NO330514B1 - Method and system for perforation and treatment of multiple formation intervals - Google Patents

Description

Field of the invention

The present invention generally applies to the field of perforating and treating underground formations to increase the production of oil and gas from them. More specifically, the invention relates to a device and a method for perforating and treating multiple intervals without it being necessary to remove equipment from the wellbore between the steps or stages.

Background for the invention

When an underground reservoir formation containing hydrocarbon deposits does not have sufficient permeability or flow capacity to allow the hydrocarbons to flow to the surface in economic quantities or at an optimal rate, hydraulic fracturing or chemical stimulation (usually acid) is often used to increase the flow capability. A wellbore that passes through an underground formation typically consists of a metal pipe (casing) cemented into the original wellbore. Holes (perforation) are made that go through the casing and the cement sleeve that surrounds the casing, so that hydrocarbons can flow into the wellbore, and so that, if necessary, treatment fluids can flow from the wellbore into the formation.

Hydraulic fracturing consists of injecting fluids (usually viscous shear-thinning, non-Newtonian gels or emulsions) into a formation at such high pressure and speed that the reservoir rock cracks and forms a planar, typically vertical, fracture (or fracture network) which can be similar to the fracture that occurs in a block of wood when you wrap a nappy in it. Granular proppant material, such as sand, ceramic beads, or other materials are usually injected with the last portion of the fracturing fluid to keep the fracture(s) open after the pressure is released. Increased flow capacity from the reservoir results from the extended flow path between the grains of proppant material in the fracture(s). In chemical stimulation treatments, the flow capacity is improved by dissolved material in the formation or changes to the formation properties in another way.

The use of hydraulic fracturing as described above is a routine part of operations within the petroleum industry as it is applied to individual target areas of up to approximately 60 meters of total vertical thickness of underground formation. When there are multiple or layered reservoirs to be hydraulically fractured, or a very thick hydrocarbon-bearing formation (over 60 meters), alternative techniques are required to achieve treatment of the entire target area. The procedures for increasing treatment coverage are often called "diversion" procedures in the petroleum industry's terminology.

When multiple hydrocarbon-bearing zones are stimulated by hydraulic fracturing or chemical stimulation treatment, economic and engineering advantages are achieved by injecting multiple treatment stages that can be diverted (or separated) by various means, including mechanical means such as bridge plugs, packings, downhole valves, sliding casings , as well as guide plate/plug combinations, ball seals, particulates such as sand, ceramic material, proppant, salt, wax, resins or other compositions, or by alternative fluid systems such as viscosified fluids, gelified fluids, foams or other chemically formed fluids, or the use of methods with limited intervention. These and all other methods and instruments for temporarily blocking fluid flows into or out of a given set of perforations will be referred to as "diversion means".

In diversion, for example with mechanical bridge plugs, the deepest interval is first perforated and fracture stimulated, then the interval is typically isolated with a wire-line inserted bridge plug, and the process is repeated in the next interval above. Assuming that the target is ten perforation intervals, treatment of 300 meters of formation in this way will typically require ten jobs over a time interval of ten days to two weeks with not only multiple fracture treatments, but also multiple perforation and bridge plug operations. At the end of the treatment process, a clean-up operation will be required for the wellbore to remove the bridging plugs and put the well into production. The main advantage of using bridge plugs or other mechanical diversion means is the certainty that the entire target zone has been treated. The shortcomings are primarily the high treatment costs resulting from multiple trips in and out of the wellbore and the risk of complications due to so many operations in the well. For example, a bridge plug can get stuck in the liner and have to be drilled out at great expense. Another shortcoming is that the necessary clean-up operation in the wellbore can damage some of the intervals that have been successfully fractured.

One alternative to using bridge plugs is to fill the portion of the wellbore associated with the newly fractured interval with fracturing sand, often referred to as the "Pine Island technique". The sand column in the wellbore will mostly plug the already fractured interval and allow the next interval to be perforated and fractured independently. The biggest advantage is the elimination of the problems and risks associated with bridge plugs. The disadvantages are that the sand plug does not form a perfect hydraulic seal and can be difficult to remove from the wellbore after all the fracture stimulations have ended. Unless the well's production of fluid is sufficiently powerful to carry the sand from the wellbore, the well may still need cleaning with an overhaul rig or coiled tubing unit. As before, additional wellbore operations will increase costs, mechanical risks and risk of damage to the fractured intervals.

Another method of diversion consists in the use of particulate materials, granular solids that are placed in the treatment fluid to aid diversion. When the fluid is pumped and particulates enter the perforations, a temporary blockage forms in the area that receives the fluid, if a sufficiently high concentration of particulates is introduced into the fluid flow. The flow restriction will then divert fluid to the other areas. After the treatment, the particulate matter is removed by produced formation fluids or by injected flushing fluid, either by fluid transport or by dissolution. Commonly available particulate control fluids include benzoic acid, naphthalene, rock salt (sodium chloride), resin materials, waxes, and polymers. Alternatively, sand, proppant and ceramic materials can be used as particle deflectors. Other specialized particulates can be engineered to precipitate and form during processing.

Another method for diverting involves using viscosified fluids, viscous gels or foam types as diverting agents. This method involves the diverter fluid being pumped over and/or into the perforated interval. These fluid systems are designed to temporarily shut off flow to the perforations due to viscosity or propagation-related permeability reductions, and are also designed so that the fluid system breaks down, degrades or dissolves (with or without the addition of chemicals or other additives to trigger such breakdown or dissolution) at the desired time so that flow can be restored to or from the perforations. These fluid systems can be used for derivation of matrix-based chemical stimulation treatments and fracture treatments. Particulate deflectors and/or ball seals are sometimes incorporated into these fluid systems to enhance diversion.

Another possible process is diversion with limited access, where the entire target area of the formation to be treated is perforated with a very small number of perforations, usually of small diameter, so that the pressure loss across these perforations during pumping will induce a high, internal wellbore pressure. The internal wellbore pressure is calculated to be high enough to ensure that all the perforated intervals are fractured simultaneously. If the pressure were to be too low, only the weakest parts of the formation would fracture. The primary advantage of limited access diversion is that there are no obstructions within the casing, such as bridging plugs or sand, which could cause problems later. The disadvantage is that limited access diversion often does not work well when the intervals are thick, because the resulting fracturing often becomes too narrow (not all the proppant can be pumped away into the narrow fracture and therefore remains in the wellbore), and the initially high wellbore pressure may persist not. When the sand material is pumped, the perforation diameter is often rapidly eroded to an increased size which reduces the internal wellbore pressure. The end result may be that the entire target area is not stimulated. A further problem is the possibility that the flow capacity into the well hole will be limited as a result of the small number of perforations.

Some of the problems resulting from failure to stimulate the entire target area or the use of mechanical methods requiring multiple wellbore operations and wellbore interventions involving greater risk and cost as described above can be circumvented by using limited, concentrated perforated intervals derived from ball seals. The area under treatment could be divided into sub-areas with perforations placed more or less centrally in each individual sub-area, or sub-areas could be selected on the basis of analyzes of the formation to target desired fracture locations. The fracture stages could then be pumped with diversion of ball seals at the end of each stage. More specifically, 300 meters of formation mass could be divided into ten sub-areas of approximately 30 meters each. In the center of each 30-meter sub-area, ten perforations could be shot at a density of 3 shots per meter of casing. A fracture stage could then be pumped with proppant-filled fluid followed by ten or more ball seals, at least one for each open perforation in a single perforation set or interval. The process could then be repeated until all the perforation sets were fractured. Such a system is detailed in US Patent No. 5,890,536, issued April 6, 1999.

To date, all areas to be treated in a given job using a ball seal as a diverter have been done prior to pumping treatment fluids, and ball seals have been used to divert treatment fluids from areas that have already been broken up or that have otherwise taken the largest fluid flow , to areas that have received little or no fluid prior to the release of ball seals. Treatment and sealing theoretically takes place on an area by area basis, depending on relative break-up pressure or permeability, but problems were often encountered with balls prematurely settling on one or more of the open perforations outside the target interval and with two or more areas being treated at the same time . Moreover, this technique assumes that each perforation interval or sub-area would be broken up and fractured at a sufficiently different pressure so that each treatment step would involve only one set of perforations.

The main advantages of ball seal derivation are low costs and low risk of mechanical problems. The cost is low because the process can typically be completed in one continuous operation, usually in just a few hours in a single day. Only the ball seals are left in the wellbore to either flow out with produced hydrocarbons or to fall to the bottom of the well in an area called the rat or junk hole. The most significant shortcoming is that one cannot be sure that only one set of perforations will fracture at a time so that the correct number of ball seals are dropped at the end of each processing step. In fact, optimal benefit of the process depends on one fracture step entering the formation through only one set of perforations and all other open perforations remaining relatively unaffected during the treatment step in question. Further deficiencies are the lack of certainty that all the perforated intervals will be processed and the order in which these intervals will be processed while the job is being executed. When the sequence of area treatment is not known or controlled, it is not possible to ensure that each individual area is treated or that an individual stimulation treatment step has been optimally calculated for the target area. In some cases, it may not be possible to control the treatment so that individual areas are treated with individual treatment steps.

To circumvent some of the shortcomings that can occur during stimulation treatments when multiple areas are perforated prior to pumping treatment fluids, an alternative mechanical method of diversion has been developed that involves the use of a coiled tubing system to sequentially stimulate multiple intervals of separate treatment. As with conventional ball seal diversion, all intervals to be treated are perforated prior to pumping the stimulation treatment. Coiled tubing is then driven into the wellbore with a mechanical pressure holding system ("straddle-packer-like") diversion tool attached to the end. This diversion tool, when properly positioned and activated over the perforations, will allow hydraulic isolation to be achieved above and below the diversion tool. After the diversion tool is positioned and activated to isolate the deepest set of perforations, stimulation fluid is pumped down the interior of the coil tube and exits through flow ports located in the diversion tool between the upper and lower sealing elements. After completion of the first processing stage, the sealing elements on the lead tool are deactivated or disconnected, and the coiled tubing is pulled up to position the lead tool over the second deepest set of perforations, and the process continues until all target intervals have been stimulated or the process is interrupted due to operational interference.

This type of coiled tubing stimulation device and method has been used for hydraulic fracturing of multiple zones in wells with depths up to about 8,000 feet (2,400 m). Various technical obstacles, including frictional pressure loss, damage to sealing elements, depth control, travel speed and potential erosion of the coiled tubing, currently limit use in deeper wells.

Extra frictional pressure is generated by pumping stimulation fluids, especially proppant-filled and/or highly viscous fluids at high speed through larger lengths of coiled tubing. Depending on the length and diameter of the coiled tubing, the viscosity of the fluid, and the maximum allowable working pressure of the surface hardware, the pumping rate could be limited to only a few barrels per minute, which, depending on the characteristics of a particular underground formation, may not allow efficient placement of proppant during hydraulic fracturing or effective solution of formation materials during acid stimulation treatment.

Erosion of the coil pipe may also be a problem as proppant-filled fluid is pumped down inside the coil pipe at high speed, including the part of the coil pipe that remains on the surface drum. Erosion concerns are amplified by the proppant-filled fluid hitting the "continuous bend" that attaches to the part of the coiled tubing that is on the surface drum.

