Spray hose carrier system

Abstract

Provided herein is a jetting hose carrier system comprising: an elongated inner conduit sized to slidably receive a jetting hose and to serve as a jetting hose carrier, forming a microannulus between the jetting hose and the surrounding inner conduit, the microannulus sized to prevent bending of the jetting hose; an elongated outer conduit surrounding the inner conduit, forming an annular region between the inner conduit and the surrounding outer conduit, the outer conduit sized to extend into a production casing string within a wellbore while accommodating a stimulation treatment between the outer conduit and the surrounding production casing; a wiring chamber housing electrical wires, data cables, or both, in the annular region between the inner conduit and the outer conduit and extending along the length of the outer conduit; a fluid chamber formed within the annular region; and a fluid pressure regulating valve located proximate a distal end of the inner conduit, the pressure regulating valve configured to move fluid between the fluid chamber and the microannulus to effect movement of the jetting hose within the inner conduit.

Description

[0001] This application is a divisional application of Chinese invention patent application No. 2016800186597, filed on January 29, 2016, entitled "Downhole Hydraulic Jetting Assembly".

[0002] Statement regarding federally sponsored research or development

[0003] not applicable.

[0004] Names of the parties to the collaborative research agreement

[0005] not applicable.

[0006] Statement of related applications

[0007] This application claims the benefit of U.S. Provisional Patent Application No. 62 / 198,575, filed July 29, 2015, entitled “Downhole Hydraulic Jetting Assembly, and Method for Forming Mini-Lateral Boreholes”. This application also claims the benefit of U.S. Provisional Patent Application No. 62 / 120,212, filed February 24, 2015, with the same title.

[0008] This application also files a continuation-in-part of U.S. Patent Application No. 14 / 612,538, filed February 3, 2015, entitled “Method of Testing a Subsurface Formation for the Presence of Hydrocarbon Fluids.” That U.S. patent application is a divisional of U.S. Patent No. 8,991,522, granted March 31, 2015.

[0009] All of these applications are incorporated into this paper by reference. Background Technology

[0010] This section aims to introduce selected aspects of the technology, which may be associated with various embodiments of this disclosure. It is believed that this discussion helps to provide a framework for a better understanding of specific aspects of this disclosure. Accordingly, it should be understood that this section should be interpreted in this light and not necessarily as an admission of prior art. Technical Field

[0011] This disclosure relates to the field of well completion. More specifically, this disclosure relates to well completion and production enhancement for hydrocarbon-producing formations by using hydraulic jetting assemblies to generate small-diameter boreholes from existing boreholes. This disclosure also relates to the controlled generation of multiple lateral boreholes extending several feet into the subsurface formation during a single trip, thereby forming a designed borehole "group".

[0012] Technical Discussion

[0013] When drilling oil and gas wells, a drill bit pushed downwards at the bottom of the drill string creates a near-vertical borehole through the formation. After drilling to the intended bottom hole location, the drill string and drill bit are removed, and the borehole is lined with a casing string. This creates an annular zone between the casing string and the formation penetrated by the borehole. Specifically, in vertical boreholes or the vertical section of horizontal wells, cementing is performed to fill or "crush" the entire annular volume with cement along part or all of the borehole's length. The combination of cement and casing reinforces the borehole and facilitates zonal isolation and subsequent completion of certain sections of the potential hydrocarbon-producing zone behind the casing.

[0014] Over the past two decades, advancements in drilling technology have enabled oil and gas operators to economically "kick-off" and shifted borehole trajectories from largely vertical to largely horizontal orientation. Now, each of these boreholes typically has a horizontal "pillar" exceeding one mile in length. This significantly increases the borehole's exposure to the target hydrocarbon-bearing formation (or "producing area"). For example, for a given target producing area with 100 feet of (vertical) thickness, a mile of horizontal pillar exposure in a horizontal borehole results in 52.8 times the producing area exposed by a conventional vertical borehole with 100 feet of exposure.

[0015] Figure 1A A cross-sectional view of a horizontally oriented borehole 4 is provided. It can be seen that borehole 4 has been formed from the surface 1, through several formations 2a, 2b…2h, down to the hydrocarbon-generating formation 3. The subsurface formation 3 represents the “producing area” for oil and gas operators. Borehole 4 includes a vertical section 4a above the producing area and a horizontal section 4c. The horizontal section 4c defines a column base 4b and a column tip 4d, and an elongated support extending between them through the producing area 3.

[0016] With the completion of borehole 4, several casing strings with gradually decreasing outer diameters have been cemented into borehole 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 (referred to as the guide pipe), which is a short section separated from and directly above the surface casing, is not shown.) One of the main functions of surface casing 6 is to isolate and protect shallower, freshwater-bearing groundwater layers from contamination by any borehole fluids. Therefore, the guide pipe and surface casing 6 are almost always completely cemented back to the surface 1.

[0017] The process of drilling and then bonding progressively smaller casing strings is repeated several times until the well reaches completion depth. In some cases, the final casing string 12 is lined, i.e., the casing string not restrained back to the surface 1. The final casing string 12, referred to as the production casing, is also typically cemented into place 13. In the case of horizontal completion, the production casing 12 can be cemented, or a layer isolation can be provided using an external casing packer (“ECP”), an expansion packer, or some combination thereof.

[0018] Well completion may include additional tubular components. These tubular components include one or more production tubing strings placed within the production casing or liner. Figure 1A (Not shown). In vertical completions, each tubing string extends from the surface 1 to a designated depth near the production section 3 and may be attached to a packer (not shown). The packer is used to seal the annular space between the production tubing string and the surrounding casing 12. In horizontal completions, the production tubing is typically (with or without a packer) positioned at or near the foot of the borehole 4.

[0019] In some cases, production area 3 cannot effectively allow fluid to flow to ground level 1. When this occurs, the operator can install artificial lifting facilities ( Figure 1A (Not shown) as part of the borehole completion. Artificial lift facilities may include a downhole pump connected to a surface pumping unit via a series of sucker rods extending within the tubing. Alternatively, an electrically driven submersible pump may be placed at the bottom of the production tubing. Air lift valves, hydraulic jet pumps, plunger lift systems, or various other types of artificial lift facilities and techniques may also be used to assist fluid flow to the surface.

[0020] As part of the completion process, wellhead assembly 5 is installed at surface 1. Wellhead assembly 5 is used to control borehole pressure and guide the flow of production fluid at surface 1. Fluid collection and treatment facilities may also be installed. Figure 1A(Not shown), such as pipes, valves, separators, dehydrators, gas desulfurization units, and oil-water storage tanks. After the production area is completed, install any necessary downhole fittings, artificial lift facilities, and wellhead equipment 5, and then production operations can begin. Maintain controlled borehole pressure and properly separate and distribute the produced borehole fluid.

[0021] In the United States, many wells currently being drilled are primarily for extracting oil and / or natural gas, and possibly liquefied natural gas, from areas previously considered impenetrable and unable to produce hydrocarbons in economically viable quantities. These “compact” or “unconventional” formations can be sandstone, siltstone, or even shale formations. Alternatively, such unconventional formations can include coal seam methane. In any case, “low permeability” generally refers to a rock segment with a permeability of less than 0.1 millidarcy.

[0022] To enhance hydrocarbon extraction, particularly in low-permeability formations, production enhancement techniques can be employed in the completion of the production area after (i.e., following perforation of the production casing or lining). These techniques include hydraulic fracturing and / or acidizing. Additionally, to create one or more new directional or horizontally completed boreholes, “open-hole” boreholes can be formed from the primary borehole. This allows the well to penetrate along the plane of the subsurface formation, increasing exposure to the production area. Horizontally completed boreholes allow the production casing to traverse or “source” multiple fracturing planes where the natural or hydraulically induced fracturing planes of the formation are vertical. Correspondingly, vertically oriented boreholes are typically limited to a single hydraulically induced fracturing plane per production area, while horizontal boreholes can be perforated and hydraulically fractured at multiple locations or “steps” along a horizontal strut.

[0023] Figure 1A A series of fracturing half-planes 16 are shown along the horizontal section 4c of borehole 4. The fracturing half-planes 16 represent the orientation of fractures that will form in connection with the perforation / fracturing operation. According to geomechanical principles, fracturing planes will generally form along a direction perpendicular to the minimum principal stress plane in the rock matrix. More simply, in most boreholes, when the horizontal section of the borehole is located more than 3,000 feet below the surface and sometimes as shallow as 1,500 feet, the rock matrix will fracture along a vertical line. In this case, hydraulic fractures will tend to propagate from the perforation 15 of the borehole along a vertically 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 strut 4c of the horizontal borehole 4 is ideally oriented parallel to it, such that multiple fracturing planes 16 will penetrate the borehole orthogonal to or approximately orthogonal to the horizontal strut 4c of the borehole, as shown below. Figure 1A As shown.

[0024] The desired density of the perforated and fracturing sections along the horizontal support 4c within production area 3 is optimized by calculating the following:

[0025] • The estimated final recovery rate (“EUR”) of hydrocarbons to be discharged from each fracture, which requires calculating the increased reservoir volume (“SRV”) that each fracturing treatment will connect to the borehole via its corresponding perforation; subtract (less)

[0026] • Any overlap with the corresponding SRV of the boundary fracturing segment; plus (coupled with)

[0027] • The expected time allocation for extracting hydrocarbons from each fracture; with

[0028] • The ratio of the incremental cost of adding another perforation / fractured section (versus).

[0029] The ability to repeatedly complete vertical wells along a single horizontal borehole enables the economical and feasible discovery of hydrocarbon reservoirs in unconventional reservoirs, particularly shale, within a relatively short period. This revolutionary technology has profound implications, as current Baker Hughes Rig Count data in the United States indicates that only about a quarter (26%) of wells drilled in the US are classified as “vertical,” while the other three-quarters are classified as “horizontal” or “directional” (62% and 12%, respectively). That is, approximately two out of every three wells drilled in the US are currently horizontal.

[0030] Compared to vertical wells, the additional costs of drilling and completing horizontal wells are not insignificant. In fact, it is not uncommon for the highest costs of drilling and completing horizontal wells (“D&C”) to be many times (two, three, or more) of their corresponding vertical wells. Depending on the geological basin, and particularly the geological features 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 those involved in controlling the radius of curvature at the start of drilling, guiding the drill bit and drilling assemblies (including MWD and LWD techniques) in the preferred horizontal trajectory of the borehole 4 initially obtained and then maintained within the production area 3, and the overall length of the horizontal section 4c. The critical process of obtaining borehole isolation between fracturing stages (due to additional cementing and / or ECP) ​​typically adds a significant increase to the completion costs, as does the cost of “bridge plug perforation” or casing or port (usually ball-actuated) completion systems.

[0031] 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.

[0032] For any horizontal well to be economically successful, achieving a satisfactory hydraulic fracturing geometry within the completed production area is crucial. Many factors can contribute to the success or failure of achieving the desired geometry. These include the rock properties of the production area, pumping limitations imposed by the borehole construction and / or surface pumping facilities, and the characteristics of the fracturing fluid. Additionally, proppant of various aperture (mesh) sizes is typically added to the fracturing mixture to maintain the hydraulically pressure-induced fracture width in a "spread" state, thereby improving the conductivity of the produced hydrocarbon fluids.

[0033] Typically, to achieve the desired fracture characteristics (fracture width, fracture conductivity, and especially fracture half-length) within a production area, a substantial overall fracture height exceeding the production area boundaries must be formed. Fortunately, vertical extra-layer fracture height growth is generally limited to a few times the overall production layer thickness (i.e., tens or hundreds of feet), thus posing no threat of contamination to much shallower freshwater sources that are 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–November 2, 2012).

[0034] Nevertheless, this increases the amount of fracturing fluid and proppant required at various "fracking" stages, and further increases the required pumping horsepower. It is known that for a typical fracturing operation, a significant portion of the cost of fracturing fluid, fluid additives, proppant, hydraulic ("pumping") horsepower (or "HHP"), and their associated costs, is spent on the non-productive portion of the fracture. This represents a problem amounting to billions of dollars annually in the United States alone.

[0035] Furthermore, complicating the planning of horizontal wells is an uncertainty associated with fracture geometry in unconventional reservoirs. Based on analysis of real-time data from tiltmeter and microseismic surveys, many experts believe that fracture geometry in less permeable and particularly more fracture-prone unconventional reservoirs can produce highly complex fracture geometries. That is, compared to the relatively overly simplistic biplane elliptical model considered to conform to the most conventional reservoirs (such as... Figure 1A (As shown in the idealized demonstration) Conversely, fracture geometry in unconventional reservoirs can be difficult to predict.

[0036] In most cases, the length and complexity of far-field fractures are considered detrimental (rather than advantageous) due to excessive fluid leakage and / or reduced fracture width (which may cause earlier sand filtration). Therefore, whether fracture complexity (or its inadequacy) enhances or reduces the fracture network will affect the SRV that the wellbore can drill, which is usually determined on a case-by-case basis (e.g., on a reservoir-by-reservoir basis).

[0037] Therefore, it is desirable, particularly for horizontal completions in tight reservoirs, to gain greater control over the geometric growth of the primary fracture network extending vertically outward from the horizontal pillar 4c. It is also desirable to extend the length of the fracture network orientation without significantly encroaching on the boundary of the horizontal production zone 3. Furthermore, it is desirable to reduce the well density required to drill a given reservoir volume by increasing the efficiency of the fracture network between boreholes using two or more hydraulically jetted micro-spurs along the horizontal pillar. Even further, it is desirable to provide this guidance, constraint, and enhancement of the SRV by creating one or more micro-spur boreholes as an alternative to conventional casing ports provided by conventional completion procedures requiring perforation, sliding sleeves, etc.

[0038] Therefore, there is a need for downhole assemblies with injection hoses and directional drilling units, allowing the assemblies to be delivered to any section of the borehole, regardless of its orientation, including extended horizontal struts. There is also a need for hydraulic jetting systems that provide injection hoses that are turned substantially 90° opposite to the casing exit point, preferably utilizing the entire casing inner diameter as the bending radius of the injection hose, thereby providing the maximum possible inner diameter of the injection hose and thus the maximum possible hydraulic horsepower to the nozzle. There is also a need for a system comprising a directional drilling unit capable of being deployed on a coiled tubing string, wherein the directional drilling unit can be reoriented in discrete, known increments and without relying on the rotation of the tubing translated downhole from the surface.

[0039] Additional requirements exist, which are discussed in some embodiments herein. There is a need for improved methods of forming lateral boreholes using hydraulic directional forces, where the desired length of the jetting hose can be transported even from the horizontal borehole. Furthermore, there is a need for methods of forming micro-lateral boreholes separated from the horizontal support, which help confine subsequent SRVs to, but not significantly beyond, the production area boundaries. Additionally, there is a need for methods that can transport and manipulate the directional drilling unit and jetting hose using hydraulic and / or mechanical thrust capable of moving the jetting nozzle and connected hose into the formation, repeatedly retrieving, reorienting, redeploying, and reoperating the directional drilling unit and jetting hose at as many desired main borehole depths and lateral azimuth orientations as possible, to generate multiple micro-lateral boreholes not only in the vertical portion of the borehole during a single trip, but also in the height-oriented and even horizontal portions of the borehole. Furthermore, there is a need for methods capable of transporting the jetting hose in a deployed state such that the bending radius within the production casing and along the directional drilling unit is the most stringent bending limit that the hose must meet.

