Method of forming lateral boreholes from a parent wellbore

Method for forming lateral borehole from main borehole

[0001] Statement on Federal Sponsorship of Research or Development

[0002] Not applicable.

[0003] The names of the parties to the collaborative research agreement

[0004] Not applicable.

[0005] Statement of related application

[0006] This application claims the benefit of U.S. Provisional Patent Application No. 62/198,575 filed on July 29, 2015. The US provisional patent application is entitled "Downhole Hydraulic Jetting Assembly, and Method for Forming Mini-Lateral Boreholes". This application also claims the benefit of US Provisional Patent Application No. 62/120,212 of the same subject filed on February 24, 2015.

[0007] This application is also filed as a partial continuation application of U.S. Patent Application No. 14/612,538 filed on February 3, 2015. The US patent application is entitled "Method of Testing a Subsurface Formation for the Presence of Hydrocarbon Fluids". This U.S. patent application is again a division of U.S. Patent No. 8,991,522 issued on March 31, 2015.

[0008] These applications are all incorporated herein by reference.

Background technique

[0009] This section is intended to introduce selected aspects of the technology that may be associated with various embodiments of the present disclosure. It is believed that this discussion will help provide a framework that facilitates a better understanding of specific aspects of the present disclosure. Correspondingly, it should be understood that this section should be understood from this perspective and is not necessarily an acknowledgment of the prior art.

Technical field

[0010] The present disclosure relates to the field of well completions. More specifically, the present disclosure relates to the completion and stimulation of hydrocarbon-producing formations by generating small-diameter boreholes from existing boreholes using hydraulic injection components. The present disclosure also relates to the controlled generation of multiple lateral boreholes extending several feet into the subterranean formation in a single trip.

[0011] Technical Discussion

[0012] When drilling oil and gas wells, a drill bit pushed down at the lower end of the drill string is used to penetrate the surface to form an approximately vertical well. After drilling to a predetermined bottomhole (bottomhole) position, the drill string and drill bit are removed, and the drilling hole is lined with a casing string. Therefore, an annular area is formed between the casing string and the formation penetrated by the wellbore. In particular, in a vertical wellbore or a vertical section of a horizontal well, cementing operations are performed in order to fill or "pack up" the entire annular volume with cement along part or all of the length of the wellbore. The combination of cement and casing strengthens the wellbore and promotes zonal isolation (zonal isolation) and subsequent completion of certain sections of possible hydrocarbon production areas behind the casing.

[0013] In the last two decades, the development of drilling technology has enabled oil and gas operators to economically "kickoff" and shift the wellbore trajectory from a generally vertical orientation to a generally horizontal orientation. Now, the horizontal "pillars" of each of these wells are usually more than a mile in length. This significantly increases the exposure of the wellbore to the target hydrocarbon-bearing formation (or "producing area"). For example, for a given target production area with a thickness of 100 feet (vertical), the production area where one mile of horizontal struts are exposed to the horizontal wellbore is 52.8 times the production area where 100 feet of the conventional vertical wellbore is exposed.

[0014] FIG. 1A provides a cross-sectional view of the wellbore 4 that has been completed in a horizontal orientation. It can be seen that the well 4 has been formed from the surface 1, through several formations 2a, 2b...2h and down to the hydrocarbon-generating formation 3. Subterranean formation 3 represents the "production area" for oil and gas operators. The well 4 includes a vertical section 4a above the production area, and a horizontal section 4c. The horizontal section 4c defines the post heel portion 4b and the post toe portion 4d and the elongated post extending through the production area 3 between them.

[0015] With the completion of the drilling hole 4, a number of casing strings with gradually smaller outer diameters have been cemented in the drilling hole 4. These casing strings include surface casing strings 6, and may include one or more intermediate casing strings 9, and finally production casing 12. (The shallowest and largest diameter casing (which is called a catheter) is not shown, which is a short pipe section separated from the surface casing and located directly above the surface casing.) The main part of the surface casing 6 One of the functions is to isolate and protect the shallow, freshwater-containing groundwater layer from being contaminated by any drilling fluid. Therefore, the conduit and the surface sleeve 6 are almost always completely fixed 7 back to the ground 1 by cement.

[0016] Repeat the process of drilling several times and then bonding the tapered casing string until the well reaches the completion depth. In some cases, the last casing string 12 is a liner, that is, a casing string that is not restrained back to the ground 1. The last casing string 12, referred to as the production casing, is also usually fixed 13 in place by cement. In the case of horizontal completion, the production casing 12 can be cemented, or an external casing packer ("ECP"), an expansion packer, or some combination thereof can be used to provide zonal isolation.

[0017] An additional tubular body may be included in the completion. These tubular bodies include one or more production tubing strings (not shown in Figure 1A) placed in a production casing or liner. In a vertical completion, each tubing string extends from the surface 1 to a specified depth close to the production section 3, and can be attached to a packer (not shown). The packer is used to close the annular space between the production tubing string and the surrounding casing 12. In a horizontal completion, the production tubing is usually (with or without the packer) arranged at or near the heel 4b of the borehole 4.

[0018] In some cases, the production area 3 cannot effectively flow fluid to the ground 1. When this happens, the operator can place an artificial lifting device (not shown in Figure 1A) as part of the completion of the wellbore. The artificial lift facility may include a downhole pump that is connected to a surface pumping unit via a series of sucker rods extending within the tubing. Alternatively, an electrically driven submersible pump can be placed at the bottom end of the production tubing. Gas lift valves, hydraulic jet pumps, plunger lift systems or various other types of artificial lift facilities and technologies can also be used to assist fluid flow to the ground 1.

[0019] As part of the completion process, the wellhead 5 is installed at the surface 1. The wellhead device 5 is used to control the wellbore pressure and direct the flow of production fluid at the surface 1. It is also possible to set up fluid accumulation and treatment facilities (not shown in FIG. 1A), such as pipes, valves, separators, dehydrators, gas desulfurization units, and oil and water storage tanks. After the production area is completed, install any necessary downhole pipe fittings, artificial lifting facilities and wellhead devices 5, and then production operations can begin. Keep the wellbore pressure under control, and properly separate and distribute the produced wellbore fluid.

[0020] In the United States, many wells are now being drilled mainly to extract oil and/or natural gas, and possibly liquefied natural gas, from production areas that were previously considered difficult to penetrate and cannot produce hydrocarbons in economically viable quantities. This "compact" or "unconventional" formation may be sandstone, siltstone or even shale formation. Alternatively, such unconventional formations may include coal bed methane. In any case, "low permeability" generally refers to a rock interval having a permeability of less than 0.1 millidarcy.

[0021] In order to enhance the production of hydrocarbons, especially in low-permeability formations, later (ie, after perforating the production casing or lining), stimulation techniques can be used in the completion of the production area. Such techniques include hydraulic fracturing and/or acidification. In addition, in order to create one or more newly oriented or horizontally completed boreholes, a "drilled" borehole can be formed from the main borehole. This allows the well to penetrate along the plane of the subterranean formation to increase exposure to the production area. In the case where the fracturing plane caused by the natural or hydraulic forces of the formation is vertical, the horizontally completed well allows the production casing to traverse or "source" multiple fracturing planes. Correspondingly, vertically oriented drilling holes are usually limited to the fracturing plane caused by a single hydraulic force in each production area, while horizontal drilling

The well bore can be perforated and hydraulically fractured in multiple positions or "steps" along the horizontal pillar 4c.

[0022] FIG. 1A shows a series of fractured half-planes 16 along the horizontal section 4c of the wellbore 4. The fracturing half-plane 16 represents the orientation of the fracture that will be formed in connection with the perforation/fracturing operation. According to the principles of geomechanics, the fracturing plane will usually be formed along the direction perpendicular to the minimum principal stress plane in the rock matrix. More simply, in most drilling holes, when the horizontal section of the drilling hole is below 3,000 feet below the surface and sometimes as shallow as 1,500 feet, the rock matrix will split along the vertical line. In this case, hydraulic fractures will tend to propagate from the perforation 15 of the wellbore along a vertical elliptical plane perpendicular to the minimum principal stress plane. If the orientation of the minimum principal stress plane is known, the longitudinal axis of the pillar 4c of the horizontal wellbore 4 is ideally oriented parallel to it, so that multiple fracture planes 16 will penetrate the horizontal pillar 4c orthogonal or approximately orthogonal to the wellbore The wellbore is shown in Figure 1A.

[0023] Optimize the desired density of the perforated and fractured intervals along the horizontal pillar 4c in the production area 3 by calculating the following:

[0024] The estimated final recovery rate ("EUR") of the hydrocarbons that each fracture will expel, which requires calculation of the stimulation reservoir volume ("SRV") that each fracturing treatment will connect to the wellbore via its corresponding perforation ); Minus (less) [0025] · Any overlap with the corresponding SRV of the boundary fracturing interval; coupled with

[0026] · The expected time allocation for the production of hydrocarbons from each fracture; and

[0027] Increase the incremental cost ratio of another perforation/fracturing interval (versus).

[0028] The ability to repeat multiple vertical completions along a single horizontal wellbore is done in a relatively short period of time from unconventional reservoirs (especially shale) in economically feasible search for hydrocarbon reservoirs. This revolutionary technology has the following far-reaching effects. The current Baker Hughes Rig Count information in the United States shows that only about a quarter (26%) of the wells drilled in the United States are classified as "vertical", and the other quarter Three are classified as "horizontal" or "directional" (62% and 12%, respectively). That is, about two of every three wells currently drilled in the United States are horizontal wells.

[0029] Compared to vertical wells, the additional cost of drilling and completing horizontal wells is not small. In fact, it is not uncommon for the highest cost of drilling and completing a horizontal well ("D&C") to be multiple (twice, triple or more) of its corresponding vertical well. Depending on the geological basin, especially the standard geological characteristics that determine the drilling penetration rate, required drilling mud rheology, casing design, and bonding, the significant additional costs of drilling and completing horizontal wells include controlling the radius of curvature of the drilling, And those costs involved in guiding the drill bit and drilling components (including MWD and LWD technology) and the overall length of the horizontal section 4c in the preferred horizontal trajectory or approximate horizontal trajectory of the wellbore 4 initially obtained and then maintained in the production area 3. The critical process of obtaining wellbore isolation between fracturing stages (due to additional cement fixation and/or ECP) usually results in a significant increase in the increased completion cost, "bridge plug perforation" or sleeve or port (Usually actuated by falling ball) The cost of the completion system is the same.

[0030] However, in many cases, the highest single cost of drilling and completing a horizontal well is the cost associated with the pumping hydraulic fracturing process itself. It is not uncommon for the total cost of hydraulic fracturing for a given horizontal well to reach or even exceed 50% of its total drilling and completion costs.

[0031] It is vital to the economic success of any horizontal well to achieve a satisfactory hydraulic fracturing geometry in the production zone of the completion. Many factors may contribute to the success or failure of the desired geometry. This includes the rock properties of the production area, the pumping restrictions imposed by the construction of the wellbore and/or surface pumping facilities, and the characteristics of the fracturing fluid. In addition, proppants of various mesh (mesh) sizes are usually added to the fracturing mixture to maintain the width of the fracture caused by hydraulic pressure in a "open" state, thereby improving the conductivity of the hydrocarbon fluid produced by the fracture.

[0032] Generally, in order to achieve the desired fracture characteristics (fracture width, fracture conductivity, and in particular fracture half-length) in the production area, an overall fracture height that significantly exceeds the boundary of the production area must be formed. Fortunately, the height of the cracks outside the vertical zone grows

It is usually limited to a few times the thickness of the overall production zone (ie, tens of feet or hundreds of feet), so it does not pose a threat of pollution to the much shallower freshwater source that is almost always separated from the production area by thousands of feet of rock formation. See K. Fisher and N. Warpinski, "Hydraulic Fracture-Height Growth: Real Data", SPE Paper No. 145,949, SPE Annual Technical Conference and Exhibit, Denver, Colorado (October 30 to November 2, 2012).

[0033] Nonetheless, this increases the amount of fracturing fluid and proppant required at various "fracturing" stages, and further increases the required pumping horsepower. It is known that for a typical fracturing operation, a large amount of fracturing fluid, fluid additives, proppant, hydraulic ("pumping") horsepower (or "HHP") and related costs are all spent on the non-producing part of the fracture . This means that there are billions of dollars in the United States alone every year.

[0034] In addition, complicating the planning of horizontal wellbore is an uncertain factor associated with fracture geometry in unconventional reservoirs. Based on the analysis of real-time data from inclinometers and microseismic surveys, many experts believe that fracture geometries in unconventional reservoirs that are less permeable and especially more fragile can produce highly complex fracture geometries. That is, in contrast to the relatively overly simple two-wing ellipse model (as shown in the idealized demonstration in Figure 1A) that is considered to be consistent with the most conventional reservoirs, the fracture geometry in unconventional reservoirs may be unpredictable.

[0035] In most cases, due to excessive fluid leakage and/or reduced fracture width (which may cause earlier sand filtration), the length and complexity of the far-field fracture are considered disadvantageous (rather than advantageous) . Therefore, whether the fracture complexity (or lack thereof) enhances or reduces the fracture network will enable the drilling of the SRV of the wellbore is usually determined on a case-by-case basis (eg, reservoir by reservoir).

[0036] Therefore, it is desirable to obtain more control over the geometric growth of the primary fracture network extending vertically outward from the horizontal struts 4c, especially in horizontal completions for tight reservoirs. It is also desirable to extend the length of the fracture network orientation without significantly intruding into the boundary of the horizontal production area 3. Further, it is desirable to increase the efficiency of the fracture network between the well bores by using two or more hydraulic jet micro-branch channels along the horizontal struts to reduce the density of wells required to drill a given reservoir volume. Furthermore, it is desirable to provide such guidance, restriction, and control of SRV by creating one or more micro-drain holes as an alternative to conventional casing ports provided by conventional completion procedures that require perforations, sliding sleeves, etc. Enhanced.

[0037] Therefore, there is a need for downhole assemblies with jet hoses and whipstocks so that the assemblies can be transported to any wellbore interval that is inclined, including extended horizontal struts. There is also a demand for a hydraulic injection system that provides a substantially 90°-turned spray hose opposite to the outlet point of the casing, preferably using the entire inner diameter of the casing as the bending radius of the spray hose, thereby providing The largest possible inner diameter of the spray hose, and therefore provide the largest possible hydraulic horsepower to the spray nozzle. There is also a need for a system that includes a whipstock that can be deployed on a string of coiled tubing (string of coiled tubing), where the whipstock can be reoriented in discrete known increments and does not rely on the ground The rotation of the pipe transferred to the downhole.

[0038] There are additional requirements, which are discussed in certain embodiments herein. There is a need for an improved method of using hydraulic directional force to form a lateral wellbore, where even a desired length of spray hose can be transported from a horizontal wellbore. In addition, there is also a need for a method of forming micro lateral boreholes branched from the horizontal pillars, which help to confine the subsequent SRV to but not significantly beyond the boundaries of the production area. In addition, there is a need for a method by which the jet nozzle and the connected hose can be transported and operated with hydraulic and/or mechanical thrust that enables the jet nozzle and the connected hose to move into the formation, as far as desired Multiple main wellbore depths and micro-lateral azimuth orientations withdraw, reorient, redeploy and re-operate the whipstock and jet hose in a single trip, not only in the wellbore

In the vertical part, multiple micro-horizontal boreholes are generated, and multiple micro-lateral boreholes are also generated in the highly oriented or even horizontal part of the borehole. In addition, there is a need for a method that can transport the spray hose in an expanded state so that the bending radius in the production casing and along the whipstock is the most stringent bending restriction that the hose must meet.

[0039] In addition, there is also a need for the following hydraulic fracturing micro-transverse drilling method, which, after the formation of the transverse drilling, is followed by spraying out the micro-transverse drilling separated from the horizontal pillars of the drilling hole, and does not require Pull the jet hose, whipstock and transport system out of the main borehole. The following method is also needed, which is based on real-time analysis of the geophysical (microseismic and/or inclinometer and/or environmental microseismic) description of the SRV development (or lack thereof) formed by pumping a given stimulation (fracturing) level, Set the path of the horizontal drilling. In addition, the following method is required, which is based on the performance of SRV based on existing conventional perforation clusters and their corresponding stimulation levels (or, more specifically, the poor performance observed by production logging or permanent environmental microseismic devices) ) To optimize the placement and contour settings of the new lateral drilling group/stimulation level, so as to optimize the re-completion of existing horizontal wells. In other words, there is a need for a method that remotely controls the erosion digging path of the jet nozzle and the connected hydraulic hose so that the profile of the lateral borehole or "groups" of multiple lateral boreholes can be set to optimally control the formation of subsequent stimulation treatments SRV geometry.

Summary of the invention

[0040] The systems and methods described herein have various benefits in performing oil and gas completion activities. In the present disclosure, it is first claimed that a method of forming a lateral borehole in a production area is required. The production area exists in the underground layer. In one embodiment, the method first includes determining the depth of the production area in the subterranean formation. The production area limit has been identified as a rock matrix containing or at least likely to contain hydrocarbon fluids, or a rock rich in organic matter. In one aspect, the method further includes determining the thickness of the production area.

[0041] The method also includes forming a well bore in the production area. In a preferred embodiment, the wellbore has deviated sections, or more specifically, is completed horizontally. In these cases, forming the well hole means forming the main well hole at an angle deviated from the vertical, or even forming the well hole along a substantially horizontal plane.

[0042] The method also includes transporting the hydraulic injection assembly on the working string into the wellbore. Preferably, the working column is a coiled tubing column with a sheath for accommodating electric wires and preferably optical fiber data cables.

[0043] The downhole hydraulic injection assembly is used to inject multiple lateral boreholes into the underground formation from the existing main wellbore. This component basically includes two cooperative systems:

[0044] (1) An internal hose system ("internal system"), which defines an elongated spray hose having a spray fluid inlet at its proximal end and a spray nozzle at its distal end, so The jet nozzle is configured to be guided to and pass through the exit position of the main wellbore; and

[0045] (2) An external hose delivery, deployment, and withdrawal system ("external system") that extends on the working column to provide a defined path of travel (including whipstock) within the wellbore, wherein the external system is constructed The long jet hose is loaded into the wellbore and "pushed" against the whipstock provided in the wellbore to push the jet nozzle forward into the surrounding formation.

[0046] In the case of casing drilling holes, jet hoses and connected nozzles are used to form a window through the casing, followed by a lateral borehole penetrating into the hydrocarbon-bearing production area. The construction and operation of these two coordinated systems allows the whipstock to be reoriented and/or repositioned, and the jet hose can be re-deployed into the casing and re-withdrawn to eject multiple jets in the same trip. Two casing outlets and lateral drilling.

[0047] As described, the internal system includes a spray hose having a proximal end and a distal end. The fluid inlet is located at the proximal end, and the jet nozzle is located at the distal end. Preferably, a power source such as a battery pack is located at the proximal end for supplying electrical components of the injection assembly

electricity.

[0048] The external system includes a pair of tubular bodies. These represent outer catheters and inner catheters. The outer tube has an upper end, a lower end, and an internal bore therebetween, the upper end being configured to be operatively attached to a working column or "tubing transport medium" for extending the spray hose assembly into the production casing. The inner tube is located in the bore of the outer tube and serves as a spray hose carrier. The spray hose carrier slidably receives the spray hose during operation.

[0049] A micro-annular gap is formed between the spray hose and the surrounding spray hose carrier. The size of the micro annulus is set to prevent the spray hose from bending when sliding in the spray hose carrier during operation of the assembly. The micro annulus is also configured to allow the operator to control the amount and flow direction of the hydraulic fluid between the spray hose and the surrounding inner conduit, which is then converted into fluid force, which can: (1) When the spray hose is When pushing downstream, maintain the spray hose in the taught configuration; or (2) When the spray hose is withdrawn into the inner duct, push the spray hose in the upstream direction.

[0050] The spray hose assembly also includes a whipstock member. The whipstock member is arranged below the lower end of the outer tube. The whipstock member includes a concave surface for receiving and directing the spray nozzle and the connected hose during operation of the assembly.

[0051] The jet hose assembly is configured to (i) transfer the jet hose out of the jet hose carrier by a transfer force and reach the desired point of the wellbore exit against the arcuate whipstock surface, and (ii) after reaching the well At the desired point of the hole exit, direct the jet fluid through the jet hose and the connected jet nozzle until an exit is formed. (iii) Continue jetting along the operators designed geographic trajectory to form a lateral borehole into the rock matrix in the production area , And then (iv) after forming the transverse borehole, the spray hose is pulled back into the spray hose carrier to allow optional adjustment of the position of the whipstock device in the borehole.

[0052] In one aspect, the whipstock is configured such that one face of the whipstock provides the jet hose with a bending radius across the entire wellbore. In the case of casing drilling, the spray hose will bend across the entire inner diameter of the production casing. Therefore, the hose contacts the production casing on one side, bends along the face of the whipstock, and then extends to the casing outlet on the opposite side of the production casing. This spray hose bending radius spanning the entire ID (inner diameter) of the production casing provides the largest possible diameter of the spray hose used, which in turn provides the maximum hydraulic horsepower to be transmitted through the spray hose to the spray nozzle.

[0053] The external system is configured such that it contains, transports, deploys, and withdraws the spray hose of the internal system in a manner that maintains the hose in a deployed state. Therefore, the minimum bend radius that the hose must meet is the bend radius in the production sleeve along the whipstock plane at the point of the desired sleeve exit. In addition, the coiled tubing-based transportation of these coordinated internal/external systems provides simultaneous operation of other conventional coiled tubing tools in the same downhole tool string. These tools include packers, mud motors, downhole (external) tractors, logging tools, and/or retrievable bridge plugs located under the whipstock components.

[0054] Returning to the method just described, the method further includes positioning the whipstock along the wellbore at the desired first casing exit location. The face of the whipstock causes the spray hose to bend substantially across the entire inner diameter of the wellbore when the spray hose is transferred out of the spray hose carrier. The method also includes transferring the spray hose out of the spray hose carrier to advance the spray nozzle to the face of the whipstock. The method then includes injecting hydraulic jet fluid through a jet hose and connected jet nozzle to dig a lateral borehole in the rock matrix in the production area.