Most sealing elements (eg the "cup" sealing technique) currently in use

in stimulation operations with coiled tubing as described above, candidates for seal problems or seal failure in deeper wells are that the seals pass a large number of perforations at the high well temperatures that accompany deep wells. As the seals run in contact with or with minimal clearance to the pipe wall, an uneven surface on the inside of the pipe and/or burrs around the perforations could damage the sealing elements. Seals which in the past are found in pressure holding system-like derivation tools are also constructed from elastomers which

may be unable to withstand the higher temperatures that often result from deeper wells.

Travel speeds for existing cup seal systems are generally on the order of 5 to 10 meters (15 to 30 feet) per minute during downhole travel, to 10 to 20 meters per minute uphole. At, for example, the lower driving speed, approximately 13 hours will be required to reach a depth of 4,000 meters before the stimulation begins. Due to safety considerations during night operations, this low travel speed could result in several days being required to complete a stimulation job. If problems arise during the job, it can be expensive to go out and into the hole, due to the overall operating times resulting from low driving speeds.

Depth control of the coil stirring system and the pressure holding system-like diversion tool also becomes more difficult with increasing depth, so positioning the tool at the correct depth for a successful stimulation operation can be difficult. This problem is compounded by firing the perforations before driving the coiled tubing system into the hole. The perforating operation uses a different depth-measuring device (usually a casing collar finder) than that normally used in a cattle tube system.

In addition, the coiled tubing method described above requires all of the perforations to be placed in the wellbore in a separate perforating operation prior to pumping the stimulation job. The presence of multiple perforation sets open above the diversion tool can lead to operational difficulties. If, for example, the proppant fracture from the area in question should grow in the vertical direction and/or poor quality cement is found behind the pipe, the fracture will be able to cross the perforation sets above the diversion tool so that proppant will be able to "dump" back into the wellbore on top of the diversion tool and prevent further movement of the tool . Furthermore, it will be difficult to perform circulation operations if multiple perforation sets are open above the diversion tool. If, for example, the circulation pressures exceed the rupture pressures that apply to the perforations that are open above the diversion tool, it may eventually become impossible to maintain the circulation with an uncalculated loss of circulation fluid to the formation.

A similar type of stimulation operation could also be performed using jointed pipes and an overhaul rig rather than a coiled pipe system. The use of a diversion tool fitted to interconnected pipes may allow larger diameter pipes to reduce frictional pressure loss and allow increased pumping speed. Moreover, the risk of erosion and pipe integrity can be reduced, compared to coiled pipes, because interconnected pipes with a thicker wall thickness can be used and interconnected pipes will not be subjected to plastic deformation when inserted into the wellbore. However, this method is likely to increase the time consumption and costs associated with the operations, as a result of slower pipe speeds than is possible with coiled pipe.

To circumvent some of the limitations associated with completion operations that require multiple trips of hardware in and out of the wellbore to perforate and stimulate subsurface formations, methods for single trip deployment of a downhole tool string have been proposed to allow fracture stimulation of areas associated with perforation. Specifically, these methods involve operations that can minimize the number of wellbore operations and the time required to complete these operations, thereby reducing the cost of stimulation treatment. These proposals include 1) having sand mud in the wellbore during overbalanced pressure perforating, 2) dumping sand from a bailer at the same time as firing the perforating charges, and 3) including sand in a separate explosively released container. These proposals all allow only minimal fracture penetration around the wellbore, and they cannot be adapted to the needs of multi-stage hydraulic fracturing as described herein.

Accordingly, there is a need for an improved method and apparatus for individually treating the individual multiple intervals in a subterranean formation penetrated by a wellbore, while retaining the economic advantages of multi-stage treatment. There is also a need for a method and device that can economically reduce the risks inherent in the present options for available stimulation treatments for hydrocarbon-bearing formations with multiple or layered reservoirs or with thicknesses exceeding about 60 meters, while ensuring that optimal treatment placement is performed with a mechanical diverter that actively guides the treatment steps to the desired positions.

A tool for well completion is known from US patent 3,417,827. The tool comprises a body with a number of perforating guns, as well as packers above and below the perforating guns. The tool is moved in the well with coiled tubing. The packers are activated with a pressurized fluid through the coil tube. After the well is perforated, the formation interval is isolated with the packers. A treatment fluid can then be sent down through the coil pipe and the tool and into the formation. This solution suffers from the same weaknesses discussed above.

Summary of the Invention

The summary is the invention as explained in the attached patent claims.

The present invention discloses a method and system for perforating and treating multiple intervals of one or more underground formations intersected by a wellbore.

The system consists of laying means (e.g. coiled tubing, interconnecting tubing, electrical cable, wires, downhole tractor, etc.) with a bottomhole assembly (BHA) consisting of at least one perforating assembly and a resettable mechanical sealing mechanism that can be activated independently via one or more signaling means (e.g. electronic signals sent via wire, hydraulic signals sent via pipe, annulus, "umbilical", tension or compression load, radio transmission, fiber optic transmission, accompanying BHA computer systems, etc.).

The procedure includes the steps of mounting the BHA inside the wellbore using mounting means which may be a pipe string, cable or downhole tractor. The perforating device is placed next to the interval to be perforated and is used to perforate the interval. The BHA is placed inside the wellbore using the mounting means, and the sealing mechanism is activated so that a hydraulic seal is created that actively directs fluid pumped down the wellbore to enter the perforated interval. The sealing mechanism is released. The process can then be repeated, without removing the BHA from the wellbore, for at least one other interval in the one or more underground formations.

The laying means may be a string of pipes, including a coiled pipe or standard interconnected pipes, a wire, a slickline or a cable. Instead of pipe or cable, the means of laying could also be a tractor system attached to the BHA. The tractor system can be self-powered, computer-controlled and include signaling systems so that it is not necessary to attach cables or pipes to control and activate the BHA and/or the tractor system. Alternatively, the tractor system could be controlled and powered by cable or pipe connections with umbilical cords so that the tractor system and BHA are controlled and activated by signals sent downhole via umbilical cords. Many different embodiments of the invention can occur, depending on the means for suspending the BHA and the relevant components in the BHA.

In one embodiment of the invention, where the laying means is a pipe string, once an interval has been perforated, the BHA can be moved and the sealing mechanism activated to create a hydraulic seal below the perforated interval. Treatment fluid can then be pumped down the annulus between the pipe string and the wellbore and into the perforated interval. Furthermore, a second treatment fluid, such as nitrogen, can also be pumped down through the pipe string at the same time as the first treatment fluid is pumped down into the annulus between the pipe string and the wellbore.

One of the main advantages of this device and method is that the BHA, including the sealing mechanism and perforating device, does not need to be removed from the wellbore prior to treatment with the treatment fluid and between treatment of multiple formation areas or intervals. Another main advantage of this device and method is that each treatment step is diverted by means of a mechanical diversion means, so that a precise control of the treatment's diversion process is achieved and so that each area can be optimally stimulated. The result is significant cost savings linked to reduced time consumption for perforation and treatment of multiple intervals within a wellbore. In addition, improved production is associated with the use of a mechanical diversion agent that provides precise control of treatment diversion by stimulating multiple formation intervals within a wellbore. In this sense, the method and device according to the invention entail significant economic advantages in relation to existing methods and equipment, because the method and device of the invention allow perforation and stimulation of multiple areas with a single introduction into the wellbore and subsequent removal, of a downhole setup that has a dual function as both a mechanical diverter and a perforating device.

The scope of the invention appears from the subsequent patent claims.

Brief description of theonin<g>sphy<g>ures

A more complete understanding of the present invention and its advantages will be obtained with the help of the following detailed descriptions and the attached drawings:

Figure 1 shows a possible typical wellbore configuration with external equipment that could be used to support the bottomhole setup used in the present invention. Figure 1 also illustrates typical storage wells for downhole setups with surface slips that can be used for storing extra or spare downhole setups. Figure 2A illustrates the first embodiment of downhole setup laid out using coiled tubing in an unperforated wellbore and positioned at the depth to be perforated by the first set of selectively fired perforating charges. Figure 2A further illustrates that the bottom hole setup consists of a perforating device, an inflatable, resettable packing, a resettable axial release device, as well as associated components. Figure 2B shows the bottom hole arrangement, coil tubing and wellbore from Figure 2A after this first set of selectively fired perforating charges has been fired, with the resulting perforation holes through the production casing and cement casing and into the first formation area so that hydraulic communication is established between the wellbore and the first formation area. Figure 2C shows the bottomhole setup, coil tubing and wellbore from Figure 2B after the bottom hole setup has been moved and the first formation zone stimulated with the first stage of the multi-stage hydraulic proppant fracturing treatment where the first stage of the fracture treatment was pumped downhole into the wellbore annulus present between the coiled tubing and the production liner. In Figure 2C, the sealing mechanism is shown in a deactivated position, because it is assumed here, for illustration purposes only, that there are no perforations other than those associated with the first area, and insofar as no isolation is required for treatment of the first the area. Figure 3A shows the bottomhole assembly, coiled tubing and wellbore from Figure 2C after the bottomhole assembly has been moved and the second set of selectively fired perforating charges has been fired, with the resulting perforation holes through the production casing and cement casing and into the second formation zone to establish hydraulic communication between the wellbore and the second formation area. Figure 3B shows the bottomhole setup, coil tubing and wellbore from Figure 3A after the bottomhole setup has been moved a sufficient distance below the deepest perforation in the second set of perforations to allow some upward movement of the BHA to reset the axial slip device, while the location of the circulation port is retained under the bottom perforation in the second set of perforations. Figure 3C shows the downhole arrangement, coil tubing and wellbore of Figure 3B after the resettable mechanical release device has been activated to provide resistance to downward axial movement thereby ensuring that the inflatable resettable packer device is positioned between the perforations in the first region and the other area. Figure 3D shows the downhole assembly, coil tubing, and wellbore from Figure 3C after the inflatable resettable packing has been activated to provide a barrier to flow between the portion of the wellbore just above the inflatable resettable packing and the portion of the wellbore just below it inflatables, simply reset the gasket. Figure 3E shows the bottomhole setup, the coil tubing and the wellbore from Figure 3D after the second formation area has been stimulated with the second stage of the fracture treatment with the multi-stage hydraulic proppant fracturing where the second stage of the fracture treatment was pumped downhole into the wellbore annulus that exists between the coil tubing and the production liner. Figure 3F shows the bottom hole assembly, coil tubing and wellbore from Figure 3E after the inflatable resettable packer has been deactivated thereby restoring pressure communication between the portion of the wellbore just above the inflatable resettable packer and the portion of the wellbore just below the inflatable , simply reset the gasket. The resettable mechanical release device is still activated and continues to prevent coiled tubing and downhole alignment from moving down the wellbore. Figure 4A shows a modified bottom hole arrangement similar to the bottom hole arrangement described in Figures 2A through 2C and Figures 3A through 3F, but with the addition of a mechanical plug that can be set with a charge alignment system for selective firing, located below the line of perforating guns. Figure 4A also shows the coiled tubing and wellbore from Figure 3F after a third perforation and fracture stimulation operation has been performed. In Figure 4A, note that only the second and third fracture and perforation sets are shown.

