult." This problem is complicated when firing the operations before running the helical pipe system in the hole. The drilling operation uses a different depth measuring device (usually an ademe collar setter system) that is generally used in the helical pipe system.In addition, the helical pipe method described above requires that all boreholes are placed in the borehole in a separate drilling operation prior to pumping the stimulation task.The presence of multiple drilling assemblies open above the deflection tool may cause operational difficulties, for example, if the fracture of the support agent from the current zone grow vertically and / or a lime If the deficient cement is present behind the tube, the fracture could intersect with the drilling assemblies above the deflection tool, so that the support agent could "sink" into the hole above the deflection tool. prevent further movement of the tool. Also, it could be difficult to execute circulation operations if multiple drill sets are open above the "Deflection tool" For example, if the circulation pressures exceed the breaking pressures associated with the open perforations above the deflection tool, circulation may not be obtained with circulation fluid unintentionally lost to the formation. A similar type of stimulation operation can also be performed using articulated tubing and a reconditioning platform instead of a helical pipe system.When using a deflection tool deployed on articulated tubing, it can allow a larger diameter tubing to reduce losses Friction pressure and allow increased pump speeds Also, concerns regarding erosion and integrity of the pipeline can be reduced when compared to the helical pipe, because a pipe of articulated pipe of thickness can be used. Thicker wall and articulated tubing it will not be exposed to plastic deformation when it is run in the hole. However, by using this procedure, the time and cost associated with the operations would probably increase, due to the slower speeds to run the tube than those that are possible with the helical pipe. To overcome some of the limitations associated with the consummation of operations that require multiple trips • of the tooling in and out of the hole to drill and stimulate underground formations, methods have been proposed for the "one-way" deployment of a series of tooling at the bottom of the well to allow fracture stimulation of areas in conjunction with the perforation. Specifically, these methods propose operations that can minimize the number of borehole operations required and the time required to consummate these operations, thereby reducing the cost of the stimulation treatment. These proposals include: (1) having a slurry or sand slurry in the borehole while drilling with unbalanced pressure, (2) emptying sand from a bailer simultaneously in an explosively released, separate container. All these proposals allow only a minimum fracture penetration surrounding the bore and are not applicable to the needs of multi-stage hydraulic fracturing as described above. Thus, there is a need for an improved method and apparatus for treating, individually, each of multiple intervals of an underground formation penetrated by a borehole, while maintaining the economic benefits of multi-stage treatment. There is also a need for a method and apparatus that can economically reduce the risks inherent in the stimulation treatment options. - currently available for hydrocarbon carrier formations with multiple deposits or deposits in layers or with thicknesses of more than approximately 60 meters (200 feet), while ensuring that optimal treatment placement is carried out with a mechanical deviation agent that positively directs the treatment stages to the desired site.
BRIEF DESCRIPTION OF THE INVENTION This invention provides a method and apparatus for drilling and treating multiple intervals of one or more underground formations intersected by a borehole. The apparatus consists of a deployment means (for example, helical pipe, articulated pipe, electric line, wire line, bottomhole tractor, etc.) with a bottomhole assembly or assembly ("BHA") consisting of of at least one drilling device and a mechanical resettable sealing mechanism that can be operated independently via one or more signaling means (e.g., electronic signals transmitted via wire; hydraulic signals transmitted via pipe, annulus, umbilicals, tension or compression, radio transmission, fiber optic transmission, BHA computer systems on board, etc.) The method includes the stages of deploying the BHA in the - hole using deployment means, wherein the deployment means may consist of a series of pipes, cable or tractor from the bottom of the well. The drilling device is placed adjacent to the interval to be drilled and is used to drill the interval, the BHA is positioned inside the hole using the deployment means and the sealing mechanism is operated to establish a hydraulic seal that positively directs the pumped fluid to the hole to enter the perforated interval. The sealing mechanism is released. Then, the process can be repeated, without removing the BHA from the borehole, by at least one additional interval of the one or more underground formations. The deployment means may consist of a chain of tubes, which include a helical pipe or standard hinge pipe, a wire line, a black sand line or a cable. Instead of the deployment of pipe or cable, the means of deployment could also be a tractor system attached to the BHA. The tractor system may consist of self-propelled signaling systems, controlled by computer and carried on board, in such a way that it is not necessary to attach cable or pipe to control and operate the BHA system and / or tractor system.
Alternatively, the tractor system could be controlled and energized by cables or pipe umbilicals, such - way that the tractor system and BHA are controlled and driven via signals transmitted to the bottom of the well using the umbilicals. There may be many different embodiments of the invention, depending on the suspension means and specific components of the BHA. In the first embodiment of the invention, when the deployment means consist of a chain of tubes. Once an interval has been drilled, the BHA can be moved and the sealing mechanism actuated to establish a hydraulic seal below the perforated interval. Then, the treatment fluid can be pumped to the annulus between the pipe chain and the hole and the perforated interval. Then a second treatment fluid, such as nitrogen, could be pumped into the pipe chain at the same time as the first treatment fluid is pumped into the annulus between the pipe chain and the borehole. In the second embodiment, when the suspension means consist of a chain of tubes, once an interval has been perforated, the BHA can be moved and the sealing mechanism actuated to establish a hydraulic seal above the perforated range. Then, the treatment fluid can be pumped to the tube chain and to the perforated interval. In the third modality, when the deployment means consist of a chain of tubes, the BHA can be moved and • the sealing mechanism operated to establish a hydraulic seal above and below the perforated interval (where the sealing mechanism consists of two sealing elements spaced a sufficient distance to be on both sides of the perforated interval). In this third embodiment, the treatment fluid can be pumped to the tube chain itself, through a flow orifice placed intermediate to the two sealing elements of the sealing mechanism and to the perforated interval. In a fourth embodiment of the invention, when the BHA is deployed in the bore using a wire line, a line of sand or cable, the BHA would be moved and the sealing mechanism actuated to establish a hydraulic seal below the perforated range at to be treated and the treatment fluid would be pumped to the annulus between the wire line, sand line or cable and the borehole. In a fifth embodiment of the invention, an "umbilical" is displayed as additional means for operating a BHA component. In the most general sense, the umbilical could take the form of a small diameter tube or multiple tubes to provide hydraulic communication with the BHA components and / or the umbilical could take the form of a cable or multiple cables to provide electrical communication or Electro-optical with the BHA components. In a sixth embodiment of the invention, when the deployment means consist of a tractor system attached to the BHA, the BHA can be moved and the sealing mechanism actuated to establish a hydraulic seal below the perforated range. The treatment fluid can be pumped to the borehole and the perforated interval. In a seventh embodiment of the invention, abrasive jet fluid cutting technology is used to perforate and the BHA is suspended by the pipe, such that the BHA can be moved and the sealing mechanism actuated to establish a hydraulic seal. below the perforated interval. Then, the treatment fluid would be pumped to the annulus between the pipe and the borehole. One of the main advantages of this method and apparatus is that the BHA, which includes the sealing mechanism and the drilling device, does not need to be removed from the borehole before treatment with the treatment fluid and between the treatment of multiple training zones or intervals. Another primary advantage of this method and apparatus is that each treatment step is diverted using a mechanical deviating agent, such that precise control of the treatment deviation process is obtained and each zone can be optimally stimulated. As a result, there are significant cost savings associated with the reduction in the time required to drill and treat - Multiple intervals within a hole. In addition, there are production improvements associated with the use of a mechanical deflection agent to provide precisely controlled deviation of the treatment when multiple formation intervals are stimulated within a borehole. As such, the method and apparatus of the invention provide significant economic advantages over existing methods and equipment, since the method and apparatus of the invention allow multiple areas to be drilled and stimulated with a single borehole entry and subsequent removal of a borehole. assembly or set of the bottom of the well that provides double functionality, both as a mechanical deviation agent and as a drilling device.