[0055] The method further includes injecting the jet fluid while also transferring the jet hose and connected jet nozzle through the jet hose carrier and along the face of the whipstock. In this way, a first lateral borehole extending at least 5 feet from the horizontal borehole is formed.

[0056] In the present disclosure, the external system is optionally provided with a unique electrically driven rotatable jet nozzle. The nozzle can imitate the hydraulic power of a conventional hydraulic perforator, so there is no need for a milling tool to work alone to form the casing outlet. The nozzle optionally includes a backward thrust nozzle around the main body to enhance forward thrust and drill hole cleaning during the formation of the micro-branch, and to provide cleaning and possible drill hole extension during pull-out.

[0057] In the external system, the following two hydraulic pressures are (a) the hydraulic pressure of the injection fluid that pushes the internal hose system downstream and (b) the hydraulic pressure of the hydraulic fluid that pushes the hose system back upstream The adjustment of the force is controlled by the valves at the top and base of the load-bearing system, and the sealing components at the top of the spray hose and the base of the load-bearing system. In addition, the external system may include an internal tractor system that provides mechanical force to selectively push the spray hose upstream or downstream.

[0058] It has been found that known injection systems generally rely only on the "slack off" weight of the continuous coiled tubing and/or injection hose string to provide the "push" force. However, this source of propulsive force is quickly dissipated by the spiral bends in the highly directional or horizontal wellbore (for example, due to friction between the jet hose and the wellbore pipe). Once the point where the helix is bent is reached, no additional thrust can be obtained from the additional lowering of the column tied to the ground. In this paper, the combination of hydraulic pressure and mechanical (traction) force overcomes the limitation of "cannot push the rope" of other systems in a unique way, so that it can deviate from the large-displacement horizontal drilling hole to form a micro branch channel.

[0059] The hydraulic injection assembly herein can generate lateral boreholes of more than 10 feet, or more than 25 feet, or even more than 300 feet, depending on the length of the spray hose and its spray hose carrier. The length of penetration and the penetration rate itself are also affected by the anti-hydraulic jet properties of the main rock. These anti-blast properties may include the inherent compressive strength, pore pressure, cement fixation, and other characteristics of the main rock matrix. In any case, the transverse boreholes can have a diameter of about 1.0" or greater, and these transverse boreholes can be formed at a penetration rate much higher than that of any previous system. These transverse boreholes are usually used for production sets. The spray hose in the tube completes a 90° turn.

[0060] The system will have the ability to form lateral boreholes from parts of the horizontal and highly oriented main borehole that have hitherto been considered inaccessible. Wherever conventional coiled tubing can be towed in the casing borehole, lateral boreholes can now be ejected hydraulically. Likewise, ultra-high efficiency will be obtained, because multiple sections of lateral boreholes are formed from a single trip. As long as satisfactory fracturing fluid power (pumping rate and pressure) can be achieved through the coiled tubing casing annulus, the entire level of the newly drilled well can be measured without the need for fracturing plugs, sliding sleeves or falling balls The pillars are graded "perforating and fracturing".

[0061] In one embodiment, a plurality of lateral boreholes and optionally lateral micro-trench boreholes together form a network or cluster of ultra-deep perforations in the rock matrix. Operators can design such a network to optimize emission production areas. Preferably, the lateral borehole extends away from the main borehole at a normal angle or a right angle, and extends to the upper boundary or the lower boundary of the production area. You can also use other angles to use the most abundant part of the production area. In any aspect, the method can then include the production of hydrocarbons. Where multiple boreholes are formed at different orientations and at different depths from a wellbore, hydrocarbons can be produced from a network of lateral boreholes. In addition, the operator can choose to perform subsequent formation fracturing operations from the lateral drilling to further extend the SRV.

[0062] In one aspect, the geometry of lateral drilling and side micro lateral drilling is customized in the main production area. The borehole can then preferably receive a subsequent stimulation (especially hydraulic fracturing) treatment. This in turn achieves optimization of the final stimulation reservoir volume to be obtained from each pumping stage ("SRV"). During the fracturing, the operator can receive real-time geophysical data representing the effects of formation treatment and SRV formation, such as microseismic, tiltmeter, and/or environmental microseismic data. On the one hand, during the completion or re-completion of the horizontal borehole, real-time customization of the geometry of the next group of lateral boreholes can be performed before pumping the next stage.

[0063] In one embodiment, hydrocarbons are produced from the borehole for a period of time before the formation of the lateral borehole. Therefore, a novel "refracture" method is provided.

[0064] In a variant, the method includes:

[0065]-Use one or more perforating guns to form perforations in successive stages along the horizontal wellbore;

[0066] Hydraulically fracturing the rock matrix along the horizontal drilling hole through perforations in successive stages;

[0067] Perform flowback operations to at least partially remove hydraulic fluid injected in connection with hydraulic fracturing; and

[0068] Optionally, the hydrocarbon fluid is generated for a period of time before the formation of the transverse borehole.

[0069] In another alternative embodiment, the method further comprises:

[0070] After forming the first transverse borehole, withdraw the spray hose and the connected nozzle from the outlet of the first casing;

[0071]-Reorient the whipstock at the desired first position;

[0072]-Inject the hydraulic jet fluid through the jet hose and the connected nozzle, thereby forming the second casing outlet;

[0073]-Further inject the jet fluid through the jet hose and the connected nozzle, thereby excavating the rock matrix in the production area; and

[0074]-While advancing the spray hose and the connected nozzle, the spray fluid is further injected to form a second transverse borehole which also extends from the horizontal well hole from the outlet of the second casing by at least 5 foot.

[0075] In the present embodiment, each of the first lateral borehole and the second lateral borehole may have an inner diameter between 0.4 and 2.5 inches. In one aspect, the second lateral borehole is offset from the first lateral borehole by between 10 degrees and 180 degrees. The method then further includes producing hydrocarbon fluids together from the first lateral borehole and the second lateral borehole.

[0076] In another alternative embodiment, the method further comprises:

[0077] After forming the first transverse borehole, withdraw the spray hose and the connected nozzle from the outlet of the first casing;

[0078]-Withdraw the spray hose and the connected nozzle from the outlet of the first casing;

[0079]-move the whipstock to the desired second position, preferably further up the well;

[0080]-Injecting a hydraulic jet fluid through a jet hose and a connected nozzle, thereby forming a second casing outlet at the second position;

[0081]-Further inject the jet fluid through the jet hose and the connected nozzle, so as to excavate the rock matrix in the production area at the second location; and

[0082]-While advancing the spray hose and the connected nozzle, further inject the spray fluid, thereby forming a second transverse borehole which also extends at least 5 feet from the horizontal borehole along the second desired location .

[0083] In this embodiment, the first lateral borehole and the second lateral borehole may be separated by about 5 to 200 feet. Preferably, the length of each of the first lateral borehole and the second lateral borehole is at least 25 feet, and more preferably, the length is at least 100 feet.

[0084] In any of the above embodiments, the method may include injecting the fracturing fluid through the annulus formed between the outer catheter and the surrounding production casing, and injecting enough to break up the rock matrix in the production area. The pressure injects fracturing fluid into one or more lateral boreholes. The hydraulic injection assembly may also include a packer or a removable bridge plug disposed under the whipstock member, and the method may also include disposing the packer or bridge plug before injecting the fracturing fluid. Alternatively or additionally, preferably before fracturing, the acid treatment is flushed through the annular area and into the lateral borehole. Taking into account the system's ability to controllably "manipulate" the jet nozzles to delineate the path of the lateral boreholes (or "groups" of boreholes), the fracturing fluid can be more optimally "guided" and restricted to the production area.

[0085] In any of the above methods, the transfer force used to remove the spray hose from the spray hose carrier may be hydraulic pressure. The spray hose and associated spray hose carrier preferably each have a length of at least 10 feet, and more preferably, a length of at least 50 feet.

[0086] In one embodiment, the spray hose assembly further includes a main control valve. The main control valve is arranged close to the upper end of the outer duct and can move between a first position and a second position. In the first position, the main control valve will pump into the wellbore

In the second position, the main control valve introduces the hydraulic fluid pumped into the wellbore into the annular area formed between the injection hose carrier and the surrounding outer duct. The placement of the main control valve in its first position allows the operator to pump the spray fluid into the work column, through the main control valve, and against the upper seal assembly in the microannular gap, thereby pistonly pushing the spray hose in the expanded state And the connected downhole nozzle, at the same time direct the jet fluid through the nozzle. The placement of the main control valve in its second position allows the operator to pump hydraulic fluid into the working column, through the main control valve, into the annular area between the spray hose carrier and the surrounding outer duct, through the pressure regulating valve and into Micro annulus, thereby pulling the spray hose back into the inner duct in its expanded state.

[0087] In a preferred embodiment, the transfer force includes a hydraulic force and a separate mechanical force. In this case, the spray hose assembly also includes an internal tractor system located downstream of the lower end of the outer duct. The internal tractor system includes an inner duct part defining a part of the jet hose carrier for receiving the jet hose and an outer duct part defining a part of the outer duct, the outer duct part having a plurality of radially arranged prongs. A star-shaped profile, a wiring chamber that houses wires, data cables, or both in one of the plurality of prongs, and at least a pair of clamps located in the opposite prongs, wherein each clamp is configured as When being rotationally actuated, the spray hose is engaged and mechanically moves the spray hose along the spray hose carrier.

[0088] In one embodiment, the hydraulic injection assembly further includes a docking station located at the upper end of the external system. The docking station is configured to cooperate with the battery pack. The docking station has a microprocessor and communicates with operators on the ground through coiled tubing wires, data cables, or both. In this arrangement, the method may also include:

[0089]-Send commands from the ground to the docking station;

[0090]-Send data from the logging tool downstream of the whipstock to the docking station; and

[0091]-Send data from the docking station to the ground.

[0092] The docking station preferably also houses a microprocessor and a micro transmitter, a micro receiver, a current regulator, or a combination thereof. The docking station can be configured to: (1) transmit power to the battery pack, the power is from ground power generation, or from power generation through a mud turbine under the whipstock member, the power is transmitted via wires located along an external system And (2) transmitting data to or from the micro transmitter and micro receiver in the docking station between at least one geospatial chip housed at or near the nozzle and the operator on the ground. The micro transmitter housed in the battery pack is configured to wirelessly transmit data received from the micro receiver to the micro receiver housed in the docking station. The docking station is configured to also (i) wirelessly, (ii) via wires bundled in coiled tubing, or (iii) via data cables bundled in coiled tubing, to transmit data to the processor on the ground.

[0093] In one arrangement, the method further includes:

[0094]-Obtain geomechanical data for the production area, the data including porosity, permeability, Poisson's ratio, elastic modulus, shear modulus, Latin American constant, Vp/Vs or a combination thereof;

[0095]-Perform geomechanical analysis on the rock matrix in the production area to determine the direction of the minimum principal stress; and

[0096]-Use the downhole hydraulic jet assembly by (1) along the direction perpendicular to the direction of the minimum principal stress, or (ii) manipulate the nozzle along the direction parallel to the direction of the minimum principal stress, to form at least two transverse directions in the production area drilling.

[0097] In one arrangement, the longitudinal axis of the horizontal wellbore is oriented parallel to the plane of minimum principal stress of the rock matrix constituting the production area. In addition, the first transverse borehole is formed along a direction perpendicular to the minimum principal stress plane of the rock matrix. Performing a geomechanical analysis of the rock matrix may include forming a finite element grid representing the production area, wherein the grid defines a plurality of nodes representing points in space. Each point has potential displacement in more than one direction. The analysis may also involve predicting changes in the stress curve within the rock matrix due to the formation of lateral boreholes.

[0098] In another arrangement, the downhole hydraulic injection assembly and method work with the guidance system. The guiding system includes the use of at least three longitudinally oriented actuator wires connected to the distal end of the jet nozzle. The actuator wires are equally spaced around its circumference at the distal end of the spray hose, and are made of a conductive material that contracts in response to an electric current. Different amounts of current directed through the actuator wire will cause a bending moment to orient the spray nozzle in the desired direction. In this arrangement, the microprocessor is configured to control a current regulator that feeds current to the corresponding actuator wire. This in turn controls the geographic orientation of the nozzles used for directional hydraulic drilling.

[0099] In one aspect of the guidance system, the geographic location signal is sent by one or more geospatial chips located along or near the nozzle. The geographic location signal indicates the position of the nozzle, the orientation of the nozzle, or both. The geographic location signal is transmitted as data from the geospatial chip to the micro receiver in the battery pack. The signal can be sent via an electric wire or data cable bundled in a spray hose. The micro transmitter housed in the end cap of the battery pack is configured to wirelessly transmit data received from the micro receiver to the corresponding micro receiver housed in the docking station. In addition, the docking station can be configured as a processor that further transmits data to the ground. The geographic data can be sent wirelessly via wires bundled in coiled tubing or via data cables bundled in coiled tubing.

[0100] The geographic trajectory command can also be sent from a control system located on the ground or a control system in a microprocessor located in a docking station downhole. The control system sends signals to one or more current regulators to adjust the amount of current to be sent to each individual actuator wire downhole. The contraction of each actuator wire is proportional to the amount of current received by each wire. The contraction generates a bending moment, so as to realize the geological manipulation of the nozzle according to the desired trajectory. In a preferred embodiment, the bending moment applied to the distal end of the spray hose is controlled by the operator at the ground through the delivery of the geographic trajectory signal sent to the microtransmitter in the docking station.

Description of the drawings

[0101] Certain illustrations, diagrams, and/or flowcharts are attached to this document so that the present invention can be better understood. However, it should be noted that the drawings only show selected embodiments of the present invention, and therefore should not be considered as limiting the scope, because the present invention may recognize other equally effective embodiments and applications.

[0102] FIG. 1A is a cross-sectional view of an exemplary horizontal wellbore. The half-fracture plane along the horizontal strut of the wellbore is shown in 3-D to show the fracture stage and fracture orientation relative to the subterranean formation.

[0103] FIG. 1B is an enlarged view of the horizontal portion of the wellbore in FIG. 1A. Conventional perforation is replaced by ultra-deep perforation or micro lateral drilling to create crack wings.

[0104] FIG. 2 is a longitudinal cross-sectional view of a downhole hydraulic injection assembly in an embodiment of the present invention. The assembly is shown in the horizontal section of the production casing. The injection assembly has an external system and an internal system.

[0105] FIG. 3 is a longitudinal cross-sectional view of the internal system of the hydraulic injection assembly of FIG. 2. The internal system extends from the upstream battery pack end cap at its proximal end (which cooperates with the mooring station of the external system) to an elongated hose with jet nozzles at its distal end.

[0106] FIG. 3A is a cross-sectional perspective view of the battery pack section of the internal system of FIG. 3.

[0107] FIG. 3B-1 is a cross-sectional perspective view of the jet fluid inlet located between the base of the battery pack section and the jet hose. The jet fluid receiving funnel is shown as being used to receive fluid into the jet hose of the internal system in FIG. 3.

[0108] FIG. 3B-1.a is an axial cross-sectional view of the internal system of FIG. 3 taken from the top of the bottom end cap of the battery pack section.

[0109] FIGS. 3B-1.b are axial cross-sectional views of the internal system of FIG. 3 taken from the top of the jet fluid inlet.

[0110] FIG. 3C is the inner part of FIG. 3 taken from the fluid receiving funnel of the spray hose to the upper sealing assembly of the spray hose.

Cut-away perspective view of the upper part of the system.

[0111] FIG. 3D-1 presents a cross-sectional view of a bundled spray hose with wires and data cables that can be used in the internal system of FIG. 3.

[0112] FIG. 3D-1a is an axial cross-sectional view of the strapping spray hose of FIG. 3D-1.

[0113] Both electrical wires and optical fiber (or data) cables can be seen.

[0114] FIG. 3E is an expanded cross-sectional view of the end of the spray hose of FIG. 3D-1, showing the spray nozzle of the internal system of FIG. 3. The bending radius of the spray hose is shown in the cross-sectional section of the whipstock of the external system of FIG. 3.

[0115] FIGS. 3F-1a to 3G-1c present enlarged cross-sectional views of the spray hose of FIG. 3E in various embodiments.

[0116] FIG. 3F-1a is an axial cross-sectional view showing the basic nozzle body. The nozzle body includes a rotor and a surrounding stator.

[0117] FIG. 3F-1b is a longitudinal cross-sectional view of the spray nozzle taken along the line CC' of FIG. 3F-1a. Here, the nozzle uses a single discharge slot located at the tip of the rotor. The nozzle also includes a bearing between the rotor and the surrounding stator.

[0118] FIGS. 3F-1c are longitudinal cross-sectional views of the jet nozzle of FIGS. 3F-1b in a modified embodiment. Here, the spray nozzle includes a geospatial chip and is shown to be connected to the spray hose via welding.

[0119] FIGS. 3F-1d are axial cross-sectional views of the spray hose of FIGS. 3F-1c taken along line c-c'.

[0120] FIGS. 3F-2a and 3F-2b present longitudinal cross-sectional views of the nozzle of FIG. 3E in an alternative embodiment. Five backward thrust nozzles are placed in the main body of the stator along with a single discharge slot at the tip of the rotor, actuated by forward displacement of the slidable nozzle throat bushing against the slidable collar and biasing mechanism.

[0121] In Figures 3F-2a, the bushing and collar are in their closed position. In Figure 3F-2b, the bushing and collar are in their open position, allowing fluid to flow through the backward thrust nozzle. When enough pumping pressure overcomes the resistance of the spring, the spout opens.

[0122] FIGS. 3F-2c are axial cross-sectional views of the nozzle of FIGS. 3F-2a. Five backward thrust nozzles are shown for generating backward thrust.

[0123] FIGS. 3F-3a and 3F-3c provide longitudinal cross-sectional views of the jet nozzle of FIG. 3E in another alternative embodiment. Here, multiple backward thrust nozzles located in both the stator body and the rotor body are used. In this arrangement, pulling the electromagnetic force on the magnetic collar biased by the spring is used to open/close the backward thrust nozzle.

[0124] In Figures 3F-3a, the collar of the jet nozzle is in its closed position. In Figure 3F-2b, the collar is in its open position, allowing fluid to flow through the backward thrust nozzle.

[0125] FIGS. 3F-3b and 3F-3d show axial cross-sectional views of the jet nozzles associated with FIGS. 3F-3a and 3F-3c, respectively. See that there are eight backward thrust nozzles. This embodiment provides intermittent alignment of the four injection ports in the rotor with any one of the two sets of four injection ports in the stator to generate a pulsed backward thrust flow.

[0126] FIG. 3G-1a is an axial cross-sectional view showing a base collar body for a spray collar that can be placed within a length of a spray hose. The collar body also includes the rotor and surrounding stator. This view is taken along the line D-D' of Figure 3G-1b.

[0127] FIG. 3G-1b is a longitudinal cross-sectional view of the injection collar of FIG. 3G-1a. Like the jet nozzles of FIGS. 3F-3a to 3F-3d, the two sets of four jet ports in the stator are intermittently aligned with the four jet ports in the rotor to generate a pulsed backward thrust flow.

[0128] FIG. 3G-1c is an axial cross-sectional view of the jet nozzle of FIG. 3G-1b taken along the line d-d'.

[0129] FIG. 4 is a longitudinal cross-sectional view of the external system of the downhole hydraulic injection assembly of FIG. 2 in one embodiment. The external system is located in the production casing of the horizontal struts of the wellbore in FIG. 2.

[0130] FIG. 4A-1. It is the transport of bundled coiled tubing that transports the external system of FIG. 4 into and out of the wellbore

An enlarged longitudinal cross-sectional view of a part of the medium.

[0131] FIG. 4A-1a is an axial cross-sectional view of the coiled tubing conveying medium of FIG. 4A-1. In this embodiment, the inner coiled tubing, along with both the electrical wires and the data cables, are concentrically "bundled" within the protective outer layer.

[0132] FIG. 4A-2 is another axial cross-sectional view of the coiled tubing transport medium of FIG. 4A-1a in different embodiments. Here, the inner coiled tubing is eccentrically "bundled" in the protective outer layer to provide more evenly spaced protection for wires and data cables.

[0133] FIG. 4B-1 is a longitudinal cross-sectional view of a crossover connection (crossover connection), which is the uppermost member of the external system of FIG. 4. The cross section is configured to connect the coiled tubing transport medium of Figure 4A-1 to the main control valve.

[0134] FIG. 4B-1a is an enlarged perspective view of the cross-connector of FIG. 4B-1 seen between sections E-E' and F-F'. This view highlights the general transition of the cross-sectional shape of the wiring chamber from circular to oval.

[0135] FIG. 4C-1 is a longitudinal cross-sectional view of the main control valve of the external system of FIG. 4.

[0136] FIG. 4C-1a is a cross-sectional view of the main control valve taken along the line G-G' of FIG. 4C-1.

[0137] FIG. 4C-1b is a perspective view of the sealing passage cover of the main control valve exploded from 4C-1a.

[0138] FIG. 4D-1 is a longitudinal cross-sectional view of the spray hose carrying section of the external system of FIG. 4. The jet hose carrying section is attached downstream of the main control valve.

[0139] FIG. 4D-1a shows an axial cross-sectional view of the main body of the spray hose carrying section taken along the line H-H' of FIG. 4D-1.

[0140] FIG. 4D-1b is an enlarged view of a portion of the jet hose carrying section of FIG. 4D-1. See the mooring station of the external system more clearly.

[0141] FIG. 4D-2 is an enlarged longitudinal cross-sectional view of the spray hose carrying section of the outer system of FIG. 4D-1 with the spray hose from the inner system of FIG. 3.

[0142] Figures 4D-2a provide an axial cross-sectional view of the jet hose carrying section of Figure 4D-1 with the jet hose located therein.

[0143] FIG. 4E-1 is a longitudinal cross-sectional view of a selected portion of the external system of FIG. 4. You can see the jet hose packing section and the outer body of the transition piece from the front circular body (I-I') of the jet hose carrying section to the star body (J-J') of the jet hose packing section .

[0144] FIG. 4E-1a is an enlarged perspective view of the transition piece between the lines II' and J-J' of FIG. 4E-1.

[0145] FIG. 4E-2 shows an enlarged view of a portion of a spray hose packing section. The inner seal of the packer conforms to the outer circumference of the spray hose (Figure 3) located in it. The pressure regulating valve is shown schematically as being located near the isolation section.