In Figure 4A, the modified hole bottom arrangement is shown hanging in the coil pipe so that the bridge plug is located above the last perforated interval and below the next interval to be perforated. Figure 4B shows the downhole array, coiled tubing, and wellbore of Figure 4A after the mechanical plug has been selectively fired in the well and after the downhole array has been moved and the first set of selectively fired perforating charges fired, with resulting perforation holes through the production casing and cement casing and into the fourth formation zone so that hydraulic communication has been established between the wellbore and the fourth formation area. Figure 5 shows a second embodiment of the invention. In this embodiment, the suspension means is a string of tubing, and once an interval has been perforated, the BHA can be moved and the sealing mechanism activated to create a hydraulic seal above the perforated interval. Treatment fluid can then be pumped down through the pipe string and into the perforated interval. Figure 6 shows a third embodiment of the invention. The suspension means is a pipe string, and the BHA can be moved and the sealing mechanism activated to create a hydraulic seal above and below the perforated interval (the sealing means consisting of two sealing means sufficiently spaced to span the perforated interval). In this third embodiment, treatment fluid can be pumped down through the pipe string itself, through a flow port placed inside between the two sealing elements in the sealing mechanism and into the perforated interval. Figure 7 shows a fourth embodiment of the invention. The BHA is suspended in the wellbore using a wireline (or slickline or cable). The BHA can be moved and the sealing mechanism activated to create a hydraulic seal below the perforated interval to be treated and treatment fluid can then be pumped down through the annulus between the wireline, slickline or cable and the wellbore. Figures 8A and 8B show a fifth embodiment of the invention and utilizes an umbilical cord tube placed inside the tube used as a deployment means for activation of the resettable sealing mechanism. Figure 9 shows a sixth embodiment of the invention which utilizes a tractor system attached to the BHA so that the BHA can be moved and the sealing mechanism activated to create a hydraulic seal below the perforated interval. Treatment fluid can then be pumped down through the wellbore and into the perforated interval. Figure 10 shows a seventh embodiment of the invention which uses an abrasive or erosive fluid jet cutting technique as a perforating agent. The BHA is suspended in the wellbore by jointed tubing and consists of a mechanical compaction kit, reset bar packing, an abrasive or erosive fluid jet perforating device, a mechanical casing collar locator, and accessories. In this embodiment, the perforations are formed by pumping an abrasive fluid down through the joined pipes and out of a jet tool located on the BHA, so that a jet of abrasive or erosive fluid is formed under high pressure and at high velocity

which serves to penetrate the production casing and the surrounding cement casing to establish hydraulic communication with the desired formation interval. After the resettable gasket is placed below the area to be stimulated, the treatment fluid can now be pumped down through the annulus between the tube string

and the production casing string.

Detailed description of the teqninqsfiqurs

The present invention will be described in connection with its preferred embodiments. However, the following description is only intended as illustrative in so far as it relates to a particular embodiment or a particular method of use for the invention, and should not be understood as limiting when it comes to the scope of the invention. In contrast, the description is intended to cover all alternatives, modifications and equivalents that lie within the spirit and scope of the invention as defined by the appended patent claims.

The present invention relates to a new method, a new system and a new device for perforating and stimulating multiple formation intervals, which allows each individual area to be treated in a separate treatment step, while the problems associated with existing arrangements with coiled pipe or linked pipe are eliminated or minimized, and it therefore offers significant economic and technical advantages over existing methods.

In particular, the invention includes suspending a downhole assembly in the wellbore to individually and sequentially perforate and treat each of the multiple areas while pumping the multiple stages of the stimulation treatment and to place a resettable mechanical mechanism to effect a controlled diversion of each treatment step. For this description, the term "wellbore" shall include sealed underground components of the well as well as all sealed equipment above ground level, such as wellhead, coil parts, blowout preventer and lubricator.

The new device consists of laying means (e.g., coiled tubing, interconnecting tubing, electrical cable, wireline, tractor system, etc.) with a downhole arrangement consisting of at least one perforating device and a resettable mechanical sealing mechanism that can be activated individually from the surface by means of one or more signaling means (eg electronic signals transmitted through wires, hydraulic signals transmitted via pipe, annulus, umbilical, tension or compression loads, radio transmission, fiber optic transmission, etc.) and which are designed for the intended wellbore environment and loading conditions .

In its most general sense, the term "downhole assembly" is used to denote a string of components consisting of at least one perforating device and a reset bar sealing mechanism. Additional components may also be mounted on the downhole assembly to enable other anticipated auxiliary or additional operations and measurements that may be desirable during the stimulation treatment, such as but not limited to the following: fishing hooks, cutting units, flushing tools, circulation port units, flow port units, pressure equalization port units , temperature gauges, pressure gauges, wire connection units, reset only mechanical slips, casing collar finders, centering units and/or connector units.

In its most general sense, the resettable mechanical seal mechanism performs its function as a "hydraulic seal", where the term hydraulic seal is defined as sufficient flow restriction or blockage to force fluid to flow to a location other than where it would otherwise be guided if the flow obstruction was not present. In particular, this broad definition of "hydraulic seal" is intended to include a "perfect hydraulic seal" such that all flow is directed to a location other than where it would otherwise be directed if the flow obstruction were not present, and an "imperfect hydraulic seal" so that a significant proportion of current is directed to a different location than where it would otherwise be directed if the flow obstruction were not present. Although the use of a reset bar mechanical seal that provides a perfect hydraulic seal will generally be preferred, it is also possible to use a sealing mechanism that provides an imperfect hydraulic seal and achieve an economical treatment even if the stimulation treatment is not perfectly diverted.

In the first preferred embodiment of the invention, coiled tubing is used as a laying aid, and the new method involves sequential perforation and then stimulation of the individual areas from bottom to top of the completion interval, with the stimulation fluid pumped down the annular space between the production casing and the coiled tubing. As discussed in more detail below, this embodiment of the new device and method provides significant improvements over existing coiled tubing and interconnected tubing stimulation techniques, and is applicable across a wide spectrum of wellbore architectures and stimulation treatment designs.

Concretely, the first preferred embodiment of the new device and method involves the layout system, the signaling means, the hole bottom arrangement and the operations which are described in detail below, where the various components, their orientation and the operation steps are chosen for description purposes only so that they correspond to components and operations which will be able to be used in conjunction with hydraulic proppant fracture stimulation of multiple intervals.

In the first preferred embodiment for a hydraulic proppant fracture stimulation treatment, the equipment would consist of the BHA placed in the wellbore by means of coiled tubing. The BHA would include a perforating device, reset bar mechanical sealing mechanism, casing collar locator, circulation ports, as well as other auxiliary components (as described in more detail below).

Furthermore, in this first preferred embodiment, the perforating device would consist of a perforating gun system with selective firing (using shaped perforating charges), and the resettable mechanical sealing mechanism would consist of an inflatable, resettable packing, a mechanical resettable release device to prevent a downward axial movement of the bottom hole assembly when added, as well as pressure relief ports located above and below the inflatable, simply reset the packing.

Additionally, in this first preferred embodiment, a wireline would be placed inside the coil tube and used to provide a signaling means, as a means of activating perforating charges for selective firing, as well as transmitting electrical signals associated with the casing collar seeker used for BHA- depth measurement.

Referring to Figure 1, an example of the type of surface equipment used in the first preferred embodiment would be a rig that used a very long lubricator 2 with the coiled pipe injector head 4 hanging high in the air after the crane arm 5 attached to a crane base 8. The wellbore would typically include a length of surface casing 78 entirely or within a cement casing 80 and a production casing 82 entirely or within a cement casing 84, the inner wall of the wellbore consisting of the production casing 82. The depth of the wellbore would preferably reach a certain distance below the lowest interval to be stimulated, to give space for the length of the downhole setup that would be attached to the end of the coiled tubing 106. The coiled tubing 106 is placed in the wellbore using the coiled tubing injector head 4 and the lubricator 2. Also installed to the lubricator 2 are blowout preventers 10 which could be remotely activated in case of operational problems. The faucet base 8, faucet arm 6, coiled tubing injector head 4, lubricator 2, blowout preventer 10 (and their associated control and/or actuation components) are standard equipment components that are well known in the art and can be used in methods and procedures for safely installing a coiled tubing downhole setup in a well under pressure, and for subsequent removal of the coiled tubing bottomhole assembly from a well under pressure.

With existing equipment that is readily available, the height of the top of the coil pipe injection head 4 could be about 30 meters from ground level with the gooseneck 12 (around which the coil is bent to go vertically down the well) approaching about 35 meters above ground. The crane arm 6 and the crane base 8 would carry the load of the injector head 4, the coil pipe 106 and any load requirements that can be expected for potential fishing operations (hitting and hauling).

In general, the lubricator 2 must have a length that is greater than the length of the downhole assembly, so that the downhole assembly can safely be placed in a wellbore under pressure. Depending on overall length requirements and what is calculated to be reasonable based on engineering design calculations for a given application, in order to provide stability for the coiled pipe injector head 4 and the lubricator 2, bar fins 14 will be attached at various locations on the coiled pipe injector head 4 and the lubricator 2. The bars 14 had to be anchored securely in the ground to prevent too much movement of the coil pipe injector head 4 and the lubricator 2, so that the ability of the surface components to hold the pressure is not jeopardized. Depending on total length requirements, alternative support systems could also be used for the injection head/lubricator system (coil tube rigs or specially adapted completion/overhaul rigs).

Figure 1 also shows several different wellhead coil parts that can be used for current control and hydraulic isolation during rigging operations, stimulation operations and derigging operations. The crown valve 16 provides the opportunity to isolate the part of the wellbore that is above the crown valve 16 from the part of the wellbore that is below the crown valve 16. The upper main fracture valve 18 and the lower main fracture valve 20 also provide valve systems for isolating wellbore pressure above and below their respective locations. Depending on what is the practice at the site in question and the composition of the stimulation job, it is possible that not all of these isolation-type valves will be used.

The injection valves 22 for side withdrawals shown in figure 1 provide the opportunity for injection of stimulation fluid into the wellbore. The piping from the surface pumps and tanks used for injection of the stimulation fluids would be attached with suitable fittings to the side outlet injection valves 22. The stimulation fluids can then be pumped into the wellbore via this flow path. With the installation of other suitable flow control equipment, it is also possible to produce fluid from the wellbore using the injection valves 22 for side withdrawal. Note that the inside of the coil pipe 106 can also be used for flow of fluid that is injected into the wellbore.

The storage well holes 24 for storing bottom hole setups, shown in Figure 1 constitute a place for storing spare bottom hole setups 27 or for storing bottom hole setups that have been used in previous operations. The storage well holes 24 for storing downhole assemblies can be drilled to a shallow depth, so that a downhole assembly that possibly contains perforating charges is placed below ground level until the downhole assembly is ready to be attached to the coil pipe 106. The storage well holes 24 for storing downhole assemblies can be drilled so that they provide space for either cemented or uncemented casing string, or they may remain completely unlined. The actual number of storage well holes 24 for storing bottom hole setups required for a given operation will depend on the overall needs of the job. The storage well holes 24 for storing downhole setups can be placed within reach of the crane arm 6 to enable rapid exchange of downhole setups during the stimulation operation, without the need to move the crane base 8 to another location.