BRIEF DESCRIPTION OF THE DRAWINGS The present invention and its advantages will be better understood by referring to the following detailed description and the accompanying drawings in which: Figure 1 illustrates a possible representative bore configuration with possible equipment that could be used to support the assembly or bottomhole assembly used in the present invention. Figure 1 also illustrates representative bottomhole storage drill holes, with surface slip elements that can be used for storage of backup or contingency pit assemblies. Figure 2A illustrates the first mode of the downhole assembly or assembly using helical pipe in an undrilled hole and positioned in the depth site to be drilled by the first set of selectively triggered drilling loads. Figure 2A further illustrates that the bottom of the well consists of a drilling device, an inflatable, resettable plug, a resettable axial slide device and auxiliary components. Figure 2B represents the assembly or assembly of the bottom of the well, helical pipe and borehole of Figure 2a after the first set of selectively triggered perforation charges are triggered, resulting in boreholes through the production and envelope of the borehole. cement and the first training area, in such a way that hydraulic communication is established between the hole and the first training area. Figure 2C represents the assembly or assembly of the bottom of the well, helical pipe and borehole of figure 2B, after the whole of the bottom of the well has been repositioned and the first formation zone stimulated with the first stage of the fracture treatment with agent of support, multi-stage, hydraulic, where the first stage of fracture treatment was pumped to the bottom of the - hole in the annulus of the existing hole between the helical pipe and the production ademe. In Figure 2C, the sealing mechanism is shown in a deactivated position since, for purposes of illustration only, it is assumed that no other perforations are present in addition to those associated with the first zone and as such, isolation is not necessary for the treatment of the first zone. Figure 3A depicts the bottomhole assembly, helical pipe and borehole of Figure 2C, after the bottomhole assembly has been repositioned and the second set of selectively triggered perforation charges have been fired, resulting in holes in the wellbore. perforation through the cement production and envelope and the second formation zone, in such a way that hydraulic communication is established between the hole and the second formation zone. Figure 3B represents the assembly or assembly of the bottom of the well, helical pipe and borehole of Figure 3A, after the bottom-hole assembly has been repositioned a sufficient distance below the deepest bore of the second drill set to allow a slight upward movement of the BHA to adjust the adjustable axial sliding device, while retaining the location of the - circulation below the lower perforation of the second drill assembly. Figure 3C depicts the bottomhole, helical pipe and bore assembly of Figure 3B, after the resettable mechanical slide device has been driven to provide resistance to downward axial movement which ensures that the inflatable resettable shutter and sliding device Resettable mechanics are placed between the perforations of the first zone and the second zone. Figure 3D represents the bottomhole, helical pipe and bore assembly of Figure 3C, after the inflatable resettable shutter has been driven to provide a flow barrier between the borehole portion directly above the inflatable resettable shutter and the portion of the bore directly below the inflatable resettable shutter. Figure 3E represents the bottomhole assembly, helical pipe and borehole of figure 3D, after the second formation zone has been stimulated with the second stage of fracture treatment of the multi-stage hydraulic support agent, where the The second stage of the fracture treatment was pumped to the bottom of the well in the annulus of the hole between the helical pipe and the production shaft. Figure 3F represents the bottomhole, helical pipe and bore assembly of Figure 3E after the inflatable resettable shutter has been activated, thereby restoring the pressure communication between the bore portion directly above the inflatable resettable plug and the portion of the bore directly below the inflatable resettable obturator. The resettable mechanical sliding device is still energized and continues to prevent the movement of the helical pipe from the bottom of the well to the hole. Figure 4A represents a modified bottom of the well bottom assembly, similar to the downhole assembly described in Figures 2A to 2C and Figures 3A to 3F, but with the addition of a mechanical plug, adjustable with a load adjustment system. Selective shot, located below the chain of drilling tools. Figure 4A also depicts the helical pipe and the borehole of Figure 3 after a third drilling and additional fracture pacing operation has been performed. In Figure 4A, it will be noted that only the second and third fractures and drill sets are shown. In Figure 4A, the modified bottomhole assembly is shown suspended by helical pipe, so that the location of the bridge plug is located above the last perforated range and below the next interval to be drilled. Figure 4B depicts the bottomhole assembly, helical pipe and borehole of Figure 4A, after the mechanical plug has been adjusted with selectively fired load in the well and after the bottomhole assembly has been repositioned and the The first set of selectively triggered perforation charges has been fired and resulted in drilling holes through the cement production and envelope and the fourth formation zone, in such a way that hydraulic communication is established between the borehole and the fourth zone. deformation. Figure 5 represents a second embodiment of the invention. In this embodiment, the suspension means consist of a chain of tubes and once a gap has been punctured, the BHA can be moved and the sealing mechanism actuated to establish a hydraulic seal above the perforated range. Then, the treatment fluid can be pumped to the tube chain and to the perforated interval. Figure 6 represents a third embodiment of the invention. The suspension means consist of a chain of tubes and the BHA can be moved and the sealing mechanism operated to establish a hydraulic seal above and below the perforated interval (wherein the mechanism of - sealing consists of two sealing elements spaced a sufficient distance apart to be on both sides of the perforated interval). In this third embodiment, the treatment fluid can be pumped to the tube chain itself, through a flow orifice placed intermediate to the two sealing elements of the sealing mechanism and to the perforated interval. Figure 7 represents a fourth embodiment of the invention. The BHA is suspended in the hole using a wire line (a line of sand or cable). The BHA would be moved and the sealing mechanism actuated to establish a hydraulic seal below the perforated interval to be treated and the treatment fluid would be pumped to the annulus between the wire line, sand line or cable and the borehole. Figures 8A and 8B represent a fifth embodiment of the invention utilizing an umbilical pipe, deployed within the pipe used as the deployment means, for actuating the resettable sealing mechanism. Figure 9 represents a sixth embodiment of the invention using a tractor system attached to the BHA, such that the BHA can be moved and the sealing mechanism operated to establish a hydraulic seal below the perforated range. The treatment fluid can be pumped to the borehole and the perforated interval. Figure 10 represents a seventh modality of the invention using abrasive or erosive jet fluid cutting technology by the drilling device. The BHA is suspended in the bore using articulated tubing and consists of a resettable obturator, adjusted by compression, mechanical, an abrasive or erosive jet fluid drilling device, an ademe-collar, mechanical and auxiliary components. In this mode, the perforations are created by pumping an abrasive fluid into the articulated pipe and out of a jet tool located on the BHA, so that a jet of abrasive or high velocity erosive fluid, at high pressure, is created and used to penetrate the surrounding production and surrounding cement envelope to establish hydraulic communication with the desired formation interval. After adjusting the resettable obturator below the area to be stimulated, the stimulation treatment can be pumped to the annulus located between the chain of tubes and the production chain.
DETAILED DESCRIPTION OF THE INVENTION The present invention will be described in relation to its preferred embodiments. However, to the extent that the following description is specific to a modality - particular or a particular use of the invention, it is proposed that it be illustrative only and not be construed as limiting the scope of the invention. On the contrary, the description is intended to cover all alternatives, modifications and equivalents that are included in the spirit and scope of the invention, as defined by the appended claims. The present invention provides a new method, new system and new apparatus for drilling and stimulating multiple training intervals, which allows each individual zone to be treated with an individual treatment step, while eliminating or minimizing the problems that are associated with the Stimulation methods of existing spiral pipe or articulated pipe and from here provide significant economic and technical benefits over existing methods. Specifically, the invention involves suspending a bottomhole assembly in the borehole to individually and sequentially drill and treat each of the multiple desired zones, while the multiple stages of the stimulation treatment are pumped and to deploy a mechanical seal mechanism resettable to provide a controlled deviation of each individual treatment stage. For the purposes of this application, it will be understood that "borehole" includes components - sealing of the well below the ground and also all equipment sealed above ground level, such as the head of the well, parts of reels, preventores of blowing and lubricator. The new apparatus consists of deployment means (eg helical pipe, articulated pipe, electric line, wire line, tractor system, etc.) - with a bottomhole assembly consisting of at least one drilling device and a resettable mechanical sealing mechanism that can be independently operated from the surface via one or more signaling means (e.g., electronic signals transmitted via wire line; hydraulic signals transmitted via pipe, annulus, umbilical devices; stress or compression loads; radio transmission, fiber optic transmission, etc.) and designed for the hole environment and anticipated loading conditions. In the most general sense, the term "bottomhole assembly or assembly" is used to denote a chain, of components consisting of at least one drilling device and a resettable sealing mechanism. Additional components including, but not limited to, jaw collars, cutting aids, washing tools, circulation bore auxiliaries, flow orifice aids, auxiliary - compensation orifice, temperature gauges, pressure gauges, wire line connection aids, adjustable mechanical slide elements, sleeve flange clamps, centralizer auxiliaries and / or connector auxiliaries can also be placed on the bottom assembly of the well to facilitate other operations and anticipated auxiliary measurements that may be desirable during the stimulation treatment.
In the most general sense, the resettable mechanical seal mechanism performs the function of providing a "hydraulic seal", where hydraulic seal is defined as a sufficient flow restriction or blockage, such that the fluid is forced to be directed to a different site than the site that would otherwise be addressed if the flow restriction was not present. Specifically, this broad definition of "hydraulic seal" is intended to include a "perfect hydraulic seal", such that the entire flow is directed to a site different from the site to which the flow would be directed if the flow restriction. was not present and an "imperfect hydraulic seal", such that an appreciable portion of the flow is directed to a site other than the site that the flow would be directed if the flow restriction were not present. Although it would be generally preferable to use a resettable mechanical seal that provides a seal - effective hydraulic to obtain an optimal stimulation; A sealing mechanism that provides an imperfect hydraulic seal could be used and an economical treatment could be obtained although the stimulation treatment may not be deviated perfectly. In the first embodiment of the invention, helical pipe is used as the deployment means and the new method involves sequential drilling and then stimulating the individual zones from bottom to top of the consummation interval, with the stimulation fluid pumped through the annular space between the production ademe and the helical pipe. As discussed hereinafter, this embodiment of the new method and apparatus offers substantial improvements with respect to the existing helical and articulated tubing stimulation technology and is applicable to a wide range of blast architectures and stimulation treatment designs. Specifically, the first preferred embodiment of the new method and apparatus involves the deployment system, signaling means, bottomhole mounting and operations, as described in detail later in the pre-eehfce, J eri where the various components, their operation and stages "Operatives are chosen, for purposes of" cr 'xipt. i pvo "s only, to correspond to the components and operations' that could be used to accommodate the • "stimulation" by fracturing the multi-interval hydraulic support agent In the first preferred embodiment for a hydraulic support agent fracture stimulation treatment, the apparatus would consist of the BHA deployed in the borehole by helical tubing. drilling; resettable mechanical sealing mechanism; ademe-collar fitting; circulation holes and other auxiliary components (as described in detail below). Also, in this first preferred embodiment, the drilling device would consist of a pistol system selected perforation drilling (using loaded charge drilling loads) and the resettable mechanical seal mechanism would consist of an inflatable, resealable shutter, a resettable mechanical sliding device to prevent downward axial movement of the bottomhole assembly when it is adjusted and orif pressure compensation devices located above and below the inflatable obturator "resettable. In addition, in this first preferred embodiment, a wire line would be placed inside the helical pipe and used to provide signaling means for driving the selected shot piercing loads and for the transmission of - electrical signals associated with the ademe - collator used to measure the depth of the BHA.
Referring now to Figure 1, an example of the type of surface equipment that could be used in the first preferred embodiment would be a platform using a very long lubricator 2 with the head 4 of the helical pipe injector suspended at the top of the air by the crane arm 6 attached to the crane base 8. The drill hole would commonly comprise a length of a surface flange 78 partially or totally within a cement shell 80 and a production flange 82 partially or completely within an envelope of cement 84, wherein the inner wall of the borehole is composed of the production flange 82. The depth of the borehole would preferably extend some distance below the lowermost interval to be stimulated to accommodate the length of the bottomhole assembly that would be attached to the borehole. end of the helical pipe 106. The helical pipe 106 is inserted into the hole using the injection head 4 of the pipe. to helical and lubricator 2. Also installed to the lubricator 2 are blow prevention preventers 10 that could be operated remotely in the case of operational alterations. The crane base 8, the crane arm 6, the helical pipe injection head 4, lubricator 2, Blowout preventers 10 (and their associated auxiliary control and / or drive components) are standard equipment components well known to those skilled in the art, which will accommodate the methods and procedures for securely installing a bottomhole assembly. helical piping in a well under pressure and subsequently removing the downhole assembly of helical piping from a well under pressure. With existing equipment readily available, the height at the top of the helical pipe injection head 4 could be approximately 27 meters (90 feet) from ground level with the "gooseneck" 12 (where the coil is bent to go vertically down to the well) reaching approximately 32 meters (105 feet) above the ground. The crane arm 6 and base 8 of the crane would support the load of the injector head 4, the helicoidal pipe 106 and any anticipated loading requirements for potential capture operations (shaking and traction). In general, the lubricator 2 must be longer than the length of the bottomhole assembly to allow the bottomhole assembly to be deployed safely in a borehole under pressure. Depending on the overall length requirements and how it is judged prudent based on engineering design calculations for an application - specific, to provide stability of the injection head 4 of the helical pipe and lubricator 2, tensioning wires 14 could be attached at various places in the injection head 4 of helical pipe and lubricator 2. The tensioning wires 14 would be firmly secured to the floor to prevent undue movement of the injection head 4 of helical piping and lubricator 2, such that the integrity of the components of the surface to maintain the pressure would not be compromised. Depending on the overall length requirements, alternative injection head / lubricator system suspension systems (helical piping platforms or completion / reconditioning platforms adapted to the purpose) could also be used. As shown in Figure 1, There are several reel parts from the wellhead that can be used for flow control and hydraulic isolation during the platform lifting operations, stimulation operations and operations at the bottom of the platform. The crown valve 16 provides a device for insulating the hole portion above the crown valve 16 from the hole portion below the crown valve 16. The upper main fracture valve 18 and the lower main fracture valve 20 also provide valve systems for the isolation of pressures from - drill above and below their respective sites.