[0040] Furthermore, there is a need for methods for hydraulically fracturing micro-lateral boreholes, in which the micro-lateral borehole is ejected from a horizontal support in the borehole, subsequently forming micro-tributaries, without requiring the ejection hose, directional drilling device, and delivery system to be pulled out of the main borehole. Finally, there is a need for methods that remotely control the erosion path of the ejection nozzle and connected hydraulic hoses, allowing the profile of the micro-lateral borehole or a "group" of micro-lateral boreholes to be optimally configured to control the SRV geometry formed by subsequent production enhancement processes. Summary of the Invention

[0041] The systems and methods described herein offer various benefits in well completion activities for oil and gas wells. This paper presents a downhole hydraulic jetting assembly. This assembly is used to inject multiple lateral boreholes into the subsurface formation from an existing main borehole. The assembly essentially consists of two synergistic systems:

[0042] (1) An internal hose system (“internal system”) defining an elongated jet hose having a jet fluid inlet at its proximal end and a jet nozzle at its distal end, the jet nozzle being configured to be directed to and pass through the main borehole outlet location; and

[0043] (2) An external hose delivery, deployment and retrieval system (“External System”) that extends on the work column to provide a defined path of travel (including a directional drilling device) within the borehole, wherein the External System is configured to load an elongated jet hose into the borehole and “push” it against a directional drilling device disposed in the borehole to push the jet nozzle forward into the surrounding formation.

[0044] In the case of casing drilling, a window is formed through the casing using a jet hose and connected nozzle, subsequently creating a lateral borehole into the hydrocarbon-bearing area. The construction and operation of these two synergistic systems allow the directional drilling tool to be reoriented and / or repositioned, and the jet hose to be redeployed into the casing and retrieved, enabling the jetting of multiple casing exits and lateral boreholes in a single trip.

[0045] As described, the internal system includes a jet hose with a proximal end and a distal end. A fluid inlet is located at the proximal end, while the jet nozzle is positioned at the distal end. Preferably, a power source, such as a battery pack, is located at the proximal end to provide power to the electrical components of the jet assembly.

[0046] The external system comprises a pair of tubular bodies. These represent an outer guide tube and an inner guide tube. The outer guide tube has an upper end, a lower end, and an internal bore between them. The upper end is configured to be operatively attached to the work column or "pipeline delivery medium" for extending the injection hose assembly into the production casing. The inner guide tube is located within the bore of the outer guide tube and serves as the injection hose carrier. The injection hose carrier slidably receives the injection hose during operation.

[0047] A micro-annular gap is formed between the injection hose and the surrounding injection hose carrier. The micro-annular gap is sized to prevent the injection hose from bending as it slides within the injection hose carrier during operation of the assembly. The micro-annular gap is also configured to allow the operator to control the amount and direction of the hydraulic fluid between the injection hose and the surrounding inner conduit, which is then converted into a fluid force that can: (1) maintain the injection hose in the taught configuration when it is pushed downstream; or (2) push the injection hose upstream when it is retrieved into the inner conduit (or injection hose carrier).

[0048] The injection hose assembly also includes a directional guide component. The directional guide component is located below the lower end of the outer conduit. The directional guide component includes a recessed surface for receiving and guiding the injection nozzle and the connected hose during operation of the assembly.

[0049] The injection hose assembly is configured to (i) transfer the injection hose out of the injection hose carrier and against the directional drilling face to the desired point at the borehole outlet by a transfer force, (ii) guide the injection fluid through the injection hose and the connected injection nozzle upon reaching the desired point at the borehole outlet until an outlet is formed, (iii) continue injection along the operator’s designed geographic trajectory to form a transverse borehole into the rock matrix within the production area, and then (iv) after forming the transverse borehole, pull the injection hose back into the injection hose carrier to allow optional adjustment of the position of the directional drilling device within the borehole.

[0050] On one hand, the directional drilling rig is configured such that one face of the directional drilling rig provides a bending radius for the injection hose across the entire borehole. In the case of casing drilling, the injection hose bends across the entire inner diameter of the production casing. Thus, the hose contacts the production casing on one side, bends along the face of the directional drilling rig, and then extends to the casing outlet on the opposite side of the production casing. This bending radius of the injection hose across the entire ID (inner diameter) of the production casing provides the maximum possible diameter of the injection hose used, which in turn provides the maximum hydraulic power transmitted through the injection hose to the injection nozzle.

[0051] The external system is configured to extend on a standard coiled tubing string, or, in a preferred embodiment, on a bundled coiled tubing product including wiring. Furthermore, the external system is configured to contain, transport, deploy, and retrieve the injection hose of the internal system in a manner that maintains the hose in an deployed state. Therefore, the minimum bend radius that the hose must meet is the bend radius within the production casing along the build-up face at the desired casing exit point. Additionally, the coordinated coiled tubing-based transport of these internal / external systems allows for the simultaneous operation of other conventional coiled tubing tools in the same downhole tool string. These tools include packers, mud motors, downhole (external) traction machines, logging tools, and / or retrieveable bridge plugs located below the build-up assembly.

[0052] The external system may optionally be equipped with a unique electrically driven rotatable jet nozzle. The nozzle can mimic the hydraulic forces of a conventional hydraulic perforator, thus eliminating the need for a separate milling operation to form the casing outlet. The nozzle may optionally include a rearward thrust nozzle around the body to enhance forward thrust and borehole cleaning during microchannel formation, and to provide cleaning and possible borehole extension during pull-out.

[0053] Within the external system, the regulation of two hydraulic pressures—(a) the hydraulic pressure of the jet fluid pushing the internal hose system downstream and (b) the hydraulic force of the hydraulic fluid pushing the hose system upstream and back—is controlled by valves at the top and base of the carrier system, and by sealing assemblies at the top of the jet hose and the base of the carrier system. Additionally, the external system may include an internal traction system that provides mechanical force to selectively push the jet hose upstream or downstream.

[0054] Known jetting systems typically rely solely on the "slack-off" weight of a continuously coiled tubing and / or jet hose string to provide thrust. However, this source of thrust is quickly dissipated by the helical bends in highly directional or horizontal boreholes (e.g., due to friction between the jet hose and borehole fittings). Once the helical bend is reached, no further thrust can be obtained from the additional slack-off of the string attached to the surface. This paper overcomes the "unable to push the rope" limitation of other systems in a unique way through a combination of hydraulic pressure and mechanical (traction) force, enabling the formation of microchannels off-center from highly displaced horizontal boreholes.

[0055] The hydraulic injection assembly also includes a wiring chamber along components of the external system. The wiring chamber provides wiring that supplies power to rechargeable batteries used for the injection nozzles and optionally other conventional downhole tools, such as logging tools. The wiring chamber may also optionally provide data cables, enabling server / transmitter / receiver systems, logging tools, etc., to feed data back to the surface. This provides real-time control of both power and data.

[0056] The hydraulic jetting assembly described herein can produce lateral boreholes exceeding 10 feet, 25 feet, or even 300 feet, depending on the length of the jetting hose and its carrier, as well as the hydraulic jetting resistance of the host rock. These jetting resistance properties can include the petrologically inherent compressive strength, pore pressure, or other characteristics such as cohesion of the host rock matrix. The boreholes produced by the hydraulic jetting assembly can have a diameter of approximately 1.0” or greater. These lateral boreholes can be formed at a significantly higher penetration rate than any previous system, and these boreholes typically complete a 90° turn of the jetting hose within the production casing. This is because, in some embodiments, the hydraulic jetting assembly presented here utilizes the entire casing ID as the bend radius of the jetting hose, thus enabling the use of larger diameter hoses, thereby allowing higher hydraulic power to be transmitted to the jetting nozzle.

[0057] This system will have the capability to create lateral boreholes from sections of the horizontal and highly directional main borehole that were previously considered inaccessible. Lateral boreholes can now be hydraulically ejected anywhere conventional coiled tubing can be pulled within the casing borehole. Similarly, significantly higher efficiency will be achieved as multiple lateral boreholes can be created from a single trip. Provided satisfactory fracturing hydraulics (pumping rate and pressure) are achieved through the coiled tubing annulus, “perforation and fracturing” can be performed on the entire horizontal support of a newly drilled well without the need for fracturing plugs, sliding sleeves, or drop balls.

[0058] In one embodiment, multiple lateral boreholes and optional lateral micro-branch boreholes together form a network or cluster of ultra-deep vaults (SRVs) in the rock matrix. The operator can design such a network to optimally discharge production areas. Preferably, the lateral boreholes extend away from the main borehole at a normal or right angle and extend to the upper or lower boundary of the production area. Other angles can also be used to utilize the richest portions of the production area. In any respect, the method can then include hydrocarbon production. Hydrocarbons can be produced from the network of lateral boreholes when multiple boreholes are formed from the borehole at different orientations and depths. Furthermore, the operator can choose to perform subsequent formation fracturing operations from the lateral boreholes to further extend the SRV.

[0059] Given the system's ability to controllably "steer" the injection nozzles to chart paths for micro-lateral boreholes (or, clusters of micro-branch boreholes), subsequent enhancement processes can be more optimally "guided" and constrained within the production area. Coupled with real-time feedback from the actual enhancement (particularly fracturing) stage geometry and resulting SRVs (such as microseismic surveys from microseismometers, tiltmeters, and / or the environment), the profiles of subsequent micro-branch boreholes can be customized to better guide each enhancement stage prior to pumping. Attached Figure Description

[0060] This document includes certain illustrations, diagrams, and / or flowcharts to provide a better understanding of the invention. However, it should be noted that the accompanying drawings only illustrate selected embodiments of the invention and should not be construed as limiting the scope, as the invention acknowledges other equally effective embodiments and applications.

[0061] Figure 1A This is a cross-sectional view of an exemplary horizontal borehole. A half-fracture plane along the horizontal strut of the borehole is shown in 3-D to illustrate the fracture stage and fracture orientation relative to the subsurface formation.

[0062] Figure 1B yes Figure 1A An enlarged view of the horizontal portion of the borehole. Conventional perforations are replaced by ultra-deep perforations or micro-lateral perforations to create fracture wings.

[0063] Figure 2 This is a longitudinal cross-sectional view of a downhole hydraulic injection assembly according to one embodiment of the present invention. The assembly is shown as being located within a horizontal section of the production casing. The injection assembly has external and internal systems.

[0064] Figure 3 yes Figure 2 A longitudinal cross-sectional view of the internal system of the hydraulic injection assembly. The internal system extends from the upstream battery pack end cap (which mates with the mooring station of the external system) at its proximal end to an elongated hose with an injection nozzle at its distal end.

[0065] Figure 3A yes Figure 3 A three-dimensional cross-sectional view of the battery pack section of the internal system.

[0066] Figure 3B-1 This 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 for receiving fluid. Figure 3 In the injection hose of the internal system.

[0067] Figure 3B-1 .a is a section cut from the top of the bottom end cap of the battery pack segment. Figure 3 Axial cross-sectional view of the internal system.

[0068] Figure 3B-1 .b is taken from the top of the jet fluid inlet. Figure 3 Axial cross-sectional view of the internal system.

[0069] Figure 3C It is the section taken from the fluid receiving funnel of the injection hose all the way to the upper sealing assembly of the injection hose. Figure 3 A sectional perspective view of the upper part of the internal system.

[0070] Figure 3D-1 It presents a kind of Figure 3 A cross-sectional view of the bundled spray hoses for the electrical wires and data cables that can be used in the internal system.

[0071] Figure 3D-1a yes Figure 3D-1 Axial cross-sectional view of the bundled spray hose.

[0072] Both electrical wires and fiber optic (or data) cables can be seen.

[0073] Figure 3E yes Figure 3D-1 A cross-sectional view of the end of the injection hose, showing... Figure 3 The internal system's injection nozzle. The bending radius of the injection hose is shown as... Figure 3 The external system of the sloping device is located within the cross-sectional section.

[0074] Figures 3F-1a to 3G-1c Presented in various implementation schemes Figure 3E Enlarged cross-sectional view of the injection hose.

[0075] Figure 3F-1a This is an axial cross-sectional view of the basic nozzle body. The nozzle body includes a rotor and a surrounding stator.

[0076] Figure 3F-1b It is along Figure 3F-1aThe image shows a longitudinal cross-sectional view of the injection nozzle taken along line C-C'. Here, the nozzle uses a single discharge slot located at the tip of the rotor. The nozzle also includes a bearing located between the rotor and the surrounding stator.

[0077] Figure 3F-1c It is in the improved implementation plan. Figure 3F-1b A longitudinal cross-sectional view of the injection nozzle. Here, the injection nozzle includes a spatial notch and is shown as being connected to the injection hose via welding.

[0078] Figure 3F-1d It is along Figure 3F-1c The line c-c' intercepts Figure 3F-1c Axial cross-sectional view of the injection hose.

[0079] Figure 3F-2a and Figure 3F-2b Presented in alternative implementation schemes Figure 3E The nozzle is shown in a longitudinal cross-sectional view. Five rearward thrust nozzles, together with a single discharge slot at the tip of the rotor, are placed in the body of the stator and actuated by the forward movement of the sliding nozzle throat bushing against the sliding collar and the biasing mechanism.

[0080] exist Figure 3F-2a In the middle, the bushing and collar are in their closed position. Figure 3F-2b In the middle, the bushing and collar are in their open position, allowing fluid to flow through the rearward thrust nozzle. The nozzle opens when sufficient pumping pressure overcomes the resistance of the spring.

[0081] Figure 3F-2c yes Figure 3F-2a An axial cross-sectional view of the nozzle. Five rearward thrust nozzles are shown for generating rearward thrust.

[0082] Figure 3F-3a and Figure 3F-3c Another alternative implementation scheme is provided. Figure 3E The longitudinal cross-sectional view of the injection nozzle. Here, multiple rearward thrust nozzles located within both the stator and rotor bodies are used. In this arrangement, an electromagnetic force pulling on a spring-biased magnetic ring is used to open / close the rearward thrust nozzles.

[0083] exist Figure 3F-3a In this configuration, the nozzle collar is in its closed position. Figure 3F-2b In the middle, the collar is in its open position, allowing fluid to flow through the rearward thrust nozzle.

[0084] Figure 3F-3b and Figure 3F-3d Showing respectively with Figure 3F-3a and Figure 3F-3cAxial cross-sectional view of the relevant injection nozzles. Eight backward thrust nozzles are visible. This embodiment provides intermittent alignment of four injection ports in the rotor with any of two sets of four injection ports in the stator to generate a pulsed backward thrust flow.

[0085] Figure 3G-1a This is an axial cross-sectional view showing the basic collar body for a jet collar that can be placed within a certain length of the jet hose. The collar body also includes a rotor and a surrounding stator. This view is along... Figure 3G-1b The line D-D' intercepts the line.