Referring to Figure 2A, the coil tube 106 is equipped with a coil tube coupling 110 which can be connected to a cutter release/fishing hook combination assembly 112 that contains both a cutter release mechanism and a fishing hook and allows the passage of pressurized fluids and the wireline 102. The cutter release/fishing hook combination assembly 112 may be connected to an assembly containing a circulation port assembly 114 which may provide a flow path for flushing debris from above the inflatable, reset packing 120, or provide a flow path for injecting fluid downhole by means of coil tubing 106. Circulation port assembly 114 contains the valve arrangement which actuates the circulation port 114 and the upper equalization port 116. The upper equalization port 116 can be connected to a lower equalization port 122 via piping through the inflatable, reset-only gasket 120. Both the circulation port 114 and the upper equalization port 116 are preferably open in the "driving position ng", so that pressure equalization can take place between the internal coil tube pressure and the pressure in the annulus between coil tube and liner. In this document, "running position" means a condition where all components in the downhole arrangement have a configuration that allows unimpeded axial movement up and down the wellbore. The lower equalization port 122 located below the inflatable, reset bar packing 120 is always open, and flow through the equalization ports is controlled by the upper equalization port 116. The circulation ports and the equalization ports can be closed simultaneously by placing a slightly compressive load on the BHA. In order to prevent potential backflow into the coil pipe when the circulation port 114 is open in the driving position, a surface pressure can be applied to the coil pipe 106 so that the pressure inside the circulation port 114 exceeds the wellbore pressure immediately outside the circulation port 114. The inflatable, resettable packing 120 is hydraulically isolated from the internal pressure in the coil tube in driving position. The inflatable, resettable packing 120 can achieve pressure communication via internal valve guidance with the internal pressure in the coil tube by placing a slight compressive load on the BHA. Mechanically actuated, reset-only axial position locking devices or "slippers" 124 may be placed below the inflatable, reset-only packing 120 to counteract movement down the wellbore. The mechanical slips 124 can be actuated by a "continuous J" mechanism by cycling the axial load between compression and tension. A wire connector assembly 126 is located above the casing collar seeker 128 and the perforating gun system with selective firing. A gun assembly 130 connects the casing collar seeker 128 to the selective firing head 152. The perforating gun system can be designed based on knowledge of the number, location and thickness of the hydrocarbon-bearing sand layers in the target areas. The cannon system will consist of a cannon array (e.g. 134) for each area to be treated. The first (lowest) gun array will consist of a selective firing head 132 and a gun casing 134 which will be loaded with perforating charges 136 and a detonation system for selective firing.

Concretely, a preferred embodiment of the new method will include the following steps, where the stimulation job has been chosen for the sake of description to be a multi-stage, hydraulic proppant fracture stimulation. 1. The well is drilled and casing cemented over the interval to be completed, and if desired, one or more well holes for storage of bottom hole setups are drilled and completed. 2. The target areas within the completion interval are identified (typically using a combination of open-hole and forethu I logs). 3. The bottom hole arrays (BHA) as well as the perforating gun arrays to be laid out on each BHA expected to be used during the stimulation operation are constructed based on the number, location and thickness of the hydrocarbon-bearing sand layers within the target areas. 4. A coiled drum is prepared with a BHA of preferred design as described above. The spooled drum is also prepared to contain wireline used to provide signaling means for activation of the perforating guns. Preferably, the desired amount of appropriately configured BHAs as a reserve or for any additional need will also be prepared and stored in the storage wellbores for the bottomhole setup(s). The coil pipe can be pre-filled with fluid either before or after connection with the downhole setup. 5. As shown in Figure 1, the coil pipe 106 with BHA is driven into the well via a lubricator 2, and the injection head 4 on the coil pipe hangs in the crane arm 6. 6. The coil pipe/BHA is driven into the well while the depth of the BHA is correlated with the casing collar finder 128 (figure 2A). 7. The coil pipe/BHA is run below the bottom target area to ensure that there is sufficient wellbore depth below the bottom perforations to

to place the BHA below the first set of perforations during fracturing operations. As shown in Figure 2A, the inflatable, reset only gasket 120 and reset only, mechanically activated release 124 are in the driving position.

8. As shown in Figure 2B, the coiler/BHA is then raised to a position in the wellbore such that the first (lowest) set of perforating charges 136 contained in the first gun array 134 of the selective firing perforating gun system is positioned just outside the lowest target area , where accurate depth control can be obtained using readings from the casing collar finder 128 and the coil tube odometer system (not shown). The activity of moving the BHA up to the location of the first perforated area will cycle the mechanical "continuous J" mechanism (not shown) into the pre-lock position so that subsequent downward movement will force the resettable mechanical slips 124 into the locked position and thereby preventing further downward movement. Note that the additional cycling of the coil tube's axial load from compression to tension and back again will bring the reset bar slips back to the running position. In this way, the mechanical "continuous J" mechanism, together with the use of compression and tension loads transmitted via the suspension means (coil tube), is used to produce downhole actuation and

deactivation of the mechanical releases.

9. The first set of perforating charges 136 is selectively fired by remote activation via wireline 102 in communication with the first selective firing head 132 to penetrate the casing 82 and cement casing 84 and establish hydraulic communication with the formation 86 through the resulting perforations 230-231. It is specified that any given set of perforations may, if desired, be a set of one, although in general multiple perforations will provide better treatment results. It is also specified that an interval is not necessarily limited to a single sand reservoir. Multiple sand intervals could be perforated and treated as a single step using other diversion means suitable for simultaneous laying with this invention within a given treatment step. 10. As shown in Figure 2C, the coil tube can be moved to position the circulation port 114 just below the deepest perforation 231 in this target area, to minimize the potential for proppant filling above the inflatable, reset bar packing 120 and minimize high velocity proppant flow past the BHA. 11. The first step in the fracture stimulation treatment is initiated by circulating a small volume of fluid down through the coil tube 106 through the circulation port 114 (via a displacement pump). This is followed by initiation of pumping stimulation fluid down through the annulus between the coiled tubing 106 and the production liner 82 in fracture stimulation amounts. The small volume of fluid flowing down the coiled tubing 106 serves to maintain an overpressure within the coiled tubing 106 to resist backflow of proppant-filled fluid into the coiled tubing 106 and to resist collapse loading of the coiled tubing during fracturing operations. Note that as an alternative means of resisting coil tube collapse, an internal valve mechanism may be used to maintain circulation port 114 in the closed position and positive pressure thereupon applied to coil tube 106 by means of a surface pump. As an illustrative example of the construction of fracturing for the stimulation of a 60-acre (15-acre) sand lens containing hydrocarbon gas, the first fracturing stage will consist of "sub-stages" as follows: (a) 20,000 liters of 2% KCI water, ( b) 8,000 liters of crosslinked gel containing 100 g/cm^ (l pound-per-US-gallon) proppant, (c) 12,000 liters of crosslinked gel containing 200 g/cm^ proppant, (d) 20,000 liters of crosslinked gel containing 300 g/cm^ proppant and (e) 12,000 liters of cross-linked gel containing 400 g/cm^ proppant, so that approx. 16,000 kilograms (35,000 pounds) of proppant is placed in the first area. 12. As shown in Figure 2C, all sub-steps in the first fracturing operation are completed with the formation of the first proppant fracture 232. 13. At the end of the first step of the stimulation treatment, if proppant in the wellbore should prevent the coil pipe/BHA from immediate movement, fluid can be circulated through the circulation port 114 to flush and purge proppant to free the coil tube/BHA and allow movement. 14. As shown in Figure 3A, the coil pipe/BHA is then pulled uphole to slightly above the second deepest target area so that the second set of perforating charges 146 contained on the selective firing perforating gun system 144 is located slightly above the second deepest target area, where again accurate depth control is achieved using readings from the casing collar finder 128 and the coil tube odometer system. The activity of moving the BHA up (to slightly above the second interval to be perforated) will cycle the reset only mechanical "continuous J" mechanism (not shown) into the pre-lock position. Further compression/tension load cycling is performed to return the mechanical "continuous J" mechanism to the drive position. The coiler tube/BHA is then moved downward to place the perforating charges 146 contained on the perforating gun system with selective firing 144 just outside the second deepest target area, where again accurate depth control is achieved using readings from the casing collar finder 128 and the coiler tube odometer system. 15. The second set of perforating charges 146 is selectively fired by remote activation via the second selective firing head 142 to penetrate the liner 82 and cement casing 86 at resulting perforations 240-241. 16. As shown in Figure 3B, the coiled tubing can be moved down the wellbore to place the BHA several feet below the deepest perforation 241 in the second target area. Subsequent upward movement of the BHA in the prayer hole to position the circulation port 114 just below the deepest perforation 241 in this second target area will cycle the resettable mechanical slips 124 to the pre-lock position such that subsequent downward movement will force the resettable mechanical slips 124 into in a locked position and thereby prevent further downward movement. 17. As shown in Figure 3C, downward movement will cause the resettable mechanical slips 124 to grip the casing wall 82 thereby preventing further downward movement of the BHA. A compression load is then applied to the coil tube, and this load closes the circulation port 114 and the upper equalization port 116 and creates pressure communication between the inflatable, reset bar gasket 120 and the internal coil tube pressure. The compression load will also lock the circulation port 114 in a position just below the deepest perforation 241 in this second target area (to minimize the potential for proppant filling above the inflatable, reset bar packing 120 and minimize high-velocity proppant flow past the BHA), and with the inflatable, reset ba re the gasket 120 positioned between the first and second perforated intervals. 18. A further compression load is placed on the coil pipe/BHA to test the resettable mechanical slips 124 and ensure that further downward force does not cause further movement of the BHA down the wellbore. 19. As shown in Figure 3D, the inflatable resettable packing 120 is activated by pressurizing the coil tube 106 to effect a hydraulic seal above and below the inflatable resettable packing 120. A compression load is maintained on the BHA to maintaining pressure communication between the internal coil tube pressure and the inflatable resettable packing 120, to keep the circulation port 114 and upper equalization port closed, and to keep the resettable mechanical slips 124 in the locked and activated position. The inflatable, resettable packing 120 is maintained in an activated state by maintaining the pressure in the coil tube 106 by means of a surface pumping system. (Note that as an alternative, the inflatable, resettable packing could be maintained in an actuated state by depressurizing the element by means of an internal valve that is remotely controlled from the surface by signaling means compatible with other BHA components and others present signaling agents.) 20. The second stage of the fracture stimulation treatment is initiated by fluid being pumped down the annulus between the coiled tubing 106 and the production liner 82 at the fracture stimulation rate, while maintaining a compression load on the BHA to keep the circulation port 114 and upper equalization port 116 closed, and coiled tubing pressure is maintained of a level sufficient to prevent collapse of the coiled tubing string and keep the inflatable, reset bar packing 120 inflated and serve as a hydraulic seal between the annular pressure above the packing before, during and after the fracturing operation and the sealed wellbore pressure below the inflatable, reset bar pa the king. 21. All substages of the fracturing operation are pumped, leaving minimal underflushing of the proppant-filled last substage in the wellbore so that the fracturing process is not over-displaced. If, during this processing step, it should occur that the sealing of the inflatable, resettable gasket 120 is questionable, the processing step can be interrupted temporarily to test the sealing of the gasket above the highest (shallowest) existing perforations (e.g. perforation 240 in Figure 3D) after inserting the inflatable, simply reset the gasket 120 into blank tube. If the sealing test is to be carried out, it could be desirable to carry out a circulation/flushing operation to ensure that any proppant that may be in the wellbore is circulated out of the wellbore prior to carrying out the test. The circulation/flushing operation could be performed by opening circulation port 114 and then pumping circulation fluid down through coiled tubing 106 to circulate proppant out of the wellbore. 22. As shown in Figure 3E, all sub-steps in the second fracturing operation are completed with the formation of a second proppant fracture 242. 23. After completion of the second-stage fracturing operation and completion of injection of stimulation fluid down through the annulus formed between the coiled tubing 106 and the production liner 82, it becomes placed on a small tensile load on the coil tube 106 while the internal coil tube pressure is kept the same. The small applied tensile load will first isolate the pressure in the inflatable reset only gasket from the coil tube pressure thereby locking the pressure in the inflatable reset only gasket 120 thereby maintaining a positive pressure seal and applying significant resistance to axial movement of the inflatable reset only bare the gasket 120. At the same moment, the applied tensile load can then open the circulation port 114 and the equalization port 116 and thereby allow the pressure in the coil tube to leak out into the annulus formed by the coil tube 106 and the production liner 82, at the same time that the pressure above and below the inflatable, reset bar the gasket 120 is allowed to equalize. The pump in the surface system which provides internal coiled pipe pressure can be stopped after the downhole pressures have been equalised. 24. After the pressures inside the coil tube, in the annulus formed by the coil tube 106 and production liner 82 above the inflatable, reset only gasket 120, as well as in the annulus formed by the BHA and production liner 82 below the inflatable, reset only gasket 120 have equalized , a compressive load applied to the coil tube will close the circulation port 114 and upper equalizer port 116 before releasing the pressure trapped in the inflatable reset only gasket 120 and into the coil tube 106. This release of internal pressure from the inflatable reset only gasket 120 will allow the inflatable reset-only packing 120 to retract from the wall of the production casing, as shown in Figure 3F, in the absence of an external differential pressure across the inflatable reset-only packing 120, which could otherwise damage the coil tubing 106 or the BHA . 25. Once the inflatable, resettable packing 120 is released, as shown in Figure 3F, tension applied to the coil tubing/BHA will deactivate the resettable mechanical slips 124, thereby freeing the BHA to move and travel up the wellbore. 26. If at the end of the second stage of stimulation treatment proppant is present in the wellbore preventing the coiled tubing/BHA from immediate movement, fluid can be circulated through circulation port 114 to flush and clean out the proppant to free the coiled tubing/BHA and allow upward movement of the BHA after releasing the inflatable, simply reset the gasket. 27. The process as described above is repeated until all planned areas are individually stimulated (Figures 3A through 3F show a BHA designed for a three-area stimulation). 28. On completion of the stimulation process, the components of the BHA are returned to the running position and the coiled tubing/BHA assembly is removed from the wellbore. 29. If all intended target areas have been stimulated, the well can be put into production immediately. 30. If it is desired to stimulate several areas, a drum can be prepared with a slightly modified BHA as shown in Figure 4A. In this arrangement, the only change to the BHA according to the preferred embodiment described above may be the addition of a selective-firing mechanical plug 164 or a selective-firing bridge plug 164 located below the lowest selective-firing gun arrangement as shown in Figure 4A. Generally, the selectively fired mechanical plug 164 can be either a bridge plug or a fracture baffle. A fracture guide plate will normally be preferred if it is desired to simultaneously produce areas separated by the plug immediately after the simulation job. 31. The modified BHA, shown in Figure 4A, consists of a perforating gun system with selective firing (Figure 4A shows a gun system comprising perforating guns 174, 184 and 194 with associated charges 176, 186 and 196 and selective firing heads 172, 182 and 192), casing collar seeker 128, flow ports 114, 116 and 122, an inflatable, resettable packer 120, a resettable mechanical release device 124 and selective firing bridge plug 164 set using selective firing head 162. The modified BHA is driven into the well via a lubricator and the coiled injection head suspended in crane or rig over the borehole. 32. The coil pipe/BHA is driven into the well while the depth is adjusted with the casing collar finder. 33. As shown in Figure 4A, coil tubing/modified BHA is driven into the wellbore to place the mechanical selective firing plug 164 above the last stimulated area 252. 34. As shown in Figure 4B, the selective firing head 162 is fired to place the mechanical selective firing plug 164 above it last stimulated area 252. 35. After the bridge plug selective firing head 162 is activated to set the bridge selective firing plug 164, the coiled tubing/modified BHA is raised to a position within the borehole such that the first (lowest) set of perforating charges 176 located on the perforating the selective firing gun system is located just outside the second lowest target area to be perforated, where accurate depth control can be achieved based on the reading of the casing collar finder 128 and the coil tube odometer system among the surface equipment. The activity of moving the BHA up to the location of the first perforated interval will cycle the resettable mechanical slips 124 to the locked position and will require the axial load on the coil tube to be cycled from compression to tension and back again for the resettable mechanical the slips must return to the driving position. 36. As shown in Figure 4B, the first set of perforating charges 176 on the modified BHA are selectively fired by remote activation via the second selective firing head 172 to penetrate the casing 82 and cement casing 84 with perforations 270, 271 and establish hydraulic communication with the formation 86 via the resulting perforations 270-271. 37. If there is insufficient space between the last preceding perforations 250, 251 and the position for the next set of perforations 270, 271 to be stimulated so that the BHA can be correctly positioned for perforation, isolation and stimulation of the next set of perforations 270, selective de- firing bridge plug 164 is placed below the last previous stimulated perforations 250, 251, and the inflatable, resettable gasket can be used during the first stimulation operation to isolate the uppermost perforations 270, 271 from the previous stimulated perforations 250, 251. 38. The entire process as described above is then repeated as needed until all planned areas are individually stimulated (Figure 4A and Figure 4B represent a BHA calculated for an additional three-area stimulation operation).