Depending on the practices and design of specific stimulation work, it is possible that not all of these isolation type valves may actually be required used. __ The outlet side injection valves 22 shown in Figure 1 provide a site for the injection of stimulation fluids into the borehole. The tubing from the pumps and surface tanks used for the injection of the stimulation fluids would be attached to the accessories and / or appropriate couplings to the injection valves on the outlet side 22. Then, the stimulation fluids would be pumped to the bore via this flow trajectory. With the installation of other appropriate flow control equipment, the fluid can also be produced from the bore using the injection valves on the outlet side 22. It will be noted that the inside of the helical pipe 106 can also be used as a conduit flow for the injection of the fluid into the hole. The wellbore mounting drill holes 24 shown in Figure 1 provide a site for the storage of back-up or backup contingent assemblies 27 or for the storage of downhole assemblies that have been used during operations. previous The storage holes 24 of the downhole assembly can be drilled at a shallow depth, so that a bottomhole assembly that can contain drilling loads can be held securely in place with slide elements 26 of the surface, such that the drilling loads are located below ground level until the bottom of the well assembly is ready to be attached to the helicoidal pipe 106. The storage holes 24 of the downhole assembly may be perforated to accommodate the placement of either a cemented or uncemented chain of ames or they may be left completely unpacked. The actual number of downhole assembly storage holes 24 required for a particular operation would depend on the overall requirements of the task. The bottomhole mounting storage holes 24 could be located in the reach of the crane arm 6 to accommodate the rapid change of the bottomhole assemblies during the course of the stimulation operation, without the need to physically relocate the Crane base 8 to another site. With reference to Figure 2A, the helical pipe 106 is equipped with a helical pipe connection 110 that can be connected to a cutting-release / jaw collar combination auxiliary 112 that contains both a cut-release mechanism and a neck. gag - for the passage of pressurized fluids and the wire line 102. The cutting-release / jaw-collar combination auxiliary 112 can be connected to an auxiliary containing an auxiliary orifice 114 that can provide a flow path to wash debris from above the resealable inflatable plug 120 or provide a path of flow for injecting fluid to the bottom of the well using the helical pipe 106. The orifice circulation auxiliary 114 contains a valve assembly that drives the circulation orifice 114 and the upper compensation orifice 116. The upper compensation orifice 116 can be connected to a lower compensation orifice 122 via tubing by means of the resealable inflatable plug 120. Both the circulation orifice 114 and the upper compensation orifice 116 would preferably be open in the "run position", thereby allowing a pressure communication between the pressure of the internal helical pipe and the t internal pipework by pressing the annulus of the 'ademe. In this document, "run position" refers to the situation where all the components in the bottomhole assembly have a configuration that allows unimpeded axial movement up and down the well. The lower compensation hole 122 located underneath the resettable inflatable plug 120 is always open and the flow at - through the compensation holes is controlled by the upper compensation hole 116. The circulation and compensation orifices can be closed simultaneously by placing a slight compression load on the BHA. To prevent potential backflow to the helical piping when the circulation orifice 114 is open in the run position, a surface pressure can be applied to the helical piping 106, such that the pressure inside the circulation orifice 114 exceeds the pressure of the bore directly to the outside of the circulation orifice 114. The resettable inflatable plug 120 is hydraulically insulated from the internal pressure of the helical pipe in the run position. The resettable inflatable plug 120 can gain pressure communication via internal valves with the pressure of the internal helical tubing by placing a slight compression load on the BHA. Axially adjustable, mechanically actuated locking or locking devices or "sliding elements" 124 can be placed under the resettable inflatable plug 120 to resist movement through the hole. The mechanical sliding elements 124 can be driven by means of a "J continuous" mechanism when cycling the axial load between compression and tension. A wire line connection auxiliary 126 is located above the ademe collar collet 128 and selective fire drill gun system. A gun connection auxiliary 130 connects the sleeve collar setter 128 to the selected shot head 152. The piercing gun system can be designed based on the knowledge of the number, location and thickness of the hydrocarbon carrier sands within the target areas. The gun system will be composed of a gun assembly (for example 134) for each area to be treated. The first (lower) gun assembly will consist of a selected firing head 132 and a gun shell 134 that will be loaded with piercing charges 136 and a selected firing trigger system. Specifically, a preferred embodiment of the new method involves the following steps, wherein the stimulation task is chosen, for description purposes, to be a multistage hydraulic support agent fracture stimulation. 1. The well is drilled and the ademe is cemented through the interval to be completed and if desired, one or more bottomhole mounting storage holes are drilled and completed. 2. The target zones within the consummation interval are identified (usually by a combination of open-hole logs and hole with • ademe). 3. Bottom of the well (BHA) assemblies and drill pistol assemblies are deployed in each BHA anticipated to be used during the stimulation operation, are designed based on the knowledge of the number, location and thickness of the sands carrying hydrocarbons within the target areas. 4. A helical pipe spool is composed with a preferred embodiment of BHA described above. The helical pipe spool must also be composed to contain the wire line that is used to provide signaling means for the drive of drill guns. Preferably, the desired amount of spare BHA or contingency configured appropriately would also be composed and stored in the (the) bottomhole mounting storage hole (s). The helical pipe can be pre-loaded with fluid, either before or after attaching "the BHA to the helical pipe." 5. As shown in Figure 1, the helical pipe 106 with BHA is run to the well via a lubricator 2 and the helical pipe injection head 4 is suspended by the crane arm 6. 6. The helical pipe / BHA is run to the well while the depth of the BHA is correlated with the - collar adapter of ademe 128 (figure 2A). 7. The helical / BHA pipe is run below the target area further to the bottom to ensure that there is sufficient depth of the borehole below the bottom bores to place the BHA below the first set of boreholes during fracture operations. As shown in Figure 2A, the resettable inflatable plug 120 and mechanically adjustable sliding elements 124 are run in the run position. 8. As shown in Figure 2B, then the helical / BHA pipe is raised to a location within the borehole, such that the first (lower) set of drilling loads 136 contained in the first gun assembly 134 of the The selected shot perforation gun is placed directly through the target area plus the bottom, where precise depth control can be established based on the readings of the ademe-collar setter 128 and helical pipe odometer systems (not shown). The action of the movement of the BHA to the site of the first perforated interval will effect the cycle of the mechanism of "J continuous" of mechanical sliding (not shown) to the pre-blocking position, where the subsequent downward movement will force the mechanical sliding element. resettable to the locked position, thereby preventing movement towards - down. It will be noted that the additional cycles of the axial load of the helical pipe of the compression to tension and return will return the adjustable mechanical sliding elements to the running position. In this way, the mechanical sliding J continuous mechanism coupled with the use of compression and tension loads transmitted via the suspension means (helical pipe) are used to provide downhole drive and deactivation of the mechanical sliding elements. . 9. The first set of drilling loads 136 are selectively triggered by remote operation via the wire line communication 102 with the first selected firing head 132 to penetrate the ademe 82 and cement shell 84 and establish hydraulic communication with the formation 86 through the resulting perforations 230-231. It will be understood that any given set of perforations may, if desired, be a set of one, although in general multiple perforations would provide improved treatment results. It will also be understood that more than one segment of the gun assembly can be fired if desired to obtain the target number of perforations, either to remedy a real or perceived poor firing or simply to increase the number of perforations. It will also be understood that an interval is not necessarily limited to a single deposit • of sand. Multiple sand intervals could be drilled and treated as a single step using other deviating agents for simultaneous deployment with this invention within a given treatment step. 10. As shown in Figure 2C, the helical pipe can be moved to position the circulation orifice 114 directly below the deepest bore 231 of this first target zone to minimize the potential for the support agent to fill above. of the resettable inflatable shutter 120 and minimize the flow of the support agent at high speed beyond the BHA. 11. The first stage of the fracture stimulation treatment is initiated by the circulation of a small volume of fluid to the helical pipe 106 through the circulation orifice 114 (via a positive displacement pump). This is followed by the start of the pumping of the stimulus fluid to the annulus between the helical pipe 106 and the production ademe 82 at fracture stimulation speeds. The small volume of fluid flowing through the helical pipe 106 serves to maintain a positive pressure inside the helical pipe 106 to withstand the counterflow of the carrier fluid loaded to the helical pipe 106 and to resist the crushing load of the pipe. helical pipe during fracturing operations. It will be noted that as an alternative means to - resisting the crushing of the helical pipe, an internal valve mechanism can be used to maintain the circulation orifice 114 in the closed position and with positive pressure then applied to the circulation pipe 106 using a surface pump. As an illustrative example of the fracture treatment design for the stimulation of a 15-acre sand lens containing hydrocarbon gas, the first fracture stage could consist of "sub-stages" as follows: (a) 18.925 liters (5,000 gallons) of KCl 2% water; (b) 7,570 liters (2,000 gallons) of crosslinked gel containing 0.454 Kg (1 pound) /3,785 liters (1 gallon) of support agent; (c) 11,355 liters (3,000 gallons) of cross-linked gel containing 0.91 kg (2 pounds) /3,785 liters (1 gallon) of support agent; (d) 18,925 liters (5,000 gallons) of crosslinked gel containing 1.36 kg (3 pounds) /3,785 liters (1 gallon) of support agent and (e) 11,355 liters (3,000 gallons) of crosslinked gel containing 1.8 kg (4) pounds) /3,785 liters (1 gallon) of support agent, such that 15,876 kg (35,000 pounds) of support agent are placed in the first zone. 12. As shown in Figure 2C, all sub-steps of the first fracture operation are consummated with the creation of the first fracture 232 of the support agent. 13. At the end of the first stage of the simulation • treatment, if the support agent in the hole prevented the helicoidal / BHA pipe from having an immediate movement; the fluid can be circulated through the circulation orifice 114 to wash and clean the support agent, to release the helical / BHA pipe and allow movement. 