[0146] FIG. 4F-1 is another downstream longitudinal cross-sectional view of the external system of FIG. 4. The jet hose packing section and the outer body transition piece from Figure 4E-1 are again shown. The internal tractor system can also be seen here. Note that each of the aforementioned components is shown in a longitudinal cross-sectional view with the spray hose of FIG. 3 located therein.

[0147] FIG. 4F-2 is an enlarged longitudinal cross-sectional view of a portion of the internal tractor system of FIG. 4F-1, again with a cross-section of the spray hose located therein. The internal motor, gear and clamp assembly are also shown.

[0148] FIG. 4F-2a is an axial cross-sectional view of the internal tractor system of FIG. 4F-2 taken along the line K-K' of FIGS. 4F-1 and 4F-2.

[0149] FIG. 4F-2b is an enlarged half view of a portion of the internal tractor system of FIG. 4F-2a.

[0150] FIG. 4G-1 is another downstream longitudinal cross-sectional view of the external system of FIG. 4. This view shows the transition from the internal tractor to the upper swivel, which is followed by the upper swivel of the outer system.

[0151] FIG. 4G-1a depicts a perspective view of the transition of the inner tractor system to the outer body between the upper swivel. This is the transition of the outer body from star (L-L') to round (M-M').

[0152] FIG. 4G-1b provides an axial cross-sectional view of the upper swivel of FIG. 4-G1 taken along the line N-N'.

[0153] FIG. 4H-1 is a cross-sectional view of the whipstock member of the external system of FIG. 4 shown vertically rather than horizontally. The spray hose of the internal system (Figure 3) is shown bent across the whipstock and extending through a window in the production casing. The spray nozzle of the internal system is shown attached to the distal end of the spray hose.

[0154] FIG. 4H-1a is an axial cross-sectional view of the whipstock member, in which the perspective view of the continuous axial spray hose section depicts the spray hose from the center of the whipstock member down to the jet at the line O-O' The path at the beginning of the bending radius when the hose approaches the line P-P'.

[0155] FIG. 4H-1b depicts an axial cross-sectional view of the whipstock member at the line P-P'.

[0156] FIG. 4I-1 is an axial cross-sectional view of the bottom swivel in the outer system of FIG. 4, just downstream of the slide near the base of the front whipstock member (shown as engaging the surrounding production sleeve) .

[0157] FIG. 4I-1a provides an axial cross-sectional view of a portion of the bottom swivel of FIG. 4I-1 taken along the line Q-Q'.

[0158] FIG. 4J is another longitudinal view of the bottom swivel of FIG. 4I-1. Here, the bottom swivel is connected to a transition section, which in turn is connected to a conventional mud motor, an external tractor, and a logging probe, thereby completing the entire downhole tool string. For simplicity, the construction does not include packers or retrievable bridge plugs.

Detailed ways

[0159] Definition

[0160] The term "hydrocarbon" as used herein refers to an organic compound that mainly (but not exclusively) includes the element hydrogen and carbon. Hydrocarbons are generally divided into two categories: aliphatic hydrocarbons or linear hydrocarbons, and cyclic hydrocarbons or closed-ring hydrocarbons, including cyclic terpenes. Examples of hydrocarbon-containing materials include any form of natural gas, oil, coal, and bitumen that can be used as fuel or can be upgraded to fuel.

[0161] The term "hydrocarbon fluid" as used herein refers to a hydrocarbon or a mixture of hydrocarbons that is a gas or liquid. For example, hydrocarbon fluids can include hydrocarbons or mixtures of hydrocarbons that are gas or liquid under formation conditions, processing conditions, or ambient conditions. Hydrocarbon fluids may include, for example, oil, natural gas, condensate, coalbed methane, shale oil, shale gas, and other hydrocarbons in gaseous or liquid state.

[0162] As used herein, the term "fluid" refers to gas, liquid, and combination of gas and liquid, and also refers to combination of gas and solid, and combination of liquid and solid.

[0163] As used herein, the term "underground" refers to a geological formation that occurs below the surface of the earth.

[0164] The term "subterranean interval" refers to a formation or part of a formation where formation fluids may be present. The fluid may be, for example, a hydrocarbon liquid, a hydrocarbon gas, a water fluid, or a combination thereof.

[0165] The term "zone" or "target zone" refers to a portion of a formation that contains hydrocarbons. Sometimes, the terms "target area", "production area" or "segment" may be used.

[0166] The term "drill hole" as used herein refers to a hole formed in the ground by drilling or inserting a pipe into the ground. The wellbore may have a substantially circular cross-section or other cross-sectional shape. When referring to an opening in a formation, the term "well" as used herein can be used interchangeably with the term "wellbore."

[0167] The term "jet fluid" refers to any fluid that is pumped through a jet hose and nozzle assembly for the purpose of erosionally drilling a lateral borehole from an existing main wellbore. The jet fluid may or may not contain abrasive materials.

[0168] The term "abrasive material" or "abrasive" refers to small solid particles mixed with or suspended in the jet fluid to enhance the penetration of the following erosion: (1) production area; and/or (2) production Cement between the casing and the production area; and/or (3) the wall of the production casing at the desired exit point of the casing.

[0169] The term "tubular member" or "tubular member" refers to any pipe, such as a coupling of a casing, a portion of a lining, a coupling of a tubing, a short drill pipe, or a coiled tubing.

[0170] The term "lateral drilling" or "micro branch canal" or "ultra-deep perforation" "UDP") refers to the formation in the subterranean formation usually when leaving the production casing in the main wellbore and the surrounding cement sheath The borehole, wherein the borehole is formed in a known or potential production area. For the purpose of this article, using jet fluid directed through the jet hose and out of the jet nozzle attached to the end of the jet hose, the hydraulic jet force erodes the drilling through the production area, thus forming a UDP. Preferably, each UDP will have a substantially normal trajectory relative to the main wellbore.

[0171] The term "steerable" or "guided" when applied to a hydraulic injection assembly refers to a part of the injection assembly that can be directed and controlled by the operator when the injection assembly is running (usually, injection nozzles and / Or the part of the spray hose next to the nozzle). This ability to direct and then redirect the orientation of the jet assembly during erosion excavation can form a UDP with one, two, or three sizes of directional components as needed.

[0172] The term "perforation cluster" or "UDP cluster" refers to a set of designed lateral boreholes that are branched from the main well casing. These groups are ideally designed to receive and transmit specific "levels" of stimulation treatment through hydraulic fracturing (or "fracking"), usually during the completion or re-completion of horizontal wells.

[0173] The term "stage" refers to a discrete part of a stimulation treatment applied to completion or recompletion of a specific production area or a specific part of a production area. In the case of casing horizontal main wells, up to 10, 20, 50 or more levels can be applied to their respective perforation (or UDP) groups. Usually, this requires some form of zonal isolation before pumping each stage.

[0174] The term "contour" or "contouring" applied to a single UDP or UDP group in a "group" refers to the steerable excavation of a lateral borehole in order to optimally receive, guide and control a given Stimulation (usually, fracturing) level of stimulation fluid or fluid and proppant. This... the ability to optimally receive, direct and control..." a given level of stimulation fluid is designed to keep the resulting stimulation geometry "in the zone" and/or to focus the stimulation effect when desired The result is optimized and usually maximized stimulation reservoir volume ("SRV").

[0175] "Real-time" or "real-time analysis" of geophysical data (such as microseismic, inclinometer, and or environmental microseismic data) obtained during the pumping stimulation (such as fracturing) processing stage, these two terms refer to The results of the data analysis can be applied to: (1) change the pumping rate, processing pressure, fluid rheology and proppant concentration of the remaining part of the stimulation treatment (still to be pumped) in order to optimize its benefits; and (2) Optimize the placement of the perforation in the subsequent "group" or the contour setting of the UDP trajectory to optimize the SRV obtained from the subsequent stimulation stage.

[0176] Description of specific embodiments

[0177] Provided herein is a downhole hydraulic injection assembly. The jet assembly is designed to direct jet nozzles and connected hydraulic hoses through a window formed along the production casing string, and then "jet" one or more boreholes outward into the underground formation. Horizontal drilling essentially means an ultra-deep perforation formed by using hydraulic pressure directed through a flexible high-pressure jet hose attached with a high-pressure jet nozzle at the distal end. The body assembly utilizes a single hose and nozzle device to continuously eject both the optional casing outlet and subsequent lateral drilling.

[0178] FIG. 1A is a schematic depiction of a horizontal well 4, in which the wellhead device 5 is located above the surface 1, and the horizontal well penetrates several series of subterranean formations 2a to 2h before reaching the production area 3. The horizontal section 4c of the well 4 is depicted between the "post heel" 4b and the "post toe" 4d. The surface casing 6 is shown as being completely cemented from the surface casing shoe 8 back to the ground 1 while the middle casing

CN 107429552 Β

The post 9 is only partially cemented 10 from its shoe 11. Similarly, although the production casing string 12 is only partially cemented 13 from its casing shoe 14, the production area 3 is sufficiently isolated. Note how in the typical horizontal wellbore depicted in FIG. 1A, the conventional perforations 15 in the production casing 12 are shown in pairs up and down, and are depicted as having a subsequent hydraulic fracturing half-plane (or "fracture wing") 16. [0179] FIG. 1B is an enlarged view of the lower part of the wellbore 4 of FIG. 1A. Here, the horizontal section 4c between the column heel part 4b and the column toe part 4d can be seen more clearly. In this depiction, the application of the subject equipment and method here replaces the conventional perforation (15 in FIG. 1A) with a pair of relatively horizontal UDP 15 as depicted in FIG. 1B, and also has a fracture half-plane 16 formed subsequently. What is specifically depicted in FIG. 1B is how the fracture wing 16 is now better confined within the production area 3, while at the same time extending significantly further into the production area 3 from the horizontal well 4c. In other words, the pre-existence of UDP 15 formed by the components and methods disclosed herein significantly enhances the crack perforation in the zone.

[0180] FIG. 2 provides a longitudinal cross-sectional view of the downhole hydraulic injection assembly 50 of the present invention in one embodiment. The injection assembly 50 is shown as being located within the production casing string 12. The production sleeve 12 may have an OD (4.0 inch ID) of 4.5 inches, for example. The production casing 12 appears along the horizontal part 4c of the wellbore 4. As shown in conjunction with Figures 1A and 1B, the horizontal portion 4c defines the column heel portion 4b and the column toe portion 4d.

[0181] The injection assembly 50 generally includes an internal system 1500 and an external system 2000. The jet assembly 50 is designed to protrude into the wellbore 4 at the end of a working column (sometimes referred to herein as a "transport medium"). Preferably, the working column is a coiled tubing string 100. The transport medium 100 may be conventional coiled tubing. Alternatively, a "strapping" product may be used, which includes a conductive wire surrounding the coiled tubing core and a data conductive cable (such as an optical fiber), the conductive wire and the data conductive cable are made of an anti-corrosion/abrasion outer layer such as PFE and/or Kevlar protection, or even protection by another (outer) coiled tubing string. The fiber optic cable was found to have an almost negligible diameter and was proven by the oil field to be effective in providing direct, real-time data transmission and communication with downhole tools. Other emerging transmission media such as carbon nanofibers can also be used.

[0182] Other transport media may be used for the spray assembly 50. These include, for example, standard electric coil systems, custom FlatPAK® components, PUMPTEK® flexible polymer steel pipe ("FSPT") or flexible pipeline ("FTC") tubing. Alternatively, the tubing has PTFE (polytetrafluoroethylene) and a Kevlar®-based material, or the Draka Cableteq USA, Inc® tubing sealing line ("TEC") system can be used. In any case, it is desirable for the transport medium 100 to be flexible, somewhat malleable, non-conductive, pressure-resistant (to withstand the high-pressure fracturing fluid that is optionally pumped down into the annulus), heat-resistant (To withstand the operating temperature of the bottom hole well, usually over 200°F, and sometimes over 300°F), chemical resistant (at least resistant to additives included in the fracturing fluid), friction resistant ( Reduce downhole pressure loss due to friction during pumping fracturing treatment), corrosion-resistant (to withstand the erosion effect of the aforementioned annular fracturing fluid) and anti-abrasion (to withstand the support suspended in the aforementioned annular fracturing fluid) The abrasive effect of the agent).

[0183] If a standard coiled tubing string is used, communication and data transmission can be completed by underwater pulse technology (or so-called mud pulse telemetry technology), acoustic telemetry technology, EM telemetry technology or some other remote transmission/reception system. Similarly, the electricity used to operate the equipment can be generated downhole by conventional mud motors, which will allow the circuit for the system to be limited below the end of the coiled tubing. The hydraulic injection assembly 50 is not limited by the data transmission system or the power transmission or transportation medium used, unless it is clearly stated as such in the claims.

[0184] It is preferable to maintain the outer diameter of the coiled tubing 100 to leave a cross-sectional area greater than or equal to the flow opening to the 3.5" 0.D. fracturing (tubing) string in the casing 12 with an ID of about 4.0". Ring area. This is because, in the preferred method (after spraying one or more (preferably two) relatively small branch canals or even specific profiled small diameter transverse drilling "groups"), the medium is transported along the coiled tubing 100 plus the downward annulus between the external system 2000 and the well casing 12 can immediately (after repositioning the tool string toward the wellhead) fracturing stimulation occurs. For 9.2#, 3.5" 0.D. tubing

(Ie, fracturing column equivalent), the ID is 2.992 inches, and the cross-sectional area open to the flow is 7.0309 square inches. According to the same 7.0309in²Calculate the maximum OD for both the coiled tubing transport medium 100 and the 2.655" external system 2000 (with a roughly circular cross-section) produced equally. Of course, a smaller OD can be used for one of them, as long as this can accommodate Spray hose 1595.

[0185] In the view of FIG. 2, the assembly 50 is in the operating position, in which the spray hose 1595 extends through the whipstock 1000, and the spray nozzle 1600 passes through the first window "W" of the production sleeve 12. At the end of the jet assembly 50 and below the whipstock 1000 are several optional components. These components include a conventional mud motor 1300, an external (conventional) tractor 1350, and a logging probe 1400. These components are shown and described more fully in conjunction with FIG. 4.

[0186] FIG. 3 is a longitudinal cross-sectional view of the internal system 1500 of the hydraulic injection assembly 50 of FIG. 2. The internal system 1500 is a steerable system that can move within the external system 2000 and extend to the outside when in operation. The internal system 1500 is mainly composed of the following items:

[0187] (1) Power and geological control components;

[0188] (2) Jet fluid introduction port;

[0189] (3) Spray hose 1595; and

[0190] Jet nozzle 1600.

[0191] The internal system 1500 is designed to be housed in the external system 2000 while being transported in and out of the main well 4 by the coiled tubing transport medium 100 and the attached external system 2000. The extension and retraction of the internal system 1500 from the external system 2000 is accomplished by applying the following items: (a) hydraulic pressure; (b) mechanical force; or (c) a combination of hydraulic pressure and mechanical force. It is beneficial to the design of the hydraulic spraying device 50 composed of the internal system 1500 and the external system 2000 to transport, deploy or withdraw the spray hose 1595, and it is never necessary to coil the spray hose. Specifically, the spray hose 1595 never experiences a bending radius smaller than the ID of the production casing 12, and only increments when pushed along the whipstock 1050 of the spray hose whipstock member 1000 of the external system 2000. Note that the spray hose 1595 is usually 1/4" to 5/8" of the ID of a flexible tubing that can withstand high internal pressure, up to about 1" OD.

[0192] The internal system 1500 first includes a battery pack 1510. FIG. 3A provides a cut-away perspective view of the battery pack 1510 of the internal system 1500 of FIG. 3. Note that for the purpose of illustration, this section 1510 is rotated 90° from the horizontal view of FIG. 3 to a vertical orientation. The individual AA batteries 1551 are shown as a series of end-to-end batteries forming a battery pack 1550. The protection of the battery 1551 is mainly performed via a battery pack case 1540, which is sealed by an upstream battery pack end cover 1520 and a downstream battery pack end cover 1530. These components (1540, 1520, and 1530) present external faces that are exposed to the high-pressure jet of fluid. Therefore, they are preferably constructed or coated with non-conductive, highly abrasion/erosion/corrosive materials.

[0193] The upstream battery pack end cap 1520 has a conductive ring around a portion of its circumference. When the internal system 1500 is "plugged in" (ie, cooperatively received into the mooring station 325 of the external system 2000), the battery pack end cap 1520 can receive and transmit current, and thus recharge the battery pack 1550. Also note that the size of the end caps 1520 and 1530 can be set to house and protect any server, microchip, circuit, geospatial or transmitter/receiver components within.

[0194] The battery pack end caps 1520, 1530 may be threadedly attached to the battery pack case 1540. The battery pack end caps 1520, 1530 may be constructed of high-pressure materials (such as titanium) that are highly resistant to corrosion and abrasion, and even protected by thin highly corrosion-resistant or corrosion-resistant coatings (such as polycrystalline diamond). The shape and configuration of the end caps 1520, 1530 are preferably such that they can divert the flow of the high-pressure jet fluid to abrasion without causing significant abrasion. The upstream end cap 1520 must divert the flow to the annular space between the battery sleeve 1540 and the surrounding jet hose conduit 420 (visible in Figure 3C) of the jet hose carrying system (shown as 400 in Figure 4D-1) (Not shown in Figure 3). The downstream end cap 1530 abuts from the annular space by jetting fluid

The collection (or "introduction") funnel (shown as 1570 in FIG. 3B-1) down enters a portion of the flow path of the spray fluid in the ID of the spray hose 1595 itself.

[0195] Therefore, the path of the high-pressure hydraulic injection fluid (with or without abrasive) is as follows:

[0196] (1) The injection fluid is discharged from the high-pressure pump at the ground level 1, and downward along the ID of the coiled tubing conveying medium 100, and the injection fluid enters the external system 2000 at the end of the coiled tubing conveying medium;

[0197] (2) The injection fluid enters the external system 2000 through the coiled tubing transition piece 200;

[0198] (3) The injection fluid enters the main control valve 300 through the injection fluid passage 345;

[0199] (4) Since the main control valve 300 is positioned to receive the injection fluid (as opposed to the hydraulic fluid), the sealing passage cover 320 will be positioned to seal the hydraulic fluid passage 340, leaving the only available fluid path through the injection fluid passage 345, The discharge end of the jet fluid channel is hermetically connected to the jet hose conduit 420 of the jet hose carrying system 400;

[0200] (5) When entering the spray hose pipe 420, the sprayed fluid will first pass through the annulus between the mooring station 325 and the spray hose pipe 420 and pass through the mooring station 325 (attached to the spray hose pipe 420). Inside);

[0201] Since the spray hose 1595 itself is located in the spray hose conduit 420, the high-pressure spray fluid must now pass or bypass the spray hose 1595; and

[0202] (7) Due to the seal 1580U of the internal system 1500 that seals the annulus between the spray hose 1595 and the spray hose conduit 420, the spray fluid cannot bypass the spray hose 1595 (note this type of seal on the seal assembly 1580). The hydraulic pressure is the force that tends to pump the internal system 1500 and therefore the spray hose 1595 "downhole"), so the spray fluid is forced to follow the following path through the spray hose 1595:

[0203] (a) The jetted fluid first passes through the top of the internal system 1500 at the upstream battery pack end cover 1520;

[0204] (b) The fluid is then sprayed through the battery pack case 1540 and the spray hose conduit of the spray hose carrying system 400

Annular gap between 420;

[0205] (c) After the ejected fluid passes through the downstream battery pack end cap 1530, it is forced to flow between the battery pack supporting ducts 1560 and into the ejected fluid receiving funnel 1570;

[0206] and

[0207] (d) Since the ejection fluid receiving funnel 1570 is rigidly and sealingly connected to the ejection hose 1595, the fluid is forced to enter the ID of the ejection hose 1595.

[0208] What is worth noting in the above-mentioned jet flow sequence is the following starting conditions:

[0209] (i) The internal tractor system 700 is first engaged to move the discrete length of the spray hose 1595 in the downstream direction, so that the spray nozzle 1600 and the spray hose 1595 enter the spray hose whipstock 1000, and specifically, at After traveling a fixed distance inside the inner wall (shown at 1020 in Figure 4H-1), it is forced radially outward to first engage the inner wall of the production sleeve 12, and then engage the upper curved surface 1050.1 of the whipstock member 1050. at this time,

[0210] (ii) The spray hose 1595 is curvilinearly "bent" approximately 90°, forming its predefined bending radius (shown at 1599 in FIG. 4H-1) and directing the spray nozzle 1600 attached to its end to engage The exact point of the desired casing outlet "W" within the ID of the production casing 12; just at this time

[0211] (iii) Then the torque of the clamp assembly 750 in the internal tractor system 700 is increased, and the signal about this is immediately electronically transported to the ground, and the operator is notified to close the clamp (see schematic diagram at 756 in FIG. 4F-2b). Fixture) rotation.

[0212] (In fact, this closure can be pre-programmed into the operating system at a certain torque level.) It should be noted that during stage (1) to stage (iii), the pressure regulating valve (see at 610 in Figure 4E-2) To) is in the "open" position. This allows the hydraulic fluid in the annulus between the spray hose 1595 and the surrounding hose conduit 420 to drain. Once the tip of the jet nozzle 1600

End joint ID (casing wall) of production casing 12, then the operator can:

[0213] (iv) Reverse the direction of rotation of the clamp 756 to move the spray hose 1595 back into the spray hose (or inner) duct 420; and

[0214] (v) Open the main control valve 300 to start pumping hydraulic fluid through the hydraulic fluid passage 340, down the conduit carrier annulus 440, through the pressure regulating valve 610, and into the spray hose 1595/spray soft The pipe conduit 420 annulus 1595.420 is used to: (1) pump up the lower seal 1580L of the sealing assembly 1580 of the spray hose to extend the spray hose 1595 to the teaching position; and (2) help (now Position the internal system 1500 for the inverted) clamp assembly 750 so that the spray nozzle 1600 has a desired reference distance (preferably less than 1 inch) between itself and the ID of the production casing 12 to start spraying the casing Exit.

[0215] When the desired reference distance is reached, the rotation of the clamp 756 is stopped, and the pressure regulating valve 610 is closed to lock the internal system in the desired fixed position for spraying the sleeve outlet "W".