It will be clear to those skilled in the art that the preferred method of suspension in the case of proppant-filled fluids would be conventional interconnected pipes or coiled pipes, preferably with one or more circulation ports so that proppant deposits in the wellbore can be easily circulated out of the wellbore. Treatments such as acid fracturing or matrix acid treatment do not necessarily require such an option, and could easily be carried out with a laying system based on cable, such as slickline or wireline, or based on a downhole tractor system.

It will be clear to those skilled in the art that, depending on the objectives of a particular job, various pumping systems could be used which could include the following arrangements: (a) pumping down through the annulus formed between the cable or pipe (if the method of laying uses cable or pipe) and the casing wall, (b) pumping down through the coiled pipe or the connected pipe internally if the suspension method involves the use of coiled pipes or connected pipes and extra friction and plug erosion are not significant in the relevant well depths, or (c) simultaneous pumping down through the annulus that has been formed between the cable or pipe (if the laying method uses cable or pipe) and the lining wall and the pipe inside, if extra friction and plug erosion are not problematic in the respective well depths. Figure 5 shows a second embodiment of the invention where coiled pipes are used as laying means and extra friction is not important and where proppant is either not pumped during the job or the use of proppant is not problematic. Figure 5 shows that coil pipe 106 is used for hanging BHA and BHA components. In this embodiment, the individual areas are processed in order from shallower wellbore locations to deeper wellbore locations. In this embodiment, the circulation port 114, as shown in Figure 5, is now placed below the inflatable, resettable packing 120, so that the treatment fluid can be pumped down through the inside of the coil tube 106, pass out the circulation port 114 and be actively forced to go into must In the perforations. As an illustration of the operations, Figure 5 shows that the inflatable resettable packing 120 has been activated and placed below the perforations 241 associated with a former area of hydraulic fracture 242. The inflatable resettable packing 120 provides hydraulic isolation so that when treatment fluid is next pumped down coil tube 106, the treatment fluid is forced to enter previously placed perforations 230 and 231 and form new hydraulic fractures 232. The operations are continued and repeated according to the desired number of formation areas and intervals. Figure 7 shows a fourth embodiment of the invention, where a wire line 102 is used as a laying means for hanging BHA and BHA components. In this embodiment, the individual areas are treated in order from deeper wellbore locations to shallower wellbore locations. In this embodiment, as shown in Figure 7, treatment fluid can be pumped down through the annulus between the wireline 102 and the production casing wall 82 and be actively forced into the perforations. In this embodiment, the inflatable resettable packing 120 will also contain an internal electric pump system 117, driven by electrical energy that is sent downhole via the line to inflate or deflate the inflatable resettable packing 120 using borehole fluid. Figure 7 shows that the inflatable, reset bar gasket 120 has been activated and placed below the perforations 241 that connect to the next area to be fractured. The inflatable, resettable packing 120 provides hydraulic isolation so that when treatment fluid is subsequently pumped down the annulus between wireline 102 and production liner 82, the treatment fluid is forced into the perforations 240 and 241 and forms new hydraulic fractures 242. The operations are then continued and repeated as needed for the desired number of formation areas and intervals.

A fifth embodiment of the invention involves the laying of extra pipe strings or cables, hereinafter called "umbilical strings", inside and outside for coiled pipes (or joined pipes). As shown in Figure 8A and Figure 8B, a pipe umbilical string 104 is shown laid out inside the coil pipe 106. In this embodiment, the pipe umbilical string 104 is connected to the resettable sealing mechanism 120 and in this embodiment, the resettable sealing mechanism 120 is now activated by of hydraulic pressure transmitted via the umbilical 104. In general, multiple umbilicals can be laid out either inside the coil pipe and/or in the annulus between the coil pipe and the production casing. In general, the umbilicals can be used to perform several different operations, including but not limited to providing (a) hydraulic communication for actuation of individual BHA components, including but not limited to the sealing mechanism and/or perforating device, (b) flow paths for downhole injection or circulation of further fluids, as well as (c) for data collection from measuring devices downhole. Note that as shown in Figure 8A, the BHA also includes centering devices 201, 203 and 205 which are used to keep the BHA centered in the borehole when the BHA components are in the travel position.

The use of umbilical cord(s) can enable hydraulic engagement and disengagement of the resettable mechanical sealing mechanism regardless of the hydraulic pressure conditions in the coil tube. This will then allow the method to be extended to use reset only mechanical sealing mechanisms that require independent hydraulic actuation. Perforating devices that require hydraulic pressure for selective firing can be activated via an umbilical cord. This can then allow the line, if it is laid out together with coil pipe and BHA, to be used for the transmission of one or more additional channels for electrical signals, which may be desirable for collecting data from measuring instruments placed on the bottom hole setup, or activating other BHA components, such as an electric downhole motor drive that could provide rotation/torque to BHA components. Alternatively, an umbilical could be used to drive a hydraulic motor to actuate various downhole components (eg a hydraulic motor to operate the reset bar seal mechanism).

The use of umbilical cord(s) can provide the ability to inject or circulate an arbitrary fluid downhole to multiple positions at will, with precise control. To help avoid proppant deposition on the seal mechanism during a hydraulic proppant fracturing treatment, for example, umbilical(s) could be laid out and used to provide independent continuous or intermittent flushing and circulation to keep proppant from accumulating on the seal mechanism. One umbilical cord, for example, could go to just above the reset mechanical sealing mechanism. Then, if desired, fluid (eg, nitrogen) could be circulated downhole to one or both locations to flush away proppant from the region surrounding the sealing mechanism and thereby reduce the possibility of BHA sticking due to proppant accumulation. In the case of fluid circulation, it is specified that the size of the umbilical cord and the nature of fluid should be chosen to ensure that the desired speed is achieved and is not unduly impeded by frictional pressure in the umbilical cord.