[0086] Figure 3G-1b yes Figure 3G-1a A longitudinal cross-sectional view of the injection collar. (Compared to...) Figures 3F-3a to 3F-3d Similar to the jet nozzles, 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.

[0087] Figure 3G-1c It is intercepted along line d-d'. Figure 3G-1b Axial cross-sectional view of the injection nozzle.

[0088] Figure 4 It is in an implementation plan Figure 2 A longitudinal cross-sectional view of the external system of the downhole hydraulic injection assembly. This external system is located... Figure 2 The production casing is located inside the horizontal support of the wellbore.

[0089] Figure 4A-1 It is to Figure 4 An enlarged longitudinal cross-sectional view of a portion of the external system that transports coiled tubing into and out of the wellbore.

[0090] Figure 4A-1a yes Figure 4A-1 An axial cross-sectional view of the coiled tubing transport medium. In this embodiment, the inner coiled tubing, along with the electrical wires and data cables, is concentrically "bundled" within the protective outer layer.

[0091] Figure 4A-2 It is in different implementation schemes Figure 4A-1a Another axial cross-sectional view of the coiled tubing transport medium. Here, the inner coiled tubing is eccentrically "bundled" within the protective outer layer to provide more evenly spaced protection for electrical wires and data cables.

[0092] Figure 4B-1 This is a longitudinal cross-sectional view of a crossover connection (transformer connection). This crossover connection is... Figure 4 The uppermost component of the external system. The intersection is constructed to... Figure 4A-1The continuous tubing transport medium is connected to the main control valve.

[0093] Figure 4B-1a It is seen between sections E-E' and F-F'. Figure 4B-1 An enlarged perspective view of the cross-connector. This view highlights the general transition of the cross-sectional shape of the wiring chamber from circular to elliptical.

[0094] Figure 4C-1 yes Figure 4 Longitudinal cross-sectional view of the main control valve of the external system.

[0095] Figure 4C-1a It is along Figure 4C-1 The cross-sectional view of the main control valve taken by line G-G'.

[0096] Figure 4C-1b This is a perspective view of the sealing passage cover of the main control valve, shown as an exploded view from 4C-1a.

[0097] Figure 4D-1 yes Figure 4 The longitudinal cross-sectional view of the jet hose carrier section of the external system. The jet hose carrier section is attached downstream of the main control valve.

[0098] Figure 4D-1a It shows along Figure 4D-1 The axial cross-sectional view of the main body of the jet hose bearing section taken by line H-H'.

[0099] Figure 4D-1b yes Figure 4D-1 An enlarged view of a portion of the jet hose carrying section. The mooring station for the external systems is now more clearly visible.

[0100] Figure 4D-2 It has the characteristics of coming from Figure 3 The internal system's injection hoses, Figure 4D-1 Enlarged longitudinal cross-sectional view of the jet hose bearing section of the external system.

[0101] Figure 4D-2a Provided with a jet hose located therein Figure 4D-1 Axial cross-sectional view of the bearing section of the injection hose.

[0102] Figure 4E-1 yes Figure 4 A longitudinal cross-sectional view of a selected portion of the external system. The injection hose enclosure section and the outer body of the transition piece from the front circular body (I-I') of the injection hose carrier section to the star-shaped body (J-J') of the injection hose enclosure section can be seen.

[0103] Figure 4E-1a yes Figure 4E-1 Enlarged 3D view of the transition piece between lines I-I' and J-J'.

[0104] Figure 4E-2 An enlarged view of a portion of the injection hose packer section is shown. The inner seal of the packer section conforms to the injection hose located therein. Figure 3 The outer circumference of the valve. The pressure regulating valve is schematically shown as being located near this sealing section.

[0105] Figure 4F-1 yes Figure 4 Another downstream longitudinal section view of the external system. Again, a view from... Figure 4E-1 The injection hose packing section and the outer body transition piece. The internal traction system is also visible here. Note that each of the aforementioned components has a [missing information - likely a component or element] located within it. Figure 3 The longitudinal cross-sectional view of the injection hose is shown.

[0106] Figure 4F-2 yes Figure 4F-1 An enlarged longitudinal cross-sectional view of a portion of the internal traction system, again showing a cross-section of the injection hose located therein. The internal motor, gears, and clamping assembly are also shown.

[0107] Figure 4F-2a It is along Figure 4F-1 and Figure 4F-2 The line K-K' intercepted Figure 4F-2 Axial cross-sectional view of the internal traction system.

[0108] Figure 4F-2b yes Figure 4F-2a An enlarged half-view of a part of the internal traction system.

[0109] Figure 4G-1 yes Figure 4 Another downstream longitudinal section view of the external system. This view shows the transition from the internal traction machine to the upper rotating ring, which is the upper rotating ring of the external system.

[0110] Figure 4G-1a A perspective view depicting the transition of the outer body from the internal traction system to the upper rotating ring is shown. This is the transition of the outer body from a star shape (L-L') to a circle shape (M-M').

[0111] Figure 4G-1b Provides the N-N' intercept along the line Figure 4 -Axial cross-sectional view of the upper rotating ring of G1.

[0112] Figure 4H-1 It is displayed vertically, not horizontally. Figure 4 Cross-sectional view of the sloping device components of the external system. Internal system ( Figure 3 The injection hose is shown bent across the inclinometer and extends through a window in the production sleeve. The injection nozzles of the internal system are shown attached to the distal end of the injection hose.

[0113] Figure 4H-1a It is an axial cross-sectional view of the directional drilling component, in which the three-dimensional view of the continuous axial injection hose cross-section depicts the path of the injection hose from the center of the directional drilling component downwards at line O-O' to the beginning of the bending radius when the injection hose approaches line P-P'.

[0114] Figure 4H-1b An axial cross-sectional view of the sloping device component at line P-P' is depicted.

[0115] Figure 4I-1 yes Figure 4 An axial cross-sectional view of the bottom swivel within the external system, located just downstream of the sliding element (shown as a production sleeve around the joint) near the base of the preceding swashplate component.

[0116] Figure 4I-1a Provides Q-Q' intercept along the line Figure 4I-1 An axial cross-sectional view of a portion of the bottom swivel.

[0117] Figure 4J yes Figure 4I-1 Another longitudinal view of the bottom swivel. Here, the bottom swivel connects to a transition section, which in turn connects to a conventional mud motor, external traction machine, and logging probe, thus completing the entire downhole tool string. For simplicity, this configuration does not include a packer or a retrieveable bridge plug. Detailed Implementation

[0118] definition

[0119] As used herein, the term "hydrocarbon" refers to organic compounds that primarily (but not exclusively) consist of the elements hydrogen and carbon. Hydrocarbons are generally classified into two categories: aliphatic hydrocarbons or straight-chain 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 upgraded to fuel.

[0120] As used herein, the term "hydrocarbon fluid" refers to hydrocarbons or mixtures of hydrocarbons that are either gaseous or liquid. For example, hydrocarbon fluids can include hydrocarbons or mixtures of hydrocarbons that are gaseous or liquid under formation conditions, processing conditions, or environmental conditions. Hydrocarbon fluids can include, for example, oil, natural gas, condensate, coalbed methane, shale oil, shale gas, and other gaseous or liquid hydrocarbons.

[0121] The term "fluid" as used in this article refers to gases, liquids, and combinations of gases and liquids, as well as combinations of gases and solids, and combinations of liquids and solids.

[0122] The term “underground” as used in this article refers to the geological layers that appear below the Earth’s surface.

[0123] The term "subsurface section" refers to a stratum or part of a stratum where formation fluids may be present. These fluids can be, for example, hydrocarbon liquids, hydrocarbon gases, water, or combinations thereof.

[0124] The term "zone" or "target zone" refers to a portion of a formation containing hydrocarbons. Sometimes, the terms "target area," "producing area," or "section" may be used.

[0125] As used herein, the term "wellhole" refers to a hole formed underground by drilling or inserting a guide tube. A wellhole may have a substantially circular cross-section or other cross-sectional shapes. When referring to an opening in the formation, the term "well" may be used interchangeably with the term "wellhole".

[0126] The term "jet fluid" refers to any fluid pumped through a jet hose and nozzle assembly for the purpose of drilling a lateral borehole erosionally from an existing main borehole. This jet fluid may or may not contain abrasive material.

[0127] The term “abrasive material” or “abrasive agent” refers to small solid particles mixed with or suspended in the jet fluid to enhance erosion penetration into: (1) the production zone; and / or (2) the cement between the production casing and the production zone; and / or (3) the wall of the production casing at the desired casing exit point.

[0128] The term “tubular component” or “tubular member” refers to any tube, such as a casing coupling, a liner portion, a tubing coupling, a short drill pipe, or coiled tubing.

[0129] The terms "lateral borehole," "micro-channel," or "ultra-deep perforation" ("UDP") refer to a borehole typically formed in subsurface formation as it exits the production casing and surrounding cemented casing in the main borehole, wherein the borehole is formed in a known or potential production area. For the purposes of this document, using jet fluid directed through a jet hose and flowing out of a jet nozzle attached to the end of the jet hose, the hydraulic jetting force erodes the drilled area, thus forming a UDP. Preferably, each UDP will have a trajectory that is approximately normal to the main borehole.

[0130] The terms "manipulated" or "guided" when applied to a hydraulic jetting assembly refer to a portion of the jetting assembly (typically the jet nozzle and / or the portion of the jetting hose immediately adjacent to the nozzle) that can be guided and controlled by the operator during operation of the jetting assembly. This ability to guide and subsequently reorient the jetting assembly during erosion excavation can be configured into UDPs with one, two, or three sizes of directional components as needed.

[0131] The term "perforation group" or "UDP group" refers to a designed set of transverse perforations branching off from the main well casing. These groups are ideally designed to be specific "stages" that typically receive and transmit production enhancement treatments via hydraulic fracturing (or "fracking") during the completion or rework of horizontal wells. Alternatively, the term "network" may be used.

[0132] The term "class" refers to a discrete portion of a production enhancement treatment applied to a specific production area or a specific section of a production area during well completion or recompletion. In the case of a casing-level main borehole, up to 10, 20, 50, or more classes can be applied to their respective perforation (or UDP) groups. Typically, this requires some form of formation isolation before pumping each class.

[0133] The term "contour" or "contouring," applied to individual UDPs or groups of UDPs within a "swarm," refers to the manipulable drilling of lateral boreholes to optimally receive, guide, and control the production-enhancing fluid or fluid and proppant at a given production-enhancing (typically fracturing) stage. This ability to "optimally receive, guide, and control..." the production-enhancing fluid at a given stage is designed to keep the resulting production-enhancing geometry "in the zone" and / or concentrate the production-enhancing effect where desired. The result is optimized and typically maximized production-enhancing reservoir volume ("SRV").

[0134] "Real-time" or "real-time analysis" of geophysical data (such as microseismic, tiltmeter, or environmental microseismic data) obtained during pumping enhancement (such as fracturing) stages refers to the fact that the results of the data analysis can be applied to: (1) modifying the pumping rate, treatment pressure, fluid rheology, and proppant concentration of the remaining portion of the enhancement process (still to be pumped) to optimize its effectiveness; and (2) optimizing the placement of perforations or the profile setting of UDP trajectories within subsequent "groups" to optimize the SRV obtained from subsequent enhancement stages.

[0135] Detailed implementation plan description

[0136] This article presents a downhole hydraulic jetting assembly. This assembly is designed to guide a jetting nozzle and connected hydraulic hose through a window formed along the production casing string and then outwards to "jet" one or more boreholes into the subsurface formation. Lateral boreholes essentially represent ultra-deep perforations formed using hydraulic pressure guided through a flexible, high-pressure jetting hose with a high-pressure jetting nozzle attached to its distal end. The main assembly utilizes a single hose and nozzle device to continuously jet both, optionally at the casing exit and subsequent lateral boreholes.

[0137] Figure 1AThis is a schematic depiction of a horizontal well 4, in which the wellhead assembly 5 is located above the surface 1, and the horizontal well penetrates several series of subsurface layers 2a to 2h before reaching the production area 3. The horizontal section 4c of the borehole 4 is depicted between the "heel" 4b and the "tip" 4d. The surface casing 6 is shown fully cemented back to the surface 1 from the surface casing shoe 8, while the intermediate casing string 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, it adequately isolates the production area 3. Note Figure 1A In the typical horizontal borehole depicted in the diagram, conventional perforations 15 within the production casing 12 are shown in pairs, and depicted as having subsequent hydraulic fracturing half-planes (or “fracture wings”) 16.

[0138] Figure 1B yes Figure 1A An enlarged view of the lower portion of borehole 4. Here, the horizontal segment 4c between the foot heel 4b and the foot tip 4d is seen more clearly. In this depiction, the application of the subject equipment and methods is shown as follows: Figure 1B The paired relative horizontal UDP 15 depicted in the image replaces the conventional perforation ( Figure 1A 15) in the middle also has a subsequently formed crack half-plane 16. In Figure 1B Specifically, it describes how the fracture wing 16 is now better confined within production zone 3, while extending significantly further into production zone 3 from the horizontal borehole 4c. In other words, it achieves fracture perforation in a pre-existing significantly enhanced zone through the components and methods disclosed herein.

[0139] Figure 2 A longitudinal cross-sectional view of the downhole hydraulic injection assembly 50 of the present invention is provided in one embodiment. The injection assembly 50 is shown as being located within a production casing string 12. The production casing 12 may have, for example, an OD of 4.5 inches (4.0 inch ID). The production casing 12 is presented as a horizontal portion 4c along the borehole 4. (As in conjunction with...) Figure 1A and Figure 1B As shown, the horizontal portion 4c defines the column base 4b and the column base tip 4d.

[0140] The injection assembly 50 typically comprises an internal system 1500 and an external system 2000. The injection assembly 50 is designed to extend into the borehole 4 at the end of a working string (sometimes referred to herein as the “delivery medium”). Preferably, the working string is a coiled tubing string 100. The delivery medium 100 can be conventional coiled tubing. Alternatively, a “bundle” product comprising conductive and data transmission cables (such as optical fibers) wrapped around a coiled tubing core, protected by an anti-corrosion / abrasion outer layer such as PFE and / or Kevlar, or even by an additional (outer) coiled tubing string, can be used. Fiber optic cables have been found to have a negligible diameter and have been proven effective in providing direct, real-time data transmission and communication with downhole tools. Other emerging transmission media such as carbon nanofibers can also be employed.

[0141] Other delivery media can be used for the jet assembly 50. These include, for example, standard coil systems, custom-made... Components Flexible polymer steel tubing (“FSPT”) or flexible pipeline (“FTC”) tubing. Alternatively, the tubing may have PTFE (polytetrafluoroethylene) and PTFE-based tubing. Materials, or Draka CableteqUSA, can be used. Tubing seal line (“TEC”) system. In any case, it is desirable that the delivery medium 100 is flexible, somewhat malleable, non-conductive, pressure resistant (to withstand high-pressure fracturing fluid optionally pumped down into the annulus), heat resistant (to withstand bottom hole drilling operating temperatures, typically exceeding 200°F and sometimes exceeding 300°F), chemical resistant (at least resistant to additives included in the fracturing fluid), abrasion resistant (to reduce downhole pressure loss due to friction during pumping fracturing), corrosion resistant (to withstand the erosive effects of the aforementioned annular fracturing fluid), and abrasion resistant (to withstand the abrasive effects of proppant suspended in the aforementioned annular fracturing fluid).