[0216] Referring back to FIG. 3A, in one embodiment, the interior of the downstream end cap 1530 houses a micro geosteering system. The system may include a micro transmitter, a micro receiver, a microprocessor, and one or more current regulators. The geosteering system is electrically or optically connected to a small geospatial IC chip located in the body of the jet nozzle 1600 (shown at 1670 in Figure 3F-1c and discussed more fully below). In this way, the nozzle orientation data can be sent from the jet nozzle 1600 to the microprocessor (or a suitable control system), and the geospatial data combined with the scattered hose length value can be used to calculate the precise geographic location of the nozzle at any point, and Therefore, the contour of the UDP path is calculated. Conversely, a geosteering signal can be sent from a control system (such as a microprocessor in a mooring station or on the ground) to modify along (at least three) actuator lines through one or more current regulators (Figure 3F-1c). Shown in 1590A) each of the individual current strength downwards, so reorient the nozzles as needed.

[0217] The geosteering system can also be used to control the rotation speed of the rotor body in the jet nozzle 1600. As will be described more fully below, the rotating nozzle structure utilizes the rotor portion 1620 of the miniature direct drive motor assembly to also form the throat and end discharge groove 1640 of the rotating nozzle itself. Rotation is induced by the electromagnetic force of the rotor/stator structure. In this way, the rotation speed can be adjusted to be proportional to the current supplied to the stator.

[0218] As depicted in FIGS. 3F-1 to 3F-3, the upstream portion of the rotor (a quadrupole rotor in this depiction) 1620 includes an approximately cylindrical inner diameter (the ID is actually slightly from the fluid inlet to the discharge groove). Reduced to further accelerate the fluid before it enters the discharge slot), the inner diameter provides a flow channel for the injected fluid through the center of the rotor 1620. This approximately cylindrical flow channel then transitions into the shape of the discharge groove 1640 of the nozzle 1600 at its distal downstream end. This is possible because instead of a typical shaft and bearing assembly that is inserted longitudinally through the central diameter of the rotor 1620, the rotor 1620 is stable and positioned to pass around the interior of the upstream flat end and outside the flow channel ("nozzle throat") 1650 The single set of bearings 1630 located radially outside rotates in balance around the longitudinal axis of the rotor 1620 so that the bearings 1630 stabilize the rotor 1620 in both the longitudinal and axial directions.

[0219] Referring now to FIG. 3B-1a, and discussing the internal system 1500 again, a cross-sectional view of the battery pack section 1510 taken along the line AAof FIG. 3B-1 is shown. This view is taken from the top of the bottom end cap 1530 of the battery pack 1510 in the ejection fluid receiving funnel 1570 looking down. In this figure, three wires 1590 extending from the battery pack 1510 can be seen. Using these wires 1590, power is sent from the "AA" size lithium battery 1551 to the geosteering system used to control the rotating jet nozzle 1600. By adjusting the current through the wire 1590, the geosteering system controls the rotation rate of the rotor 1620 and its orientation.

[0220] Note that since the longitudinal axis of the discharge flow of the nozzle is designed to be continuous with and aligned with the longitudinal axis of the nozzle throat, the thrust of the outlet jet fluid does not actually act on the nozzle. That is, because the nozzle is designed to operate in an axial "balanced" condition, the torsional moment required to actually rotate the nozzle around its longitudinal axis is

Quite small. Similarly, since the rotational speed (RPM) required for rotary excavation is relatively low, the electromagnetic force required for the rotor/stator interaction of the nozzle is also relatively small.

[0221] It is noted from FIG. 3 that the spray nozzle 1600 is located at the far downstream end of the spray hose 1595. Although the diameters of the components of the internal system 1500 must meet some fairly stringent diameter restrictions, the individual length of each component (except for the jet nozzle 1600, and if desired, in addition to one or more jet collars) is usually limited. many. This is because the spray nozzle 1600 and the collar are just components attached to the spray hose 1595, and will generally form a bend of approximately 90° as directed by the whipstock surface 1050.1. All other components of the internal system 1500 will always be located somewhere within the jet hose carrier system 400 above the jet hose packer section 600 (discussed below).

[0222] The length of many components can also be adjusted. For example, although the battery pack 1510 in FIG. 3A is depicted as accommodating six AA batteries 1551, a larger number of batteries can be easily accommodated by simply constructing a longer battery pack case 1540. Similarly, the battery pack end caps 1520, 1530, the support column 1560, and the fluid introduction funnel 1570 can also be greatly elongated to meet the fluid flow and power requirements.

[0223] Referring again to the mooring station 325, the mooring station 325 is used as a physical "stop", and the internal system 1500 of the mooring station is no longer allowed to travel upward. Specifically, the restriction of the internal system 1500 (mainly including the spray hose 1595) upstream is that the upstream battery pack end cap 1520 is inserted (or "plugged") at the point within the bottom conical socket 328 of the mooring station 325. The socket 328 is used as a lower end cover. The socket 328 provides mating conductive contacts that are aligned with the upstream battery pack end cap 1520 to form a plug-in point. In this way, data and/or power (specifically, to recharge the battery 1551) can be transmitted when "plugged in". [0224] The mooring station 325 also has a conical end cap 323 at the upstream (proximal) end of the mooring station 325. The conical shape is used to minimize erosion effects by diverting the flow of jet fluid around its body, thereby helping to protect the system components housed in the mooring station 325. Depending on the desired guidance, steering, and communication capabilities, the upper part 323 of the mooring station 325 can accommodate a pair of systems designed to communicate directly with the internal system 1500 (in a continuous real-time manner or only discretely when docked. Way) servo, transmission and receiving circuit and electronic system. Note that, as shown in FIG. 3, the OD of the cylindrical mooring station 325 is approximately equal to the OD of the spray hose 1595.

[0225] The internal system 1500 also includes a jet fluid receiving funnel 1570. FIG. 3B-1 includes a cut-away perspective view of the jet fluid receiving funnel 1570, with an axial cross-sectional view along BB' as shown in FIG. 3B-1b. The jet fluid receiving funnel 1570 is located below the base of the battery pack section 1510, as shown and described above in connection with FIG. 3A. As the name implies, the spray fluid receiving funnel 1570 is used to introduce the spray fluid into the spray hose 1595 during the formation process of the casing outlet and the micro branch channel. Specifically, the circular flow of the jet fluid (eg, flowing through the battery pack case 1540 and then through the battery pack end cover 1530 and into the ID inside the jet hose duct 420) is forced to transition between the three battery pack support ducts 1560 Because the upper seal (seen at 1580U in Figure 3) prevents any fluid flowing along the path outside the spray hose 1595. Therefore, all the flow of the jet fluid (as opposed to the hydraulic fluid) is forced between the ducts 1560 and flows into the fluid receiving funnel 1570.

[0226] In the design of FIG. 3B-1, three columnar supports 1560 are used to accommodate wires 1590. The columnar support 1560 also provides an area open to fluid flow. The interval between the supports 1560 is designed to be significantly larger than the interval provided by the ID of the spray hose 1595. At the same time, the supporting member 1560 has an ID large enough to accommodate and protect the wire 1590 up to AWG#5. The columnar support 1560 also supports the battery pack 1510 at a certain distance above the spray fluid introduction funnel 1570 and the spray hose sealing assembly 1580. The support 1560 may be sealed with a sealing end cap 1562 such that the removal of the end cap 1562 provides access to the wires 1590.

[0227] FIGS. 3B-1b provide a second axial cross-sectional view of the fluid introduction funnel 1570. The view is along the line B31 of Figure 3B-1

B'intercepted. Three columnar supports 1560 are also seen. This view is taken at the top of the ejection fluid inlet or receiving funnel 1570.

[0228] Downstream of the spray fluid receiving funnel 1570 is a spray hose sealing assembly 1580. 3C is a cut-away perspective view of the sealing assembly 1580. In the view of FIG. 3C, the columnar support member 1560 and the wires 1590 have been removed for clarity. However, a receiving funnel 1570 is also seen at the upper end of the sealing assembly 1580.

[0229] The upper end of the spray hose 1595 can also be seen in FIG. 3C. The spray hose 1595 has the outermost spray hose wrap OD1595.3 (also visible in Figure 3D-1a), and the outermost spray hose wrap can be joined to the spray hose conduit 420 at multiple points. A micro-annular gap 1595.420 is formed between the spray hose 1595 and the surrounding tube 420 (shown in Figure 3D-1 and Figure 3D-1a). The spray hose 1 595 also has a core (OD1 595.2, ID1595.1) that transports the spray fluid during the spraying operation. The spray hose 1595 is firmly connected to the sealing assembly 1580, which means that when the spray hose is pushed into the micro branch channel, the sealing assembly 1580 moves together with the spray hose 1595.

[0230] As previously described, the upper seal 1580U (shown as a solid portion with a slightly upwardly recessed upper surface) of the sealing assembly 1580 of the spray hose prevents any continuous spray fluid downstream from flowing out of the spray hose 1595. Similarly, the lower seal 1580L (shown as a series of downwardly recessed cup surfaces) of the seal assembly 1580 prevents any upstream flow of hydraulic fluid from below. Note how any hydraulic pressure from upstream to downstream of the jet fluid will tend to expand the jet fluid into the funnel 1570 and thus push the upper seal 1580U of the seal assembly 1580 radially outward to sealingly engage the jet hose carrier The (inner) jet hose duct 42 0 ID420.1. Similarly, any downstream to upstream hydraulic pressure from the hydraulic fluid radially expands to make the bottom cup surface of the lower seal 1580L to sealingly engage the ID420.1 of the inner duct 420 of the spray hose carrier. Therefore, when the injection fluid pressure is greater than the captured hydraulic fluid pressure, the imbalance will tend to "pump" the entire assembly "downhole." Conversely, when the pressure imbalance is reversed, the hydraulic fluid pressure will tend to "pump" the entire seal assembly 1580 and the connected hose 1595 back "uphole."

[0231] Returning to FIGS. 2 and 3, the upper seal 1580U provides an upstream pressure and a fluid tight connection for the internal system 1500 to the external system 2000. (Similarly, as will be discussed further below, the packing seal 650 within the packing section 600 provides a downstream pressure and fluid tight connection between the internal system 1500 and the external system 2000). The sealing assembly 158 0 includes seals 1580U, 1580L that hold an incompressible fluid between the hose 1595 and the surrounding conduit 420. In this way, the spray hose 1595 is operatively connected to the coiled tubing string 100 and sealingly connected to the external system 2000.

[0232] FIG. 3C illustrates the effectiveness of the sealing mechanism included in the upstream seal 1580. During the operation, spray fluid:

[0233] (1) Flow through the annulus 420.2 between the battery pack case 1540 and the inner duct 420 of the spray hose carrier;

[0234] (2) Flow between the battery pack supporting ducts 1560;

[0235] (3) Flow into the fluid receiving funnel 1570;

[0236] Flow down the core 1595.1 (ID) of the spray hose 1595; and

[0237] (5) Then exit the spray nozzle 1600.

[0238] As described, the downstream hydraulic pressure of the jet fluid acting on the axial cross-sectional area of the fluid receiving funnel 157 0 of the jet hose creates an upstream to downstream force that tends to seal the assembly The 1580 and the connected spray hose 1595 are "pumped" into the "downhole". In addition, since the components of the fluid receiving funnel 1570 and the supporting upper seal 1580U of the sealing assembly 1580 are slightly flexible, the net pressure drop described above is used to expand the outer diameter of the upper seal 1580U radially outward And unfold, thereby creating a fluid seal that prevents fluid from flowing to the back of the hose 1595.

[0239] FIG. 3D-1 provides when the "strapping" spray hose 1595 of the internal system 1500 is located inside the spray hose carrier.

A longitudinal cross-sectional view of the duct 420 when in. The longitudinal section also includes a perspective view (dashed line) of the electric wire 1590 and the data cable 1591. It is noted from the axial cross-sectional view of FIG. 3DTa that all the wires 1590 and data cables 1591 in the "bundled" spray hose 1595 are safely located in the outermost spray hose wrap 1595.3.

[0240] In a preferred embodiment, the spray hose 1595 is a "strapping" product. The hose 1595 is available from manufacturers such as Parker Hannifin. The strapping hose includes at least three conductive wires 1590 and at least one but preferably two dedicated data cables 1591 (such as fiber optic cables), as depicted in Figs. 3BTb and 3DTa. Note that these wires 1590 and optical fiber stranded wires 1591 are located on the outer perimeter of the core 1595.2 of the spray hose 1595 and are surrounded by a thin outer layer 1595.3 of flexible high-strength material or "wraps" (such as Kevlar®) for protection . Therefore, the electric wire 1590 and the optical fiber stranded wire 1591 are protected from any corrosive effect of the high-pressure jet fluid.

[0241] Now that the hose 1595 is moved down to the distal end, FIG. 3E provides an enlarged cross-sectional view of the end of the spray hose 1595. Here, the spray hose 1595 passes through the whipstock member 1000, and finally reaches the casing outlet "W" along the whipstock surface 1050.1. The spray nozzle 1600 is attached to the distal end of the spray hose 1595. The jet nozzle 1600 is shown at a position where an outlet opening or window "W" will be formed in the production sleeve 12 thereafter. Of course, it can be understood that the assembly 50 can be reconfigured to be deployed in a casing-less wellbore.

[0242] As described in the related application, the spray hose 1595 spans the entire ID of the production casing 12 at the aforementioned point of the casing outlet "W"._OIn this way, the bending radius "R" of the spray hose 1595 is always set to be equal to the ID of the production casing 12. This is important because the subject assembly 50 will always be able to use the entire casing (or wellbore) ID as the spray hose 1595 The bending radius "R", so as to use the largest ID/OD hose. This in turn allows for the placement of maximum hydraulic horsepower ("HHP") at the jet nozzle 1600, which further translates into the ability to maximize formation jet results, such as penetration rate or lateral bore diameter or some optimization of both.

[0243] It is observed here that there are three consecutive "contact points" in the bending radius "R" of the spray hose 1595. First, there is a contact point where the hose 1595 contacts the ID of the sleeve 12. This occurs at a point directly opposite and slightly above the point of the casing exit "W" (approximately one casing ID width). Second, there are contact points along the whipstock curved surface 1050.1 of the whipstock member 1000 itself. Finally, at least until the window "W" is formed, there is a contact point for the ID of the sleeve 12 against the sleeve outlet "W".

[0244] As depicted in FIG. 3E (and in FIG. 4HT), the jet hose whipstock member 1000 is in its set and operating position within the casing 12. (US Patent No. 8,991,522 also shows the whipstock member 1050 in its extended position, which is incorporated herein by reference). The actual whipstock 1050 in the whipstock member 1000 is supported by the lower whipstock rod 1060. When the whipstock member 1000 is in its setting and operating position, the upper curved surface 1050.1 of the whipstock member 1050 itself substantially spans the entire ID of the casing 12_OFor example, if the casing ID becomes slightly larger, this is obviously not the case. However, although the slightly larger bending radius "R" equal to the (new) enlarged ID of the sleeve 12 is precisely formed, the three aforementioned "contact points" of the spray hose 1595 will remain unchanged.

[0245] As described in more detail in co-owned U.S. Patent No. 8,991,522, the whipstock rod is part of the tool assembly and also includes an orienting mechanism and an anchor section including a slide. Once the slider is fixed, the orienting mechanism utilizes a ratchet-shaped movable part that can rotate the upstream portion of the whipstock member 1000 in discrete increments of 10°. Therefore, the angular orientation of the whipstock member 1000 in the wellbore can be incrementally changed downhole.

[0246] In one embodiment, the whipstock 1050 is a single body with an integrated concave surface configured to receive a spray hose and redirect the hose by approximately 90 degrees. Note that the whipstock 1050 is configured so that when in the set and operating position, a bending radius of the jet hose is formed at the exit point of the casing, the bending radius spanning the production of the main wellbore

The entire ID of the sleeve 12.

[0247] FIG. 4H-1 is a cross-sectional view of the whipstock member 1000 of the external system of FIG. 4 shown vertically rather than horizontally. The spray hose of the internal system (FIG. 3) is shown curved across the whipstock face 1050 and extending through the window "W" of the production casing 12. The spray nozzle of the internal system 1500 is shown attached to the distal end of the spray hose 1595.

[0248] FIG. 4H-1a is an axial cross-sectional view of the whipstock member 1000, wherein the perspective view of the continuous axial spray hose section depicts the center of the whipstock member 1000 from the line O-0' The path down to the beginning of the bend radius when the spray hose approaches the line P-P'.

[0249] FIG. 4H-1b depicts an axial cross-sectional view of the whipstock member 1000 at the line P-P'. Note the adjustment of the position and configuration of both the wiring chamber and the hydraulic fluid chamber of the whipstock member from the line O-O' to the line P-P'.

[0250] As mentioned above, the present assembly 50 is preferably used in connection with a nozzle with a unique design. 3F-1a and 3F1b provide enlarged cross-sectional views of the nozzle 1600 of FIG. 3 in the first embodiment. The nozzle 1600 utilizes a rotor/stator design in which the forward portion 1620 of the nozzle 1600 (and therefore the forward spray slot (or "port") 1640) is caused to rotate. In contrast, the rear part of the nozzle 1600, which itself is directly connected to the spray hose 1595, remains fixed with respect to the spray hose 1595. Note that in this arrangement, the jet nozzle 1600 has a single forward discharge slot 1640.

[0251] First, FIG. 3F-1a presents a basic nozzle body with a stator 1610. The stator 1610 defines an annulus body having a proximal end 1611 with a series of inwardly facing shoulders 1615 equally spaced therein. The nozzle 1600 also includes a rotor 1620. The rotor 1620 also defines a main body and has a series of outwardly facing shoulders 1625 equally spaced around it. In the arrangement of Figure 3F-1a, the stator 1610 has six inward facing shoulders 1615, and the rotor 1620 has four outward facing shoulders 1625.

[0252] Along each shoulder 1615 is arranged a small diameter conductive wire 1616 with a plurality of wrappers wrapping the inward facing shoulders (or "stator poles") 1615 of the stator. Therefore, according to the DC rotor/stator system, the movement of current through the wire 1616 creates an electromagnetic force. The power to the wires is provided from the battery 1551 (or battery pack 1550) of FIG. 3A.

[0253] As seen above, the stator 1610 and rotor 1620 bodies are similar to direct drive motors. The stator 1610 (in this case, a six-pole stator) of the direct drive motor analog is included in the outer body of the nozzle 1600 itself, wherein each pole directly protrudes from the body 610 and is equally wrapped in the wire 1616. The current source of the wire 1616 used to wrap the stator poles is derived from the'bundled' wire 1590 of the spray hose 1595, and is therefore composed of a current regulator and a micro-servo housed in the (downstream) end cap 1530 of the conical battery pack. Institutional manipulation. The rotation of the rotor 1620 of the nozzle 1600, especially the speed of rotation (RPM), is controlled by the induced electromagnetic force of the DC rotor/stator system.

[0254] Note that FIG. 3F-1a can be used to represent an axial section of basically any basic DC electromagnetic motor, with the central shaft/bearing assembly removed. By eliminating the central shaft and bearings, the nozzle 1600 can now accommodate the nozzle throat 1650 placed longitudinally through its center. The throat 1650 is suitable for high-pressure fluid flow.

[0255] FIG. 3F-1b provides a longitudinal cross-sectional view of the nozzle 1600 of FIG. 3F-1a taken along the line CC' of FIG. 3F-1b. The rotor 1620 and the surrounding stator 1610 can be seen again. The bearing 1630 is provided to promote relative rotation between the stator 1610 and the rotor 1620.

[0256] It is observed in FIGS. 3F-1b that the nozzle throat 1650 has a tapered narrowing portion before terminating in a single fan-shaped discharge groove 1640. This profile provides two benefits. First, an additional non-magnetic high-strength material can be placed between the throat 165 0 and the magnetic rotor portion 1625 of the forward portion of the nozzle body 1620. Second, adjust the final acceleration of the sprayed fluid passing through the throat 1650 before the sprayed fluid enters the discharge slot 1640. The size, location, load capacity, and freedom of movement of the bearing 1630 are also considered. The forward slot 164 0 begins with a relatively miniature hemispherical opening and is in a curved, relatively elliptical shape.

(Or alternatively, in a curved rectangle with a curved small end) terminates at the forward portion of the nozzle 1600.

[0257] The simulation was performed with a single flat groove, which was slightly twisted so that the discharge angle of the fluid produced enough thrust to rotate the nozzle 1600. The problem found is that the nozzle rotation rate is very sensitive to changes in the fluid flow rate, causing the bearing 1630 to instantaneously overload and frequent overload (accompanied by the resulting failure). The solution is to design a balanced single tank system as much as possible, so that the fluid discharge does not produce a perceivable axial thrust. In other words, the nozzle 1600 is no longer sensitive to the injection rate.

[0258] At this point, it is important to pay attention to the basic nozzle design criteria for the flow capacity of the combined flow path formed by the throat 1650 and groove 1640 elements. That is, the size maintained by these internal throat 1650 and groove 1640 elements of the nozzle 1600 may be similar to the size of a conventional hydraulic jet casing perforator and the resulting hydraulic power. Specifically, the nozzle 1600 depicted in FIG. 3F-1a and the throat 1650 and groove 1640 depicted in FIG. 3F-1b are sized to approximate the perforating hydraulic power obtained through the 1/8 inch orifice of the perforator. Note that the width of the end of the groove 1640 can not only accommodate 100 mesh sand as an abrasive, but also larger size such as 80 mesh sand.

[0259] The angles θsLoτ 1641 and θ^ 1642 are shown in FIG. 3F-1b. (These angles are also shown in Figures 3F-2b and Figure 3F-3b, discussed below.) The angle θsLoτ1641 represents the actual angle of the outer edge of the groove 1640, and the angle Omax 1642 represents the existing geometry and configuration of the nozzle 1600. The maximum Oslot 1641 achieved within the limit. In FIGS. 3F-1b, 3F-2b, and 3F-3b, the angles Oslot 1641 and Omax 1642 are both shown as 90 degrees. This geometry plus the rotation of the rotor 1620 (and, therefore, the rotation of the jet slot 1640) provides even at a reference distance (eg, the distance from the tip of the nozzle 1600 at the longitudinal centerline to the target rock along the same centerline) In the case of zero, the hole diameter at least equal to the outer diameter of the nozzle is also eroded.