Besides umbilicals consisting of tubing strings that provide hydraulic communication downhole as a signaling means for activation of BHA components (or possibly as a signal transmission means for surface registration of downhole measuring instruments).

Figure 9 shows a sixth embodiment of the invention where a tractor system comprising upper tractor drive unit 131 and lower tractor drive unit 133 is attached to the BHA and is used to deploy and position the BHA within the wellbore. In this embodiment, the individual areas are treated in order from deeper wellbore locations to shallower wellbore locations. In this embodiment, the BHA also contains an internal electrical pumping system 117, driven by electrical energy sent downhole via line 102, to inflate or deflate the inflatable, resettable packing 120 using wellbore fluid. In this embodiment, treatment fluid is pumped down through the annulus between the line 102 and the production casing wall 82, and is actively forced into the target perforations. Figure 9 shows that the inflatable, reset only gasket 120 has been activated and placed below the perforations 241 belonging to the next area to be fractured. The inflatable, resettable packing 120 provides hydraulic isolation so that when treatment fluid is subsequently pumped down through the annulus between the line 102 and the production casing wall 82, the treatment fluid is forced to enter the perforations 240 and 241 and form new hydraulic fractures 242. The operations are then continued and repeated as needed for the desired number of formation areas and intervals.

As alternatives to this sixth embodiment, the tractor system could be self-powered, controlled by computer systems on board, and carry signaling systems on board so that it would not be necessary to add cable or piping for positioning, control and/or activation of the tractor system. Furthermore, the various BHA components could also be controlled by computer systems on board, and lead signaling systems on board so that it would not be necessary to add cable or piping for positioning, control and/or activation of the components. The tractor system and/or the BHA components could, for example, carry on board power sources (e.g. batteries), data systems and data transmission systems so that the tractor and BHA components could either be remotely controlled from the surface by remote signaling means, or alternatively the various components on board could be programmed on advance on the surface to perform the desired sequence of operations once deployed in the wellbore.

In a seventh embodiment of the present invention, abrasive (or erosive) fluid jets are used as a means of perforating the wellbore. Abrasive (or erosive) fluid jets are in common use in the oil industry to cut and perforate downhole tubing strings and other wellbore and wellhead components. The use of coiled tubing or interconnected tubing as a suspension means for the BHA provides a flow path for the use of abrasive fluid jet technology. To do this, the BHA is configured with a jetting tool. This jet tool allows abrasive (or erosive) fluid systems or mud to be pumped downhole through the pipe and through jet nozzles. The abrasive (or erosive) fluid cuts through the production casing wall and cement casing and penetrates the formation to create flow paths to it. Using this tool, an arbitrary distribution of holes and slots can be placed throughout the completion interval during the stimulation job. In general, abrasive (or erosive) fluid cutting and perforating can be readily performed under a wide range of pumping conditions, using a wide range of fluid systems (water, gelatins, oil and combined fluid/gas fluid systems), and with a wide variety of abrasive solids (sand, ceramic materials, etc.), if the use of abrasive solids is required for the relevant wellbore perforation.

The pressure jet tool replaces the conventional perforating gun system with selective firing described in the previous six embodiments, and since this pressure jet tool can have a length of about 30 cm to 120 cm, the height requirement for the surface lubricator system is greatly reduced (by perhaps up to 20 meters or more ), compared to the height required using conventional selective-firing gun emplacements as a perforating device. Reducing the height requirement for the surface lubricator system provides several benefits, including cost reductions and reduced operating time.

Figure 10 shows in detail a seventh embodiment of the invention, where a pressure jet tool 310 is used as a perforating device and interconnected pipes 302 are used to suspend the BHA in the wellbore. In this embodiment, a resettable, compression actuated mechanical packing 316 is used as the resettable sealing device, a mechanical casing collar locator 318 is used for depth control and positioning of the BHA, a one-way, full opening flap valve assembly 304 is used to ensure that fluid shall not float up through the tubing string 302, a combined shear release fishing hook assembly 308 is used to provide a method of fluid circulation and also of pressure equalization above and below the resettable, compression actuated mechanical packing 316 under certain conditions, and a one-way ball seat stop valve assembly 314 is used to ensure that fluid can only flow upward from below the resettable, compression-actuated mechanical seal 316 and to the circulation/equalization port assembly 308. The cross-sectional area of the flow path associated with the conductors within the circulation/equalization port assembly 308 is sized to have a significantly larger flow cross-section than the flow cross-section associated with the jet flow ports 312 when the circulation/equalization port assembly 308 is in the open position. The circulation/equalization port assembly 308 is opened and closed by the up and down axial movement of the pipe string 302.

In this embodiment, interconnected tubes 302 are preferably used with the resettable, compression-actuated mechanical seal 316, because this can be easily activated and deactivated by vertical movement and/or rotation applied via the tube string 302. Vertical movement and/or rotation is applied via the tube string 302 using a completion rig assisted snubbing unit using a power swivel unit as surface means for connecting, installing and removing the tubing string 302 in and out of the borehole. Note that the surface hardware, methods and procedures associated with the use of a completion rig assisted snubbing unit with a power swivel unit are common and well known to those skilled in the art in connection, installation and removal of tubing strings in and out of a pressurized wellbore. Alternatively, the use of a completion rig using a power swivel unit and stripping head instead of the snubbing unit could handle the connection, installation and removal of tubing strings in and out of a pressurized borehole; which again is common and well known by those skilled in the art of connecting, installing and removing pipe strings in and out of a pressurized borehole. Note also that the surface rig and piping configuration will include appropriate manifolds, pipelines and valves to handle flows to, from and between all relevant surface components/facilities and the wellbore, including but not limited to interconnecting tubing, annulus between interconnecting tubing and production casing, pumps, fluid tanks and backflow pits.

Because the resettable compression actuated mechanical seal 316 is activated via vertical movement or rotation of the tubing string 302, fluid can be pumped down through the tubing string 302 without the need for additional control valves and/or isolation valves that would otherwise be required if an inflatable packing were used as the reset bar sealing device. The inside of the pipe string 302 is used in this way to provide an additional flow line between the surface and the pressure jet tool 310 so that abrasive fluid can be pumped down the pipe string 302 to the pressure jet tool 310. The pressure jet ports 312 located on the pressure jet tool 310 then form an abrasive fluid jet that is directed so that it perforates the production liner 82 and the cement casing 84 to establish hydraulic communication with the formation 86. Figure 10 shows that the pressure jet tool 310 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 also shows that the pressure jet tool 310 has been moved within the wellbore and used to place perforations 324 in the second formation interval of interest, and that the resettable compression actuated mechanical pack 316 has been activated to provide a hydraulically sealing the wellbore prior to the stimulation perforations 324 with the second stage of the multi-stage hydraulic proppant fracturing treatment.

Note that the pressure jet ports 312 may be located between about six inches and one foot from the reset bar compression actuated mechanical packing 316 so that if after pumping the second proppant fracturing stage there are problems with proppant accumulation on top of the reset bar , compression actuated mechanical packing 316, non-abrasive and non-eroding fluid can be pumped down the tubing string 302 and through the pressure jet ports 312 and/or the circulation/equalizing port assembly 308 as needed to clean the top of the resettable compression actuated mechanical packing 316 for proppant. Furthermore, the pressure jet tool 310 can be rotated (when the resettable compression-actuated mechanical seal 316 is not activated) using the tubing string which can be rotated with the power swivel on the surface to further assist in removing proppant accumulations that may occur above the resettable compression-actuated mechanical the gasket 316. Since the perforations are formed using a fluid jet, burrs are not formed. By the fact that there are no degrees of perforation that will potentially lead to extra wear on the elastomers in the resettable, compression-activated mechanical seal 316, the lifetime of the resettable, compression-activated mechanical seal 316 can be extended compared to other methods where perforation degrees occur.

Additionally, note that the flow control achieved by the one-way ball seat stop valve assembly 314 and the one-way, full-open flap valve assembly 304 only allows for pressure equalization above and below the resettable compression-actuated mechanical seal 316 when the pressure below the resettable compression-actuated mechanical seal 316 is greater than the pressure above this. In cases where the pressure above the resettable, compression-activated mechanical seal 316 has to be greater than the pressure below it, the pressure above the resettable, compression-activated mechanical seal 316 can be easily reduced by performing a controlled backflow of the just stimulated area using the annulus between the pipe string 302 and the production liner 82, or by circulating fluid with a lower specific gravity (e.g. nitrogen) down through the pipe string 302 and up through the annulus between the pipe string 302 and the production liner 82.

The one-way, full opening poppet valve assembly 304 is preferred as this type of construction allows unrestricted pumping of abrasive (or erosive) fluid downhole, and also allows the passage of pilot balls which, depending on the particular design of individual BHA components, can be dropped from the surface to control fluid flow and hydraulics in individual BHA components or provide safety tripping of the BHA. Depending on the relevant tool construction, many different valve configurations can be deployed to provide the same functionality as the flow control valves described in this embodiment.

As an alternative to this seventh embodiment, a device containing a nipple could be included which could provide a capability for suspension and retention of other measuring instruments or BHA components. For example, this nipple could hold a conventional casing collar finder and gamma ray tool that is laid out via wireline and be located in the nipple to provide additional diagnostic data on BHA position and location of interesting formation intervals. In addition, multiple abrasive pressure jet tools can be deployed as part of the BHA to control perforation cutting characteristics, such as hole/slot size and cutting speed, handling of different abrasive materials and/or to provide system redundancy in case of premature component failure.

Professionals will be aware that many different components can be laid out as part of the bottom hole arrangement. The downhole array can be configured to contain instruments for measuring reservoir, fluid and wellbore properties as needed for a given application. Temperature and pressure gauges could, for example, be laid out to measure fluid temperature and pressure conditions downhole during treatment, a densitometer could be used to measure effective fluid density downhole (especially useful for determining the distribution and location of proppant downhole during fracture treatment with hydraulic proppant), as well a radioactive detector system (eg gamma ray or neutron measurement systems) to locate hydrocarbon-bearing areas or to identify or locate radioactive material in the wellbore or formation.

Depending on the components in question in the bottom hole array and whether the perforator creates perforation holes with burrs that could damage the sealing mechanism, the bottom hole array could be configured with a tool for removing perforation burrs that would serve to scrape away perforation burrs from the casing wall.

Depending on the relevant components in the downhole assembly and whether overwhelming wear on the components in the downhole assembly could occur if the assembly is driven into contact with the casing wall, centering units could be placed on the downhole assembly to ensure active mechanical positioning of the downhole assembly and avoid or minimize the possibility of damage as a result of the arrangement running in contact with the lining wall.