[0142] If a standard coiled tubing string is used, communication and data transmission can be accomplished via subsea pulse technology (or so-called mud pulse telemetry), acoustic telemetry, EM telemetry, or some other remote transmission / reception system. Similarly, power for operating the equipment can be generated downhole by a conventional mud motor, which would allow the circuitry for the system to be confined below the end of the coiled tubing. This hydraulic injection assembly 50 is not limited by the data transmission system or the medium for power transmission or delivery, unless clearly stated in the claims.

[0143] Preferably, the outer diameter of the coiled tubing 100 is maintained such that an annular region, greater than or equal to the cross-sectional area open to the flow of a 3.5” OD fracturing (tubing) string, is left within the casing 12, which has an ID of approximately 4.0”. This is because, in the preferred method (after injecting one or more (preferably two) relatively micro-channels or even a specific profile of a small-diameter lateral borehole “group”), fracturing can immediately occur downwards along the coiled tubing delivery medium 100 plus the annular gap between the external system 2000 and the well casing 12 (after repositioning the tool string toward the wellhead). For a 9.2#, 3.5” OD tubing (i.e., the fracturing string equivalent), the ID is 2.992 inches, and the cross-sectional area open to the flow is 7.0309 square inches. Based on this same 7.0309 in… 2 The maximum OD of both the coiled tubing transport medium 100 and the external system 2000 (with a generally circular cross-section) is calculated by reverse estimation. Of course, a smaller OD can be used for one of them, as long as it can accommodate the injection hose 1595.

[0144] exist Figure 2 In the view, assembly 50 is in the operating position, with the injection hose 1595 extending through the directional drilling rig 1000 and the injection nozzle 1600 passing through the first window "W" of the production casing 12. At the end of the injection assembly 50, and below the directional drilling rig 1000, are several optional components. These components include a conventional mud motor 1300, an external (conventional) traction machine 1350, and a logging probe 1400. Figure 4 These components are shown and described more comprehensively.

[0145] Figure 3 yes Figure 2 A longitudinal cross-sectional view of the internal system 1500 of the hydraulic injection assembly 50. The internal system 1500 is an operable system that, during operation, can move within the external system 2000 and extend to the outside. The internal system 1500 mainly consists of the following items:

[0146] (1) Power and geological control components;

[0147] (2) Jet fluid inlet;

[0148] (3) Spray hose 1595; and

[0149] (4) Spray nozzle 1600.

[0150] The internal system 1500 is designed to be housed within the external system 2000, and is simultaneously transported into and out of the main borehole 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: (a) hydraulic pressure; (b) mechanical force; or (c) a combination of hydraulic pressure and mechanical force. The design of the hydraulic jetting device 50, comprised of the internal system 1500 and the external system 2000, is advantageous because the transport, deployment, or retrieval of the jetting hose 1595 never requires coiling. Specifically, the jetting hose 1595 is never subjected to a bending radius smaller than ID of the production casing 12, and only increases when pushed along the directional drilling member 1050 of the jetting hose directional drilling component 1000 of the external system 2000. Note that the jetting hose 1595 is typically 1 / 4” to 5 / 8” of ID of a flexible tubing capable of withstanding high internal pressures, up to approximately 1” OD.

[0151] The internal system 1500 primarily includes the battery pack 1510. Figure 3A Provided Figure 3 A sectional perspective view of the battery pack 1510 within the internal system 1500. Note that, for illustrative purposes, this section 1510 is shown from... Figure 3 The horizontal view is rotated 90° to a vertical orientation. Individual AA batteries 1551 are shown as a series of end-to-end cells forming a battery pack 1550. Protection of the batteries 1551 is primarily provided via a battery pack housing 1540, which is sealed by an upstream battery pack end cap 1520 and a downstream battery pack end cap 1530. These components (1540, 1520, and 1530) have external surfaces exposed to the high-pressure jet of fluid. Therefore, they are preferably constructed or coated with a non-conductive, highly abrasion / erosion / corrosion-resistant material.

[0152] The upstream battery pack end cap 1520 has a conductive ring surrounding a portion of its circumference. When the internal system 1500 is "plugged in" (i.e., 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. It should also be noted that the sizes of the end caps 1520 and 1530 can be configured to accommodate and protect any server, microchip, circuit, geospatial, or transmitter / receiver components within them.

[0153] Battery pack end caps 1520 and 1530 can be threadedly attached to the battery pack housing 1540. Battery pack end caps 1520 and 1530 can be constructed of highly corrosion- and abrasion-resistant high-pressure materials (such as titanium), and may even be protected by a thin, highly corrosion- or abrasion-resistant coating (such as polycrystalline diamond). The shape and construction of end caps 1520 and 1530 are preferably such that they can redirect the flow of the high-pressure jet fluid to abrasion-resistant surfaces without causing significant abrasion. The upstream end cap 1520 must redirect the flow to the battery sleeve 1540 and the jet hose carrier system (in... Figure 4D-1 The surrounding spray hose conduit 420 (shown as 400 in the middle) Figure 3C The annular space between (visible in the middle) Figure 3 (Not shown in the image). The downstream end cap 1530 is adjacent to the funnel that receives (or "introduces") fluid from the annular space via jet fluid. Figure 3B-1 (As shown in 1570) is part of the flow path of the jet fluid that enters downward into the ID of the jet hose 1595 itself.

[0154] Therefore, the path of the high-pressure hydraulic jet fluid (with or without abrasive) is as follows:

[0155] (1) The jet fluid is discharged from the high-pressure pump at ground 1 and flows downward along the ID of the coiled tubing transport medium 100. The jet fluid enters the external system 2000 at the end of the coiled tubing transport medium.

[0156] (2) The jet fluid enters the external system 2000 through the continuous tubing transition connector 200;

[0157] (3) The jet fluid enters the main control valve 300 through the jet fluid channel 345;

[0158] (4) Since the main control valve 300 is positioned to receive the jet fluid (opposite to the hydraulic fluid), the sealing channel cover 320 will be positioned to seal the hydraulic fluid channel 340, leaving the only available fluid path through the jet fluid channel 345, the discharge end of the jet fluid channel being sealed to the jet hose conduit 420 of the jet hose carrying system 400.

[0159] (5) When entering the jet hose conduit 420, the jet fluid will first pass through the annular gap between the mooring station 325 and the jet hose conduit 420 and pass through the mooring station 325 (attached to the inside of the jet hose conduit 420);

[0160] (6) Since the injection hose 1595 is located within the injection hose conduit 420, the high-pressure injection fluid must now pass through or bypass the injection hose 1595; and

[0161] (7) Due to the seal 1580U of the annular gap between the internal system 1500's sealing injection hose 1595 and the injection hose conduit 420, the injection fluid cannot bypass the injection hose 1595 (note that this hydraulic pressure on the sealing assembly 1580 is a force that tends to pump the internal system 1500 and thus the injection hose 1595 "downhole"). Therefore, the injection fluid is forced to pass through the injection hose 1595 via the following path:

[0162] (a) The jet fluid first passes over the top of the internal system 1500 at the upstream battery pack end cap 1520;

[0163] (b) The jet fluid then passes through the annular gap between the battery pack housing 1540 and the jet hose conduit 420 of the jet hose carrying system 400;

[0164] (c) After passing through the downstream battery pack end cap 1530, the jet fluid is forced to flow between the battery pack support conduits 1560 and enters the jet fluid receiving funnel 1570; and

[0165] (d) Because the jet fluid receiving funnel 1570 is rigidly and sealingly connected to the jet hose 1595, fluid is forced into the ID of the jet hose 1595.

[0166] The following startup conditions are noteworthy in the above jet fluid flow sequence:

[0167] (i) The internal traction system 700 first engages to move the discrete length of the injection hose 1595 downstream, such that the injection nozzle 1600 and the injection hose 1595 enter the injection hose skewer 1000, and specifically, on the inner wall (in Figure 4H-1 After traveling a fixed distance (as shown in 1020), 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 skewing device component 1050. At this point,

[0168] (ii) The spray hose 1595 is curved and "bent" at approximately 90°, forming its predetermined bending radius (in Figure 4H-1 (As shown in 1599) and guides the injection nozzle 1600 attached to its end to engage the desired outlet "W" of the production sleeve 12 within the ID; at this moment

[0169] (iii) Then, the torque of the internal traction system 700 and the clamp assembly 750 is increased, and a signal regarding this is immediately transmitted electronically to the ground, notifying the operator to close the clamp (in Figure 4F-2b The rotation of the schematic fixture can be seen at position 756.

[0170] (In fact, this closure can be pre-programmed into the operating system at a certain torque level.) Note that during phases (i) to (iii), the pressure regulating valve (in...) Figure 4E-2 (See at point 610) is in the "open" position. This allows hydraulic fluid to drain from the annulus between the injection hose 1595 and the surrounding hose conduit 420. Once the tip of the injection nozzle 1600 engages the ID (casing wall) of the production sleeve 12, the operator can:

[0171] (iv) Reverse the rotation direction of clamp 756 to move spray hose 1595 back into spray hose (or inner conduit) 420; and

[0172] (v) Open the main control valve 300 to begin pumping hydraulic fluid through the hydraulic fluid passage 340, down along the conduit carrier annulus 440, through the pressure regulating valve 610, and into the annulus 1595.420 of the injection hose 1595 / injection hose conduit 420, for: (1) pumping upward against the lower seal 1580L of the sealing assembly 1580 of the injection hose to extend the injection hose 1595 to the taught position; and (2) assisting (now reversed) the clamp assembly 750 in positioning the internal system 1500 such that the injection nozzle 1600 has a desired reference distance (preferably less than 1 inch) between itself and the ID of the production sleeve 12 to begin spraying.

[0173] The outlet of the casing is shot.

[0174] Upon reaching the desired reference distance, the rotation of the clamp 756 stops, and the pressure regulating valve 610 closes to lock the internal system in the desired fixed position for spraying the sleeve outlet "W".

[0175] Return to reference Figure 3A In one embodiment, the downstream end cap 1530 internally houses a micro-geoguiding system. The system may include a micro-transmitter, a micro-receiver, a microprocessor, and a current regulator. This geoguiding system is electrically or optically connected to a small geospatial IC chip located in the body of the jet nozzle 1600. Figure 3F-1c (Seen in Figure 1670 and discussed more fully below). In this way, geospatial data can be sent from the jet nozzle 1600 to a microprocessor (or a suitable control system). This geospatial data, combined with values ​​of the dispersed hose lengths, can be used to calculate the precise geographic location of the nozzle at any point, and thus the profile of the UDP path. 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 the direction of the actuator line (at least three) via one or more current regulators. Figure 3F-1cThe individual downward current intensity of each nozzle (shown as 1590A) allows for reorientation of the nozzle as needed.

[0176] The geological guidance system can also be used to control the rotational speed of the rotor body within the injection nozzle 1600. As will be described more fully below, the rotary nozzle configuration utilizes the rotor portion 1620 of a miniature direct drive motor assembly to also form the throat and end discharge slot 1640 of the rotary nozzle itself. Rotation is initiated by electromagnetic force from the rotor / stator configuration. In this way, the rotational speed can be adjusted to be proportional to the current supplied to the stator.

[0177] like Figure 3 F-1 to Figure 3 As depicted in F-3, the upstream portion of the rotor (in this depiction, a four-pole rotor) 1620 includes an approximately cylindrical inner diameter (ID actually decreases slightly from the fluid inlet to the discharge channel to further accelerate the fluid before it enters the discharge channel), which provides a flow channel for the jet fluid through the center of the rotor 1620. This approximately cylindrical flow channel then transitions into the shape of the discharge channel 1640 of the nozzle 1600 at its distal downstream end. This is possible because, instead of a typical shaft and bearing assembly that longitudinally inserts through the central diameter of the rotor 1620, the rotor 1620 is stabilized and positioned to rotate in balance about the longitudinal axis of the rotor 1620 by a single set of bearings 1630 positioned inside the upstream flat end and outside the outer diameter of the flow channel (“nozzle throat”) 1650, such that the bearings 1630 stabilize the rotor body 1620 in both the longitudinal and axial directions.

[0178] Now refer to Figure 3B-1a And again, the internal system 1500 is discussed, showing the path along... Figure 3B-1 The image shows a cross-sectional view of the battery pack segment 1510 taken along line A-A'. This view is taken from the top of the bottom end cap 1530 of the battery pack 1510, looking downwards into the jet fluid receiving funnel 1570. Three wires 1590 extending from the battery pack 1510 are visible in the image. These wires 1590 supply power from the “AA”-sized lithium battery 1551 to a geological guidance system that controls the rotating jet nozzle 1600. By adjusting the current flowing through the wires 1590, the geological guidance system controls the rotational speed and orientation of the rotor 1620.

[0179] Note that because the longitudinal axis of the nozzle's discharge flow is designed to be continuous with and aligned with the longitudinal axis of the nozzle throat, the thrust of the ejected fluid at the outlet has virtually no axial torque acting on the nozzle. That is, because the nozzle is designed to operate under axially "balanced" conditions, the torsional torque actually required to rotate the nozzle about its longitudinal axis is quite small. Similarly, because the rotational speed (RPM) required for rotary digging is quite low, the electromagnetic force required for the rotor / stator interaction of the nozzle is also quite small.

[0180] from Figure 3 It is noted that the injection nozzle 1600 is located at a distant downstream end of the injection hose 1595. While the diameters of the components of the internal system 1500 must meet some rather strict diameter constraints, the constraints on the length of each component (besides the injection nozzle 1600, and, as desired, one or more injection collars) are generally much fewer. This is because the injection nozzle 1600 and the collars (not shown) are merely components attached to the injection hose 1595 and will generally form an approximately 90° bend as indicated by the inclinometer surface 1050.1. All other components of the internal system 1500 will always be located somewhere within the injection hose carrier system 400, above the injection hose partition section 600 (discussed below).

[0181] The length of many components can also be adjusted. For example, although Figure 3A The battery pack 1510 is depicted as housing six AA batteries 1551, but a larger number of batteries can be easily accommodated by simply constructing a longer battery pack housing 1540. Similarly, the battery pack end caps 1520, 1530, support pillars 1560, and fluid inlet funnels 1570 can also be made much longer to accommodate fluid flow and power requirements.

[0182] Referring again to mooring station 325, mooring station 325 acts as a physical "stop" preventing further upward movement beyond the internal system 1500. Specifically, the upward movement of the internal system 1500 (primarily including the injection hose 1595) is limited by the point where the upstream battery pack end cap 1520 is inserted (or "plugged in") into the bottom conical receptacle 328 of mooring station 325. Receptacle 328 serves as the lower end cap. Receptacle 328 provides mating conductive contacts that align with the upstream battery pack end cap 1520 to form a plug-in point. Thus, data and / or power (specifically, for recharging battery 1551) can be transmitted during "plugging in".