[0260] FIGS. 3F-2a and 3F-2b provide longitudinal cross-sectional views of the spray nozzle of FIG. 3E in an alternative embodiment. In this embodiment, multiple ports are used for the modified nozzle 1601, including a forward port 1640 and multiple backward thrust nozzles 1613.

[0261] The nozzle structure of FIGS. 3F-2a and 3F-2b is the same as that of FIG. 3F-1a, except for the following three additional components:

[0262] (1) Use of the backward thrust nozzle 1613;

[0263] (2) Use of a slidable collar 1633 biased by a biasing mechanism (spring) 1635; and

[0264] (3) Use of slidable nozzle throat bushing 1631.

[0265] The first of these three additional components, the backward thrust spout 1613, provides backward thrust, effectively dragging the jet hose 1595 along the lateral borehole or micro branch channel when forming the lateral borehole or micro branch channel. Preferably, five rearward thrust nozzles 1613 are used along the main body 1610, although various numbers and/or outlet angles 1614 of the nozzles 1613 can be utilized.

[0266] FIGS. 3F-2c are axial cross-sectional views of the jet nozzle 1601 of FIGS. 3F-2a and 3F-2b. This shows a star-shaped nozzle pattern formed by multiple backward thrust nozzles 1613. Five points are seen in the star, representing five schematic backward thrust nozzles 1613.

[0267] Special attention should be paid to the fact that the forward (injection) hydraulic horsepower required to excavate fresh rock at a given penetration rate is basically the same in the main homogeneous production area. However, the backward thrust hydraulic horsepower requirement is constantly increasing in proportion to the increase in the length of the micro branch canal. Because the continuous extension of the micro branch canal requires that the spray hose 1595 be dragged along an ever-increasing distance for an ever-increasing length, the backward thrust hydraulic horsepower required to maintain the spray nozzle 1601 and the hose 1595 forward increases by the same amount. [0268] In order to extend the spray hose 1595 and the connected nozzles 1601, 1602 to the furthest lateral extent, it may be necessary to consume more than two-thirds of the available horsepower through the backward thrust nozzle 1613. If during the whole drilling and spraying process,

With this maximum requirement, most of the available horsepower will be wasted in the early stages of jet drilling. This is particularly disadvantageous when the same jet nozzles and components used in rock excavation are also used to form the initial casing outlet "W". In addition, if the same backward jet force at the'point' of cutting the star-shaped rock excavation is active in the wellbore fittings (especially when the casing outlet "W" is ejected), it may affect the nearby tool string (especially , Whipstock member 1000) and well casing 12 caused significant damage. Therefore, the optimized design will provide the activation/deactivation of the backward thrust nozzle 1613 when needed (especially after the casing outlet is formed and the first 5 feet or 10 feet of the lateral borehole is formed).

[0269] There are several possible mechanisms through which the spout can be activated/deactivated to help preserve HHP and protect tool posts and pipes. One method is mechanical, in which the opening and closing of the flow to the spout 1613 is actuated by overcoming the force of a biasing mechanism. This is shown in conjunction with the spring 1635 in FIGS. 3F-2a and 3F-2b, where the throat bushing 1631 and the slidable collar 1633 move together to open the backward thrust nozzle 1613. The other method is electromagnetic, in which the magnetic port seal is pulled against the biasing mechanism (spring 1635) by electromagnetic force. This is shown in conjunction with FIGS. 3F-3a and 3F-3c, which will be discussed below.

[0270] The second of the three additional components incorporated into the nozzle design of FIGS. 3F-2a and 3F-2b is a slidable collar 1633. The collar 1633 is biased by a biasing mechanism (spring) 1635. The function of the collar 1633 (whether directly or indirectly (by exerting a force on the slidable nozzle throat bushing 1631)) temporarily seals the fluid inlet of the thrust nozzle 1613. Note that this sealing function of the slidable collar 1633 is "temporary"; that is, unless a specific condition determined by the biasing mechanism 1635 is met. As shown in the embodiments presented in Figures 3F-2a and 3F-2b, the biasing mechanism 1635 is a simple spring.

[0271] In FIG. 3F-2a, the collar 1633 is in its closed position, while in FIG. 3F-2b the collar 1633 is in its open position. Therefore, the specific differential pressure exerted on the cross-sectional area of the slidable nozzle throat bushing 1631 has overcome the preset compression force of the spring 1635.

[0272] The third of the three additional components incorporated into the nozzle 1601 design of FIGS. 3F-2a and 3F-2b is a slidable nozzle throat bushing 1631. The slidable throat bushing 1631 has two basic functions. First, the liner 1631 provides an intentional and pre-defined protrusion into the flow path within the nozzle throat 1650. Second, the liner 1631 provides an anti-erosion and anti-abrasion surface in the highest fluid velocity portion of the internal system 1500. For the first of these three functions, the degree of protrusion to be designed into the slidable nozzle throat bushing 1631 is the function of what point in the micro lateral formation the operator expects to actuate the thrust spout 1613.

[0273] For illustrative purposes, assume that the system hydraulics provide an appropriate pumping rate of 0.5 BPM through the nozzle 1601 at the outlet "W" point of the casing, and that the pumping rate can be maintained at a surface pumping pressure of 8,000 psi. Suppose further that the thrust nozzle 1613 in the nozzle 1601 does not need to be activated before the nozzle 1601 achieves a lateral distance of 50 feet from the main borehole. That is, especially when spraying the casing outlet "W" itself and pumping the abrasive mixture (for example, 1.0 ppg 100 mesh sand in a 1 pound guar gum-based fresh water gum system), the nozzle l613 does not open (it may exist Risk of clogging by abrasives in the sprayed fluid mixture). Therefore, after it is determined that the nozzle 1600 has sufficiently cleaned the sleeve outlet "W", no abrasive is included in the spray fluid. Correspondingly, when a hole is sprayed in the production casing 12 to form a casing outlet "W", no backward spray force from the fluid driven through the thrust nozzle 1613 can be applied to the spray hose 1595, whipstock member 1000 or Any of the production casings 12 poses a threat of unintentional damage.

[0274] Later, after the casing outlet "W" is generated plus a micro branch channel length of approximately 50 feet, the pump pressure is increased to 9,000 psi, and the 1,000 psi increase in the surface pumping pressure is sufficient to overcome the biasing mechanism 1635 The force is reacted on the cross-sectional area of the protrusion of the bushing 1631 to activate the spout 1613. Therefore, in the micro branch channel 50 feet away from the main borehole 4

At the length, the thrust nozzle 1613 is actuated and a high pressure backward thrust flow through the nozzle 1613 is generated.

[0275] Assume that these conditions are sufficient to continue to spray out the micro branch trenches up to a branch trench length of 300 feet. At 300 feet, the length of the spray hose resting against the bottom of the micro branch channel causes the same amount of frictional resistance, so that the frictional resistance and the thrust generated by the thrust nozzle 1613 are approximately balanced. (Instrument devices such as tensiometers, for example, will indicate this approximate balance). At this time, the pumping rate is increased to, for example, 10,000 psi, and the backward thrust nozzle 1613 remains actuated, but is actuated at a higher pressure difference and flow rate, thereby generating a higher tension on the spray hose 1595.

[0276] FIGS. 3F-3a and 3F-3c provide longitudinal cross-sectional views of jet nozzle 1602 in another alternative embodiment. Here, multiple backward thrust nozzles 1613 and a single forward spray slot 1640 are used again. The collar 1633 and spring 1635 are again used to provide a selected fluid flow through the backward thrust nozzle 1613.

[0277] FIGS. 3F-3b and 3F-3d show axial cross-sectional views of the jet nozzle 1602 of FIGS. 3F-3a and 3F-3c, respectively. These figures show the star-shaped nozzle pattern created by multiple nozzles 1613. Eight points are seen in the star, representing two groups of four (alternating) exemplary thrust nozzles 1613. In FIGS. 3F-3a and 3F-3b, the collar 1633 is in its closed position, while in FIGS. 3F-3c and 3F-3d, the collar 1633 is in its open position, allowing fluid to flow through the spout 1613. The biasing force provided by the spring 1635 has been overcome.

[0278] The nozzle 1602 of FIGS. 3F-3a and 3F-3c is similar to the nozzle 1601 of FIGS. 3F-2a and 3F-2b; however, in the arrangements of FIGS. 3F-3a and 3F-3c, resistance is generated The electromagnetic force of the slidable collar 1633 downstream of the magnetic pulling force that is sufficient to overcome the biasing force of the biasing mechanism (spring) 1635 replaces the slidable throat in the jet nozzle 1601 of FIGS. 3F-2a and 3F-2b. The hydraulic pressure of the bushing 1631.

[0279] The nozzle 1602 of FIGS. 3F-3a and 3F-3c presents another preferred embodiment of the rotating nozzle 1602, which is also suitable for forming a casing outlet and continuously digging through the cement sheath and the main rock formation. In Figures 3F-3a and 3F-3c (and in Figure 3G-1, described in more detail below), the electromagnetic force generated by the rotor/stator system must overcome the force of the spring 1635 to open to the backward thrust nozzle 1613 (And 1713) hydraulic inlet. (Note that in Figure 3G-1, the coaxial hydraulic injection collar is depicted, which will be discussed more fully below. The direct mechanical connection of the internal turbine fin 740 to the slidable collar 733 changes the pressure to one of the different pressures. The offset standard is the same as the jet nozzle depicted in Figure 3F-2a). The key here is the ability: before the operator starts to open the fluid inlet to the backward thrust nozzle 1613 (and 1713) (specifically by increasing the pumping rate, the pressure difference across the nozzle and/or the nozzle rotation speed is combined with The electromagnetic pulling force on the slidable collar 1633/1733 increases proportionally before opening the path to the fluid inlet of the thrust nozzle 1613/1713, so that the fluid inlet remains closed.

[0280] It is also observed that in the nozzle 1602, the number of backward thrust nozzles 1613 (although also placed symmetrically around the circumference of the rotor 1610) has increased from a single group of five to two groups of four. Note that each of the four nozzles 1613 in each of the two groups is also placed symmetrically around the circumference of the rotor 1610, orthogonal to each other; therefore, the two groups of nozzles 1613 must overlap. In addition, the path of each nozzle now not only travels through the backward (stator) portion 1610 of the nozzle 1602, but also now passes through the forward (rotor) section 1620 of the nozzle 1602. Note, however, that as depicted in FIGS. 3F-3b and 3F-3d, there are eight separate spray channels through the backward (stator) portion 1610 of the nozzle 1602, and through the forward (rotor) section 1620 of the nozzle 1600 There are only four. Therefore, the rotation of the forward (rotor) section 1620 of the nozzle 1602 will only provide alignment of a set of four nozzles 1613 at a time, and subsequent fluid flow through them. In fact, for most of the duration of a single rotation, the flow channel of the rotor 1620 does not have an entrance to the flow channel of the stator 1610 and thus is effectively sealed. The result will be an oscillating (or "pulsed") jet flow through the backward thrust nozzle 1613.

[0281] The same reduction in the volume of ejected fluid passing through the nozzle port 1640 also produces the same amount of pulsed direction for excavation.

Front jet flow. The benefits of the continuous flow used in the excavation system and the reverse pulse flow have been fully proven and will not be repeated here. Note, however, that the subject nozzle design not only obtains the benefits of rotary jet rock excavation, but also the benefits of pulse jetting.

[0282] Another embodiment of a thrust collar using electromagnetic force is provided in FIGS. 3G-1a and 3G-1b. 3G-1a presents an axial cross-sectional view of the basic body of the thrust injection collar 1700 of the internal system 1500 of FIG. 3. This view is taken along the line D-D' of Figure 3G1b. Here, like the jet nozzle 1602, two layers of backward thrust jet ports 1713 are again provided.

[0283] The collar 1700 has a rear stator 1710 and an inner (rotating) rotor 1720. The stator 1710 defines an annular body having a series of inwardly facing shoulders 1715 equally spaced therein, and the rotor 1720 defines a series of outwardly facing shoulders 1725 that are equally spaced around it. Main body. In the arrangement of Fig. 3G.1.a, the stator body 1710 has six shoulders 1715 facing inward, and the rotor body 1720 has four shoulders 1725 facing outwards.

[0284] Along each shoulder 1715 is arranged a small-diameter conductive wire 1716 with a plurality of wrappers wrapping the inward facing shoulders (or "stator poles") 1715 of the stator 1710. Therefore, according to the DC rotor/stator system, the movement of current through the wire 1716 creates electromagnetic force. The power to the wire is supplied from the battery 1551 of FIG. 3A.

[0285] FIG. 3G-1b is a longitudinal cross-sectional view of the nozzle 1700. Fig. 3G-1c is an axial cross-sectional view of the thrust nozzle 1713 taken along the line d-d' of Fig. 3G-1b.

[0286] FIGS. 3G-1a to 3G-1c show similarly conceptual embodiments of rotating nozzles 1600, 1601 and 1602, but with modifications that make the device suitable for use as a coaxial thrust jet collar 1700. Special attention has been paid to the provision of the collar throat 175 0 and the flow-through rotor 1725 coupled with the stator 1715 and the bearing 1730. However, the fixed flow channels for the backward thrust nozzles 1713 passing through the stator 1710 are split in two sets of four staggered. For each complete rotation, each of the single set of four orthogonal nozzles that penetrate the rotor 1725 "matches" the nozzles that penetrate the stator 1710 four times, and each match provides equidistantly spaced intervals around the outer circumference of the collar 1700 Four instantaneous pulse streams. Similar to the rotating nozzle 1602, the slidable collar 1733 is electromagnetically moved against the biasing mechanism (spring) 1735 to actuate the flow through the backward thrust nozzle 1713.

[0287] FIGS. 3G-1c are another cross-sectional views showing the star-shaped pattern of the backward thrust spout 1713. See eight points.

[0288] There is a unique opportunity to configure the collar 1733 as a net power consumer or net power provider. The former relies on the power provided by the battery pack, just like the jet nozzle 1600, to activate the stator, rotate the rotor and generate the required electromagnetic field. The latter is accomplished by incorporating a slightly angled internal turbine fin 1740 into the ID of the rotor 1720, thus utilizing the hydraulic pressure of the jet fluid as it is pumped through the collar 1700. This force will only depend on the pumping rate and the configuration of the turbine fin 1740.

[0289] On the one hand, the internal turbine fins 1740 are placed equidistantly around the collar throat 1750 so that hydraulic pressure is utilized to rotate the rotor 1720 and provide a net residual current to be fed back to the circuitry of the internal system. This can be achieved by sending the excess current back to the wire 159 0. Incorporating the rotor/stator configuration into the configuration of the backward thrust spout collar can make the fully open ID equal to the ID of the spray hose. More and sufficient hydraulic power can be obtained to generate the electromagnetic field required to operate the sliding port collar 1733. Once the internal system 1500 is separated from the mooring station 325, the available remaining hydraulic power will be fed to the present " Shut down the power system. Therefore, the remaining hydraulic power generated by the collar 1700 can be advantageously used to maintain the charge of the battery 1551 in the battery pack 1550.

[0290] It can be observed that the various nozzle designs 1600, 1601 and 1602 discussed above are designed to not only spray through the rock matrix, but also through the steel casing and the cement sheath around the well 4c in order to reach the rock . The nozzle design incorporates the ability to process a relatively large particle size abrasive through the forward nozzle jet port 1640 before engaging with the RTJ 1613. It can be understood that although other nozzle designs can be used to complete the purpose of forming micro-branch channels, this design is not strong enough.

Can cut through steel.

[0291] In the various nozzle designs 1600, 1601, and 1602 discussed above, a single forward port is used in the hemispherical nozzle. The forward port 1640 is defined by the angle 9max (where the width of the nozzle is equal to the width of the nozzle when the outermost edge of the nozzle reaches a forward point equivalent to the nozzle tip) and Oslot (the actual slot angle). Pay attention to OslotWmax. For the purpose of description here, Oslot = Omax, so that even if the tip of the rotating nozzle abuts the main rock (or casing ID) surface during spraying, the tip still digs a tunnel diameter equal to the diameter of the outer (largest) nozzle. It is this single-planar rotating groove configuration that will provide the maximum width in order to provide sufficient passage capacity for any abrasive that may be incorporated into the jet fluid.

[0292] The preferred rearward orifice injection orientation is 30° to 60° from the longitudinal axis. The backward thrust nozzle 1613/1713 is designed to be symmetrical around the circumference of the nozzle/collar stator body 1610/1710. This maintains the fully forward orientation of jet assemblies 1600, 1601, and 1602 along the longitudinal axis. Accordingly, there should be at least three nozzles 1613/1713 equally spaced around the circumference, preferably at least five nozzles 1613/1713 equally spaced.

[0293] As mentioned above, the nozzle in any of its embodiments can be deployed as part of a guidance or geosteering system. In this case, the nozzle will include at least one geospatial IC chip, and at least three actuator lines will be used. The actuator wire 1590A is equally spaced around the distal end of the spray hose and extends into the nozzle, and receives current or excitation from a wire 1590 that has been provided in the spray hose 1595.

[0294] FIGS. 3F-1c are longitudinal cross-sectional views of the jet nozzle 1600 of FIGS. 3F-1b in a modified embodiment. Here, the spray nozzle 1600 is shown as being connected to the spray hose 1595. The connection may be a threaded connection; alternatively, the connection may be made by welding. In Figures 3F-1c, a schematic welded connection is shown at 1660.

[0295] In the arrangement of FIGS. 3F-1c, the jet nozzle 1600 includes a geospatial IC chip 1670. The geospatial chip 1670 is located within the port seal 1675. The geospatial chip 1670 may include a two-axis or three-axis accelerometer, a two-axis or three-axis gyroscope, a magnetometer, or a combination thereof. The present invention is not limited by the type or number of geospatial chips used or their corresponding positions within the component, unless it is clearly stated in the claims. Preferably, the chip 1670 will be associated with a microelectromechanical system located on or near the nozzle body (such as shown and described in connection with the nozzle embodiments (1600, 1601, 1602) described above).

[0296] FIGS. 3F-1d are axial cross-sectional views of the spray hose 1590 of FIGS. 3F-1c taken along the line c-c'. What can be seen in this figure are the wire 1590 and the actuator wire 1590A. Also visible is the optional fiber optic data cable 1591. The wires 1590, 1590A, 1591 can be used to transmit geographic location data from the chip 1670 to the microprocessor in the battery section 1550, and then wirelessly transmit it to the mooring station (shown as 325 in Figure 4D-1b) Out), where the receiver communicates with the microprocessor in the mooring station 325. Preferably, the microprocessor in the mooring station 325 processes the geographic location data and adjusts the current in the actuator line 1590A (using one or more current regulators) to ensure that the nozzle is oriented along the pre-programmed The horizontal drilling is drilled hydraulically in the direction of the direction.

[0297] The micro-transmitter in the battery pack is preferably housed in the downstream end cap 1530 of the battery pack, while the mooring station 325 is preferably attached to the inside of the jet hose carrier system 400 (hereinafter in conjunction with FIG. 3A, FIG. 3B-1 and Figure 4D-1 for description). The receiver housed in the mooring station 325 may be electrically or optically connected to the microprocessor on the ground 1. For example, the fiber optic cable 107 can extend along the coiled tubing transportation system 100 to the ground 1, where the geographic location data is processed as part of the control system.

[0298] Hard-wiring (again, preferably, the optical fiber cable 107 in the medium 100 and the external system 2000 through the coiled tubing) of the ground instrument to a specific end receiver (not shown) housed in the mooring station 325 The fiber optic) connection also facilitates reverse (surface to downhole instrument) communication. Then the adjacent wireless transmitter in the mooring station 325 will

CN 107429552 Β

The command is transmitted to the wireless receiver housed in the end cover 1530 of the internal system 1500. The communication system allows the operator to execute commands to set the rotation speed and/or trajectory of the jet nozzle 1600.

[0299] When the nozzle 1600 exits the sleeve, the operator knows the position and orientation of the nozzle 1600. By monitoring the length of the spray hose 1590 being moved out of the spray hose carrier, combined with any changes in orientation, the operator knows the geographic location of the nozzle 1600 in the reservoir.

[0300] In one option, the desired geographic trajectory is first issued as a geosteering command from the ground 1, down to the coiled tubing 100, and then to the microprocessor associated with the mooring station 325. When receiving geosteering commands from the ground 1 (such as from an operator or a ground control system), the microprocessor will wirelessly push the signal to the corresponding micro receiver associated with the battery pack segment 1550. This signal will cause one or more current regulators to change the current conducted downward along one, two, or all three of the at least three wires 1590 directly connected to the jet nozzle 1600. Note that at least part of these wire connections, preferably the segment closest to the jet nozzle 1600, is composed of an actuator wire 1590A (such as a Flexinol® actuator wire manufactured by Dynalloy, Inc). These small-diameter fettered titanium wires shrink when they are electrically excited. This ability to flex or shorten is a characteristic of certain alloys that dynamically change their internal structure at certain temperatures. The shrinkage of the actuator wire is contrary to ordinary thermal expansion, it will become hundreds of times larger, and a huge force must be applied for its small size. Assuming that the temperature is tightly controlled under constant stress, precise position control can be obtained, that is, control in microns or less. Accordingly, it is assumed that (at least) three separate actuator wires 1590A are positioned equidistantly or approximately equidistantly around the circumference of the spray hose and within the body (toward the end, Close to the jet nozzle 1600), a small increase in current in any given wire will cause it to shrink more than the other two, thereby manipulating the jet nozzle 1600 along the desired trajectory. Given the initial depth and orientation via the geospatial IC chip in the nozzle 1600, the determined path for the lateral drilling 15 can be pre-programmed and automatically executed.

[0301] Relatedly, the actuator wire 1590A has a distal segment located along the cavity or sheath, or even interwoven within the matrix of the distal segment of the jet hose 1595. In addition, the distal end of the actuator wire 1590A can continue to partially enter the nozzle body, wrapping the stator pole 1615 to connect to or even form the electromagnetic coil 1616. This is also shown in Figure 3FTc. In this way, power is supplied from the battery pack section 1550 to induce relative rotational movement between the rotor body and the stator body.