14. As shown in Figure 3A, then, the helical / BHA pipe is pulled up the well to slightly above the second deeper target zone, such that the second set of drilling loads 146 contained in the selective firing pistol 114 system is located slightly above the second deeper target zone where depth control is again established based on readings of the ademe-collar setter 128 and helical pipe odometer systems. The action of the movement of the BHA upwards (slightly above the second interval to be drilled) will cycle the "J continuous" mechanism of mechanical sliding resettable to the preset position. The additional cycling of the compression / tension loads is carried out to place the mechanical sliding J mechanism back to the run position. Then, the helical / BHA pipe is moved down to place the drilling loads 146 contained in the firing drilling gun system - selected 144 directly through the second deeper target zone where again the precise depth control is established based on readings from the ademe-collet setter 128 and the odometer systems of the helical piping. 15. The second set of drilling loads 146 are selectively triggered by remote actuation via the second selected firing head 142 to penetrate the ademe 82 and the cement shell 84 and establish hydraulic communication with the formation 86 by means of the resulting perforations. 240 - 241. 16. As shown in Figure 3B, the helical pipe can be moved to the borehole to position the BHA several feet below the deepest drilling 241 of the second target zone. Subsequent movement of the BHA upwardly of the bore to position the circulation orifice 114 directly below the deepest bore 241 of this second target zone will cycle the resettable mechanical skim elements 124 to the preset position, where movement towards Subsequent down will force the resettable mechanical sliding elements 124 into the locked position, thereby preventing further downward movement. 17. As shown in Figure 3C, the downward movement engages the mechanical sliding elements • readjustable 124 with the wall of the ademe 82, thereby preventing further downward movement of the BHA. A compression load on the helical pipe is then applied and this load closes the circulation orifice 114 and upper compensation orifice 116 and creates pressure communication between the resettable inflatable plug 120 and the internal pressure of the helical pipe. The compression load also fixes the circulation orifice 114 to a position directly below the deepest bore 241 of this second target zone (to minimize the potential for the support agent to fill above the resettable inflatable seal 120 and minimize the flow of the high-speed support agent beyond the BHA) and with the resettable inflatable plug 120 placed between the first and second perforated intervals. 18. A compression load is fitted to the helical / BHA pipe to test the resettable mechanical slide elements 124 and ensure that the additional downward force does not translate into additional movement of the BHA to the bore. 19. As shown in Figure 3D, the resettable inflatable plug 120 is actuated by pressurizing the helical line 106 to effect a hydraulic seal above and below the sealable inflatable plug 120. A compression load is maintained on the BHA to maintain - the pressure communication between the internal pressure of the helical pipe and the resettable inflatable plug 120, to keep the circulation hole 114 and the upper compensation orifice 116 closed and to keep the adjustable mechanical sliding elements 125 in the locked position and energized The resettable inflatable plug 120 is maintained in the actuated state by maintaining the pressure in the helical line 106 via a surface pump system (it will be noted that alternatively, the resettable inflatable plug could be maintained in a powered state by setting the pressure in the element using an internal valve remotely controlled from the surface by means of signaling elements compatible with other BHA components and other signaling means present). 20. The second stage of the fracture stimulation treatment is initiated with the fluid pumped into the annulus between the helical pipe 106 and the production ademe 82 at fracture stimulation speeds, while maintaining the compression load on the BHA for maintaining the circulation orifice 114 and the upper compensation orifice 116 closed and maintaining the pressure of the helical piping at a level sufficient to withstand the crushing of the helical pipe chain and keeping the inflatable sealant reclosable 120 inflated and serving as - a hydraulic seal between the annular pressure above the obturator before, during and after the fracture operation and the pressure of the sealed bore less than the inflatable obturator resettable. 21. All the sub-stages of the fracture operation are pumped leaving a sub-discharge of the last sub-stage loaded with support agent in the hole to avoid over-displacing the fracture element. If, during the course of this treatment step, it is believed that seal integrity of the resettable inflatable seal 120 is compromised, the treatment stage could be temporarily suspended to test the integrity of the seal of the plug above the existing higher perforations. (shallow) (for example, bore 240 in Figure 3D) after adjustment of the resettable inflatable plug 120 on the blank tube. If seal integrity tests were to be carried out, it may be desirable to perform a circulation / wash operation to ensure that any support agent that may be present in the borehole is circulated out of the borehole before carrying out the operation. the proof. The circulation / washing operation could be carried out by opening the circulation orifice 114 and then pumping the circulation fluid through the helical line 106 to circulate the support agent out of the hole. 22. As shown in Figure 3E, all the sub-steps of the second fracture operation are consummated with the creation of a second fracture by the support agent 242. 23. After the completion of the second stage fracture operation and the injection interruption the annulus stimulation fluid formed between the helical pipe 106 and the production ademe 82, a small stress load is applied to the helical pipe 106, in so much that the internal pressure of the helical pipe is maintained. The applied small voltage first isolates the pressure of the inflatable obturator from the pressure of the helical pipe, thereby fixing the pressure in the resettable inflatable plug 120 and thereby maintaining a positive pressure seal and imparting significant resistance to the axial movement of the shutter inflatable re-adjustable 120. In the same movement, the applied tension can then open the circulation orifice 114 and the compensation orifice 116, thereby allowing the pressure of the helical pipe to drain to the annulus formed by the helical pipe 106 and the flange. of production 82, while simultaneously allowing the pressure above and below the resettable inflatable plug 120 to equilibrate. The pump system of the surface allows the internal pressure of the helical pipe to be stopped after balancing the pressures of the bottom of the well. 24. After the pressures inside the helical pipe, in the annulus formed by the helical pipe 106 and the production ademe 82 above the resettable inflatable seal 120 and in the annulus formed by the BHA and the production ademe 82 below of the resettable inflatable shutter 120 are balanced, a compression load placed on the helical pipe will close the compression orifice 114 and the upper compensation orifice 116 before releasing the trapped pressure inside the resettable inflatable plug 120 to the helical pipe 106. This release of the internal pressure of the resettable inflatable plug 120 will allow the resettable inflatable plug 120 to be retracted from the wall of the production ademe, as shown in FIG. 3F, in the absence of an external differential pressure through the resettable inflatable plug 120, which could otherwise result in forces and movement that could damage the pipe Elicoidal 106 or BHA. 25. Once the resettable inflatable seal 120 is separated, as shown in FIG. 3F, the tension pulled on the helical / BHA pipe could de-energize the mechanical resettable slide elements 124, thereby allowing the BHA to be free to move. and be positioned above the hole. 26. If at the end of the second stage of the stimulation treatment, the support agent in the bore prevents the helical / BHA pipe having an immediate movement, fluid can be circulated through the circulation orifice 144 to wash and clean the support agent, to release the helical / BHA pipe and allow upward movement of the BHA after releasing the resettable inflatable shutter. 27. The process as described above is repeated until all the planned zones are stimulated individually (Figures 3A to 3F represent a BHA designed for a stimulation of three zones). 28. After the completion of the stimulation process, the BHA components are returned to the run position and the helical / BHA pipe assembly is removed from the borehole. 29. If all desired target zones have been stimulated, the well can be immediately placed into production. 30. If it is desirable to stimulate additional zones, a spool of helical piping can be composed with a modified BHA slightly as shown in Figure 4A. In this assembly, the only alteration to the BHA of the preferred embodiment described above may be the addition of a mechanical cap 164 of selected shot adjustment or plug - selected trigger setting bridge 164, placed below the lower selected trigger gun assembly, as shown in Figure 4A. In general, the selected trigger setting mechanical plug 164 may be either a bridge plug or a fracture deflector. A fracture deflector would generally be preferred if it is desirable to simultaneously produce zones separated by the plug immediately after the stimulation work. 31. The modified BHA, shown in Figure 4A, consists of a selected shotgun system (Figure 4A illustrates a gun system comprising piercing guns 174, 184 and 194 with associated charges 176, 186 and 196. and firing heads "selected 172, 182 and 192), an ademe-collar setter 128, flow ports 114, 116 and 122, a resettable inflatable plug 120, a resettable mechanical axial slide device 124 and bridge plug assembly selected firing head 164 using the selected firing head 162. The modified BHA is run into the well via a lubricator and the injection head of the helical pipe is suspended by a crane or platform above the drill hole. BHA is run in the well while the depth is correlated with the ademe-collar inserter 33. As shown in Figure 4A, the modified helical / BHA pipe is made to run r to the auger to position the selected mechanical trip plug 164 above the last previously stimulated zone 252. 34. As shown in Fig. 4B, the selected trip head 162 is triggered to adjust the selected mechanical trip plug 164 by above the last previously stimulated zone 252. 35. After the selected trigger head 162 of the bridge plug is activated to adjust the selected trigger bridge plug 164, the modified helical / BHA pipe is then raised to a location within the hole, in such a way that the first (lower) set of drilling loads 176 contained in the selected firing drilling gun system are placed directly through the next lower target area to be drilled, where a control can be established accuracy of the depth based on readings from the ademe - collar setter 128 and helical pipe odometer systems l placed on the surface equipment. The action of moving the BHA up to the site of the first perforated interval will cycle the resettable mechanical slide elements 124 to the locked position and will require the cycling of the axial load of the helical pipe from tension to tension and back. - to return the adjustable mechanical sliding elements to the running position. 36. As shown in Figure 4B, the first set of operating loads 176 in the modified BHA are selectively triggered by remote operation, via the second selected firing head 172 to penetrate the ademe 82 and cement shell 84 with perforations. 270, 271 and establish hydraulic communication with the formation 86 by means of the resulting perforations 270-217. 37. If there is sufficient space between the last pre-positioned perforations 250, 251 and the location of the next set of perforations 270, 271 to be stimulated to allow proper placement of the BHA for perforation, isolation and stimulation of the next set of perforations 270, the selected trigger bridge plug 164 can be fixed below the last pre-stimulated perforations 250, 251 and the resettable inflatable plug can be used during the first stimulation operation to isolate the upper perforations 270, 271 from the pre-stimulated perforations 250 , 251. 