[0183] The mooring station 325 also has a conical end cap 323 at its upstream (proximal) end. The conical shape helps to minimize erosion effects by diverting the flow of jet fluid around its body, thereby contributing to the protection of system components housed within the mooring station 325. Depending on the desired guidance, steering, and communication capabilities, the upper portion 323 of the mooring station 325 can house servo, transmission, and reception circuitry and electronics designed to communicate directly with the paired system in the internal system 1500 (either in a continuous real-time manner or discretely only when plugged in). Note, as Figure 3 As shown, the OD of the cylindrical mooring station 325 is approximately equal to the OD of the jet hose 1595.

[0184] The internal system 1500 also includes a jet fluid receiving funnel 1570. Figure 3B-1 A cross-sectional perspective view including the jet fluid receiving funnel 1570, having, as Figure 3B-1b The diagram shows an axial cross-sectional view along B-B'. The jet fluid receiving funnel 1570 is located below the base of the battery pack section 1510, as described above. Figure 3A As shown and described. As the name suggests, the jet fluid receiving funnel 1570 is used to introduce jet fluid into the interior of the jet hose 1595 during the casing outlet and micro-branch formation process. Specifically, the annular flow of the jet fluid (e.g., flowing through the battery pack housing 1540 and then through the battery pack end cap 1530 and into the interior of the jet hose conduit 420) is forced to transition into flow between the three battery pack support conduits 1560 because of the upper seal ( Figure 3 (As seen at 1580U) any fluid flowing along the path outside the injection hose 1595 is blocked. Therefore, all flow of the injection fluid (as opposed to the hydraulic fluid) is forced between the conduits 1560 and flows into the fluid receiving funnel 1570.

[0185] exist Figure 3B-1 In the design, three columnar supports 1560 are used to house the wires 1590. The columnar supports 1560 also provide areas open to fluid flow. The spacing between the supports 1560 is designed to be significantly larger than the spacing provided by the ID of the jet hose 1595. Simultaneously, the supports 1560 have an ID large enough to accommodate and protect the wires 1590 up to AWG#5 specification. The columnar supports 1560 also support the battery pack 1510 at a specific distance above the jet fluid inlet funnel 1570 and the jet hose sealing assembly 1580. The supports 1560 can be sealed with sealing end caps 1562, allowing the removal of the end caps 1562 to provide an inlet to the wires 1590.

[0186] Figure 3B-1b A second axial cross-sectional view of the fluid introduction funnel 1570 is provided. This view is along... Figure 3B-1The view is taken from line B-B'. Three columnar supports 1560 are also visible. This view is taken from the top of the jet fluid inlet or receiving funnel 1570.

[0187] Downstream of the jet fluid receiving funnel 1570 is the jet hose sealing assembly 1580. Figure 3C This is a sectional perspective view of sealing assembly 1580. Figure 3C In the view, for clarity, columnar support member 1560 and wire 1590 have been removed. However, receiving funnel 1570 is still visible at the upper end of sealing assembly 1580.

[0188] Figure 3C The upper end of the injection hose 1595 can also be seen. The injection hose 1595 has an outermost injection hose cover OD1595.3. Figure 3D-1a As can also be seen, the outermost spray hose sheath can engage the spray hose conduit 420 at multiple points. Micro-annular gaps 1595 and 420 are formed between the spray hose 1595 and the surrounding conduit 420. Figure 3D-1 and Figure 3D-1a (As shown in the diagram). The spray hose 1595 also has a core (OD1595.2, ID1595.1) for transmitting the sprayed fluid during spraying operations. The spray hose 1595 is securely connected to the sealing assembly 1580, meaning that the sealing assembly 1580 moves with the spray hose 1595 as the spray hose is advanced into the microchannel.

[0189] As previously described, the upper seal 1580U of the sealing assembly 1580 of the injection hose (shown as a solid portion with a slightly upwardly concave upper surface) prevents any continuous downstream injection fluid from flowing out of the injection hose 1595. Similarly, the lower seal 1580L of the sealing assembly 1580 (shown as a series of downwardly concave cups) prevents any upstream flow of hydraulic fluid from below. Note how any upstream-to-downstream hydraulic pressure from the injection fluid will tend to expand the injection fluid inlet funnel 1570, and thus push the upper seal 1580U of the sealing assembly 1580 radially outward to sealably engage ID420.1 of the (inner) injection hose conduit 420 of the injection hose carrier. Similarly, any downstream-to-upstream hydraulic pressure from the hydraulic fluid radially expands to form the bottom cup-shaped surface of the lower seal 1580L to sealably engage ID420.1 of the inner conduit 420 of the injection 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 sealing assembly 1580 and the connected hose 1595 back "uphole".

[0190] Return to Figure 2 and Figure 3 The upper seal 1580U provides upstream pressure and fluid sealing connection between the internal system 1500 and the external system 2000. (Similarly, as will be discussed further below, the packer seal 650 within the packer section 600 provides downstream pressure and fluid sealing connection between the internal system 1500 and the external system 2000). The sealing assembly 1580 includes seals 1580U and 1580L that retain incompressible fluid between the hose 1595 and the surrounding conduit 420. Thus, the injection hose 1595 is operatively connected to the coiled tubing string 100 and sealingly connected to the external system 2000.

[0191] Figure 3C The utility of the sealing mechanism included upstream is shown. During operation, fluid is ejected:

[0192] (1) The annular gap 420.2 between the battery pack housing 1540 and the inner conduit 420 of the jet hose carrier;

[0193] (2) Flowing between the battery pack support conduits 1560;

[0194] (3) Inflow fluid receiving funnel 1570;

[0195] (4) The core 1595.1 (ID) flows downward into the jet hose 1595; and

[0196] (5) Then exit the spray nozzle 1600.

[0197] As described, the downstream hydraulic pressure of the jet fluid acting on the axial cross-sectional area of ​​the fluid receiving funnel 1570 of the jet hose creates an upstream-to-downstream force that tends to "pump" the sealing assembly 1580 and the connected jet hose 1595 "downhole". Additionally, because 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 cause the outer diameter of the upper seal 1580U to expand and unfold radially outward, thereby creating a fluid seal that prevents fluid from flowing behind the hose 1595.

[0198] Figure 3D-1 A longitudinal cross-sectional view is provided when the "bundled" injection hose 1595 of the internal system 1500 is located within the inner conduit 420 of the injection hose carrier. The longitudinal section also includes a perspective view (dashed lines) of the electrical wire 1590 and data cable 1591. From Figure 3D-1a As can be seen in the axial cross-sectional view, all the wires 1590 and data cables 1591 in the "bundled" jet hose 1595 are securely located within the outermost jet hose wrapping 1595.3.

[0199] In a preferred embodiment, the jet hose 1595 is a "bundling" product. The hose 1595 can be obtained from manufacturers such as Parker Hannifin. The bundled 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... Figure 3B-1b and Figure 3D-1a As depicted in the image. Note that these wires 1590 and fiber optic strands 1591 are located on the outer periphery of the core 1595.2 of the jet hose 1595 and are encased in a flexible, high-strength material or "wrap" (such as...). A thin outer layer 1595.3 surrounds the wire 1590 and the fiber optic stranded cable 1591 for protection. This protects the wire 1590 and the fiber optic stranded cable 1591 from any corrosive effects of the high-pressure jet fluid.

[0200] Now move the hose down 1595 to the distal end. Figure 3E An enlarged cross-sectional view of the end of the injection hose 1595 is provided. Here, the injection hose 1595 passes through the directional drilling assembly 1000 and ultimately reaches the casing outlet “W” along the directional drilling face 1050.1. An injection nozzle 1600 is attached to the distal end of the injection hose 1595. The injection nozzle 1600 is shown in the position where the outlet opening or window “W” will subsequently be formed in the production casing 12. Of course, it is understood that this assembly 50 can be reconfigured for deployment in a casing-free borehole.

[0201] As described in the relevant application, the injection hose 1595 spans the entire ID of the production casing 12 at the aforementioned casing outlet "W" point. Thus, the bending radius "R" of the injection hose 1595 is always set equal to the ID of the production casing 12. This is important because the main assembly 50 will always be able to use the entire casing (or borehole) ID as the bending radius "R" of the injection hose 1595, thereby utilizing the maximum ID / OD hose. This, in turn, allows for the arrangement of maximum hydraulic horsepower ("HHP") at the injection nozzle 1600, which further translates into the ability to maximize formation injection results, such as penetration rate or lateral borehole diameter, or some optimization of both.

[0202] Here, it is observed that the bending radius "R" of the injection hose 1595 has three consecutive "contact points". First, there is a contact point at the ID of the hose 1595 contacting the sleeve 12. This occurs at a point directly opposite to and slightly (approximately one sleeve ID width) above the point of the sleeve outlet "W". Second, there is a contact point along the directional drilling surface 1050.1 of the directional drilling member 1000 itself. Finally, at least until the window "W" is formed, there is a contact point abutting against the ID of the sleeve 12 at the sleeve outlet "W".

[0203] like Figure 3E (as well as Figure 4H-1 As depicted in the image, the directional spray hose directional spray member 1000 is in its set and operating position within the sleeve 12. (US Patent No. 8,991,522 also shows the directional spray member 1050 in its extended position, which is incorporated herein by reference). The actual directional spray member 1050 within the directional spray member 1000 is supported by the lower directional spray member rod 1060. When the directional spray member 1000 is in its set and operating position, the upper curved surface 1050.1 of the directional spray member 1050 itself substantially spans the entire ID of the sleeve 12. For example, this is obviously not the case if the sleeve ID becomes slightly larger. However, although a slightly larger radius of curvature “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.

[0204] As described in more detail in common U.S. Patent No. 8,991,522, the directional drilling rod is part of a tool assembly that also includes an orientation mechanism and an anchoring section including a slider. Once the slider is fixed, the orientation mechanism utilizes a ratchet-like movable part that can rotate the upstream portion of the directional drilling member 1000 in discrete 10° increments. Therefore, the angular orientation of the directional drilling member 1000 within the borehole can be incrementally changed downhole.

[0205] In one embodiment, the directional drilling tool 1050 is a single body with an integrated recessed surface configured to receive the injection hose and redirect the hose by approximately 90 degrees. Note that the directional drilling tool 1050 is configured such that, when in the set and operating position, a bend radius of the injection hose is formed at the casing exit point, which spans the entire ID of the production casing 12 of the main borehole.

[0206] Figure 4H-1 It is displayed vertically, not horizontally. Figure 4 A cross-sectional view of the external system's sloping device component 1000. Internal system ( Figure 3 The injection hose is shown bent across the inclinator face 1050 and extending through the window “W” of the production sleeve 12. The injection nozzle of the internal system 1500 is shown attached to the distal end of the injection hose 1595.

[0207] Figure 4H-1a This is an axial cross-sectional view of the slant builder component 1000, in which a three-dimensional view of the continuous axial injection hose cross-section depicts the path of the injection hose from the center of the slant builder component 1000 at line O-O' downwards to the starting point of the bending radius when the injection hose approaches line P-P'.

[0208] Figure 4H-1bAn axial cross-sectional view of the directional drilling component 1000 at line P-P' is depicted. Note the adjustment of the position and structure of the wiring chamber and hydraulic fluid chamber of the directional drilling component from line O-O' to line P-P'.

[0209] As described above, this component 50 is preferably used for connection with a nozzle having a unique design. Figure 3F-1a and Figure 3F-1b The first implementation scheme is provided Figure 3 An enlarged cross-sectional view of nozzle 1600. Nozzle 1600 utilizes a rotor / stator design, wherein the forward portion 1620 of nozzle 1600 (and thus the forward spray channel (or "port") 1640) rotates. Conversely, the rearward portion of nozzle 1600, which is directly connected to the spray hose 1595, remains fixed relative to the spray hose 1595. Note that in this arrangement, the spray nozzle 1600 has a single forward discharge channel 1640.

[0210] first, Figure 3F-1a A basic nozzle body with a stator 1610 is presented. The stator 1610 defines an annular body having a proximal end 1611 and a series of inwardly facing shoulders 1615 equidistantly spaced within the annular body. The nozzle 1600 also includes a rotor 1620. The rotor 1620 also defines a body and has a series of outwardly facing shoulders 1625 equidistantly spaced around it. Figure 3F-1a In the arrangement, the stator 1610 has six inward-facing shoulder-shaped structures 1615, while the rotor 1620 has four outward-facing shoulder-shaped structures 1625.

[0211] Along each shoulder 1615, small-diameter conductive wires 1616, each encased inwards by multiple wrappings, are arranged around the stator. Therefore, according to the DC rotor / stator system, the movement of current through the wires 1616 creates an electromagnetic force. Figure 3A Battery 1551 (or battery pack 1550) provides power to the wires.

[0212] As seen above, the stator 1610 and rotor 1620 bodies are similar to a direct drive motor. The stator 1610 (a six-pole stator in this specification), an analogous to this direct drive motor, is contained within the outer body of the nozzle 1600 itself, with each pole protruding directly from the body 610 and equally wrapped in wires 1616. The current source for the wires 1616 used to wrap the stator poles is derived from the 'bundling' wires 1590 of the injection hose 1595, and is therefore operated by a current regulator and micro-servo mechanism housed in the (downstream) end cap 1530 of the conical battery pack. The rotation of the rotor 1620 of the nozzle 1600, particularly its rotational speed (RPM), is controlled via the inductive electromagnetic force of the DC rotor / stator system.

[0213] Notice, Figure 3F-1a This can be used as an axial section representing virtually any basic DC electromagnetic motor, with the central shaft / bearing assembly removed. By eliminating the central shaft and bearing, the nozzle 1600 can now accommodate a nozzle throat 1650 positioned longitudinally through its center. The throat 1650 is suitable for high-pressure fluid flow.

[0214] Figure 3F-1b Provided along Figure 3F-1b The line C-C' intercepted Figure 3F-1a A longitudinal cross-sectional view of nozzle 1600. Rotor 1620 and the surrounding stator 1610 are seen again. Bearing 1630 is provided to facilitate relative rotation between stator body 1610 and rotor body 1620.

[0215] exist Figure 3F-1b It is observed that the nozzle throat 1650 has a tapered narrowing section before terminating in a single fan-shaped discharge groove 1640. This profile provides two benefits. First, additional non-magnetic high-strength material can be placed between the throat 1650 and the magnetic rotor portion 1625 of the forward portion of the nozzle body 1620. Second, the final acceleration of the jet fluid passing through the throat 1650 is adjusted before the jet fluid enters the discharge groove 1640. The size, location, load capacity, and degrees of freedom of movement of the bearing 1630 are also considered. The forward groove 1640 begins with a relatively micro-hemispherical opening and terminates in a curved, relatively elliptical shape (or alternatively, a curved rectangle with curved small ends) in the forward portion of the nozzle 1600.