[0302] As can be seen from the above discussion, an internal system 1500 for the hose spray assembly 50 is provided. The system 1500 enables powerful hydraulic nozzles (1600, 1601, 1602) to spray underground rock in a controlled (or steerable) manner, thereby forming miniature lateral boreholes that may extend into the formation several feet. The unique combination of the injection fluid receiving funnel 1570, the upper seal 1580U, and the injection hose 1595 of the internal system 1500 combined with the pressure regulating valve 610 of the external system 2000 and the packing section 600 (discussed below) provides a system through which Regardless of the orientation of the well 4, the system can completely advance and retract the jet hose 1595 by the hydraulic device. Alternatively, mechanical devices can be added by using the internal tractor system 700, which will be described more fully below.

[0303] Controlling the components listed above not only determines the direction in which the spray hose 1595 advances (eg, advances or retracts), but also controls the rate of advancement. The rate of advancement or retraction of the internal system 1500 may be directly proportional to the rate (and pressure) at which fluid is discharged and/or pumped in, respectively. Specifically, "pump hose 1595 downhole" will have the following sequence:

[0304] (1) Fill the spray hose by pumping hydraulic fluid through the main control valve 310 and then through the pressure regulating valve 610

The micro-annular gap 1595.420 between 1595 and the inner duct 420 of the jet hose carrier; then

[0305] (2) Use the ground controller to electronically switch the main control valve 310 to start directing the jet fluid to the internal system

1500; this

[0306] (3) It is triggered relative to the internal system 1500 to direct the spray fluid into the spray hose through the introduction funnel 1570

1595 and to the hydraulic pressure "downhole"; this force is resisted by

[0307] Compress the hydraulic fluid in the micro annulus 1595.420; the hydraulic fluid

[0308] (5) According to expectations, discharge from the ground controller of the pressure regulating valve 610 to adjust the internal system

The rate at which 1500 falls into the "downhole".

[0309] Similarly, the internal system 1500 can be pumped back "uphole" by directing the pumped hydraulic fluid (first) through the main control valve 310 and (then) through the pressure regulating valve 610, thereby forcing The increasing (expanding) hydraulic fluid volume enters the micro-annular gap 1595.420 between the spray hose 1595 and the spray hose conduit 420, which pushes up the bottom seal 1580L of the spray hose seal assembly 1580, thereby driving the internal system 1500 back "Inoue". The direction and rate of the advancement of the internal system 1500 by the hydraulic device may be added or replaced by the advancement of the internal system 1500 via the mechanical device of the internal tractor system 700, as described below.

[0310] Advantageously, once the jet hose assembly 50 is deployed at a downhole position near the desired point of the casing outlet "W" in the main wellbore 4 with any inclination (including horizontal or approximately horizontal), it can be used without resorting to The entire length of the spray hose 1595 is deployed and retracted by gravity. This is because the propulsion force used to deploy and retract the spray hose 1595 and maintain its proper alignment during the process is hydraulic or mechanical, as described more fully below. Also note that for overcoming the movement of the internal system 1500 (including, specifically, the spray hose 1595 ) within the external system 2000 (including, specifically, the spray hose carrier 420) caused by any non-vertical alignment Regarding any frictional force and maintaining the hose 1595 in the basic taught state along the length of the hose in the external system 2000, these propulsion hydraulic and mechanical forces are available in sufficient quantities. Therefore, these hydraulic and mechanical propulsion forces completely overcome the limitation of "cannot push the rope".

[0311] The hydraulic pressure used to advance the spray hose 1595 into the external system 2000 and then exit the external system will be observed at any time when the spray fluid is pumped; specifically, in the longitudinal direction of the spray hose 1595 The force along the upstream to downstream direction in a plane parallel to the axis, because the hydraulic pressure is applied to the upstream end cap of the battery pack 1520, the fluid introduction funnel 1570, and the inner surface of the jet nozzle 1600 (such as the surface of any internal system 1500). This surface: (A) Exposure to the jet of fluid; and (b) have a directional component that is not parallel to the longitudinal axis of the main borehole. Since these surfaces are rigidly attached to the spray hose 1595 itself, whenever the spray fluid is transported from the ground 1 along the coiled tubing 100 (as seen in FIG. 2) down and through the spray in the main control valve 300 The fluid channel 345 (described below in conjunction with FIG. 4C-1) is pumped, and this force from upstream to downstream is directly transmitted to the spray hose 1595. Note that the only other valve in the system, namely, the pressure regulating valve 610 located just upstream of the packing seal assembly 650 of the packing section 600 (as seen and described in conjunction with Figures 4E-1 and 4E-2 The function of the) is to simply release the annulus 1595.420 from the jet hose 1595/jet hose conduit 420 at a rate equivalent to the rate at which the operator expects to lower the internal system 1500 (see Figure 3D-1a and Figure 4D-2) To the pressure of the compressed hydraulic fluid within).

[0312] Conversely, whenever the medium 100 is transported from the ground 1 along the coiled tubing, the hydraulic fluid is pumped down and through the hydraulic fluid passage 345 in the main control valve 300, and the internal system is propelled in the downstream to upstream direction. At 1500, hydraulic pressure is operational. In this configuration, the pressure regulating valve 610 allows the operator to introduce injection fluid into the injection hose 1595/jet hose conduit 420 annulus 1595.420 in a manner commensurate with the rate at which the operator desires to ascend the internal system 1500. Therefore, hydraulic pressure can be used to help transport and retrieve the spray hose 1595.

[0313] Similarly, the mechanical force exerted by the internal tractor system 700 helps transport, retrieve the spray hose 1595, and maintain the alignment of the spray hose. The close tolerance between the OD of the jet hose 1595 and the ID of the jet hose conduit 420 of the jet hose carrying system 400 (thus defining the annulus 1595.420) is used to provide a limited axial force. Helps maintain the alignment of the hose 1595 so that the portion of the hose 1595 located within the jet hose carrier system 400 will never experience significant bending forces. The direct mechanical (tension) force used for the deployment and withdrawal of the jet hose 1595 passes through the internal tractor system 700

The clamp 756 of the specially designed clamp assembly 750 is applied by direct friction attachment with the spray hose 1595, as discussed below in conjunction with FIGS. 4F-1 and 4F-2.

[0314] As mentioned above, the hydraulic pressure from the backward thrust nozzle 1613 of the jet nozzle 1601, 1602 itself also helps to transport the jet hose, and, if any additional jet collar 1700 is included, is derived from the direction of the jet collar The hydraulic pressure of the rear thrust nozzle 1713 also helps transport the spray hose. These hydraulic pressures at the most downstream are used to push the spray hose 1595 forward into the production area 3 while forming the UDP 15 (Figure 1B), and maintain the spray fluid aimed forward to be closest to the rock face in the excavation. The balance between deploying hydraulic energy forward close to the nozzle (for digging new holes) and deploying backward (for propulsion) needs to be balanced. If you push back too much, there is not enough remaining hydraulic horsepower to concentrate on digging new holes forward. If there is too much spray fluid that is expelled by advancing forward, there is not enough fluid that can be used to push the nozzle 1613/1713 backward to generate the horsepower required to drag the spray hose along the lateral borehole. Therefore, the ability to redirect backward or forward concentrated hydraulic horsepower through the nozzle in situ as described herein is an important improvement.

[0315] For descriptive purposes, two configurations of the backward thrust nozzle 1613/1713 are included here: one configuration pulsates the flow, in which eight backward thrust nozzles (each inclined by 30° from the longitudinal axis and around the circumference Equidistantly spaced) are grouped into two groups of four, with alternating backward flow (or "pulsation") between the two groups; a configuration for continuous flow, which shows a single group of five nozzles, each from The longitudinal axis is inclined by 30° and is equally spaced around the circumference. However, other nozzle numbers and angles can be used.

[0316] The series of figures in FIG. 3 and the preceding paragraphs discussing those figures are directed to the internal system 1500 for the hydraulic injection assembly 50. The internal system 1500 provides a novel system for transporting the jet hose 1595 in and out of the main borehole 4 in a single trip, facilitating the subsequent manipulable formation of multiple micro-transverse boreholes 15. The jet hose 1595 can be as short as 10 feet, or as long as 300 feet or even 500 feet, depending on the thickness and compressive strength of the formation or the desired geographic trajectory of each lateral wellbore.

[0317] As mentioned, the hydraulic injection assembly 50 also provides an external system 2000 that is uniquely designed for the transportation, deployment, and retrieval of the internal system 1500 previously described. The external system 2000 can be transported on the conventional coiled tubing 100; but more preferably, the external system is deployed on the "stranded" coiled tubing product (Figure 3D-1a, Figure 4A-1 and Figure 4A-1a) to provide real-time power and data transmission.

[0318] Consistent with the related and commonly-owned patent documents cited herein, the external system 2000 includes a jet hose whipstock member 1000 that includes a whipstock 1050 having a curved surface 1050.1, which preferably forms The spray hose 1595 spans the bending radius of the entire ID of the production casing 12. The external system 2000 may also include a mud motor 1300, (external)

[0319] Coiled tubing tractor 1350, logging tool 1400 and/or packer or bridge plug (preferably, retrievable type) constitute a conventional tool assembly. In addition, the external system 2000 provides power and data transmission throughout, so that the downhole assembly 50 can be controlled in real time.

[0320] FIG. 4 is a longitudinal cross-sectional view of the external system 2000 of the downhole hydraulic injection assembly 50 of FIG. 2 in one embodiment. The external system 2000 is shown inside the 12 string of production casing. For the sake of clarity, FIG. 4 presents the external system 2000 as "empty"; that is, it does not house the components of the internal system 1500 described with respect to the series of figures in FIG. 3. For example, spray hose 1595 is not shown. However, it is understood that the spray hose 1595 is mostly contained in the external system during extension and extension.

[0321] When presenting the components of the external system 2000, it is assumed that the system 2000 is extended into a production sleeve 12 with a standard 4.50" OD and approximately 4.0" ID. In one embodiment, the external system 2000 has a maximum outer diameter limit of 2.655", and preferably a maximum outer diameter of 2.500". The OD limit provides equal to or greater than 7.0309in²Ring open to flow

(That is, between the OD of the system 2000 and the ID of the surrounding production casing 12) area, this is equivalent to a 9.2#, 3.5" fracturing (tubing) string.

[0322] The external system 2000 is configured to allow the operator to optionally "fract" down the annulus between the medium 100 (with equipment attached) and the surrounding production casing 12 along the coiled tubing. A substantially annular area is reserved between the OD of the external system 2000 and the ID of the production casing 12, allowing the operator to pump the fracturing down the subject annulus immediately after ejecting the desired number of lateral boreholes (or Other processing) fluid, without the need to lift the coiled tubing 100 with the equipment 2000 attached out of the main well 4. Therefore, multiple stimulation treatments can be performed in only one trip of the assembly 50 in and out of the main borehole 4. Of course, the operator can choose to shut down the well for each fracturing operation, in which case the operator will use standard (mechanical) bridge plugs, fracturing plugs and/or movable sleeves. However, this will require significantly higher time (accompanied by the same amount of expense), and cause greater abrasion and fatigue of the transport medium 100 based on coiled tubing.

[0323] In fact, strict compliance (OD) restrictions may only be essential for the coiled tubing transport medium 100 that may account for more than 90% of the length of the system 50. A slight violation of the OD restriction on the relatively small length of other components of the external system 2000 should not cause a significant annular hydraulic pressure drop that is prohibited. If these outer diameter restrictions can be met, while maintaining sufficient inner diameter to accommodate the design function of each component (especially the components of the external system 2000), and for the operation in the smaller 4.5" OD standard oilfield production casing 4 The system 50 can achieve this, so there should be no obvious obstacles to adapt the system 50 to any larger standard oilfield production casing size (5.5", 7.0", etc.).

[0324] Each of the main components of the external system 2000 presented below will follow the upstream to downstream direction. Note the division of the main components of the external system 2000 in Figure 4, where the corresponding figure here:

[0325] a. Coiled tubing delivery medium 100, shown in Figures 4A-1 and 4A-2;

[0326] b first cross-connecting piece (coiled tubing transition piece) 200, shown in Figure 4B-1;

[0327] c. The main control valve 300, shown in Figure 4C.1;

[0328] d. Jet hose carrying system 400 and its mooring station 325, shown in Figure 4D-1 and Figure 4D-2;

[0329] e The second cross-connecting piece 500 (transitions the outer body from a circular shape to a star shape) and the jet hose packing section 600, Figure

Shown in 4E-1 and Figure 4E-2;

[0330] f. The external tractor system 700 and the third cross-connect 800, shown in Figures 4F-1 and 4F-2;

[0331] g. The third cross-connect 800 and the upper swivel 900, shown in Figure 4G-1;

[0332] h. Whipstock member 1000, shown in Figure 4H-1;

[0333] i. Lower swivel 1100, shown in Figure 4I-1; and finally

[0334] j. The transition piece 1200 connected to the coiled tubing mud motor 1300 and the conventional coiled tubing tractor 1350, coupled to the conventional logging probe 1400, as shown in FIG. 4J.

[0335] FIG. 4A-1 is a longitudinal cross-sectional view of the "bundled" coiled tubing transport medium 100. The transportation medium 100 is used as a transportation system for the downhole hydraulic injection assembly 50 of FIG. 2. The transport medium 100 is shown as being located within the production casing 12 of the main well 4 and extending through the column heel 4b and into the horizontal column 4c.

[0336] FIG. 4A-1a is an axial cross-sectional view of the coiled tubing transport medium 100 of FIG. 4A-1. It can be seen that the transport medium 100 includes the core 105. In one aspect, the coiled tubing core 105 consists of a standard 2.000"OD (105.2) and 1.620"ID (105.1), 3.68 1bm/ft.HSt110 coiled tubing string with a minimum field strength of 116,700lbm and an internal minimum yield pressure of 19,000ps i. constitute. This standard size coiled tubing provides 2.06in open to flow²The inner cross-sectional area. As shown, the "bundling" product 100 includes three wire ports 106 with a diameter of up to 0.20", which can accommodate AWG#5 standard wires and two data cable ports 107 with a diameter of up to 0.10".

[0337] Coiled tubing transportation medium 100 also has an outermost or "wrapped" layer 110. In one aspect, the outer layer 110 has an outer diameter of 2.500", and an inner diameter of 2.000", which engages and is exactly equal to the OD105 of the core coiled tubing string 105.

[0338] The axial and longitudinal sections presented in FIGS. 4A-1 and 4A-1a assume that the product 100 is bundled concentrically, but in practice, eccentric bundles may be preferable. The eccentric bundling provides more protection for the wire 106 and the data cable 107. Figure 4A-2 includes this depiction of an eccentrically bundled coiled tubing transport medium 101. Fortunately, the eccentric strapping has no actual differences in the size of the packing rubber or the injection part of the wellhead set to lubricate the entry and exit of the main wellbore, because the OD105.2 and ring retention of the outer wrap 110 of the eccentric transport medium 101 Not affected.

[0339] The transport medium 101 may have, for example, 2.0612 in²Internal flow area, 0.190in²The thickness of the core wall 105, and 0.25in²Average outer wall thickness. The outer wall 110 may have 0.10in²The minimum thickness.

[0340] Note that whether concentric 100 or eccentric 101 is bundled, the main design standard of the transport medium is to provide real-time power to the operator located on the ground 1 (via wires) when the equipment 50 is deployed, operated, and withdrawn in the well 4 106) and data (via data cable 107) transmission capability. For example, in a standard electric coil system, the components 106 and 107 will extend into the coiled tubing core 105, exposing them to any fluid pumped through the ID 105.1 of the core 105. Considering that the subject method provides abrasives in the pumped high-pressure jet fluid (in particular, while eroding the casing outlet "W" from the production casing 12), it is preferable to place the parts 106 and 107 at the OD105 of the core 105 instead. .2 places.

[0341] Similarly, the subject method provides for pumping the proppant in the high pressure hydraulic fracturing fluid down the annulus between the coiled tubing delivery medium 100 (or 101) and the production casing 12. Therefore, the protective coiled tubing wrap 110 preferably has sufficient thickness, strength, and corrosion resistance to isolate and protect the components 106 and 107 during the fracturing operation.

[0342] The transport medium 100 (or 101) also maintains a sufficiently large inner diameter 105.1 of the core wall 105 to avoid obvious frictional losses when pumping injection and/or hydraulic fluids (and losses caused by the internal system 1500 and the external system 2000) compared to). At the same time, the system maintains a sufficiently small outer diameter of 110.2 to avoid excessive pressure loss when pumping down the hydraulic fracturing fluid along the annulus between the coiled tubing 100 (or 101) and the production casing 12 . In addition, the system 50 maintains a sufficient wall thickness of the outer coating layer 110, regardless of whether it is wrapped concentrically or eccentrically around the inner coiled tubing core 105, so as to provide sufficient insulation protection and separation for the electrical transmission line 105 and the data transmission line 107. It is understood that other sizes and other tubular bodies can be used as the transportation medium for the external system 2000.

[0343] Moving further down the external system 2000, FIG. 4B-1 shows a longitudinal cross-sectional view of the first cross-connecting piece, that is, the coiled tubing cross-connecting piece 200, and FIG. 4B-1a shows the coiled tubing cross-connecting piece 200. Part of the perspective view. Specifically, the transition between the line E-E' and the line F-F' is shown. In this arrangement, the outer contour transitions from a circular shape to an oval shape to bypass the main control valve 300.

[0344] The main functions of the cross-connect 200 are as follows:

[0345] (1) The coiled tubing delivery medium 100 (or 101) is connected to the injection assembly 50, and specifically, to the main control valve 300. In Figure 4B-1, the connection is depicted by a steel coiled tubing core 105 connected to the outer wall 290 of the main control valve at a connection point 210.

[0346] (2) Transition the electric wire 106 and the data cable 107 from the outside of the core 105 of the coiled tubing conveying medium 100 (or 101) to the inside of the main control valve 300. This is done by the wiring port 220 that facilitates the transition of the wire/data cable 106/10 7 in the outer wall 290.

[0347] (3) Provide easy access points, such as threads and pairs of collars 235 and 250, for splicing/connection of wires 106 and data cables 107.

[0348] and

[0349] Provide wires 106 and data through the pressure and fluid protection conduits, that is, the wiring chamber 230

[0350] According to the cable 107 alone, there is no crossover and no interference path.

[0351] The next component in the external system 2000 is the main control valve 300. Figure 4C-1 provides a longitudinal cross-sectional view of the main control valve 300. Figure 4C-1a provides an axial cross-sectional view of the main control valve 300 taken along the line G-G' of Figure 4C-1. The main control valve 300 will be discussed in conjunction with FIGS. 4C1 and 4C-1a.

[0352] The function of the main control valve 300 is to receive high-pressure fluid pumped from the coiled tubing 100, and to selectively direct them to the internal system 1500 or the external system 2000. The operator sends control signals to the main control valve 300 through the wire 106 and/or the data cable port 107.

[0353] The main control valve 300 includes two fluid passages. These passages include a hydraulic fluid passage 340 and an ejection fluid passage 345. The sealing channel cover 320 can be seen in FIGS. 4C-1, 4C-1a, and 4C-1b (longitudinal cross-sectional view, axial cross-sectional view, and perspective view, respectively). The sealing passage cover 320 is assembled to form a liquid-tight seal for the introduction ports of both the hydraulic fluid passage 340 and the ejection fluid passage 345. Relatedly, Figures 4C-1b present a three-dimensional depiction of the channel cover 320. This view shows how the cover 320 is shaped to help minimize friction and erosion effects.

[0354] The main control valve 300 also includes a cover pivot 350. The passage cover 320 rotates with the rotation of the passage cover pivot 350. The cover pivot 350 is driven by the passage cover pivot motor 360. The sealing passage cover 320 is positioned by the passage cover pivot 350 (for example, driven by the passage cover pivot motor 360) to: (1) seal the hydraulic fluid passage 340, thereby introducing all the fluid flow from the coiled tubing 100 into the injection fluid passage 345, Or (2) the injection fluid passage 345 is sealed, so that all fluid flows from the coiled tubing 100 are introduced into the hydraulic fluid passage 340.

[0355] The main control valve 300 further includes a wiring duct 310. The wiring duct 310 carries the electric wire 106 and the data cable 107. The shape of the wiring conduit 310 is optionally set to an ellipse at the receiving point of the coiled tubing transition piece 200, and gradually transitions to a point where the wire 106 and the data cable 107 are put into the jet hose carrying system 400 Curved rectangular shape. Beneficially, this curved rectangular shape is used to place the spray hose conduit 420 over the entire length of the spray hose carrying system 400.

[0356] The next component of the external system 2000 is the spray hose carrying system 400. Figure 4D-1 is a longitudinal cross-sectional view of the jet hose carrying system 400. The spray hose carrying system 400 is attached downstream of the main control valve 300. The spray hose carrying system 400 is a substantially elongated tubular body that houses the mooring station 325, the battery pack section 1550 of the internal system, the spray fluid receiving funnel 1570, the sealing assembly 1580 and the connected spray hose 1595. In the view of FIG. 4D-1, only the mooring station 325 can be seen, so that the outline of the jet hose carrying system 400 itself can be seen more clearly.

[0357] FIG. 4D-1a is an axial cross-sectional view of the jet hose carrying system 400 of FIG. 4D.1 taken along the line H-H' of FIG. 4D-1. 4D-1b is an enlarged view of a portion of the spray hose carrying system 400 of FIG. 4D-1. Here, the mooring station 325 can be seen. The spray hose carrying system 400 will be discussed with reference to each of FIGS. 4D-1, 4D-1a, and 4D-1b.

[0358] The spray hose carrying system 400 defines a pair of tubular bodies. The first tubular body is the spray hose duct 420. The spray hose conduit 420 houses, protects, and stabilizes the internal system 1500 (and in particular, the spray hose 1595). As previously presented in the discussion of the internal system 1500, it is the size (specifically, ID), strength and rigidity of the fluid-tight and pressure-tight conduit 420 that provide a channel and in particular a microannular space (FIG. 3D-1a, Figure 4D-2 and Figure 4D-2a are shown as 1595.420) for the injection hose 1595 of the internal system 1500 to "pump down" and reverse along the longitudinal axis of the external system 2000 when running in the production casing 12 To "pump up".