38. Then, the entire process described above is repeated as appropriate, until all the planned zones are stimulated individually (Figure 4A and • Figure 4B represents a BHA designed for an additional three-zone stimulation operation). It will be recognized by those skilled in the art that the preferred suspension method when fluids loaded with support agent are involved would be conventional hinged tubing or helical tubing, preferably with one or more circulation holes, such that • the support agent that sits in the hole could be easily circulated out of the hole. Treatments such as acid fracturing or matrix acidification may not require such capacity and could be easily carried out with a cable-based deployment system, such as a sand line or wire line or based on a tractor system in the bottom of the well. It will be recognized by those skilled in the art that, depending on the objectives of a particular task, several pumping systems could be used and could involve the following arrangements: (a) pumping over the annulus created between the cable or pipe (if the deployment uses cable or pipe); (b) pumping into the helical pipe or articulated pipe, if the suspension method involves the use of helical pipe or articulated pipe and the excess friction and erosion of the supporting agent were not of concern for the well depths considered or - (c) pumping simultaneously to the annulus created between the pipeline (if the deployment method involves piping) and the ademe wall and the interior of the pipe, if excessive friction and erosion of the support agent were not of concern for the well depths considered. Figure 5 illustrates a second embodiment of the invention where helical tubing is used as the deployment means and the excess friction is not of concern and whether the support agent is not pumped during the task or use of the support agent It is not of concern. Figure 5 shows that the helical pipe 106 is used to suspend the BHA and the components of the BHA. In this mode, the individual zones are treated in sequential order, from the sites of the little hole 'deep to deeper borehole sites. In this embodiment, as shown in FIG. 5, the circulation orifice 114 is now positioned below the resettable inflatable plug 120, so that the treatment fluid can be pumped into the helical tube 106, exit the orifice. circulation 114 and be positively forced to enter the target perforations. As an illustration of the operations, Figure 5 shows that the resettable inflatable plug 120 has been driven and adjusted below the perforations 241 that are associated with a hydraulic fracture of the previous zone. 242. The resettable inflatable plug 120 provides hydraulic isolation, such that when the treatment fluid is subsequently pumped into the helical pipe 106, the treatment fluid is forced to enter the pre-positioned holes 230 and 231 and create new fractures. hydraulic 232. Then, the operations are continued and repeated as appropriate by the desired number of training zones and intervals. Figure 6 illustrates a third embodiment of the invention wherein the helical pipe is used as the deployment means and the excess friction is not of concern and if the supporting agent is not pumped during the task or use of the supporting agent there is no It is of concern. Figure 6 shows that helical pipe 106 is used to suspend the BHA and BHA components. In this mode, individual zones can be treated in any order. In this embodiment, as shown in Figure 6, an inflatable saddle seal sealant mechanism 125 is used as the resettable sealing mechanism and the circulation orifice 114 is now positioned between the upper inflatable seal element 121 and the lower inflatable sealing element 123. When the upper inflatable sealing element 121 and the lower inflatable sealing element 123 are actuated, the treatment fluid can be pumped into the interior of the pipeline - helical 106 to exit the circulation hole 114 and then be positively forced to enter the target perforations. As an illustration of the operations, Figure 6 shows that the upper inflatable sealing element 121 and the lower inflatable sealing element 123 have been driven and adjusted through perforations 241 that are associated with the next zone to be fractured. The resettable inflatable plug 120 provides hydraulic isolation, such that when the treatment fluid is subsequently pumped into the helical pipe 106, the treatment fluid is forced into the pre-positioned holes 240 and 241 and create new hydraulic fractures 242. Then the operations are continued and repeated as appropriate by the desired number of training zones and intervals. Figure 7 illustrates a fourth embodiment of the invention wherein a wire line 102 is used as the deployment means for suspending the BHA and BHA components. In this mode, the individual zones are treated in sequential order, from the deepest borehole sites to the shallow borehole sites. In this embodiment, as shown in Figure 7, the treatment fluid can be pumped through the annulus between the wire line 102 and the wall of the production flange 82 and be positively forced into the target perforations. In this In this embodiment, the resettable inflatable shutter 120 also contains the electric pump system 117, energized by electrical energy transmitted to the bottom of the well via the wire line, to inflate or deflate the sealable inflatable plug 120 using the borehole fluid. Figure 7 shows that the resettable inflatable plug 120 has been driven and adjusted below the perforations 241 that are associated with the next zone to be fractured. The resettable inflatable plug 120 provides hydraulic isolation, such that when the treatment fluid is subsequently pumped to the annulus between the wire line 102 and the production die 82, the treatment fluid is forced into the perforations 240 and 241. and create new hydraulic fractures 242. Then the operations are continued and repeated as appropriate by the desired number of training zones and intervals. A fifth embodiment of the invention involves the deployment of additional pipe chains or cables, hereinafter referred to as "umbilicals" to the interior and / or exterior of the helical pipe (or articulated pipe). As shown in Figure 8A and Figure 8B, a pipe umbilical 104 is shown deployed into the helical pipe 106. In this embodiment, the pipe umbilical 104 is connected to the resettable sealing mechanism 120 and in this embodiment, the sealing mechanism Resettable 120 is now driven via hydraulic pressure transmitted via umbilical 104. In principle, multiple umbilicals can be deployed either inside the helical pipe and / or annulus between the helical pipe and the production flange. In general, umbilicals can be used to perform different operations, which include, but are not limited to, providing: (a) hydraulic communication for driving individual BHA components including, but not limited to a: the sealing mechanism and / or drilling device; (b) flow conduits for injection or downhole circulation of additional fluids; and (c) for data acquisition of bottomhole measurement devices. It will be noted that, as shown in Figure 8A, the BHA also includes centralizers 201, 203 and 205 that are used to keep the BHA centered in the borehole when the BHA components are in the run position. The use of an umbilical (s) may provide the ability to hydraulically couple and / or disengage the resettable sealing mechanism of the hydraulic pressure condition within the helical piping. Then, this allows the method to be extended to the use of adjustable mechanical sealing mechanisms that require independent hydraulic operation for operation. The devices - Drilling that require hydraulic pressure for selective firing can be triggered by an umbilical. This can then allow the wire line, if deployed with the helical pipe and the BHA, to be used for the transmission of a channel or additional channels of electrical signals, as may be desirable for the acquisition of meter data located in the bottomhole mounting or drive of other BHA components, for example, an electric motor impeller downhole that could provide rotation / torque for BHA components. Alternatively, an umbilical could be used to operate a hydraulic motor for the drive of several components to the bottom of the well (for example, a hydraulic motor to couple or separate the resettable sealing mechanism). The use of an umbilical (s) can provide the ability to inject or circulate any fluid to the bottom of the well to multiple sites as desired with precise control. For example, to help mitigate the seating of the support agent on the sealing mechanism during a fracture treatment of the supportive agent, hydraulic, umbilical (s) could be deployed (s) and used to provide continuous or intermittent washing and circulation to prevent the support agent from accumulating on the sealing mechanism. For example, an umbilical could run - just above the resettable mechanical seal mechanism, while another runs just below the resettable mechanical seal mechanism. Then, as desired, fluid (eg nitrogen) can be circulated to the bottom of the well either to one or both sites to wash the support agent from the region surrounding the sealing mechanism and hence mitigate the potential for the BHA sticks due to the accumulation of the support agent. In the case of fluid circulation, it will be noted that the size of the umbilical and fluid would be selected to ensure that the desired velocity is obtained and is not unduly limited by the friction pressure in the umbilical. In addition to the umbilicals consisting of chains of tubes that provide hydraulic communication to the bottom of the well as signaling means for actuating BHA components (or possibly as means of signal transmission for recording on the surface of measurements at the bottom of the well) in general, one or more wire line or fiber optic cables could be employed in the borehole to provide electrical or electro-optical communication to the bottom of the well as signaling means for driving the BHA components (or possibly as a means of of signal transmission for the recording on the surface of measurements at the bottom of the well). Figure 9 illustrates a sixth embodiment of the invention, wherein a tractor system, consisting of the upper drive tractor unit 131 and the lower tractor drive unit 133, is attached to the BHA and is used to deploy and position the BHA inside the hole. In this modality, the individual zones are treated in sequential order, from the deepest sites of the hole to the shallow sites of the hole. In this embodiment, the BHA also contains an internal electric pump system 117, energized by electrical energy transmitted to the bottom of the well via the wire line 102, to inflate or deflate the sealable inflatable plug 120 using the borehole fluid. In this embodiment, the treatment fluid is pumped into the annulus between the wire line 102 and the wall of the production flange 82 and is positively forced into the target perforations. Figure 9 shows that the resettable inflatable plug 120 has been driven and adjusted below the perforations 241 that are associated with the next zone to be fractured. The resettable inflatable plug 120 provides hydraulic isolation, such that when the treatment fluid is subsequently pumped to the annulus between the wire line 102 and the production die 82, the treatment fluid is forced into the perforations 240 and 241. and create new hydraulic fractures 242. Then, the operations are continued and - repeated as appropriate by the desired number of training zones and intervals. As alternatives to this sixth modality, the tractor system could be self-propelled, controlled by on-board computer systems and signaling systems carried on board, in such a way that it would not be necessary to attach the cable or pipe for positioning, control and / or tractor system drive. In addition, the various components of the BHA could also be controlled by on-board computer systems and signaling systems carried on board, so that it is not necessary to attach the cable or pipe for the control and / or actuation of the components. For example, the tractor system and / or BHA components would carry on-board power supplies (eg, batteries), computer systems and data transmission / reception systems, such that the tractor and BHA components could be remotely controlled from the surface by remote signaling means or alternatively, the various on-board computer systems could be preprogrammed on the surface to execute the desired sequence of operations when deployed in the borehole. In a seventh embodiment of this invention, abrasive (or erosive) fluid jets are used as the means for drilling the borehole. The fluid jet projection - Abrasive (or erosive) is a common method used in the petroleum industry to cut and drill pipe chains to the bottom of the well and other components of the borehole and well head. The use of helical tubing or articulated tubing as the suspension means of the BHA provides a flow conduit for the deployment of abrasive fluid jet cutting technology. To accommodate this, -the BHA is configured with a jet projection tool. This jet projection tool allows high-speed, high-pressure abrasive (or erosive) fluid systems or suspensions to be pumped to the bottom of the well through the pipe and through the jet nozzles. The abrasive (or erosive) fluid cuts through the wall of the production ademe, cement envelope and penetrates the formation to provide a flow path communication to the formation. Arbitrary distributions of holes and slots can be placed using this jet tool throughout the consummation interval during the stimulation task. In general, cutting and drilling with abrasive (or erosive) fluid can be easily carried out under a wide range of pumping conditions, using a wide range of fluid systems (water, gels, oils and liquid fluid systems combination). / gas) and with a variety of solid abrasive materials (sand, ceramic materials, - etc.), if the use of solid abrasive material is required for the specific bore hole application. The jet projection tool replaces the conventional selective shot perforating gun system described in the six previous modes and since this jet projection tool may be of the order of 30 cm to 1.20 meters (one foot to four feet) of length, the height requirement for the surface lubricator system is greatly reduced (possibly by up to 18 meters (60 feet) or greater) when compared to the required height when using conventional selected perforation shotgun assemblies as the drilling device. The reduction of the height requirement for the surface lubrication system provides several benefits which include cost reductions and reductions in operating time. Fig. 10 illustrates in detail a seventh embodiment of the invention wherein a jet projection tool 310 is used as the piercing device and articulated tubing 302 is used to suspend the BHA in the borehole. In this embodiment, a resettable mechanical plug 316 set by compression is used as the resettable sealing device; a mechanical adjuster of ademe - collar 318 is used for the control and positioning -of the depth of the BHA; a one-way unidirectional unidirectional butterfly valve 304 auxiliary is used to ensure that fluid will not flow to the articulated tubing 302; a combination of release jaw collar assistant - cut 306 is used as a safety release device; an auxiliary circulation / compensation orifice 308 is used to provide a method for fluid circulation and also pressure compensation above and below the mechanical resettable inflatable shutter 318 adjusted by compression, under certain circumstances and a unidirectional valve auxiliary 314 of The unidirectional ball seat is used to ensure that the fluid can only flow upwards from below the mechanical resettable inflatable plug 316 adjusted by compression to the circulation orifice orifice aids 308. The jet projection tool 310 contains flow orifices at jet 312 which are used to accelerate and direct the pumped abrasive fluid to the articulated tubing 302 for jetting with direct shock on the production flange 82. In this configuration, the proximal mechanical fitting 318 is appropriately designed and connected to reset mech shutter nico compression set 316 to allow fluid to flow upward from the mechanical shutter adjusted resettable -compression 316 to the circulation orifice orifice 308 auxiliary. The cross-sectional flow area associated with the flow conduits contained within the circulation orifice orifice auxiliary 308 is dimensioned to provide a substantially cross-sectional flux area. larger than the flow area associated with the jet flow orifices' 312, such that most of the flow contained within the articulated tubing 302 or BHA preferably flows through the circulation orifice orifice aids 308, instead of the jet flow orifices 312, when the circulation orifice orifice auxiliary 308 is in the open position. The circulating / compensating orifice auxiliary 308 is opened and closed by the upward and downward axial movement of the articulated tubing 302. In this embodiment, the articulated tubing 302 is preferably used with the compressed mechanical resettable obturator 316, since the compression adjustable mechanical resettable shutter 316 can be easily activated and deactivated by the vertical movement and / or rotation applied via the articulated tubing 302. The vertical movement and / or rotation is applied via the articulated tubing 302 using a scour unit assisted by the completion platform, with the help of a unit - rotating power as the surface means for connection, installation and removal of the articulated pipe 302 in and out of the borehole. It will be noted that the physical elements of the surface, methods and procedures associated with the use of a scour unit assisted by a rotating power unit are common and well known to those skilled in the art for connection, installation and removal. of articulated pipe to / from a borehole under pressure. Alternatively, the use of a completion platform with the help of a rotating power unit and separation head in place of the scour unit could accommodate the connection, installation and removal of the articulated pipe in / from a borehole under pressure; again this is common and well known to those skilled in the art for connection, installation and removal of articulated tubing in / from a borehole under pressure. It will be further noted that the configuration of the platform and plumbing of the platform on the surface will include manifolds, pipes and valves appropriate to accommodate the flow towards, from and between all the appropriate surface components / facilities and the borehole, including, but not limited to, the articulated pipeline, the annulus between the articulated pipe and the production line, pumps, fluid tanks and Counterflow pits. Since the compression-set mechanical resettable shutter is actuated via the articulated movement and / or rotation of the articulated tubing 302, the fluid can be pumped through the articulated tubing 302 without the need for additional control valves and / or isolation valves that otherwise they would be required if an inflatable shutter were used as the resettable sealing device. The interior of the articulated tubing 302 is used in this manner to provide an independent flow passage between the surface and the jet projection tool 310, such that the abrasive fluid can be pumped to the articulated tubing 302 to the tool. jetting 310. The jet flow orifices 312 located on the jet projection tool 310 then create a jet of high speed abrasive fluid which is directed to perforate the production ademe 82 and cement shell 84 to establish communication Hydraulic with the formation 86. Figure 10 shows the jet projection tool 310 that has been used to place perforations 320 to penetrate the first formation interval of interest and that the first formation interval of interest has been stimulated with hydraulic fractures 322 Figure 10 further shows that the jet projection tool 310 has been repositioned nothing inside the hole and used to - placing perforations 324 in the second formation interval of interest and that the compression-set mechanical adjusting seal 316 has been driven to provide a hydraulic seal within the hole, in advance to the stimulation of perforations 324 with the second stage of the fracture treatment with multi-stage hydraulic support agent. It will be noted that the jet flow orifices 312 can be positioned within about 15 cm (six inches) to 30 cm (one foot) of the compression-set mechanical resettable plug 316, such that after pumping of the second stage of If the build-up of the support agent on top of the mechanical resettable obturator 316 is out of interest, a non-abrasive and non-erosive fluid can be pumped into the articulated tubing 302 and through the jet flow orifices 312 and / or the circulation orifice orifice auxiliary _308 as necessary to clean the support agent from the top of the compression-set mechanical resettable shutter 316. In addition, the jet projection tool 310 can be rotated (when the mechanical resettable shutter adjusted by compression 316 is not actuated) using the articulated tubing 302 that can be rotated with the rotating power unit in the super also help to clean up the accumulation of the support agent that - may occur above the compression-set mechanical adjusting plug 316. Since the perforations are created using a jet fluid, no burrs are created. Since drilling burrs are not present to potentially provide additional tear and wear on the elastomers of the compression-set mechanical resettable plug 316, the longevity of the compression-settable mechanical resettable plug 316 may be increased compared to applications where burrs may exist. drilling.
It will further be noted that the flow control provided by the unidirectional ball-seat valve auxiliary 314 and the unidirectional valve-type auxiliary 304 fully open-ended only allows pressure compensation above and below the mechanically adjustable sealant set by compression 326 when the pressure below the mechanical adjustable resettable plug 316 is greater than the pressure above the mechanical resettable plug set by compression 316. In circumstances when the pressure above the resettable mechanical plug set by compression 316 may be greater than the pressure below of the mechanically resettable shutter fitted by compression 316, the pressure above the mechanically resettable obturator adjusted by compression 316 can be easily reduced by carrying out a Controlled backflow of the newly stimulated zone using the annulus between the articulated tubing 302 and the production ademe 82 or by the circulation of the lower density fluid (eg nitrogen) to the articulated tubing 302 and up to the annulus between the tubing articulated 302 and the production ademe 82. The fully opened unidirectional fin-type valve 304 auxiliary is preferred since this type of design accommodates the unrestricted pumping of the abrasive (or erosive) fluid to the bottom of the well and also allows the passage of balls control that, depending on the specific detailed design of the individual BHA components, can be dropped from the surface to control the fluid and hydraulic flow of the individual BHA components or provide for the safe release of the BHA Depending on the specific design of the tool, many different valve configurations could be deployed to provide the functionality provided by the flow control valves described in this mode.
As alternatives to this seventh modality, an auxiliary containing a nipple could be included, which could provide the ability to suspend and retain other measuring devices or BHA components. This nipple, for example, could retain a conventional ademe-collar inserter and gamma-ray tool that is deployed - via wire line and seated in the nipple to provide additional diagnosis of the position and placement of the BHA of training intervals of interest. Additionally, multiple abrasive jet projection tools can be deployed as part of the BHA to control cutting-perforation characteristics, such as hole / slot size, cutting speed, to accommodate various abrasive materials and / or to provide system redundancy. in the case of premature failure of the components. It will be recognized by those skilled in the art that many different components may be deployed as part of the bottomhole assembly or assembly. The bottomhole assembly may be configured to contain instruments for reservoir measurement, fluid and borehole properties as deemed desirable for a given application. For example, temperature and pressure gauges could be deployed to measure the temperature and pressure conditions of the fluid at the bottom of the well during the course of treatment. A densitometer could be used to measure the effective density of the fluid at the bottom of the well (which would be particularly useful to determine the distribution and location in the bottom of the well of the support agent during the course of a hydraulic support fracture treatment) and a radioactive detector system (for example, gamma ray or neutron measurement systems) could be used "for the location of hydrocarbon carrier zones or to identify and locate radioactive material within the borehole or formation.