Depending on the relevant components of the downhole layout and the objectives of a particular job, perforating devices and any other desirable BHA components can be placed either above or below the resettable seal mechanism and in any relative order. The laying system itself, whether it is wire, electric cable, coiled tubing, conventional interconnected tubing, or downhole tractor, can be used to carry signals to activate the sealing mechanisms and/or perforations. It could also be possible to suspend such signaling means in a conventional pipe string or in coiled pipes which are used to suspend the sealing means and perforations themselves. Alternatively, the signaling means, whether electrical, hydraulic or otherwise, could be run in the hole outside the suspension means or even placed in or consist of one or more separate strings of coiled tubes or ordinary interconnected tubes.

In the case of treatments using high viscosity fluid systems in wells deeper than about 2,400 meters, a number of important technological and economic advantages are achieved by the application of the present novel invention. Reduction of frictional pressure limitations allows treatment of deeper wells and reduces the need for special fracturing fluid compositions. The frictional pressure limitations are reduced or eliminated because the high viscosity fluid can be pumped down the annulus between the coil tubing or other suspension means and the production casing. As the friction pressure limitations are reduced or eliminated compared to what applies when high viscosity fluid systems are pumped down the coil tube, the depths at which this technique can be used are significantly extended. For example, assume that with 1.5-inch (approx. 4 cm) coiled tubing laid out in a liner with 5.5-inch (approx. 14 cm) OD and approx. 25 kg per meter, the effective cross-section becomes approximately equivalent to a casing string with an outer diameter of 5 inches (about 12.5 cm). With this effective cross-sectional area for flow, well depths of the order of 6,000 meters or more could be treated, and higher pumping speeds (e.g. of the order of 10 to 30 barrels per minute or more) could be achieved for efficient transport of proppant and hydraulic fracturing with use of high viscosity fluids.

Because the annulus can typically have a larger equivalent flow cross-section, conventional fracturing fluids can be used, as opposed to when special low-viscosity fluids (such as Dowell-Schlumberger's ClearFrac(TM) fluid) are used to reduce frictional pressure drop through coiled tubing. The use of fluid engineering with conventional fracturing fluid would then allow the treatment of formations with temperatures higher than 120 °C, where expensive special fluids currently available may begin to degrade.

The sealing mechanism used could be an inflatable device, a resettable mechanical packer with compression activation, a mechanical pressure holding system (straddle packer) with compression activation, cup sealing devices, or some other alternative device that can be deployed via a suspension means and provide a reset ba r hydraulic sealing option or a similar function. Both inflatable and compression-actuated devices exist that provide radial clearance between seals and liner wall (eg, on the order of 6 mm to 25 mm for inflatable devices, to 2.5 to 5 mm for compression-actuated devices), so that seal wear would be drastic reduced or completely eliminated. In a preferred embodiment of the present invention, there would be sufficient clearance between the sealing mechanism in the deactivated state and the casing wall to allow rapid movement into and out of the wellbore without significant damage to the sealing mechanism or without pressure regulation problems in connection with surging/swabbing the well due to tool movement . The increased clearance between the seal face and the casing wall (when the seal is not activated) would also allow coiled tubing/BHA to be run out of and into the hole at significantly higher speeds than with currently available coiled tubing systems. In addition, in order to minimize potentially unwanted seal wear, the perforator in a preferred embodiment would ensure perforation of the liner wall so that a perforation hole with a relatively smooth edge is obtained. Alternatively, the resettable mechanical sealing mechanism need not produce a perfect hydraulic seal, but could, for example, leave a small gap around the circumference of the device. This small gap could be dimensioned to provide a sealing mechanism (if desired) whereby proppant bridges the small gap and provides a seal (if desired) that can be removed by circulating fluid. Furthermore, depending on the specific application, it is possible that a stimulation job could be done economically even if a complete hydraulic seal was not achieved with the resettable mechanical seal mechanism.

As the perforation device is laid out at the same time as the resettable sealing mechanism, all the components can be depth controlled at the same time with the same measurement standard. This eliminates depth regulation problems that existing methods face when perforation operations and stimulation operations are carried out using two different measuring systems at different times and different wellbore trips. Very accurate depth control can be achieved using a casing collar finder, which is a preferred method of depth control.

Total height for each of the individual perforated target intervals is not limited. This is in contrast to the problem with existing coiled pipe systems that use a gasket-like device that limits their use to 5 - 10 meters with perforated interval height.

Because permanent bridge plugs are not necessarily used, the additional cost and borehole risk associated with bridge plug drilling operations is eliminated. If coiled tubing is used as a means of laying, it is possible that the string of coiled tubing used for the stimulation job could be suspended in the wellhead and used as a production tubing string, which could lead to significant cost savings by eliminating the need for rig mobilization to the well site to install conventional production tubing string which consists of interconnected pipes.

Controlling the order of areas to be treated allows the construction of individual treatment steps to be optimized based on the characteristic properties of the individual area. Furthermore, the potential for unit-optimized stimulation resulting from simultaneous treatment of multiple areas is largely eliminated by exposing only one open set of perforations to each treatment step. In the case of hydraulic fracturing, for example, the present invention can minimize the potential for overwash or unit optimal placement of proppant into the fracture. Also, if a problem occurs that causes the treatment to be interrupted, the areas higher up the hole to be stimulated will not be at risk, since they have not yet been perforated. This is in contrast to conventional methods of ball sealing or coil tube stimulation, where all the perforations must be shot in advance for the job. Should a conventional coiled pipe job fail, it can be extremely difficult to efficiently divert and stimulate over a long completion interval. In addition, if only one set of perforations is open above the sealing element, fluid could be circulated without the possibility of breaking down the other multiple sets of open perforations above the top sealing element, as could occur in the conventional coiled pipe job. This can minimize or eliminate loss of fluid and damage to the formation when the circulation pressure in the bottom of the hole would otherwise exceed the pressure in the formation pores.

The entire treatment can be pumped in a single trip, leading to significant cost savings compared to other techniques that require multiple wireline or rig work to make trips in and out of the hole between treatment stages.

The present invention can be used for multi-stage treatments in diverted and horizontal wellbores. Typically, other conventional diversion techniques in diverted and horizontal wells will be more demanding due to the nature of fluid transport of the diversion material over the long intervals typically associated with diverted or horizontal wells.

If a screen-out should occur during the fracturing treatment, the present invention has a method for immediately circulating sand-filled fluid in the annulus out of the hole, so that stimulation operations can be resumed without the coil pipe/BHA having to take a trip out of the hole. The presence of the coiled tubing system provides a means to measure downhole pressure after perforating or during stimulation operations based on pressure calculations involving the coiled tubing string under shut-in (or low flow rate) conditions.

The presence of coiled tubing or a conventional system of interconnected tubing constitutes, if used as a means of laying, a means of injecting fluid downhole independently of fluid being injected into the annulus. For example, this can be useful in addition to other applications, such as (a) keeping the BHA seal mechanism and flow ports free of proppant accumulation (which could potentially cause tool retention) by pumping fluid downhole at a nominal rate to clean the seal mechanism and flow ports, (b) downhole mixing operations (as further explained below), (c) downhole acid discovery during perforating to assist with perforation hole cleanout and communication with the formation, and (d) independent stimulation of two areas isolated from each other of the reset bar re sealing mechanism. In that case, if piping is used as the means of laying, fluid, depending on the actual operations desired and the components of the actual downhole arrangement, could be circulated downhole at any time, or only when the seal element is not activated, or when equalizing ports are open or closed. Depending on the relevant components in the downhole arrangement and the relevant construction of flow control valves downhole which may be used for example as components integrated in equalization gate units, circulation gate or flow gate units, downhole control valves can be operated by wireline activation, hydraulic activation, current activation, "j- lock" activation, sliding sleeve activation or by many other means known to those skilled in the art of operating and activating downhole control valves.

The coiled tubing system still allows for a controlled flow back of individual treatment steps to aid in cleanup and fracture closure. Backflow can be carried out up to the annulus between the coiled tubing and the production casing, or alternatively, backflow can be carried out up to the coiled tubing string if large backflow is not considered to be problematic. The perforation device can consist of commercially available perforation systems. These gun systems could include what will hereafter be called a "selective-firing system", so that a single perforating gun array is composed of multiple charges or sets of perforating charges. Each individual set of one or more perforating charges can be remotely controlled and fired from the surface using electrical, radio, pressure, fiber optic or other activation signals. Each set of perforating charges can be engineered (in terms of number of charges, number of rounds per liner, hole size, penetration characteristics) for optimum performance in the individual area to be treated with an individual step. With the current technique of selective firing, there are commercial gun systems that could permit sequential perforation of on the order of 30 to 40 intervals in a single trip downhole. Cannons can be pre-fitted and engineered to fire multiple sets of perforations. Guns can be placed anywhere on the downhole arrangement, including either above or below the resettable mechanical seal mechanism.

Intervals can be grouped for treatment on the basis of reservoir characteristics, treatment scheme considerations, or equipment limitations. After each group of intervals (preferably 5 to about 20), at the end of the working day (often given by the lighting conditions), or if difficulties arise in sealing one or more areas, a bridge plug or other mechanical device can preferably be used to isolate the group of intervals that have already been processed from the next group awaiting processing. One or more selectively fired bridge plugs or fracture baffles could be run with the bottomhole array and activated as desired during the completion operation to provide positive mechanical isolation between perforated intervals and to eliminate the need for a separate wire to activate mechanical isolation devices or diverters between groups of fractured stages .

In general, the method according to the invention can be readily used in production casings of 4.5-inch (about 11 cm) to 7-inch (about 18 cm) diameter with existing, commercially available perforating gun systems and reset only mechanical sealing mechanisms. The method according to the invention will be able to be used in smaller or larger liners with resettable mechanical sealing mechanisms that are specially designed for such smaller or larger liners.

If selective-firing perforating guns are used, each of the guns can be on the order of 0.6 to 2.4 meters long and contain on the order of 8 to 20 perforating charges placed along the barrel with a firing density of between 1 and 6 rounds 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 on top of each other so that the total length of the entire gun system is preferably kept less than about 24 to 30 meters. This total barrel length can be driven into the borehole using an easily accessible crane and lubrication system on the surface. Longer gun lengths could also be used, but may require additional or special equipment on the surface, depending on the total number of guns that had to make up the entire perforation nord ni ng. Note that in some special applications, gun length, number of charges per gun and shot density could be greater or less than what is specified above, as the final design of the perforation system will depend on the current formation characteristics present in the wellbore to be stimulated.

To minimize the overall length of the gun system and BHA, it may be desirable to use multiple (two or more) charge carriers spaced evenly around and bonded, welded or otherwise attached to the coil tube or connected below the resettable mechanical seal mechanism. If, for example, it is desired to stimulate 30 areas, where each area is perforated with a 1.2 meter cannon, a single cannon arrangement would result in a total length of around 50 metres, which may be impractical to handle on the surface. Alternatively, two gun arrays could be laid out facing each other on the coil pipe, where each array could contain 15 guns, and the total length could be about 25 metres, which can easily be handled on the surface with existing lubricator and crane systems.

An alternative arrangement for the perforating gun(s) could be to place one or more guns above the resettable mechanical sealing mechanism. There could be two or more separate gun arrays attached in such a way that the charges faced away from the components of the borehole array or coil tube. It could also be a single array with charges spaced closer together and firing mechanisms designed to fire only a subset of the charges simultaneously within a given interval, perhaps all in a given phase orientation.