[0359] The spray hose carrying section 400 also has an outer duct 490. The outer duct 490 is arranged along the inner duct 420 and circumscribes the inner duct. On the one hand, the outer tube 490 and the spray hose tube 420 are concentric 2.500"OD and 1.500", respectively

ODHSt100 coiled tubing string. The inner duct or spray hose duct 420 is sealed to the spray fluid passage 345 of the main control valve 300 and is connected to the spray fluid passage. When the valve 300 introduces the high-pressure injection fluid into the injection fluid passage 345, the fluid directly and only flows into the injection hose conduit 420, and then flows into the injection hose 1595.

[0360] There is an annular area 440 between the inner (jet hose) duct 420 and the surrounding outer duct 490. The annular area 440 is also liquid-tight, and is directly sealed to the hydraulic fluid passage 340 of the control valve 300 and connected to the hydraulic fluid passage. When the main control valve 300 introduces the high-pressure injection fluid into the hydraulic fluid passage 340, the fluid directly flows into the pipe bearing annulus 440.

[0361] The spray hose carrying section 400 also includes a wiring chamber 430. The wiring chamber 430 has an axial cross section of a rectangular shape bent upward, and receives the electric wire 106 and the data cable 107 from the wire guide 310 of the main control valve 300. The liquid-tight chamber 430 not only partitions, insulates, accommodates and protects the electric wire 106 and the data cable 107 over the entire length of the spray hose carrying section 400, but also has a bracket shape for supporting and stabilizing the spray hose conduit 420. Note that the spray hose carrying section 400 wiring chamber 430 and the inner (spray hose) duct 420 may or may not be attached to each other and/or to the outer duct 490.

[0362] In addition to accommodating and protecting the electrical wiring 106 and the data transmission cable 107, the wiring duct 430 in the spray hose carrying system 400 also supports the spray at a position slightly higher than the horizontal axis dividing the outer duct 490 into two parts. The horizontal axis of the hose conduit 420. Considering that the strictness of its design restrictions is significantly less than those of the outer layer of CT-based transportation media, especially in terms of chemical resistance and abrasion resistance, different types of materials can be used in its construction, because the wiring duct 430 The exterior will only be exposed to hydraulic fluid-never to jet or fracturing fluid.

[0363] If it is desired to rigidly attach the wiring duct 430 to the spray hose duct 420 or the outer duct 490 or both, additional design criteria may be proposed for the wiring duct. In one aspect, the wiring duct 430 has a width of approximately 1.34" and provides three 0.20" diameter circular channels for electrical wires and two 0.10" diameter circular channels for data transmission cables. To It is understood that, depending on the design purpose, other diameters and configurations of the wiring duct 430 may vary, as long as the annular area 440 open to the flow of hydraulic fluid remains.

[0364] The mooring station 325 can also be seen in FIG. 4D-1. The mooring station 325 is located just downstream of the connection between the main control valve 300 and the spray hose carrying system 400. The mooring station 325 is rigidly attached in the interior of the spray hose duct 420. The mooring station 325 is supported in the spray hose duct 420 by diagonal supports. The diagonal support is hollow, and its interior is used as a liquid-tight and pressure-tight conduit for introducing the electric wires 106 and the data cable 107 into the communication/control/electronic system of the mooring station 325. This is similar to the function of the battery support duct 1560 of the internal system 1500. Whether connected to servo equipment, transmitters, receivers, or other equipment housed in mooring station 325, these equipment are therefore "hard-wired" to operators at ground level 1 via wires 106 and data cables 107 Control system (not shown).

[0365] FIG. 4D-2 provides an enlarged longitudinal cross-sectional view of a portion of the spray hose carrying system 400 of the external system 2000, depicting the same length of the spray hose 1595 operatively containing it. 4D-2a provides an axial cross-sectional view of the jet hose carrying system 400 of FIG. 4D-2 taken along the line H-H'. Note that the cross-sectional view of FIG. 4D-2a is similar to the cross-sectional view of FIG. 4D-1a, except that the duct 420 in FIG. 4D-1a is "empty" to indicate that the spray hose 1595 is not shown.

[0366] The length of the jet hose conduit 420 is quite long and should be approximately equal to the desired length of the jet hose 1595, thereby defining the maximum reachable distance of the jet nozzle 1600 orthogonal to the wellbore 4 and the micro branch channel 15 The corresponding length. The inner diameter specification defines the size of the micro-annular gap 1595.420 between the spray hose 1595 and the surrounding spray hose conduit 420. Its ID should be close enough to the OD of the spray hose 1595 to prevent the spray hose 1595 from becoming bent or kinked, but it must be large enough to provide a sufficient annular area for the solid seal 1580L group through which to pass, Hydraulic fluid can be pumped into the sealed micro-annular gap 1595.420 to help control the rate at which the spray hose 1595 is deployed, or to help withdraw the hose.

[0367] The hydraulic pressure in the sealed micro-annular space 1595.420 keeps the segment of the spray hose (located above the internal tractor system 700) straight and slightly taut. Similarly, the ID of the spray hose duct 420 cannot be too close to the OD of the spray hose 1595 to prevent unnecessary high friction between the two. The OD of the spray hose conduit 420 (plus the ID of the outer conduit 490, minus the outer dimensions of the wiring chamber 430 of the spray hose carrier) defines an annular area 440 through which hydraulic fluid is pumped. Of course, if the inner duct 420 O.D. of the spray hose carrying system is too large, it will therefore cause excessive friction losses when pumping hydraulic fluid. However, if it is not large enough, the inner tube 420 will not have enough wall thickness to support the required internal or external operating pressure. Note that for the subject equipment designed to be deployed in a 4.5" drilling casing, the inner column includes coiled tubing of 1.5" OD and 1.25" ID (ie, 0.125" wall thickness). For example, if it is 1.84#/ft, HSt110, it will provide an internal minimum yield pressure rating of 16,700ps i. Similarly, the outer tube 490 may be constructed of standard coiled tubing. In one aspect, the outer tube 490 includes 2.50" OD. and 2.10" ID, thereby providing a wall thickness of 0.20".

[0368] Traveling from the well to the downhole again, the external system 2000 successively includes the second cross-connect 500, transitioning to the jet hose packing section 600. Figure 4E-1 provides an elongated cross-sectional view of the cross-connecting piece (or transition piece) 500 and the jet hose packing section 600. 4E-1a is an enlarged perspective view of the outer body shape of the transition piece 500 protruding from a circle to a star shape. Axial section lines I-I' and J-J' show the contour of the transition piece 500, which at its beginning suitably matches the size of the outer wall 490 of the jet hose carrying system 400 and at its ends suitably matches the packing The dimensions of the outer wall 690 of the segment 600.

[0369] FIG. 4E-2 shows an enlarged portion of the jet hose packing section 600 and in particular the sealing assembly 650 of FIG. 4E-1. The transition piece 500 and the jet hose packing section 600 will be discussed together with reference to each of these views.

[0370] As the name suggests, the main function of the spray hose isolation section 600 is to "seal" or seal the annular space between the spray hose 1595 and the surrounding inner duct 620. The spray hose packing section 600 is a fixed part of the external system 2000. Passing through the transition piece 500 and partially passing through the packing section 600 is a direct extension of the micro annulus 1595.420. The extension part abuts against the inner surface of the sealing cup constituting the packing and sealing assembly 650 and terminates at the pressure/fluid seal of the spray hose 1595. Just before this end point is the position of the pressure regulating valve, which is shown schematically as part 610 in FIGS. 4E-1 and 4E-2. The valve 610 is used to connect the annulus 1595.420 or isolate the annulus from the hydraulic fluid flowing through the entire external system 2000. The hydraulic fluid flows out from the inner diameter of the coiled tubing transport medium 100 (specifically, from the ID 105.1 of the coiled tubing core 105), and advances through the continuous hydraulic fluid channels 240, 340, 440, 540, 640, 740, 840, 940, 1040 and 1140, then pass through the transition piece 1200 to reach the coiled tubing mud motor 1300, and finally terminate at the tractor 1350. (Or, terminate at some other conventional downhole application operation such as hydraulically set removable bridge plugs or packers). [0371] It is worth noting that the carrier system 40 from the spray hose There are several reasons for the cross-connect 500 from 0 to the packing section 600 as follows:

[0372] First, in the transition piece 500, the free flow of hydraulic fluid from the pipe bearing annulus 440 of the jet hose carrying section 400 will be within the upper (triangular) quarter of the star outer pipe 69 0 Redirected and re-divided. The pressure regulating valve 610 faces the upstream end of the inner duct 620. The pressure regulating valve 610 provides increased or decreased hydraulic fluid (and the same amount of hydraulic pressure) in the micro-annular gap 1595.42 0 between the spray hose 1595 and the surrounding spray hose conduit 420. The operation of this valve 610 provides for the internal system 1500 (and in particular the spray hose 1595) to "pump down" along the longitudinal axis of the production casing 12 and then "pump up" in the reverse direction.

[0373] The upwardly curved rectangular liquid-tight cavity 430 that separates, insulates, accommodates and protects the wires 106 and data cables 107 along the length of the spray hose carrier body 400 transitions into the packing section via the wiring cavity 530 The lower (triangular) quarter 630 of the star-shaped outer body 690 of 600. This keeps the electrical wires 106 and data cables 107 separated, insulated, housed, and protected in the spray hose packing section 600. The star-shaped outer body 690 forms an annulus between itself and the ID of the surrounding production sleeve 12.

[0374] Considering that the distance from the pointed tip of the four-pointed star-shaped outer tube 690 to the relatively pointed tip is only slightly smaller than the ID of the production casing 12, the packing section 600 is also used to make the spray hose 1595 approximately centered in the main The well bore is produced in the casing 12. As will be explained later, this approximate centering will translate through the inner tractor system 700 to beneficially center the upstream end of the whipstock member 1000.

[0375] Recall that the outer diameter of the upstream end of the spray hose 1595 is hydraulically sealed with respect to the inner diameter of the inner tube 420 of the spray hose carrying system 400 by forming the upper seal 1580U and the lower seal 1580L of the spray hose forming a single sealing assembly 1580. . The seals 1580U and 1580L attached to the spray hose 1595 in shape travel upward and downward along the inner duct 420. Similarly, the outer diameter of the downstream end of the spray hose 1595 is hydraulically sealed with respect to the inner diameter of the inner tube 620 of the packing section 600 by the sealing assembly 650 of the packing section 600. Therefore, when the internal system 1500 is "plugged in" (that is, when the upstream battery pack end cap 1520 is in contact with the mooring station 325 of the external system), then the distance between the two sealing components 1580, 620 is approximately the spray soft The full length of the tube 1595. Conversely, when the spray hose 1595 and the spray nozzle 1600 have fully extended into the maximum length achievable transverse bore (or UDP) 15 through the spray assembly 50, then the distance between the two sealing assemblies 1580, 620 can be ignored Excluding. This is because, although the spray hose sealing assembly 158 0 of the internal system basically passes through the entire length of the spray hose carrying system 400 of the external system 2000, the sealing assembly 650 (of the packing section 600 in the external system 2000) is relatively fixed , Because the sealing cup including the sealing assembly 650 must be located between the opposite sealing cup stoppers 615.

[0376] Note also how the alignment of the two sets of opposed sealing cups (eg, the upstream facing upstream group and the downstream facing downstream group placed back to back) including the sealing assembly 650 provides a measure of the pressure difference from the upstream or downstream direction Pressure/fluid seals. In the enlarged view of Fig. 4E-2, these opposed sealing cup sets including the sealing assembly 650 are shown with a longitudinal section of the spray hose 1595 concentrically passing through them.

[0377] As described, the pressure maintained by the pressure regulating valve 610 in the micro-annular space 1595.420 provides a hydraulic action of "pumping the hose down the hole" or reversely "pumping the hose up the hole" . These annular hydraulic pressures are also used to relieve other potentially harmful forces that may be exerted on the spray hose 1595, such as bending force when pushing the hose 1595 downstream, or internal explosive force during spraying. Therefore, in combination with the upper hose sealing assembly 158 0 and the spray hose conduit 420, the spray hose isolation section 600 is used to maintain the spray hose 1595 in a substantially tensioned state. Therefore, the diameter of the hose 1595 that can be used will only be limited by the bending radius imposed by the ID of the production casing 12 of the wellbore and the same pressure level of the hose 1595. At the same time, the length of the available hose 1595 is of course preferably several hundred feet.

[0378] Note that the most likely limit on the length of the hose 1595 will not be anything imposed by the external system 2000, but the hydraulic horsepower that can be distributed to the backward thrust nozzle 1613/1713, so that enough horsepower can be kept focused forward. Used to dig rocks. As one might expect, the length (and the same volume) of the micro branch canal that can be ejected is ultimately related to the strength of the rock in the underground formation. This length limitation is very different from the system proposed in US Patent No. 6,915,853 (Bakke et al.) that attempts to transport the entire spray hose in the equipment itself to the well in a continuous state. That is, in the Bakke et al. patent, the hoses are stacked horizontally and housed in 360 inside the device. Storage and transportation of coiled parts. In this case, the bend radius/pressure hose restriction is not (among other restrictions) imposed by the ID of the casing, but by the ID of the device itself. This results in a significantly smaller hose ID/OD, and therefore in the geometry of the horsepower that can be delivered to Bakke's jet nozzles.

[0379] In operation, after the UDP 15 has been formed and the main control valve 300 is set to close the flow of hydraulic injection fluid to the internal system 1500 and then provide the flow of hydraulic fluid to the external system 2000, the pressure regulating valve 610 may be reversed The direction feeds the stream into the micro-annular gap 1595.420. This downstream-to-upstream force "pumps" the assembly back into the wellbore 4 and "uphole" because the bottom of the seal assembly 1580 faces downwardly on the cup 1580L to restrain flow (and pressure) below the cup.

[0380] The next component within the external system 2000 (again, advancing from uphole to downhole) is the optional internal tractor system 700. 4F-1 provides an elongated cross-sectional view of the tractor system 700 downstream of the jet hose packing section 600. Figure 4F-2 shows an enlarged portion of the tractor system 700 of Figure 4F-1. 4F-2a is an axial cross-sectional view of the internal tractor system 700 taken along the line K-K' of FIGS. 4F-1 and 4F-2. Finally, Figures 4F-2b are enlarged half views of a portion of the internal tractor system 700 of Figures 4F-2a. The internal tractor system 700 will be discussed with reference to each of these four figures.

[0381] It can first be seen that there are two types of tractor systems known. These are the wheel tractor system and the so-called creeping tractor system. These tractor systems are all "external" systems, ie they have fixtures designed to engage the inner wall of the surrounding casing (or, if in an open hole, the wall of the wellbore). In the oil and gas industry, the tractor system is mainly used to advance the logging cable or coiled tubing string (and the connected downhole tools) along the horizontal (or highly inclined) wellbore up or down the well.

[0382] In this assembly 50, a unique tractor system using an "internal" clamp has been developed. This means that the clamp assembly 750 is aligned inwardly to facilitate advancing or retracting the spray hose 1595 relative to the external system 2000. The result of this reversal is that the coiled tubing string 100 and the attached external system 2000 can now be fixed, while the somewhat flexible hose 1595 translates in the borehole 4c. The outwardly aligned electric drive wheels of conventional ("external") tractors are replaced by inwardly directed concave clamps 756. The result is that the inwardly directed concave clamp 756 frictionally attaches the spray hose 1595, with subsequent rotation of the clamp 756 advancing the spray hose 1595 in a direction corresponding to the direction of rotation.

[0383] Pay particular attention to the following results of this reversal: In conventional systems, the relative movement that occurs is the rigid fixture attachment body (ie, coiled tubing) relative to the fixed frictionally attached body (ie, wellbore Wall) relative movement. Conversely, the subject internal tractor system is rigidly attached to the fixed body (ie, the external system 2000) and the clamp 756 rotates to move the spray hose 1595. Therefore, when the internal tractor system 700 is activated, the whipstock member 1000 will already be in its set and operating position; for example, the slider of the whipstock member 1000 will engage the inner wall of the sleeve 12. Therefore, when the external system 2000 is fixed by itself and is stationary in the production casing 12, all advancement/retraction of the spray hose 1595 by the tractor system 700 will occur.

[0384] Secondly, it can be seen that the internal tractor system 700 preferably maintains the star profile of the jet hose packing system 600. The star-shaped profile of the internal tractor system 700 and its four points help center the tractor system 700 within the production casing 12. This is beneficial because when the tractor system 700 is operated, the whipstock member 1000 will be engaged (located relatively close to the tractor system 700 because of the third cross-connect (or transition piece) 800 between them and the upturn The short length of the ring 900, as discussed below), means that the centering of the tractor system 700 is used to align the path of the jet hose 1595 and prevent any improper connection with the jet hose whipstock device 1000 Torque. As can be seen in FIGS. 4F-1 and 4F-2a, the position of the spray hose 1595 is approximately centered within the tractor system 700 and therefore within the production casing 12. This places the hose 1595 in the best position to be fed into the jet hose whipstock device 1000 or retracted from the jet hose whipstock device.

[0385] In addition to centering the hose 1595, another function provided by the star-shaped profile of the tractor system 700 is that it provides internal space for the placement of two opposing sets of clamp assemblies 750. Specifically, the clamp assembly 750 is located in the "dry" working chamber of the two chambers, while providing separate chambers for the wires 106 and data cables 107 (shown in the lower chamber 730) and hydraulic fluid (in the upper chamber 740) . At the same time, a sufficient cross-sectional flow area is reserved in their corresponding annular area 700.12 between the tractor system 700 and the ID of the production casing 12 for conducting fracturing fluid.

[0386] As shown, in the 4.5" production casing 12, the annular area 700.12 open to flow is approximately 10.74 in.², Equal to the equivalent pipe diameter (ID) of 3.69in. Recall that the design goal is to keep the annular flow area greater than or equal to the typical 3.5"OD (2.922" I.D., 10.2#/ft.) internal area of the fracturing column, which is 6.706in.². Then note that if the "star"

The tip-to-tip size of the relatively pointed tip is, for example, 3.95in, and (in order to obtain additional internal volume in the four chambers of the tractor system 700) the star shape is turned into a perfect square, then the external area of the square will be 7.801in²And 4.00"ID. The remaining annular area in the production casing (open to the flow of fracturing fluid) will be 4.765in², Equivalent to a pipe ID of 2.463". Therefore, although the base of each triangular cavity in the star shape can be extended to a certain extent to provide additional internal volume or wall thickness, the outer periphery may not be completely square and still meet the optimal The 3.5" fracturing column standard. Note, however, that there is no reason why the triangular dimensions of each chamber must remain symmetrical; for example, the dimensions can be individually changed to suit the internal volume requirements of each chamber, as long as the 3.5" fracturing column requirements are still preferably met.

[0387] Each of the clamp assemblies 750 includes a micro motor 754 and a motor mount 755 that fixes the motor 754 to the outer wall 790. In addition, each of the clamp assemblies 750 includes a pair of shafts. These represent the clamp shaft 751 and the clamp motor shaft 753. Finally, each of the clamp assemblies 750 includes a clamp gear 752.

[0388] The tractor system 700 also includes a bearing system 760. The bearing system 760 is placed along the length of the inner wall 720. The bearing system 760 isolates the friction force acting on the spray hose 1595 at the contact point of the clamp 756, and eliminates the unnecessary friction force acting on the inner wall 720.

[0389] The backward rotation of the clamp 756 is used to advance the hose 1595, and the forward rotation of the clamp 756 is used to withdraw the hose 1595. The propulsion provided by the clamp 756 helps the jet hose to advance by pulling the jet hose 1595 through the jet hose carrying system 400, the transition piece 500, and the packing section 600, and by pushing the jet hose 1595 into the lateral borehole 15 in itself to help the spray hose advance.

[0390] The diagram of FIG. 4F-1 depicts only two sets of opposed clamp assemblies 750. However, depending on compression, torsion, and horsepower limitations, the clamp assembly 750 can be added to accommodate spray hose 1595 of almost any length and configuration. The additional clamp assembly 750 should increase traction, which may be desirable for the extended length of the transverse bore 15. Although it is presumed that when the pair of clamp assemblies 750 are placed axially opposite to each other in the same plane (as shown in Figure 4F-2.a), the maximum clamping force will be obtained, that is, to maximize the spray hose 1595 However, other arrangements/placements of the clamp system 750 are also within the scope of this aspect of the invention.

[0391] Optionally, the internal tractor system 700 further includes a tensiometer. The tensiometer is used to provide real-time measurement of the tension force on the upstream section of the hose 1595 and the pushing and compression force on the downstream section of the hose 1595. Similarly, the following mechanism may be included, which allows the compression force of each set of clamps 756 to be individually applied to the spray hose 1595 in order to compensate for the uneven wear of the clamps 756.

[0392] Once again the description of the main components of the external system 2000 from upstream to downstream, FIG. 4G-1 shows the internal tractor to the upper swivel (or third) cross-connect 800 and the upper swivel 900 itself. Longitudinal section view. FIG. 4G-1a depicts a perspective view of the cross-connect 800 between its upstream and downstream ends represented by lines L-L' and M-M', respectively. Figure 4G-1b presents an axial cross-sectional view inside the upper swivel 900 along the line N-N'. The third transition piece 800 and the upper swivel 900 are discussed in conjunction with FIGS. 4G-1 and 4G-1a.

[0393] The function of the transition piece 800 is similar to the previous transition section (200, 500) of the external system 2000 discussed herein. For example, the transition piece 800 includes an inner wall 820 and a surrounding outer wall 890, and defines a hydraulic fluid passage 840 therebetween. In a nutshell, the main function of the transition piece 800 is to convert the axial profile of the star-shaped internal tractor system 700 back to the concentric circular profile for the swivel 900, and to meet the 3.5" fracturing column test I .D. Perform this conversion within the limits.

[0394] The upper swivel 900 performs three important functions at the same time:

[0395] (1) First, it allows an indexing mechanism (indexing mechanism) to rotate the connected whipstock member 1000 without twisting any upstream components of the system 50.

[0396] (2) Second, it provides rotation of the whipstock 1000 while maintaining the straight path of the wires 106 and data cables 107 through the wiring chamber 930 between the transition piece 800 and the whipstock member 1000, It also provides

[0397] (3) Third, it provides adaptation to the rotation of the whipstock member 1000 while maintaining the transition piece 800 and the whipstock member

1000 horseshoe-shaped hydraulic fluid chambers 940 of continuous hydraulic flow paths.