Depending on the specific downhole assembly components and if the drilling device creates burr holes that can damage the sealing mechanism, the bottomhole assembly could be configured with a "burr removal tool". "that act to scrape and remove burrs drilling the wall of the ademe. Depending on the specific downhole assembly components and if excessive downhole component wear can occur if the assembly is run in contact with the wall of the well, centralizer aids could be deployed in the bottom mount of the hole to provide positive mechanical positioning of the assembly and to prevent or minimize the potential for damage because the assembly runs in contact with the wall of the housing. Depending on the specific downhole mounting components and whether the drilling loads create severe shock waves and induce undue vibrations when fired, the downhole assembly may be configured with shock / vibration damping aids that would eliminate or they would minimize any »- adverse effects on the performance of the system due to detonation of the drilling load. Depending on the deployment system used and the objectives of a particular task, the drilling devices and any other desired BHA components can be positioned either above or below the resealable sealing mechanism and in any desired order with each other. The deployment system itself, whether wire line, power line, helical pipe, conventional articulated pipe or downhole tractor, can be used to transport signals to activate the sealing mechanism and / or drilling device. It would also be possible to suspend such signaling means within conventional articulated tubing or helical tubing used to suspend the sealing and piercing devices themselves. Alternatively, the signaling means, whether electric, hydraulic or other means, could be run in the hole externally to the suspension means or even housed in or consist of one or more separate chains of helical pipe or conventional articulated pipe. With respect to treatments using high viscosity fluid systems in shallow wells of 2,438 meters (8,000 feet) several technological and economic benefits are derived immediately from the application of "This new invention.The reduction of friction pressure limitations allows the treatment of deeper wells and reduces the requirement of special fracture fluid formulations.The friction pressure limitations are reduced or eliminated due to high fluidity. The viscosity can be pumped to the annulus between the helical pipe or other means of suspension and production, since the friction pressure limitations can be reduced or eliminated from those experienced with the pumping of high viscosity fluid systems into the interior of the helical pipe, the depths of the well where this technique can be applied are substantially increased, for example, assuming a 3.8 cm (1 1/2 inch) helical pipe deployed in a 14 cm (5 1/2 inch) hole outer diameter of 0.434 Kg (1 pound) / 30 cm (1 foot), the effective cross sectional flow area is approximately equi suitable for an ademe chain of 12.7 cm (5 inches) in outside diameter. With this effective cross-sectional flow area, well depths of the order of 6,096 meters (20,000 feet) or greater can be treated at higher pumping rates (eg, of the order of 10 to 30 barrels per minute or more). be obtained for effective transport and hydraulic fracturing using high viscosity fluids. Since the annulus can commonly have a larger equivalent flow area, conventional fracture fluids can be used, as opposed to special low viscosity fluids (such as Dowell-Schlumberger ClearFrac ™ fluid) used to reduce pressure flow. by friction through the helical pipe. The use of conventional fracture fluid technology will then allow the treatment of formations with temperatures greater than 121 ° C (250 ° F), above which the highest cost specialty fluids currently available can begin to degrade. The sealing mechanism used could be an inflatable device, a mechanically adjustable resettable obturator, a compression-fitted mechanical saddle seal design, cup seal devices or any other alternative device that can be deployed via suspension means and that it provide a resettable hydraulic sealing capacity or equivalent function. There are both inflatable and compression-adjusted devices that provide radial separation between the seals and the wall of the ademe (eg, from the order of 0.635 cm (0.25 inches) to 2.54 cm (1 inch) for inflatable devices or 0.254 cm (0.1 inches) - 0.51 cm (0.2 inches) for compression-adjusted devices) in such a way that the wear and tear of the seal "would be drastically reduced or completely eliminated." In a preferred embodiment of this invention, there would be sufficient separation between the sealing mechanism that in its deactivated state and the ademe wall, to allow rapid inward and outward movement of the auger without damage significant to the sealing mechanism or without pressure control issues concerning sudden rise of pressure / well movement to tool movement Increased separation between seal surface and wall of ademe (when seal is not actuated) it will also allow the helical / BHA pipe to travel in and out of the hole at much faster speeds than is possible with currently available helical piping systems, and to minimize undesirable seal wear and tear. , in a preferred embodiment, the piercing device would accommodate the drilling the ademe wall in such a way that a drilling hole with a relatively smooth edge would be obtained. Alternatively, the mechanical resettable sealing mechanism may not be necessary to provide a perfect hydraulic seal and, for example, could retain a small space around the circumference of the device. This small space could be sized to provide a sealing mechanism (if desired) - by which the support agent joins through the small space and provides a seal (if desired) that can be removed by the circulation of the fluid. Furthermore, depending on the specific application, it is possible that a stimulation task could proceed in an economically viable manner, even if a perfect hydraulic seal was not obtained with the mechanical resettable sealing mechanism. Since the drilling device is deployed simultaneously with the resettable sealing mechanism, all components can be controlled in depth at the same time by the same measurement standard. This eliminates the problems of depth control that existing methods experience when performing drilling and stimulation operations using two different measurement systems at different times and different trips to the borehole. Very precise depth control can be obtained through the use of an ademe-collar insert, which is the preferred method of depth control. The gross height of each of the individual perforated target ranges is not limited. This is in contrast to the problem that existing helical piping systems possess when using a device similar to a saddle shutter that limits the application to 4.5-9 meters (15-30 feet) of height of the perforated interval. Since permanent bridge plugs are not necessarily used, the increased cost and risk of the borehole associated with bridge plug drilling operations are eliminated. If helical piping is used as the means of deployment, it is possible that the chain of tubes used for the stimulation task could be hung at the head of the well and used as the production pipeline chain, which would result in cost savings significant by eliminating the need to mobilize the platform to the well site for the installation of the conventional production pipeline consisting of articulated pipe. The control of the sequence of zones to be treated allows the design of the individual treatment stages to be optimized based on the characteristics of each individual zone. In addition, the potential for suboptimal stimulation because multiple zones are treated simultaneously is eliminated by having only one set of open perforations exposed to each stage of treatment. For example, in the case of hydraulic fracturing, this invention can minimize the potential for overflow or suboptimal placement of the fracture support agent.
Also, if a problem occurs, such that the - treatment must be completed, the areas upstream of the well to be stimulated have not been compromised, since they still have to be drilled. This is in contrast to conventional ball sealant or helical pipe stimulation methods, where all perforations must be fired before the task. If the task of conventional helical piping fails, it can be extremely difficult to effectively deflect and stimulate in a long consummation interval. Additionally, if only one set of perforations is open above the sealing element, the fluid can be circulated without the possibility of breaking the other multiple sets of open perforations above the sealing element, as could occur in the task of conventional helical pipe. This can minimize or eliminate the loss of fluid and damage to the formation, when the pressure of circulation to the bottom of the well will otherwise exceed the pressure of the formation pore. All the treatment can be pumped in a single trip, resulting in significant cost savings over other techniques that require multiple wire lines or platform work to effect the trip in and out the hole between stages of treatment.
The invention can be applied to multi-stage treatments in deviated and horizontal holes.
"Commonly, other conventional deviation technology in the deviated and horizontal holes is more challenging due to the nature of the fluid transport of the deviating material at long intervals commonly associated with deviated or horizontal holes, if a sieving occurs during the fracture treatment, the invention provides a method for the fluid loaded with sand in the annulus to be circulated immediately out of the hole, so that the stimulation operations can be restarted without having to make the trip of the helical / BHA pipe to Outside the hole The presence of the helical pipe system provides a means to measure the bottomhole pressure after drilling or during stimulation operations based on pressure calculations involving the helical pipeline under shutdown conditions ( or low flow velocity.) The presence of the helical pipe or conventional articulated piping system, if used as the deployment means, provides a means to inject fluid to the bottom of the well independently of the fluid injected into the annulus. This may be useful, for example, in additional applications such as: (a) maintaining the BHA sealing mechanism and flow openings free from accumulation of the support agent (which could possibly cause sticking or adhesion of the tool) by pumping of the fluid to the bottom of the well at a nominal speed to clean the sealing mechanism and flow orifices; (b) downhole mixing applications (as discussed further below); (c) acid staining at the bottom of the well during drilling, to help clean the drill hole and communicate with the formation and (d) to independently stimulate two zones isolated from each other by the resettable sealing mechanism. As such, if pipe is used as the deployment means, depending on the specific operations desired and the specific components of the downhole assembly, the fluid could be circulated to the bottom of the well at all times or only when the The seal is energized or only when the sealing element is not energized or while the compensation orifices are open or closed. Depending on the specific downhole mounting components and the specific design of downhole flow control valves, such as can be used for example as integral components of compensating orifice aids, auxiliary orifice or auxiliary from the flow orifice, flow control valves can be put into operation downhole by wire line drive, hydraulic drive, flow drive, "j-shaped" drive, sliding sleeve drive or by many other means known to those skilled in the operation and operation technique of downhole flow control valves. The helical pipe system still allows controlled backflow of individual treatment stages to assist in cleaning and assist in the closure of the fracture. The counterflow can be carried out to the annulus between the helical pipe and the production flange or alternatively, the backflow can be carried out up to the helical pipe chain if the counterflow of the excessive support agent is not considered a problem.
The drilling device may consist of commercially available drilling systems. These gun systems could include what will be referred to herein as a "shotgun selected" system, such that a single drill gun assembly consists of multiple loads or sets of drilling loads. Each individual set of one or more drilling loads can be remotely controlled and fired from the surface using electrical, radio, pressure, fiber optic or other drive signals.
Each set of drilling loads can be designed (number of loads, number of shots per foot, hole size, penetration characteristics) for an optimal perforation of the individual area that will be treated with an individual stage. With the current selective firing gun technology, commercial pistol systems exist that could allow for the order of 30 to 40 intervals to be drilled sequentially in a single trip to the bottom of the well. The guns can be pre-dimensioned and designed to provide firing of multiple sets of perforations. The guns can be located anywhere in the bottom of the hole assembly, which include either above or below the mechanically resettable sealing mechanism. The intervals can be grouped for treatment based on deposit properties, treatment design considerations or equipment limitations. After each group of intervals (preferably 5 to about 20) at the end of a working day (often defined by lighting conditions) or if difficulties are encountered with sealing one or more zones, a bridge plug or other mechanical device would preferably be used to isolate the group of already treated intervals from the next group to be treated. One or more selected tripping bridge plugs or fracture deflectors could be run in conjunction with the downhole assembly and adjusted as desired during the course "of the completion operation to provide positive mechanical isolation between the perforated intervals and eliminate the need for a separate wire line to run to adjust the mechanical isolation devices or deviating agents between groups of fracture stages. of the invention can be easily employed in production tapes of 11.4 cm (4 1/2 inches) in internal diameter to 17.8 cm (7 inches) in diameter with existing commercially available drill pistol systems and mechanical resettable sealing mechanisms. The method of the invention could be employed in smaller or larger adams with mechanically adjustable sealant mechanisms designed appropriately for smaller or larger aemes.If selective firing drilling guns are used, each individual gun can be of the order of 0.61. cm (2 feet) to 2.43 m (8 feet) in length and contain the order 8 to 20 drilling loads placed along the gun tube at a shot density ranging from 1 to 6 shots per foot, but preferably 2 to 4 shots per foot. In a preferred embodiment, as many as 15 to 20 individual guns could be stacked one on top of the other, such that the overall length of the mounted gun system is preferably maintained at less than about 24.4 meters to 30.5 meters (80 to 100 meters). feet).
"This total length of the gun can be run into the hole using an easily available surface crane and lubricator system.Long gun lengths could also be used, but may require additional or special equipment depending on the total number of guns It would be noted that in some unique applications, the lengths of the gun, number of charges per gun and density of shot could be greater or less than as specified above, since the design of the drilling system In order to minimize the total length of the gun and BHA system, it may be desirable to use multiple (two or more) load carriers evenly distributed around and fastened, welded or otherwise attached to the helical pipe or connected below the mechanism Mechanical resettable seal. For example, if it is desired to stimulate 30 zones, where each zone is perforated with a 1.2 cm (4 ft.) gun, a single gun assembly would result in a total length of approximately 45.7 m (150 ft), which may be impractical. handle on the surface. Alternatively, two pistol assemblies located opposite each other in the helical pipe could be deployed, where each assembly could contain 15 pistols and the total length could be approximately 23 m (75 ft), which could be easily manipulated on the surface with existing lubricator and crane systems.