Although the perforating device described in this embodiment used remotely fired charges or fluid pressure jets to perforate the liner and cement casing, alternative perforating devices, including but not limited to chemical dissolution or drill/mill cutting devices, could be used within the scope of the present invention for the purpose of creating a flow path between the wellbore and the surrounding formation. For the purposes of the present invention, the term "perforating device" will be used in a broad sense and include all of the above, in addition to any activation means suspended in the wellbore for the purpose of activating charges or other perforating means that may be carried by the casing or other means apart from the bottom hole arrangement or suspension method which is used for suspending the bottom hole setup.

The BHA could contain a downhole motor or other mechanism to provide rotation/torque for activation of mechanical sealing mechanisms that require rotation/torque for activation. Such a device, together with an orientation device (eg gyroscope or compass) could allow oriented perforation so that perforation holes are placed in a preferred compass direction. Alternatively, if interlocking pipes were used, it is possible that rotation and torque could be transmitted downhole by direct rotation of the interlocking pipes using rotary drive equipment readily available on conventional right-of-way rigs. Downhole instrumentation for measuring well conditions (collar finder, pressure, temperature and other instruments) for real-time downhole monitoring of stimulation job parameters, reservoir properties and/or well performance could also be deployed as part of the BHA.

In addition to the resettable mechanical diversion device, other diversion materials/devices may be pumped downhole during treatment, including but not limited to ball seals or particulates such as sand, ceramic material, proppant, salt, waxes, resins or other organic or inorganic compounds, or alternative fluid systems such as viscosified fluids, gelified fluids, foam types or other chemically composed fluids or other injectable diverting agents. The additional lead material could be used to help minimize the duration of the stimulation treatment in that some time saving could be achieved by reducing the number of times the mechanical lead device is activated, while lead ability could still be achieved over the multiple areas. For example, in an interval of 1,000 meters, where individual areas with a nominal separation of 30 meters are to be treated, it may be desirable to use the resettable mechanical diversion device which works in increments of 170 meters (500 feet) up the hole, and then diverting each of the six steps with a diverting agent entrained in the treatment fluid. Alternatively, limited-input techniques can be used for multiple intervals as a subset of the entire interval to be processed. Any of these variations would reduce the number of mechanical activations of the mechanical diversion device and possibly extend its effective life.

If a pipe string is used as a means of laying, the pipe allows the laying of downhole mixing devices and the direct use of downhole mixing techniques. Concretely, the pipe string can be used to pump chemicals downhole and through the flow ports in the bottom hole setup for subsequent mixing with fluid that is pumped into the pipe via the production casing annulus. During, for example, a hydraulic fracturing treatment, it may be desirable to pump nitrogen or carbon dioxide downhole into the pipe and allow it to mix with the treatment fluid downhole, so that nitrogen-assisted or carbon dioxide-assisted backflow can take place.

This method and device could be used to treat vertical, diverted or horizontal wellbores. The invention specifies, for example, a method for generating vertical (or nearly vertical) fractures so that they cross horizontal or derived wellbores. Such a technique could lead to economical completion of multiple wells from a single ramp location. Treatment of a multilateral well could also be carried out where the deepest lateral is treated first, after which a plug is inserted or a sleeve is activated to isolate this lowest lateral, and the next lateral up the hole is then treated, another plug is inserted or sleeve activated to isolate this lateral, and the process continues with processing the desired number of laterals within a single wellbore.

If perforating guns with selective firing are used, which may be desirable to maximize the number of intervals that can be treated, the use of short guns (ie, 4-foot length or less) could limit well productivity in some cases by causing increased pressure drop in reservoir space prevailed near the wellbore, compared to the use of longer guns. Well productivity may similarly be limited if only a short interval (ie, 4-foot length or less) is perforated using an abrasive jet. The potential for excess backflow proppant may also increase and lead to reduced stimulation efficiency. Backflow will preferably be carried out at a controlled low speed to limit potential backflow of proppant. Depending on the resulting backflow, resin-coated proppant or alternative gun configurations could be used to improve stimulation efficiency.

In addition, if pipe or cable is used as a laying agent to remedy potential proppant erosion on the pipe string or cable by direct impact of the proppant-filled fluid when it is pumped into the injection ports in the side outlet, an "isolation device" can be rigged up on the wellhead. The isolation device may consist of a flange attached to a short length of pipe that descends through the center of the wellhead to a few feet below the injection ports. The bottom hole assembly and the pipe or cable run inside the isolation device pipe. Consequently, the pipe in the isolation device will deflect proppant and isolate the pipe or cable from direct impact of proppant. The pipe in the isolation device thus diverts the proppant and isolates the pipe string or cable from direct impact of the proppant. Such an isolation device would consist of a pipe of suitable diameter so that the largest outer diameter dimension in terms of pipe string or cable and hole bottom arrangement would be able to pass unhindered. The length of the isolation device would be set so that in the event of damage, the lower main fracture valve would still be able to close and the wellhead rigged down as needed to remove the isolation tool. Depending on the stimulation fluids and the way the injection is performed, there would be no need for an isolation device if there were no erosion problems. Although field testing of isolation devices has not shown erosion problems, depending on the job construction, there may be some risk of erosion damage to the isolation tool pipe arrangement leading to difficulties in removing it. If an isolation tool is used, preferred practice will be to keep the impact velocity of the isolation tool pipe significantly below typical erosion limits, preferably below about 60 m/s, and most preferably below 50 m/s.

Another issue regarding this technique is that premature seepage can occur if fluid displacement during pumping is not sufficiently measured, as it can be difficult to initiate a fracture with proppant-filled fluid over the next area to be perforated. It may be preferable to use a KCI fluid or other non-gelled fluid to better initiate fracturing of the next area. Pumping the job at a higher rate with a non-gelled fluid between stages to achieve turbulent flushing/sweeping of the liner will minimize the risk of proppant leakage. Also, spare guns present on the tool string would allow continuing the job after a suitable waiting time.

Claims (19)

1. Method for perforating and treating multiple intervals of one or more underground formations cut through by a wellbore, said method comprising: (a) laying out a bottom hole assembly (Bottom Hole Assembly - BHA) using a laying agent inside said wellbore (78 ), wherein said BHA has a perforating device and a sealing mechanism, (b) positioning said BHA within said wellbore (78), (c) using said perforating device to perforate said interval, (d) activating said sealing mechanism to create a hydraulic sealing in the wellbore, (e) pumping a treatment fluid into said wellbore and into the perforations formed by said perforating device (230, 231), without removing said perforating device from said wellbore, (0 release of said sealing mechanism, as well as (g) repetition of steps (b) through (f) for at least one more interval of said one or more underground formations characterized in that the treatment fluid is pumped down into the annulus between said laying agent and said wellbore. 2. Procedure according to claim 1, where said laying means are selected from the group consisting of a string of pipes such as coiled pipes (106) or interconnected pipes (302), a wireline (102), a slickline, a cable and a tractor system (131, 133). 3. Procedure according to claim 1 or 2, where the BHA is positioned inside the wellbore using a depth control device such as a casing collar finder (128) and a measurement system on the surface. 4. Method according to one of claims 1 to 3, wherein said perforating device is a perforating gun (134, 144, 154) with selective firing containing multiple sets of one or more shaped perforating charges (136, 146, 156), where each of said sets of one or more shaped perforating charges is individually controlled and activated by an electrical or optical signal transmitted via a cable laid out in the wellbore. 5. Procedure according to claim 2, where the laying means is a pipe string and where said perforating device is a pressure jet cutting device (310) which uses fluid pumped down said pipe string to establish hydraulic communication between said wellbore and said one or more intervals of said one or more underground formations. 6. Procedure according to claim 2, where said treatment fluid is pumped down said pipe string, through flow ports in said BHA, and into said perforations. 7. Procedure according to claim 6, where a second treatment fluid is pumped down through said pipe string, through flow ports in said BHA and into said perforations. 8. Procedure according to claim 7, wherein said second treatment fluid is nitrogen. 9. Method according to one of claims 1 to 8, where said sealing mechanism is a reset ba r seal (120). 10. Method according to one of claims 1 to 9, where said treatment fluid is selected from the group consisting of an acid solution, an organic solvent and a slurry of proppant material and a carrier fluid. 11. Method according to one of claims 1 to 10, where said method additionally comprises the step where, prior to release of said sealing mechanism, at least one diverting agent such as particulates, gels, viscous fluids, foam or ball seals is laid out in said well hole to block further flow of treatment fluid into said perforations. 12. Method according to one of claims 1 to 11, where said perforating device is activated by hydraulic pressure transmitted from the surface through an umbilical string, through the wellbore or through the pipe string. 13. Method according to one of claims 1 to 12, where said BHA is moved inside said wellbore before said sealing mechanism is activated. 14. Method according to one of claims 1 to 13, where said sealing mechanism is activated by hydraulic pressure to establish a hydraulic seal below said perforated interval. 15. Method according to one of claims 1 to 14, wherein the BHA has at least one pressure equalizing means to establish pressure communication between the parts of the wellbore above and below said sealing mechanism prior to release of the sealing mechanism. 16. Method according to one of claims 1 to 15, where the perforation device in the BHA is positioned below the sealing mechanism in said BHA. 17. Method according to one of claims 1 to 16, where said perforation device is not equipped with any continuous fluid passage for washing fluid. 18. The method of claim 1 for perforating and treating multiple intervals including a deepest target interval and sequentially shallower target intervals, wherein (a) the BHA's perforating device is positioned below the sealing mechanism, (b) said perforating device is used to perforate said deepest target interval of said one or more underground formations, (c) a treatment fluid is pumped down the annulus between said expansion means and said wellbore and into the formations produced in said deepest target interval by said perforating device without removing said perforating device from said wellbore, (d) said BHA is positioned in said wellbore and said perforating device is used to perforate the next sequentially shallower target interval of said one or more subsurface formations, (e) said BHA is repositioned in said wellbore and said sealing mechanism is activated to hydraulically isolate the perforations produced in said next sequentially shallower m eel interval from the perforated deepest target interval, (0 a treatment fluid is pumped down the annulus between said laying means and said wellbore and into the formations produced in said next sequentially shallower target interval by said perforating device without removing said perforating device from said wellbore, (g) said sealing mechanism is released, and (h) step ( d) through (g) are repeated for at least one further sequentially shallower target interval of said one or more underground formations where the perforations produced in said at least one further sequentially shallower target interval are hydraulically isolated from the perforated intervals below. 19. System for stimulation treatment for use in perforating and treating multiple intervals of one or more subsurface formations intersected by a wellbore, said system comprising: (a) a treatment fluid, (b) a laying agent placed inside said wellbore (78), ( c) a bottom hole assembly (Bottom Hole Assembly - BHA) adapted for laying with said laying means, where said BHA has at least one common perforating device (134, 144, 154, 174, 184, 194, 207, 209, 211, 213), for sequential perforating said multiple intervals, as well as at least one sealing mechanism (120), wherein said BHA is positionable within said wellbore (78) to allow activation of said perforating device and said sealing mechanism, (d) said sealing mechanism capable of creating a hydraulic seal in said wellbore and furthermore capable of canceling said hydraulic seal so that the BHA can move to another position inside said wellbore, whereby each of the said multiple treatment intervals can be treated with said treatment fluid separately from the said other treatment intervals, where the treatment fluid is contained within an annular area between said laying agent and said wellbore's lining.