[0398] The two sets of bearings 960 (inner bearing) and 965 (outer bearing) are required to meet the above design standards at the same time. In one aspect, the upper swivel 900 has an OD of 2.6 in.

[0399] The outer wall 990 of the upper swivel 900 maintains the circular profile realized by the outer wall 890 of the transition piece 800. Similarly, concentric circular contours are obtained in the middle body 950 and the inner wall 920 of the upper swivel 900. These three continuous and concentric smaller cylinders (990, 950 and 920) provide the inner set of circumferential bearings 960 (between the inner wall 920 and the middle body 950) and the outer set of circumferential bearings 965 (between the middle body 950 and the outer wall 990) . The larger cross-sectional area of the middle body 950 allows it to accommodate the horseshoe-shaped hydraulic fluid chamber 940 and the placement of the arcuate wiring chamber 930. Bearing 960.965 facilitates the relative rotation of three continuous and concentric smaller cylindrical bodies 990, 950 and 920. The bearings 960, 965 also provide for rotatable movement of the whipstock member 1000 under the upper swivel ring 900 (also shown in Figure 4G-1) when in its set and operating position. This in turn provides for changing the orientation of subsequent lateral boreholes ejected from a given set depth in the main borehole 4. In other words, the upper swivel ring 900 allows the indexing mechanism (described in related US Patent No. 8,991,522, and the entire contents of which are incorporated herein) to rotate the whipstock member 1000 without twisting any upstream components of the external system 2000.

[0400] It can also be observed that the upper swivel 900 provides rotation of the whipstock member 1000 while maintaining the straight path of the electrical wires 106 and the data cables 107. The upper swivel 900 also permits the horseshoe-shaped hydraulic fluid chamber 940 to provide rotation of the whipstock member 1000 while maintaining a continuous hydraulic flow path down to the whipstock member 1000 and further.

[0401] Returning to FIG. 4, as described above, the external system 2000 includes the whipstock member 1000. The jet hose whipstock component 1000 is a fully reoriented, resettable, and retractable whipstock device, which is compatible with the previous work, US Provisional Patent Application No. 61/308,060, filed on February 25, 2010. February 23, 2011 The whipstock device described in the filed U.S. Patent No. 8,752,651 and U.S. Patent No. 8,991,522 filed on August 5, 2011 are similar. These patents are again cited and incorporated herein for the discussion of whipstock setting, actuation, and indexing in these applications. Therefore, the detailed discussion of the jet hose whipstocking device 1000 will not be repeated here.

[0402] Figure 4H.1 provides a longitudinal cross-sectional view of a portion of the wellbore 4 of Figure 2. Specifically, the jet hose whipstock member 1000 can be seen. The jet hose whipstock member 1000 is in its set position, wherein the upper curved surface 1050.1 of the whipstock 1050 receives the jet hose 1595. The spray hose 1595 bends across the hemispherical channel defining the surface 1050.1. The surface 1050.1 combines with the inner wall of the production casing 12 to form the only possible path in which the spray hose 1595 can be pushed through the casing outlet "W" and the transverse bore 15, and then from the casing outlet "W" and transversely Retract during drilling.

[0403] The nozzle 1600 is also shown in FIG. 4H.1. The nozzle 1600 is provided at the end of the spray hose 1595. The jet fluid is dispersed through the nozzle 1600 to begin the formation of micro lateral boreholes penetrating the formation. The spray hose 1595 extends downward from the inner wall 1020 of the spray hose whipstock member 1000 to deliver the nozzle 1600 to the whipstock member 1050.

[0404] As discussed in U.S. Patent No. 8,991,522, the spray hose whipstock member 1000 is provided using hydraulically controlled manipulation. On the one hand, hydraulic pulse technology is used for hydraulic control. The sliding part is released by the tension force on the tool. These manipulations are designed in the whipstock member 1000 to comply with the general restrictions of the transport medium (conventional coiled tubing) 100, which can be transported only hydraulically (e.g., by manipulating hydraulic pressure on the ground and therefore downhole hydraulic pressure) and mechanically ( That is, the force is conveyed by pulling the tension of the coiled tubing, or by using the compression force of the coiled tubing itself to drop its weight.

[0405] Here, the jet hose whipstock component 1000 is designed to adapt to the electric wire 106 and the data cable 107 to be further transported downhole. To this end, a wiring chamber 1030 (conductive wire 106 and data cable 107) is provided. The external system 2000 provides power and data to a conventional logging facility 1400 that cooperates with a gyroscope tool, such as a gamma ray-casing collar locator logging tool. This will be directly attached under the conventional mud motor 1300 and coiled tubing tractor 1350. Therefore, for this embodiment, the conventional ("external") hydraulic-electric coiled tubing tractor 1350 immediately below needs to be operated by the hydraulic conduction of the whipstock 1000, and electrical (preferably, optical fiber) conduction is required to operate the continuous The logging probe 1400 below the tubing tractor 1350. 4H-1a and 4H-1b show cross-sectional views of the wiring chamber 1030 along the lines O-O' and P-P' of FIG. 4H-1, respectively.

[0406] Note that the tractor 1350 is placed below the operating point of the jet nozzle 1600, and therefore never requires a conductive jet hose 1595 or high-pressure jet fluid to form the casing outlet "W" or subsequent lateral drilling. Therefore, except for the wellbore itself, there is no ID restriction on the (bottom) coiled tubing tractor 1350. The coiled tubing tractor 1350 can be of the conventional wheel ("external roller") type or the clamp ("creep") type.

[0407] Along the jet hose whipstock member 1000, a hydraulic fluid chamber 1040 is also provided. The wiring chamber 1030 and the fluid chamber 1040 transition from a semicircular profile (roughly matching their counterparts 930 and 940 to the upper swivel 900) to a single end section of a rounded rectangle in which each cavity occupies (straddling When the whipstock member 1050) is contoured, the wiring chamber and the fluid chamber become bifurcated. Once located sufficiently downstream of the whipstock member 1050, the chambers can be reassembled into their original circular pattern, ready to mirror their respective sizes and alignments in the lower swivel 1100. This enables power, data, and high-pressure hydraulic fluid to be transported through the whipstock member 1000 (via their respective wiring chamber 1030 and hydraulic fluid chamber 1040) down to the mud motor 1300.

[0408] Below the whipstock member 1000 and nozzle 1600 but above the tractor 1350 is an optional lower swivel 1100. 4I-1 is a longitudinal cross-sectional view of the lower swivel 1100 located between the jet hose whipstock member 1000 and the cross-connecting piece 1200 and in the production casing 12. The slide 1080 is shown as being disposed within the sleeve 12. Fig. 4I-1a is an axial cross-sectional view of the lower swivel 1100 taken along the line Q-Q' of Fig. 41.1. The lower swivel 1100 will be discussed with reference to FIGS. 4I-1 and 4I-1a.

[0409] The lower swivel 1100 is basically a mirror image of the upper swivel 900. Like the upper swivel 900, the lower swivel 1100 includes an inner wall 1120, a middle body 1150, and an outer wall 1190. In a preferred embodiment, the outer catheter has an OD of 2.60" or slightly smaller. The OD limit of the outer catheter 1190 is the 3.5" fracturing column equivalent test imposed by itself.

[0410] The intermediate body 1150 also houses a wiring chamber 1130 and a hydraulic fluid chamber 1140. The fluid chamber 1140 transports hydraulic fluid to the cross-connect 1200 and finally to the mud motor 1300.

[0411] The lower swivel 1100 also includes a wiring chamber 1130 that houses the wires 106 and the data cables 107. When real-time transmission of logging data (such as gamma rays and casing collar locator "CCL" data) or orientation data (such as gyroscope data) is required, continuous electrical and/or fiber optic transmission may be required. In addition, continuous electrical and/or optical fiber conduction capabilities enable direct guidance of the operation of downhole components from the surface 1 in response to received real-time data.

[0412] Note that the inner duct 920 of the upper swivel 900 defines a hollow core having a size sufficient to receive and conduct the spray hose 1595, while the lower swivel 1100 does not have such a requirement. This is because in the design of the assembly 50 and its method of use, the spray hose 1595 is not intended to travel downstream to a point beyond the whipstock member 1050. Therefore, the innermost diameter of the lower swivel 1100 may actually be composed of a solid core, as depicted in Figure 4I-1a, thereby adding additional strength quality.

[0413] The lower swivel 1100 is located between the jet hose whipstock member 1000 and any necessary cross-connects 1200 and downhole tools such as a mud motor 1300 and a coiled tubing tractor 1350. A logging tool 1400, packer or bridge plug (preferably retractable, not shown) can also be provided. Note that depending on the length of the horizontal part 4c of the well 4, the transport medium

Depending on the respective sizes of the media 100 and the production casing 12, and the friction forces that will be encountered accordingly, more than one mud motor 1300 and/or CT tractor 1350 may be required.

[0414] The final drawing is presented in Figure 4J. Figure 4J depicts the final transition part 1200, conventional mud motor 1300 and (external) coiled tubing tractor 1350. In addition to the tools listed above, the operator can also choose to use a logging probe 1400 composed of a gamma ray-casing coupling locator and a gyroscope logging tool. The gyro logging tool provides real-time data that not only describes the precise downhole position of the whipstock face 1050.1 of the previous jet hose whipstock member 1000, but also describes its initial alignment. This data is used to determine:

[0415] (1) In order to guide the initial lateral drilling along its preferred orientation, how many degrees need to be aligned and re-aligned via the whipstock surface 1050.1; and

[0416] (2) After ejecting the first lateral boreholes, guide the subsequent lateral boreholes along their respective preferred orientations to how much further alignment is required.

[0417] It is expected that when preparing for subsequent hydraulic fracturing treatment in the horizontal main borehole 4c, the initial borehole 15 will be jetted out substantially vertically at or near the same horizontal plane as the main borehole 4c, and the initial borehole 15 will be ejected from the One drill rotates 180. (Again, perpendicularly at or near the same horizontal plane as the main borehole 4c) jetted out the second lateral borehole. However, in thicker formations, especially considering the ability to steer the jet nozzle 1600 in the desired direction, more complicated lateral drilling may be required. Similarly, in a given "perforation cluster" designed to receive a single hydraulic fracturing treatment stage, multiple lateral boreholes (from multiple set points that are usually close together) may be required. The complexity of the design of each lateral borehole is usually a reflection of the hydraulic fracturing characteristics of the main reservoir rock in production zone 3. For example, the operator can design individually profiled lateral boreholes within a given "cluster" to help keep the hydraulic fracturing treatment mainly in the "layer".

[0418] It can be seen that an improved downhole hydraulic injection assembly 50 is provided herein. The assembly 50 includes an internal system 1500 composed of a guideable spray hose and a rotating spray nozzle that can spray out the casing outlet and subsequent lateral drilling in a single step. The assembly 50 also includes an external system 2000. In addition to other components, the external system includes a load-bearing device that can accommodate, transport, deploy, and retract the inner system to enter and exit the main well 4 (regardless of its inclination). The required lateral boreholes are repeatedly constructed during the second trip. The external system 2000 provides annular fracturing treatment (ie, pumping fracturing fluid down the annulus between the coiled tubing deployment string and the production casing 12) To deal with the newly ejected lateral boreholes. When combined with the staged packing provided by the packer and/or positioning temporary or retractable plugs, thus providing a repeated sequence of plug-UDP-fractures, the entire horizontal section 4c can be completed in Completed in a single trip.

[0419] In one aspect, when forming the bend radius 1599 of the spray hose 1595, the assembly 50 can utilize the full ID of the production sleeve 12, thereby allowing the operator to use the spray hose 1595 with the largest diameter. This in turn allows the operator to pump the spray fluid at a higher pumping rate, thereby generating higher hydraulic horsepower at a given pumping pressure at the spray nozzle 1600. This will greatly increase the power output at the jet nozzle, which will achieve:

[0420] (1) Optionally, inject a lateral borehole with a larger diameter in the target formation;

[0421] Optionally, to achieve a longer lateral length;

[0422] Optionally, to achieve a larger erosion penetration rate; and

[0423] Realize the penetration of the oil/gas production area that the existing hydraulic injection technology thinks cannot penetrate with higher intensity and threshold pressure (6m and PTh).

[0424] It is also important that the internal system 1500 allows the jet hose 1595 and the connected jet nozzle 1600 to be propelled without being affected by the mechanical downhole transport medium. The spray hose 1595 is not attached to the rigid working column that "pushes" the hose and the connected nozzle 1600, but instead uses a rigid working column that allows the hose and nozzle to travel longitudinally within the external system 2000 (in both upstream and downstream directions).

Upward) hydraulic system. It is this transformation that enables the subject system 1500 to overcome the "inability to push the rope" limitation inherent in all other hydraulic injection systems to date. In addition, because the subject system does not rely on gravity to propel or align the jet hose/nozzle, system deployment and hydraulic jetting can occur at any angle and at any point within the main wellbore 4 into which the assembly 50 can be "towed" .

[0425] The downhole hydraulic jet assembly allows the formation of multiple micro-drains or boreholes of extended length and controlled direction from a single main wellbore. Each micro branch canal can extend from 10 feet to 500 feet or more from the main borehole. When applied to horizontal wellbore completion in preparation for subsequent hydraulic fracturing ("frac") treatment in certain geological formations, these small lateral wellholes can produce optimized and enhanced fractures (or fracture networks) The geometric structure and subsequent hydrocarbon generation rate and reserves production have significant benefits. By achieving: (1) better extension of the supported fracture length; (2) better restriction of the height of the fracture in the production area; (3) better placement of proppant in the production area; and (4) in the cross phase By further extending the fracture network before the breakthrough, lateral drilling can significantly reduce the necessary fracturing fluids, fluid additives, proppants, hydraulic horsepower, and therefore related fracturing costs required to obtain the desired fracture geometry (if it can be achieved). In addition, for fixed inputs of fracturing fluids, additives, proppants and horsepower, the formation of lateral boreholes in the production area before fracturing can form a significantly larger stimulation reservoir volume, which can increase the well spacing in a given oil field. Degree. In other words, fewer wells may be required in a given oil field, resulting in significant cost savings. In addition, in conventional reservoirs, the emission enhancement obtained from the lateral drilling itself may be completely sufficient to eliminate the need for subsequent hydraulic fracturing.

[0426] As an added benefit, the downhole hydraulic injection assembly 50 and method herein allow operators to apply radial hydraulic injection technology without "damaging" the main wellbore. In addition, the operator can eject radial lateral boreholes from the horizontal main borehole as part of the new completion. In addition, the spray hose can utilize the entire ID of the production casing. In addition, a reservoir engineer or oilfield operator can analyze the geomechanical properties of the target reservoir and then design a fracture network that originates from the customized structure of the laterally drilled directional drilling.

[0427] During well completion, hydraulic jetting of lateral drilling can be performed to enhance fracturing and acidification operations. As mentioned, in fracturing operations, fluids are injected into the formation at a pressure sufficient to separate or split the rock matrix. In contrast, in acid treatment, the acid solution is pumped at a bottom hole pressure that is less than the pressure required to rupture or fract a given production zone. (However, in acid fracturing, the pumping pressure intentionally exceeds the formation fracture pressure). Examples where pre-increased injection of lateral drilling may be beneficial include:

[0428] (a) Before hydraulic fracturing (or before acid fracturing), in order to help limit the propagation of fractures (or fracture networks) in the production zone and before any boundary layer rupture or any cross-stage pressure may occur The length of the fracture (net) formed at a large distance from the main well hole before the fracture; and

[0429] (b) Before the acid can be "consumed", and before the pumping pressure approaches the formation fracture pressure, use lateral drilling to increase production by treating the matrix acid far beyond the area near the wellbore. The downhole hydraulic jetting assembly 50 and method herein also permit operators to perform acid fracturing operations through a network of lateral boreholes formed by using very long jetting hoses and connected nozzles that are pushed through the rock matrix. In one aspect, the operator can determine the direction of pressure drop in a reservoir, such as from an adjacent production well. The operator can then form one or more lateral boreholes in orthogonal directions, and then perform acid fracturing through the boreholes. In this case, the crack will open in the direction of the pressure drop.

[0430] The operator may alternatively consider or determine the flow of acid (or other formation-dissolving fluid) in the rock matrix. In this case, the acid is not injected at the pressure of the formation separation, but allows the formation of pores in the direction of the pressure drop. The operator can also perform the following steps: create a pressure boundary in the reservoir by injecting fluid into the first lateral borehole in a first direction, and then pass the second lateral borehole in a second direction that deviates from the first direction. Perform acid fracturing on the hole. The acid

Melting cracks are in the form of wormholes in a direction that does not intersect the pressure boundary.

[0431] The downhole hydraulic injection assembly 50 and method herein also allows the operator to predetermine the injection path of the lateral borehole. This drilling can be controlled in terms of length, direction or even shape. For example, curved boreholes or each "group" of curved boreholes may be intentionally formed to further increase the SRV exposure of the formation 3 to the wellbore 4c. The borehole may optionally be formed in a spiral form to further expose the formation 3 to the borehole 4c.

[0432] The downhole hydraulic jetting assembly 50 and method herein also allow operators to re-enter existing wells that have been completed in unconventional formations, and to "re-press" by using hydraulic jetting technology to form one or more lateral boreholes. "Crack" well hole. The hydraulic injection process can use the hydraulic injection assembly 50 in any embodiment of the present invention. There is no need for workover rigs, ball falling/catching machines, drillable bases or sliding sleeve components.

[0433] The downhole hydraulic jet assembly 50 and method herein also allow operators to form a network of lateral boreholes that includes lateral micro lateral boreholes formed separately from newly formed boreholes. This method can include the following steps:

[0434] (a) Partially withdraw the spray hose and the connected nozzle from the first transverse borehole;

[0435] (b) Identify the position of the jet nozzle in the rock matrix;

[0436] (c) Reorient the jet nozzle; and

[0437] (d) Inject the hydraulic jet fluid through the jet hose and the connected jet nozzle, so as to excavate the first side micro lateral borehole separated from the first lateral borehole in the rock matrix in the production area.

[0438] The method may also include:

[0439] (e) Withdraw the spray hose and the connected nozzles from the micro transverse borehole on the first side;

[0440] (f) Repeat step (a) to step (c); and

[0441] (g) Inject the hydraulic jet fluid through the jet hose and the connected jet nozzle, so as to excavate the second side micro transverse borehole separated from the first micro transverse borehole in the rock matrix in the production area.

[0442] The method may further include (h) repeating step (a) to step (g) at least once to form a lateral micro-lateral drilling network configured to optimize the subsequent hydraulic fracturing treatment from (1), (ii ) Subsequent acid treatment, or (iii) stimulated reservoir volume (SRV) of both. Alternatively, the method may also include:

[0443] (i) Repeat step (a) to step (g) at least once to form a lateral micro lateral drilling network;

[0444] (j) Injecting fracturing fluid through the annulus formed between the outer catheter and the surrounding production casing;

[0445] (k) Injecting fracturing fluid into a network of lateral micro-lateral boreholes at an injection pressure sufficient to split the rock matrix in the production area to form a network of hydraulic fractures; and

(1) Using (i) inclinometer, (ii) microseismic survey, (iii) environmental microseismic survey, (iv) microphone or their combination real-time monitoring of the network of hydraulic fractures originating from the network of micro lateral boreholes And the growth of the stimulated reservoir volume (SRV).

[0447] The method may then include the production of hydrocarbon fluids from a network of lateral micro lateral boreholes.

[0448] Based on the above-mentioned downhole hydraulic injection assembly 50, a unique method of forming a well hole can be performed. In one embodiment, the method includes:

[0449]-Use the transport medium to extend the spray hose into the horizontal section of the main borehole, the spray hose has a nozzle at the distal end;

[0450]-When the spray hose and the connected nozzle are advanced to the surrounding formation, the spray fluid is injected through the spray hose and the connected nozzle, thereby forming a first transverse drill separated from the horizontal section of the first wellbore exit position hole;

[0451]-Withdraw the jet hose and the connected nozzle from the first lateral well hole at the exit position of the first well hole, and

And reposition the nozzle to the exit position of the second well hole in the same trip (either by placing the whipstock at a different depth, or by placing the whipstock at the same depth but at a different angle orientation); as well as

[0452]-When the jet hose and the connected nozzle enter the surrounding formation, the jet fluid is injected through the jet hose and the connected nozzle, thereby forming a second transverse drill separated from the horizontal section at the exit position of the second well hole hole.

[0453] In this method, advancing the spray hose into each of the lateral boreholes is at least partly by hydraulic pressure acting on the seal assembly along the spray hose (such as at the upstream end of the spray hose). To be done. In addition, advancing and subsequently retracting the spray hose does not require crimping or unrolling the spray hose in the wellbore.

[0454] In one embodiment, pushing the spray hose into each of the lateral boreholes is also accomplished by mechanical force applied by a rotating clamp of a mechanical tractor assembly located in the borehole, wherein the clamp Frictionally engages with the outer surface of the spray hose.

[0455] In another embodiment, pushing the spray hose into each of the lateral boreholes is accomplished by a forward thrust generated by flowing spray fluid through a backward thrust nozzle located in the spray assembly. These backward thrust nozzles are specifically located in the jet nozzle, or in a combination of the nozzle and one or more coaxial jet collars strategically placed along the jet hose. Preferably, the nozzle permits the spray fluid to flow through the backward thrust nozzle in response to a designated hydraulic pressure level. In this case, the flow of fluid through the backward thrust nozzle will only be activated after the jet hose has been pushed into each borehole at least 5 feet from the main borehole. Then usually when the jet hose has extended a significant length from the main wellbore so that only the backward thrust nozzle in the nozzle can no longer generate significant pulling force to continue to drag the entire length of the jet hose along the transverse borehole, the coaxial jet is located The additional backward thrust nozzles in the collar are actuated by incrementally increasing operating pressures.

[0456] In a related aspect, the method can include monitoring tensiometer readings at the ground. The tensiometer reading indicates the drag force experienced by the spray hose when forming a transverse borehole. In this case, in response to a designated tensiometer reading, fluid flow is actuated in each of the plurality of boreholes through the backward thrust nozzle.

CN 107429552 Β