[0216] Simulations were conducted using a single flat groove, slightly twisted to allow the fluid discharge angle to generate sufficient thrust to rotate nozzle 1600. The problem discovered was that the nozzle rotation rate was highly sensitive to changes in fluid flow rate, causing momentary and frequent overloads of bearing 1630 (accompanied by resulting failures). The solution was to design a balanced single-groove system such that fluid discharge does not generate perceptible axial thrust. In other words, nozzle 1600 is no longer sensitive to injection rate.

[0217] In this respect, it is important to note the fundamental nozzle design criteria regarding the flow capacity of the combined flow path formed by the throat 1650 and groove 1640 elements. That is, the dimensions maintained by these internal throat 1650 and groove 1640 elements of the nozzle 1600 may approximate the dimensions of a conventional hydraulic jet sleeve perforator and the resulting hydraulic pressure. Specifically, Figure 3F-1a The nozzle 1600 depicted in the image Figure 3F-1bThe dimensions of the throat 1650 and groove 1640 depicted are set to approximate the perforating hydraulic pressure obtained through the 1 / 8-inch orifice of the perforator. Note that the width of the end of the groove 1640 is not only sufficient to accommodate 100-mesh abrasive, but also larger sizes such as 80-mesh abrasive.

[0218] Figure 3F-1b The angle θ is shown in the figure. SLOT 1641 and θ MAX 1642. (in) Figure 3F-2b and Figure 3F-3b These angles are also shown in the diagram and will be discussed below. (Angle θ) SLOT 1641 represents the actual angle of the outer edge of groove 1640, angle θ. MAX 1642 represents the maximum θ that can be achieved within the existing geometry and construction constraints of nozzle 1600. SLOT 1641. In Figure 3F-1b , Figure 3F-2b and Figure 3F-3b In the middle, angle θ SLOT 1641 and θ MAX 1642 are both shown as 90 degrees. This geometry, combined with the rotation of the rotor body 1620 (and therefore the rotation of the jet 1640), provides an orifice diameter at least equal to the outer diameter of the nozzle, even when the reference distance (e.g., the distance from the tip of the nozzle 1600 at the longitudinal centerline to the target rock along the same centerline) is zero.

[0219] Figure 3F-2a and Figure 3F-2b Provided Figure 3E The jet nozzle is shown in a longitudinal cross-sectional view in an alternative embodiment. In this embodiment, the modified nozzle 1601 uses multiple ports, including a forward port 1640 and multiple rearward thrust nozzles 1613.

[0220] Figure 3F-2a and Figure 3F-2b The nozzle structure and Figure 3F-1a The nozzle has the same construction, except for the following three additional components:

[0221] (1) Use of the rearward thrust nozzle 1613;

[0222] (2) Use of a sliding collar 1633 biased by a biasing mechanism (spring) 1635; and

[0223] (3) Use of the sliding nozzle throat bushing 1631.

[0224] The first of these three additional components, the rearward thrust nozzle 1613, provides rearward thrust to effectively drag the jet hose 1595 along the lateral borehole or microchannel when forming the lateral borehole or microchannel. Preferably, five rearward thrust nozzles 1613 are used along the body 1610, although various numbers and / or outlet angles 1614 of nozzles 1613 can be utilized.

[0225] Figure 3F-2c yes Figure 3F-2a and Figure 3F-2b An axial cross-sectional view of the injection nozzle 1601. This shows a star-shaped nozzle pattern formed by multiple rearward thrust nozzles 1613. Five dots are seen in the star, representing five schematic rearward thrust nozzles 1613.

[0226] It is particularly noteworthy that in homogeneous primary producing areas, the forward (jetting) hydraulic horsepower required to excavate fresh rock at a given penetration rate remains essentially constant. However, the backward thrust hydraulic horsepower required increases steadily and proportionally with the increase in the length of the micro-channels. Because the continuous extension of the micro-channels requires an increasing length of the jet hose 1595 to be dragged along an increasing distance, the backward thrust hydraulic horsepower required to maintain the forward propulsion of the jet nozzle 1601 and the hose 1595 increases by the same amount.

[0227] To extend the jet hose 1595 and the connected nozzles 1601, 1602 to the maximum lateral extent, more than two-thirds of the available horsepower may need to be consumed through the rear thrust nozzle 1613. If this maximum requirement is utilized throughout the entire hole jetting process, a significant portion of the available horsepower will be wasted in the early stages of jetting the hole. This is particularly disadvantageous when the same jet nozzles and components used in rock excavation are also used to form the initial casing exit “W”. Furthermore, if the same rear thrust of the 'point' used in cutting star-shaped rock excavation is active in the borehole fittings (particularly when jetting the casing exit “W”), it may cause significant damage to nearby tool strings (particularly the directional drilling assembly 1000) and the well casing 12. Therefore, an optimized design will provide the activation / deactivation of the rear thrust nozzle 1613 when needed (particularly after casing exit formation and after the first 5 or 10 feet of lateral borehole formation).

[0228] Several possible mechanisms exist that can enable / deactivate the nozzle to help conserve HHP and protect tool posts and fittings. One approach is mechanical, where the opening and closing of the flow to nozzle 1613 is actuated by overcoming the force of a biasing mechanism. (Combined) Figure 3F-2a and Figure 3F-2bThis is illustrated by spring 1635, in which the throat bushing 1631 and the sliding collar 1633 move together to open the rearward thrust nozzle 1613. Another method is electromagnetic, where an electromagnetic force pulls the magnetic port seal against a biasing mechanism (spring 1635). Figure 3F-3a and Figure 3F-3c This point will be illustrated and discussed below.

[0229] merged into Figure 3F-2a and Figure 3F-2b The second of the three additional components in the nozzle design is a sliding collar 1633. The collar 1633 is biased by a biasing mechanism (spring) 1635. The function of this collar 1633 is to temporarily seal the fluid inlet of the thrust nozzle 1613, either directly or indirectly (by applying force to the sliding nozzle throat bushing 1631). Note that this sealing function of the sliding collar 1633 is "temporary"; that is, unless specific conditions determined by the biasing mechanism 1635 are met. Figure 3F-2a and Figure 3F-2b As shown in the implementation scheme presented, the biasing mechanism 1635 is a simple spring.

[0230] exist Figure 3F-2a In the middle, collar 1633 is in its closed position, while Figure 3F-2b The central collar 1633 is in its open position. Therefore, the specific differential pressure applied to the cross-sectional area of ​​the sliding nozzle throat bushing 1631 has overcome the preset compression force of the spring 1635.

[0231] merged into Figure 3F-2a and Figure 3F-2b The third of the three additional components in the nozzle 1601 design is the sliding nozzle throat bushing 1631. The sliding throat bushing 1631 has two basic functions. First, the bushing 1631 provides an intentionally and predefined protrusion into the flow path within the nozzle throat 1650. Second, the bushing 1631 provides an erosion-resistant and abrasion-resistant surface within the highest fluid velocity section of the internal system 1500. Regarding the first of these three functions, the extent to which the protrusion into the sliding nozzle throat bushing 1631 is designed determines the point at which the operator intends to actuate the thrust nozzle 1613 within the micro-lateral formation.

[0232] For illustrative purposes, it is assumed that the system hydraulics provide a suitable pumping rate of 0.5 BPM through nozzle 1601 at the casing outlet “W” point, and that this pumping rate can be maintained at a surface pumping pressure of 8,000 psi. It is further assumed that the thrust nozzle 1613 in nozzle 1601 does not need to be actuated until nozzle 1601 reaches a lateral distance of 50 feet from the main borehole. That is, specifically when jetting the casing outlet “W” itself and pumping an abrasive mixture (e.g., 1.0 ppg of 100-mesh sand in a 1 pound guar gum-based freshwater adhesive system), nozzle 1613 does not open (as it may be at risk of being clogged by the abrasive in the jet fluid mixture). Therefore, after determining that nozzle 1600 has adequately cleaned the casing outlet “W”, the jet fluid does not contain abrasive. Accordingly, when the injection hole in the production casing 12 is used to form the casing outlet “W”, there is no backward jetting force from the fluid driven by the thrust nozzle 1613 that could pose a threat of unintentional damage to any of the injection hose 1595, the skewing device component 1000, or the production casing 12.

[0233] Subsequently, after generating the casing outlet "W" plus a micro-branch length of approximately 50 feet, the pump pressure is increased to 9,000 psi. The 1,000 psi increase in surface pumping pressure is sufficient to overcome the force of the bias mechanism 1635 and react on the cross-sectional area of ​​the protrusion of the bushing 1631, thereby actuating the nozzle 1613. Thus, at a micro-branch length of 50 feet from the main borehole 4, the thrust nozzle 1613 is actuated, generating a high-pressure backward thrust flow through the nozzle 1613.

[0234] Assume these conditions are sufficient to continue jetting microchannels up to a length of 300 feet. At 300 feet, the length of the jet hose resting against the bottom of the microchannel causes a similar amount of frictional resistance, such that the frictional resistance is approximately balanced with the thrust generated through the thrust nozzle 1613. (Instruments such as a tension meter, for example, will indicate this approximate balance). At this point, the pumping rate increases to, for example, 10,000 psi, and the rearward thrust nozzle 1613 remains actuated, but actuated with a higher pressure differential and flow rate, thus generating a higher pull on the jet hose 1595.

[0235] Figure 3F-3a and Figure 3F-3c A longitudinal cross-sectional view of the injection nozzle 1602 in another alternative embodiment is provided. Here, multiple rearward thrust nozzles 1613 and a single forward injection channel 1640 are used again. A collar 1633 and a spring 1635 are used again to provide selected fluid flow through the rearward thrust nozzles 1613.

[0236] Figure 3F-3b and Figure 3F-3d They are shown respectively Figure 3F-3a and Figure 3F-3c Axial cross-sectional views of the injection nozzle 1602 are shown. These figures illustrate a star-shaped nozzle pattern created by multiple nozzles 1613. Eight dots are visible within the star, representing two sets of four (which may alternate) exemplary thrust nozzles 1613. Figure 3F-3a and Figure 3F-3b In the middle, collar 1633 is in its closed position, while... Figure 3F-3c and Figure 3F-3d In the middle, the collar 1633 is in its open position, allowing fluid to flow through the nozzle 1613. The biasing force provided by the spring 1635 has been overcome.

[0237] Figure 3F-3a and Figure 3F-3c Nozzle 1602 and Figure 3F-2a and Figure 3F-2b The nozzle 1601 is similar; however, in Figure 3F-3a and Figure 3F-3c In this arrangement, an electromagnetic force that generates a force sufficient to overcome the biasing force of the biasing mechanism (spring) 1635, which is sufficient to resist the downstream magnetic pull of the sliding collar 1633, replaces the resistance. Figure 3F-2a and Figure 3F-2b The hydraulic pressure of the sliding throat bushing 1631 in the injection nozzle 1601.

[0238] Figure 3F-3a and Figure 3F-3c Nozzle 1602 presents another preferred embodiment of the rotary nozzle 1602, also suitable for forming a casing outlet and continuously excavating through cemented retaining walls and main rock formations. Figure 3F-3a and Figure 3F-3c (as well as Figure 3 In G-1 (described in more detail below), the electromagnetic force generated by the rotor / stator system must overcome the force of spring 1635 to open the hydraulic inlet to the rearward thrust nozzles 1613 (and 1713). (Note in...) Figure 3 In G-1, a coaxial hydraulic injection collar is depicted, which will be discussed in more detail below. The direct mechanical connection between the internal turbine fins 740 and the sliding collar 733 alters the bias standard for one of the different pressures. Figure 3F-2a (The same as the jet nozzles depicted). The key here is the ability to keep the fluid inlet closed before the operator begins to open the fluid inlet to the rearward thrust nozzles 1613 (and 1713) (specifically by increasing the pumping rate so that the pressure differential through the nozzle and / or the nozzle rotation speed increases proportionally to the electromagnetic pull on the sliding collar 1633 / 1733 to open the fluid inlet to the thrust nozzles 1613 / 1713).

[0239] It was also observed that the number of rearward thrust nozzles 1613 (although also symmetrically placed around the circumference of rotor 1610) in nozzle 1602 has increased from five in a single group to four in two groups. Note that each of the four nozzles 1613 in each of these two groups is also symmetrically placed around the circumference of rotor 1610, orthogonal to each other; therefore, the two groups of nozzles 1613 must overlap. Furthermore, the path of each nozzle now travels not only through the rearward (stator) portion 1610 of nozzle 1602, but also through the forward (rotor) section 1620 of nozzle 1602. However, it should be noted that, as Figure 3F-3b and Figure 3F-3d As depicted, there are eight separate injection channels through the rearward (stator) section 1610 of nozzle 1602, while only four exist through the forward (rotor) section 1620 of nozzle 1600. Therefore, each rotation of the forward (rotor) section 1620 of nozzle 1602 will only provide alignment of a set of four nozzles 1613, and subsequent fluid flow through them. In fact, for most of the duration of a single rotation, the flow channels of rotor 1620 do not have inlets to the flow channels of stator 1610, thus being effectively sealed. The result will be an oscillating (or “pulsating”) jet flow through the rearward thrust nozzles 1613.

[0240] The same reduction in the volume of the jet fluid passing through nozzle port 1640 also produces an equivalent amount of pulsed forward jet flow for digging. The benefits of continuous flow and the opposite pulsed flow for the digging system have been well demonstrated and will not be repeated here. However, it should be noted that the subject nozzle design not only gains the benefits of rotary jet rock digging but also the benefits of pulsed jet.

[0241] Figure 3G-1a and Figure 3G-1b Another implementation scheme for a thrust collar using electromagnetic force is provided. Figure 3G-1a Presented Figure 3 An axial cross-sectional view of the basic body of the thrust injection collar 1700 of the internal system 1500. This view is along... Figure 3G-1b The line D-D' is cut off. Here, similar to the jet nozzle 1602, two layers of rearward thrust nozzles 1713 are provided again.

[0242] 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 equidistantly spaced therein, while the rotor 1720 defines a body having a series of outwardly facing shoulders 1725 equidistantly spaced around it. Figure 3 In the arrangement of G.1.a, the stator body 1710 has six inward-facing shoulder-shaped structures 1715, while the rotor body 1720 has four outward-facing shoulder-shaped structures 1725.

[0243] Along each shoulder 1715, small-diameter conductive wires 1716 are arranged, each encased inwardly with multiple wrappings around the stator 1710's inward-facing shoulder (or "stator pole") 1715. Therefore, according to a DC rotor / stator system, the movement of current through the wires 1716 creates an electromagnetic force. Figure 3A The 1551 battery provides power to the wires.

[0244] Figure 3G-1b This is a longitudinal cross-sectional view of nozzle 1700. Figure 3G-1c It is along Figure 3G-1b The axial cross-section of the thrust nozzle 1713 is taken from the line d-d'.

[0245] Figures 3G-1a to 3G-1c Schemes of rotary nozzles 1600, 1601, and 1602 are shown, but with modifications to adapt the device for use as a coaxial thrust jet collar 1700. Particular attention is paid to the retention of the collar throat 1750 and the flow rotor 1725 coupled to the stator 1715 and bearing 1730. However, the fixed flow channel through the stator 1710 for the rearward thrust nozzle 1713 is split in two sets of four staggered sections. For each complete rotation, each of the four orthogonal nozzles in the single set of four through the rotor 1725 "matches" four times with the nozzle through the stator 1710, each match providing four instantaneous pulses of flow equidistantly spaced around the outer circumference of the collar 1700. Similar to rotary nozzle 1602, a sliding collar 1733 is electromagnetically moved against a biasing mechanism (spring) 1735 to actuate the flow through the rearward thrust nozzle 1713.