An alternative arrangement for the gun or drill guns would be to place one or more guns above the mechanical seal mechanism. There could be two or more separate pistol assemblies attached in such a way that the charges were oriented away from the components in the bottomhole assembly or helical piping. It could also be a single assembly with denser proportional loads and trigger mechanisms designed to simultaneously trigger only a subset of the loads within a given interval, perhaps all in a given phase orientation. Although the drilling device described in this embodiment uses remote fired charges or fluid jet projection to pierce the cement ademe and envelope, alternative drilling devices, including, but not limited to, chemical dissolution or devices for drilling / milling cutting, could be used within the scope of this invention for the purpose of creating a flow path between the borehole and the surrounding formation. For the purposes of this invention, the term "piercing device" will be used broadly to include all of the above, as well as any drive device suspended in the borehole for the purpose of driving loads or other piercing means that can be transported by the ademe or other means external to the bottomhole assembly or suspension method used to support the bottomhole assembly. The BHA could contain a downhole motor or other mechanism to provide rotation / torque to accommodate the actuation of mechanical sealing mechanisms that require rotation / torque for the drive. Such a device, in conjunction with an orientation device (eg, gyroscope or compass) could allow the oriented perforation of such piercing holes to be placed in a preferred direction of the compass. Alternatively, if conventional articulated tubing is used, it is possible that rotation and torque could be transmitted to the bottom of the well by direct rotation of the articulated tubing using rotating drive equipment that can be readily available on conventional reconditioning platforms. Downhole instrumentation meters for the measurement of well conditions (ademe - collar, pressure, temperature, pressure and other meters) for the verification or real time monitoring of the parameters of the task of stimulation, deposit properties and / or well performance could also be deployed as part of the BHA. In addition to the resettable mechanical deflection device, other deviating materials / devices may be pumped to the bottom of the well during treatment, which include, but are not limited to, ball sealants or particulate materials such as sand, ceramic material , support agent, salt, waxes, resins or other organic or inorganic components by alternative fluid systems such as viscous fluid, gelled fluids, foams or other chemically formulated fluid or other injectable deviating agents. The additional deviation material could be used to minimize the duration of the stimulation treatment since time savings can be made to reduce the number of times that the mechanical deviation device is adjusted, while still obtaining deviation capabilities over the multiple zones. For example, in an interval of 914 m (3,000 ft) where the individual zones are nominally separated at 30.5 m (100 ft) are going to be treated, it may be desirable to use the resettable mechanical deflection device that works and increments of 152 meters upstream of the well and then s deviate from each other in each of the six stages with a deviation agent carried in the treatment fluid. Alternatively, limited entry techniques for multiple intervals could be used as a subset of the coarse interval to be treated. Either one or the other of these variations would decrease the number of mechanical sets of the deviating device and possibly extend its effective life. If a pipe chain is used as the means of deployment, the pipeline allows the deployment of downhole mixing devices and easy application of bottomhole mixing technology. Specifically, the chain of tubes can be used to pump chemical compounds to the bottom of the well and through the flow holes in the bottomhole assembly to subsequently mix with the fluid pumped into the pipeline by the annulment of the production ademe. For example, during a hydraulic fracture treatment, it may be desirable to pump nitrogen or carbon dioxide to the bottom of the well in the pipeline and mix it with the treatment fluid at the bottom of the well, so that backflow assisted by nitrogen can be accommodated. or aided by carbon dioxide. This method and apparatus could be used for the treatment of vertical, deviated or horizontal holes.
For example, the invention provides a method for generating multiple vertical (or somewhat vertical) fractures for - intersect with horizontal or diverted holes. Such a technique could allow the economic consummation of multiple wells from a single location block. The treatment of a multilateral well could also be carried out where the deeper side is treated first; then a plug is fitted or a sleeve is operated to isolate this side; next the next side hole is treated; another plug is fitted or sleeve is operated to isolate this side and the process is repeated to treat the desired number of sides within a single hole. If drill guns of selected shot are desired, although desirable from the point of view of maximizing the number of intervals that can be treated, the use of short guns (ie, 1.2 meters (4 feet) in length or less) could limit the productivity of the well in some instances, by inducing an increased pressure drop in the reservoir region near the borehole, when compared to the use of longer guns. The productivity of the well could be similarly limited if only a short interval (that is, 1.2 meters (4 feet) in length or less) is drilled using abrasive jet projection. The potential of excessive counterflow of the support agent can also be increased leading to a reduced stimulation effectiveness. The backflow would be effected preferably at a low speed - controlled to limit the potential counterflow of the support agent. Depending on the counterflow results, alternative configurations of resin-coated support agent guns could be used to improve the effectiveness of the stimulation. In addition, if pipe or cable is used as the deployment means to help mitigate the erosion of the potential undesirable support agent in the pipe or cable from the direct shock of the fluid loaded with support agent when it is pumped to the injection ports on the side At the outlet, an "isolation device" could be installed on the platform of the well head. The isolation device may consist of a flange with a short length of attached pipe, which runs through the center of the well head up to a few feet below the injection holes. The bottom of the well assembly and pipe or cable are run inside the pipe of the insulation device. Thus, the pipe of the isolation device deflects the support agent and isolates the pipe or cable from the direct shock of the support agent. Such an isolation device would consist of a pipe of appropriate diameter, such that it would easily allow the largest external diameter dimension associated with the pipe or cable and the bottomhole assembly to pass unimpeded. The length of the insulation device could be dimensioned such that in the event of damage, the lower main fracture valve could still be closed and the wellhead placed on the platform as necessary to remove the insulation tool. Depending on the stimulation fluids and the injection method, a device and isolation would not be necessary if corrosion concerns are not present. Although field tests of the insulation devices have not shown erosion problems, depending on the design of the task, there could be some risk of erosion damage to the pipe assembly of the insulation tool, resulting in difficulty in removing it. If an insulation tool is used, the preferred practices would be to keep the crash velocity in the insulation tool substantially below the typical erosion limits, typically less than 55 meters / second (180 feet / second) and more preferably less than approximately 18 meters / second (60 feet / second). Another concern with this technique is that premature sieving may occur if the displacement of the fluid during pumping is not properly measured, since it can be difficult to initiate a fracture with fluid loaded with support agent through the next area to be perforated. It may be preferable to use a KCl fluid or some other ungelled fluid or fluid system for the block, instead of a gelled block fluid to better initiate fracture of the next zone. Pumping the task at a higher speed with an ungelled fluid between the stages to obtain a turbulent sweep / wash of the ademe will minimize the risk of screening the support agent. Also, the contingency pistols available in the tooling chain would allow the task to be continued after an appropriate waiting time. Although the modalities discussed above are primarily concerned with the beneficial effects of the process of the invention when applied to hydraulic fracturing processes, this should not be construed to limit the claimed invention, which is applicable to any situation in which drilling and Execution of other drill operations in a single trip is beneficial. Those skilled in the art will recognize that many variations not specifically mentioned in the examples will be equivalent in function to the purposes of this invention.

Claims (8)

  1. CLAIMS 1. A method for drilling and treating multiple intervals of one or more underground formations intersected by a borehole, the method is characterized in that it comprises: (a) deploying a bottomhole assembly ("BHA") inside the borehole, mounting from the bottom of the well has a drilling device, a sealing mechanism and at least one pressure compensation means; (b) using the drilling device to drill an interval of one or more underground formations; (c) actuate the sealing mechanism to establish a hydraulic seal in such a borehole; (d) pumping a treatment fluid into the borehole and to the bores created by the drilling device, without removing the borehole drilling device; (e) establishing pressure communication between the portions of the bore above and below the sealing mechanism by means of at least one pressure compensation means; (f) releasing the sealing mechanism and (g) repeating steps (b) to (f) at least one additional interval of the one or more subterranean formations. 2. A method for drilling and treating multiple intervals of one or more underground formations intersected by a borehole, the method is characterized in that it comprises: (a) deploying a bottomhole assembly ("BHA") into the borehole, mounting the bottom of the borehole, Well has a drilling device and at least one sealing mechanism, the drilling device is positioned below the sealing mechanism; (b) using the at least one drilling device to drill a range of the one or more underground formations; (c) actuating the at least one sealing mechanism to establish a hydraulic seal in such a bore; (d) pumping a treatment fluid into the borehole and to the bores created by the drilling device, without removing the borehole drilling device; (e) releasing the sealing mechanism and (g) repeating steps (b) to (e) at least one additional interval of the one or more subterranean formations. 3. The method according to claim 2, characterized in that the drilling device has no passage for the flow of the washing fluid provided therethrough. The method according to claim 1 or 2, characterized in that the bottomhole assembly is repositioned in the hole and the sealing mechanism is operated to establish a hydraulic seal below the perforated range. 5. A method for drilling and treating multiple ranges of one or more underground formations intersected by a borehole, the multiple ranges include a larger depth target range and sequentially shallow target ranges, the method is characterized in that it comprises: (a) deploying an assembly from the bottom of the well ("BHA") inside the hole, the bottomhole assembly has a drilling device and a sealing mechanism, the drilling device is positioned below the sealing mechanism; (b) using the drilling device to drill the deepest objective range of the one or more underground formations; (c) pumping a treatment fluid into the borehole and into the bores created in the deeper target range by the drilling device, without removing the borehole drilling device; (d) positioning the bottomhole assembly in the borehole and using the drilling device to drill the next sequentially shallower objective range of such one or more underground formations; (e) repositioning the bottomhole assembly in the borehole and actuating the sealing mechanism to hydraulically isolate the perforations created in the next sequentially shallower target range from the deeper target perforated range; (f) pumping a treatment fluid into the borehole and to the bores created in the next sequentially shallower target range by the drilling device, without removing the borehole drilling device; (g) releasing the sealing mechanism and (h) repeating steps (d) to (g) by at least one additional sequentially shallower target interval of the one or more subterranean formations, wherein the perforations created in the less additional sequentially shallower target ranges are hydraulically isolated from the perforated intervals below. 6. An apparatus for use in drilling and treating multiple intervals of one or more underground formations intersected by a borehole, the apparatus is characterized in that it comprises: (a) a bottomhole assembly (BHA), adapted to be deployed at such a hole by deployment means, the bottomhole assembly has at least one - drilling device for sequentially piercing the multiple intervals, at least one sealing mechanism and at least one compensation means and (b) the sealing mechanism is capable of establishing a hydraulic seal in the borehole, the compensation means of pressure are able to establish a pressure communication between portions of the hole above and below the sealing mechanism and the sealing mechanism is also capable of releasing the hydraulic seal to allow the bottomhole assembly to move to a different position within the hole, thereby allowing each of the multiple treatment intervals to be treated separately from the other treatment intervals. 7. An apparatus for use in the drilling and treatment of multiple intervals of one or more underground formations intersected by a borehole, the apparatus is characterized in that it comprises: (a) a bottomhole assembly (BHA), adapted to be deployed in such a borehole by deployment means, the bottomhole assembly has at least one drilling device for sequentially drilling the multiple intervals and at least one sealing mechanism, the drilling device is positioned below the sealing mechanism and (b) ) the sealing mechanism is able to establish a - hydraulic seal in the hole and is also capable of releasing the hydraulic seal to allow the bottomhole assembly to move to a different position within the borehole, thereby allowing multiple treatment intervals to be treated separately from the other ranges of treatment. The apparatus according to claim 7, characterized in that the drilling device has no flow passage for the flushing fluid provided therethrough.
MXPA02007728A 2000-02-15 2001-02-14 Method and apparatus for stimulation of multiple formation intervals. MXPA02007728A (en)

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