[0246] Figure 3G-1c This is another cross-sectional view showing the star-shaped pattern of the rearward thrust nozzle 1713. Eight points can be seen.

[0247] There is a unique opportunity to configure the collar 1733 as either a net power consumer or a net power provider. The former relies on power supplied by the battery pack, just as the injection nozzle 1600 does, to actuate the stator, rotate the rotor, and generate the required electromagnetic field. The latter is achieved by incorporating slightly angled turbine fins 1740 within 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 depend solely on the pumping rate and the configuration of the turbine fins 1740.

[0248] On one hand, the internal turbine fins 1740 are equidistantly positioned around the collar throat 1750, allowing hydraulic pressure to be used to rotate the rotor 1720 and provide net residual current to be fed back to the internal system circuitry. This can be achieved by feeding excess current back to the wires 1590. Incorporating the rotor / stator configuration into the configuration of the rearward thrust nozzle collar allows the fully open ID to be equal to the ID of the injection hose. More ample hydroelectric power can be obtained to generate the electromagnetic field required to operate the sliding port collar 1733, and once the internal system 1500 is detached from the mooring station 325, the available residual hydroelectric power is fed to the now “off” electrical system. Therefore, this residual hydroelectric power generated by the collar 1700 can be advantageously used to maintain the charge of the battery 1551 in the battery pack 1550.

[0249] It can be observed that the various nozzle designs 1600, 1601, and 1602 discussed above are designed to not only jet through the rock matrix but also through the steel casing and the cemented liner around the borehole 4c to reach the rock. The nozzle design incorporates the ability to pre-treat the relatively large-particle abrasive through the forward nozzle jet port 1640 before engaging with the RTJ 1613. It is understandable that while other nozzle designs could be used to achieve the purpose of forming microchannels, this design is not robust enough to cut through steel.

[0250] 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 determined by angle θ. MAX (Where, when the outermost edge of the nozzle reaches the point corresponding to the forward direction of the nozzle tip, the width of the nozzle is equal to the width of the nozzle) and θ SLOT (Actual groove angle) is limited. Note θ. SLOT ≤θ MAX For descriptive purposes, θ is used here. SLOT =θ MAX This design ensures that even when the tip of the rotating nozzle touches the surface of the main rock (or casing ID) during jetting, the tip still excavates a tunnel diameter equal to the outer (maximum) nozzle diameter. It is this single-plane rotating groove construction that provides the maximum width to allow sufficient passage capacity for any abrasives that may be incorporated into the jet fluid.

[0251] The preferred rearward orifice injection orientation is 30° to 60° away from the longitudinal axis. The rearward thrust nozzles 1613 / 1713 are designed to be circumferentially symmetrical about the stator body 1610 / 1710 of the nozzle / collar. This maintains the fully forward orientation of the injection assemblies 1600, 1601, and 1602 along the longitudinal axis. Accordingly, there should be at least three nozzles 1613 / 1713 equidistantly spaced around the circumference, preferably at least five equidistant nozzles 1613 / 1713.

[0252] As described above, the nozzle in any of its embodiments can be deployed as part of a guidance or geoguided system. In this case, the nozzle will include at least one geospatial chip and will employ at least three actuator lines. The actuator lines are equidistantly spaced around the nozzle and receive current or excitation from wires 1590 already disposed in the injection hose 1595.

[0253] Figure 3F-1c It is in the revised implementation plan Figure 3F-1b A longitudinal cross-sectional view of the injection nozzle 1600. Here, the injection nozzle 1600 is shown connected to the injection hose 1595. This connection can be a threaded connection; alternatively, the connection can be made by welding. Figure 3F-1c In the diagram, 1660 illustrates a schematic welded connection.

[0254] exist Figure 3F-1c In the arrangement, the jet nozzle 1600 includes a geospatial integrated circuit (“IC”) chip 1670. The geospatial chip 1670 is located within an IC chip 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 invention is not limited by the type or number of geospatial chips used or their corresponding location within the assembly, unless 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 those shown and described in conjunction with the nozzle embodiments (1600, 1601, 1602) described above).

[0255] Figure 3F-1d It is intercepted along line c-c'. Figure 3F-1c An axial cross-sectional view of the injection hose 1590. Wires 1590 and actuator line 1590A are visible in this view. Optional fiber optic data cable 1591 is also visible. Wires 1590, 1590A, and 1591 can be used to transmit geographic location data from chip 1670 to a microprocessor in battery section 1550, and then wirelessly to a location at the mooring station (…). Figure 4D-1b The receiver (best shown in 325) communicates with the microprocessor in the mooring station 325. Preferably, the microprocessor in the mooring station 325 processes 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 to hydraulically drill a lateral borehole in a pre-programmed direction.

[0256] The micro-emitter 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 interior of the injection hose carrier system 400 (hereinafter referred to as...). Figure 3A , Figure 3B-1 and Figure 4D-1 (Description to follow). The receiver housed in mooring station 325 can be electrically or optically connected to a microprocessor at ground 1. For example, fiber optic cable 107 can extend along coiled tubing transport system 100 to ground 1, where geographic location data is processed as part of the control system.

[0257] Hardwired (again, preferably fiber optic) connections, via fiber optic cable 107 within coiled tubing transport medium 100 and external system 2000, to a specific end receiver (not shown) housed within mooring station 325, also facilitate reverse (surface to downhole instrument) communication. A neighboring wireless transmitter within mooring station 325 then transmits operator-desired commands to a wireless receiver housed within end cap 1530 of internal system 1500. This communication system allows the operator to execute commands to set the rotational speed and / or trajectory of injection nozzle 1600.

[0258] When nozzle 1600 leaves the casing, the operator knows the position and orientation of nozzle 1600. By monitoring the length of the injection hose 1590 that has been moved out of the injection hose carrier, and in conjunction with any changes in orientation, the operator knows the geographical location of nozzle 1600 in the reservoir.

[0259] In one option, the desired geographic trajectory is first issued as a geological guidance command from ground 1, down to coiled tubing 100, and then to a microprocessor associated with mooring station 325. Upon receiving the geological guidance command from ground 1 (e.g., from an operator or ground control system), the microprocessor wirelessly pushes a signal to a corresponding microreceiver associated with battery segment 1550. This signal, in turn, causes one or more current regulators to alter the current conducted downwards along one, two, or all three of at least three wires 1590 directly connected to the injection nozzle 1600. Note that at least a portion of these wires, preferably the segment closest to the injection nozzle 1600, is connected by actuator lines 1590A (such as those manufactured by Dynalloy, Inc.). The actuator wires are composed of small-diameter nickel-titanium wires that contract when electrically excited. This ability to bend or shorten is characteristic of certain alloys that dynamically change their internal structure at certain temperatures. The contraction of the actuator wires, unlike ordinary thermal expansion, can increase by hundreds of times, requiring enormous forces to accommodate their small size. Precise position control, i.e., control at the micrometer level or smaller, can be achieved by tightly controlling the temperature under constant stress. Accordingly, assuming (at least) three separate actuator wires 1590A are positioned equidistantly or approximately equidistantly around the perimeter of the injection hose and within its body (towards its end, near the injection nozzle 1600), a small increase in current in any given wire will cause it to contract more significantly than the other two, thereby manipulating the injection nozzle 1600 along the desired trajectory. Given the initial depth and orientation via a geospatial chip in the nozzle 1600, a predetermined path for the lateral drilling 15 can be pre-programmed and automatically executed.

[0260] Accordingly, the actuator line 1590A has a distal segment positioned along the cavity or sheath, or even interwoven with the matrix of the distal segment of the injection hose 1595. Furthermore, the distal end of the actuator line 1590A may continue partially into the nozzle body, wrapping around the stator pole 1615 to connect to or even form the electromagnetic coil 1616. Figure 3F-1c This is also demonstrated in the diagram. In this way, power is provided from the battery pack section 1550 to initiate the relative rotational movement between the rotor body and the stator body.

[0261] As can be seen from the above discussion, an internal system 1500 is provided for the hose injection assembly 50. System 1500 enables powerful hydraulic nozzles (1600, 1601, 1602) to inject subsurface rock in a controlled (or maneuverable) manner, thereby creating a micro-lateral borehole that may extend several feet into the formation. The unique combination of the internal system 1500's injection fluid receiving funnel 1570, upper seal 1580U, and injection hose 1595, in conjunction with the pressure regulating valve 610 and packer section 600 of the external system 2000 (discussed below), provides a system by which the advance and retraction of the injection hose 1595 can be performed entirely hydraulically, regardless of the orientation of the borehole 4. Alternatively, mechanical devices can be added using an internal traction system 700, which is described in more detail below.

[0262] Controlling the components listed above not only determines the direction of the injection hose 1595's advance (e.g., forward or retraction), but also controls the rate of advance. The forward or retraction rate of the internal system 1500 can be directly proportional to the rate (and pressure) of fluid venting and / or pumping in. Specifically, "pumping hose 1595 downhole" will have the following sequence:

[0263] (1) Hydraulic fluid is pumped through the main control valve 310 and then through the pressure regulating valve 610 to fill the micro-annular gap 1595.420 between the injection hose 1595 and the inner conduit 420 of the injection hose carrier; then

[0264] (2) Using the ground controller, electronically switch the main control valve 310 to begin directing the jet fluid to the internal system 1500;

[0265] (3) This generates hydraulic pressure relative to the internal system 1500, guiding the jet fluid through the inlet funnel 1570 into the jet hose 1595 and to the “downhole”; this force is resisted by the following

[0266] (4) The hydraulic fluid in the compressed micro-annular gap 1595.420; the hydraulic fluid

[0267] (5) As desired, release from the surface controller of the pressure regulating valve 610 to regulate the rate at which the internal system 1500 is brought down to the “downhole”.

[0268] Similarly, the internal system 1500 can be pumped back to the "well surface" by guiding the pumped hydraulic fluid (first) through the main control valve 310 and (then) through the pressure regulating valve 610, thereby forcing the increasing (expanding) volume of hydraulic fluid into the micro-annular gap 1595.420 between the injection hose 1595 and the injection hose conduit 420. This pushes upward on the bottom seal 1580L of the injection hose sealing assembly 1580, thereby driving the internal system 1500 back to the "well surface". The direction and rate of propulsion of the internal system 1500 via the hydraulic system can be increased or replaced by propulsion of the internal system 1500 via the mechanical system of the internal traction system 700, as described below.

[0269] Advantageously, once the injection hose assembly 50 is deployed in a downhole location near the desired point of the casing outlet “W” within the main borehole 4, regardless of its inclination (including horizontal or near-horizontal), the entire length of the injection hose 1595 can be deployed and retrieved without the aid of gravity. This is because the propulsion forces used for deploying and retrieving the injection hose 1595, and in doing so, maintaining its proper alignment, are hydraulic or mechanical, as described more fully below. It should also be noted that the available amount of these propulsion hydraulic and mechanical forces is more than sufficient to overcome any frictional forces arising from movement of the internal system 1500 (including, specifically, the injection hose 1595) within the external system 2000 (including, specifically, the injection hose carrier 420) due to any non-vertical alignment, and to maintain the hose 1595 in a substantially taught state along its length within the external system 2000. Therefore, these hydraulic and mechanical propulsion forces completely overcome the limitation of “unable to push the rope.”

[0270] At any point during the pumping of the jet fluid, hydraulic pressure will be observed to advance the jet hose 1595 into and subsequently out of the external system 2000; specifically, a force in the upstream-to-downstream direction in a plane parallel to the longitudinal axis of the jet hose 1595, because the hydraulic pressure is applied relative to the upstream end cap of the battery pack 1520, the fluid inlet funnel 1570, and the inner surfaces of the jet nozzle 1600 (such as any surface of the internal system 1500), which: (a) are exposed to the flow of the jet fluid; and (b) have an directional component that is not parallel to the longitudinal axis of the main borehole. Since these surfaces are rigidly attached to the jet hose 1595 itself, whenever the jet fluid is transported from the surface 1 along the coiled tubing medium 100 (… Figure 2 (As seen in the image) downwards and through the jet fluid passage 345 within the main control valve 300 (see below) Figure 4C-1 (As described) is pumped, and this force from upstream to downstream is directly transmitted to the injection hose 1595. Note that the only other valve in the system, namely the pressure regulating valve 610 located just upstream of the packer sealing assembly 650 in the packer section 600 (as described). Figure 4E-1 and Figure 4E-2 The function (as seen and described) is to simply release from the jet hose 1595 / jet hose conduit 420 annulus 1595.420 at a rate comparable to the rate at which the operator expects the internal system 1500 to be lowered. Figure 3D-1a and Figure 4D-2 The pressure of the compressed hydraulic fluid seen in the image.

[0271] Conversely, whenever hydraulic fluid is pumped downwards from ground 1 along the coiled tubing medium 100 and through the hydraulic fluid passage 345 within the main control valve 300, the hydraulic pressure is operable as the internal system 1500 is advanced in a downstream-to-upstream direction. In this configuration, the pressure regulating valve 610 allows the operator to introduce injection fluid into the injection hose 1595 / injection hose conduit 420 annulus 1595.420 at a rate corresponding to the operator's desired rise in the internal system 1500. Therefore, the hydraulic pressure can be used to assist in the transport and retrieval of the injection hose 1595.

[0272] Similarly, the mechanical force applied by the internal traction system 700 helps transport, retrieve, and maintain the alignment of the injection hose 1595. The tight tolerance between the OD of the injection hose 1595 and the ID of the injection hose conduit 420 of the injection hose carrier system 400 (thus defining the annular gap 1595.420) provides a restrained axial force that helps maintain the alignment of the hose 1595, ensuring that the portion of the hose 1595 within the injection hose carrier system 400 never experiences significant bending forces. The direct mechanical (tension) force for the deployment and retrieval of the injection hose 1595 is applied through the direct frictional attachment of the clamp 756 of the specially designed clamp assembly 750 of the internal traction system 700 to the injection hose 1595, as described below. Figure 4F-1 and Figure 4F-2 discuss.

[0273] As described above, the hydraulic pressure from the rearward thrust nozzle 1613 originating from the injection nozzles 1601, 1602 themselves also helps transport the injection hose, and, if any additional injection collar 1700 is included, the hydraulic pressure from the rearward thrust nozzle 1713 originating from the injection collar also helps transport the injection hose. These downstream hydraulic pressures are used to form UDP15 ( Figure 1B Simultaneously, the injection hose 1595 is pushed forward into the drilling area 3, maintaining the forward-aimed injection fluid as close as possible to the rock surface being excavated. A balance needs to be struck between deploying hydraulic energy forward toward the nozzle (for excavating a new hole) and deploying it backward (for advancing). If too much backward thrust is used, there isn't enough remaining hydraulic horsepower to concentrate on excavating a new hole. If too much injection fluid is expelled forward, there isn't enough fluid available to push the nozzles 1613 / 1713 backward to generate the horsepower needed to drag the injection hose along the transverse borehole. Therefore, the ability to redirect the concentrated hydraulic horsepower backward or forward through the nozzle, as described here, is an important improvement.

[0274] For descriptive purposes, two configurations of the rearward thrust nozzles 1613 / 1713 are included herein: one configuration causes the flow to pulsate, wherein eight rearward thrust nozzles (each inclined at 30° from the longitudinal axis and equidistantly spaced around the circumference) are divided into two groups of four, with alternation (or “pulsation”) of rearward flow between the two groups; and a configuration for continuous flow, wherein a single group of five nozzles is shown, each inclined at 30° from the longitudinal axis and equidistantly spaced around the circumference. However, other numbers and angles of nozzles may be employed.

[0275] Figure 3The series of figures and the preceding paragraphs of the discussion of those figures pertain to the internal system 1500 for the hydraulic injection assembly 50. This internal system 1500 provides a novel system for delivering and transporting the injection hose 1595 into and out of the main borehole 4 in a single trip-in / trip-out, facilitating the subsequent operative formation of multiple micro-lateral boreholes 15. The injection hose 1595 can be as short as 10 feet or as long as 300 feet or even 500 feet or longer, depending on the formation thickness and compressibility strength or the desired geographic trajectory of each lateral borehole.

[0276] As described, the hydraulic injection assembly 50 also provides an external system 2000, which is uniquely designed for transporting, deploying, and retrieving the previously described internal system 1500. The external system 2000 can be transported on a conventional coiled tubing 100; however, more preferably, the external system is deployed on a “bundled” coiled tubing product (…). Figure 3D-1a , Figure 4A-1 and Figure 4A-1a It provides real-time power and data transmission.

[0277] Consistent with the relevant and shared patent documents cited herein, the external system 2000 includes a jet hose directional drilling component 1000, which includes a directional drilling device 1050 having a curved surface 1050.1, which preferably forms the bending radius of the jet hose 1595 across the entire ID of the production casing 12. The external system 2000 may also include a conventional tool assembly consisting of a completion-facilitating mud motor 1300, an (external) coiled tubing tractor 1350, logging tools 1400, and / or packers or bridge plugs (preferably retrievable). Furthermore, the external system 2000 provides power and data transmission throughout, enabling real-time control of the downhole components 50.

[0278] Figure 4 yes Figure 2 A longitudinal cross-sectional view of the external system 2000 of the downhole hydraulic injection assembly 50 in one embodiment. The external system 2000 is shown located within the production casing 12 string. For clarity, Figure 4 The external system 2000 is presented as "empty"; that is, it does not contain any information about... Figure 3 The series of accompanying drawings depict the components of the internal system 1500. For example, the injection hose 1595 is not shown. However, it should be understood that the injection hose 1595 is largely contained within the external system during insertion and withdrawal.

[0279] When presenting the components of the external system 2000, it is assumed that the system 2000 extends into a production sleeve 12 having 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 2.500”. This OD limit provides an outer diameter equal to or greater than 7.0309 inches. 2 The flow-open annular region (i.e., between the OD of system 2000 and the ID of the surrounding production casing 12) corresponds to a 9.2#, 3.5” fracturing (tubing) string.

[0280] The external system 2000 is configured to allow the operator to optionally “fracture” downwards along the annulus between the coiled tubing delivery medium 100 (attached to the equipment) and the surrounding production casing 12. A substantially annular region is maintained between the OD of the external system 2000 and the ID of the production casing 12, allowing the operator to pump fracturing (or other treatment) fluid downwards along the main annulus immediately after injecting the desired number of lateral boreholes, without needing to pull the coiled tubing 100 with the equipment 2000 out of the main borehole 4. Therefore, multiple production enhancement treatments can be performed in a single trip-in / trip-out of the assembly 50 into the main borehole 4. Of course, the operator can choose borehole shutdown for each fracturing operation, in which case the operator will utilize standard (mechanical) bridge plugs, fracturing plugs, and / or movable sleeves. However, this would impose significantly higher time requirements (with a similar amount of cost) and cause greater erosion and fatigue of the coiled tubing-based delivery medium 100.

[0281] In practice, strict adherence to the (OD) limits may only be fundamental for the coiled tubing transport medium 100, which may account for more than 90% of the length of system 50. Slight violations of the OD limits on the relatively small lengths of other components of the external system 2000 should not cause a significant drop in annular hydraulic pressure that would lead to prohibition. If these outer diameter limits 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 this can be achieved for system 50 operating in a standard oilfield production casing 4 with a smaller 4.5” OD, then there should be no significant obstacle to adapting system 50 to any larger standard oilfield production casing size (5.5”, 7.0”, etc.).

[0282] Each of the main components of the external system 2000 presented below will be arranged in a upstream-to-downstream direction. Note Figure 4 The main components of the external system 2000 are divided into sections, and the corresponding diagram is shown here:

[0283] a. 100 tons of medium transported via coiled tubing Figure 4A-1 and Figure 4A-2 As shown in the image;

[0284] b. First cross connector (coiled tubing transition piece) 200, Figure 4B-1 As shown in the image;

[0285] c. Main control valve 300 Figure 4 As shown in C.1;

[0286] d. Jet hose carrying system 400 and its mooring station 325, Figure 4D-1 and Figure 4D-2 As shown in the image;

[0287] e. The second cross connector 500 (transitioning the outer body from a circular to a star shape) and the injection hose sealing section 600, Figure 4E-1 and Figure 4E-2 As shown in the image;

[0288] f. External traction system 700 and third cross connector 800 Figure 4F-1 and Figure 4F-2 As shown in the image;

[0289] g. Third cross connector 800 and upper swivel 900 Figure 4G-1 Shown;

[0290] h. Inclined beam components 1000, Figure 4H-1 Shown;

[0291] i. Lower rotating ring 1100, Figure 4I-1 As shown in the middle; and finally

[0292] j. A transition connector 1200 that connects to the coiled tubing mud motor 1300 and the conventional coiled tubing traction machine 1350, and is coupled to the conventional logging probe 1400. Figure 4J As shown in the image.

[0293] Figure 4A-1 This is a longitudinal cross-sectional view of the coiled tubing transport medium 100. The transport medium 100 is used as... Figure 2 The delivery system for the downhole hydraulic injection assembly 50. The delivery medium 100 is shown as being located within the production casing 12 of the main borehole 4 and extending through the column foot heel 4b and into the horizontal support 4c.

[0294] Figure 4A-1a yes Figure 4A-1An axial cross-sectional view of the coiled tubing transport medium 100 is shown. It can be seen that the transport medium 100 includes a core 105. In one aspect, the coiled tubing core 105 is constructed from a standard 2.000” OD (105.2) and 1.620” ID (105.1), 3.68 lbm / ft. HST110 coiled tubing string with a minimum field strength of 116,700 lbm and an internal minimum yield pressure of 19,000 psi. This standard-size coiled tubing provides a 2.06-inch flow-open section. 2 The inner cross-sectional area. As shown, the "bundling" product 100 includes three wire ports 106 with a diameter up to 0.20”, which can accommodate standard wires of AWG#5 specification and two data cable ports 107 with a diameter up to 0.10”.

[0295] The coiled tubing transport medium 100 also has an outermost or “wrap” 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 with and is exactly equal to the OD105.2 of the core coiled tubing string 105.

[0296] Figure 4A-1 and Figure 4A-1a The axial and longitudinal sections presented in the diagram assume that the product 100 is bundled concentrically. However, in practice, eccentric bundling may be preferred. Eccentric bundling provides more protective sheathing for the wires 106 and data cables 107. Figure 4A-2 This includes the depiction of the eccentrically bundled coiled tubing delivery medium 101. Fortunately, there is no practical disagreement regarding the size of the eccentric bundle, which is set for lubricating the sealing rubber or wellhead device injection components entering and exiting the main borehole, because the OD105.2 and annular shape of the outer sheath 110 of the eccentric delivery medium 101 remain unaffected.

[0297] The transport medium 101 may have, for example, 2.0612 inches. 2 The internal flow region, 0.190 in 2 The core wall thickness is 105 mm, and the thickness is 0.25 inches. 2 Average outer wall thickness. The outer wall 110 can have a thickness of 0.10 inches. 2 The minimum thickness.

[0298] Note that regardless of whether the binding is concentric 100 or eccentric 101, the primary design standard for the transport medium is to provide real-time power (via wire 106) and data (via data cable 107) transmission capabilities to the operator at the surface 1 when deploying, operating, and retrieving equipment 50 in the borehole 4. For example, in a standard coil system, components 106 and 107 would extend into the coiled tubing core 105, thus exposing them to any fluid pumped via ID 105.1 of the core 105. Considering that the main approach provides abrasives within the pumped high-pressure jet fluid (particularly, simultaneously eroding the casing outlet "W" from within the production casing 12), it is preferable to alternatively position components 106 and 107 at OD 105.2 of the core 105.

[0299] Similarly, the main method provides to pump proppant within the high-pressure hydraulic fracturing fluid downwards along the annulus between the coiled tubing transport medium 100 (or 101) and the production casing 12. Therefore, the protective coiled tubing sheath 110 preferably has sufficient thickness, strength, and corrosion resistance to isolate and protect components 106 and 107 during fracturing operations.

[0300] The transport medium 100 (or 101) also maintains a sufficiently large inner diameter 105.1 of the core wall 105 to avoid significant frictional losses (compared to the losses caused by the internal system 1500 and the external system 2000) during pumping of jet and / or hydraulic fluid. Simultaneously, the system maintains a sufficiently small outer diameter 110.2 to avoid excessive pressure losses when pumping hydraulic fracturing fluid down the annulus between the transport medium 100 (or 101) and the production casing 12 along the coiled tubing. Furthermore, the system 50 maintains a sufficient wall thickness for the outer sheath 110, whether it is concentrically or eccentrically wrapped around the inner coiled tubing core 105, to provide adequate insulation and spacing for the electrical transmission line 105 and the data transmission line 107. It should be understood that other sizes and other tubular bodies can be used as transport media for the external system 2000.

[0301] Moving further down along the external system 2000, Figure 4B-1 The longitudinal cross-sectional view of the first cross connector, namely the continuous tubing cross connector 200, is presented. Figure 4B-1a A perspective view of a portion of the coiled tubing cross connector 200 is shown. Specifically, the transition between lines E-E' and F-F' is shown. In this arrangement, the outer contour transitions from a circle to an ellipse to bypass the main control valve 300.

[0302] The main functions of the cross connector 200 are as follows:

[0303] (1) Connect the coiled tubing delivery medium 100 (or 101) to the injection assembly 50, and specifically, to the main control valve 300. Figure 4B-1In the diagram, the connection is depicted as a steel continuous tubing core 105 connected at connection point 210 to the outer wall 290 of the main control valve.

[0304] (2) The wire 106 and data cable 107 are transitioned from the outside of the core 105 of the coiled tubing transport medium 100 (or 101) to the inside of the main control valve 300. This is accomplished by the wiring port 220 that facilitates the transition of the wire / data cable 106 / 107 in the outer wall 290.

[0305] (3) Provides easily accessible points, such as threads and paired collars 235 and 250, for splicing / connection of wires 106 and data cables 107.

[0306] as well as

[0307] (4) The pressure and fluid protection conduit, i.e. the wiring chamber 230, provides a separate, non-crossing and non-interfering path for the wires 106 and the data cables 107.

[0308] The next component in the external system 2000 is the main control valve 300. Figure 4C-1 A longitudinal cross-sectional view of the main control valve 300 is provided. Figure 4C-1a Provided along Figure 4C-1 The axial cross-sectional view of the main control valve 300 taken by line G-G'. (This will be combined with...) Figure 4C-1 and Figure 4C-1a Let's discuss the main control valve 300 together.

[0309] The function of the main control valve 300 is to receive high-pressure fluid pumped from the continuous tubing 100 and selectively direct it to the internal system 1500 or the external system 2000. The operator sends control signals to the main control valve 300 via wire 106 and / or data cable port 107.

[0310] The main control valve 300 includes two fluid passages. These passages include a hydraulic fluid passage 340 and a jet fluid passage 345. Figure 4C-1 , Figure 4C-1a and Figure 4C-1b The sealing channel cover 320 can be seen in the longitudinal section view, axial section view, and perspective view, respectively. The sealing channel cover 320 is assembled to form a liquid-tight seal for the inlets of both the hydraulic fluid channel 340 and the jet fluid channel 345. Relatedly, Figure 4C-1b A three-dimensional depiction of the channel cover 320 is presented. This view shows how the cover 320 is shaped to help minimize friction and erosion effects.

[0311] 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 a passage cover pivot motor 360. The sealing passage cover 320 is positioned by the passage cover pivot 350 (e.g., driven by the passage cover pivot motor 360) to: (1) seal the hydraulic fluid passage 340, thereby introducing all fluid flow from the coiled tubing 100 into the jet fluid passage 345, or (2) seal the jet fluid passage 345, thereby introducing all fluid flow from the coiled tubing 100 into the hydraulic fluid passage 340.

[0312] The main control valve 300 also includes a wiring conduit 310. The wiring conduit 310 carries the electrical wire 106 and the data cable 107. The wiring conduit 310 is optionally elliptical at the receiving point of the coiled tubing transition connector 200, and gradually transitions to a curved rectangular shape at the point where the electrical wire 106 and data cable 107 are inserted into the injection hose support system 400. Advantageously, this curved rectangular shape is used to position the injection hose conduit 420 along the entire length of the injection hose support system 400.

[0313] The next component of the external system 2000 is the jet hose carrying system 400. Figure 4D-1 This is a longitudinal cross-sectional view of the injection hose support system 400. The injection hose support system 400 is attached downstream of the main control valve 300. The injection hose support system 400 is a generally elongated tubular body that houses the mooring station 325, the battery pack section 1550 of the internal system, the injection fluid receiving funnel 1570, the sealing assembly 1580, and the connected injection hose 1595. Figure 4D-1 In the view, only mooring station 325 is visible, making the outline of the jet hose carrying system 400 more clearly visible.

[0314] Figure 4D-1a It is along Figure 4D-1 The line H-H' intercepted Figure 4 Axial cross-sectional view of the jet hose support system 400 of D.1. Figure 4D-1b yes Figure 4D-1 An enlarged view of a portion of the jet hose carrying system 400. Mooring station 325 can be seen here. (Refer to...) Figure 4D-1 , Figure 4D-1a and Figure 4D-1b Each of these is discussed together in the jet hose carrying system 400.

[0315] The jet hose support system 400 defines a pair of tubular bodies. The first tubular body is the jet hose conduit 420. The jet hose conduit 420 houses, protects, and stabilizes the internal system 1500 (and specifically, the jet hose 1595). As previously presented in the discussion of the internal system 1500, the size (specifically, ID), strength, and stiffness of this liquid-tight and pressure-tight conduit 420 provide a passage, particularly for micro-annular gaps (…). Figure 3D-1a , Figure 4D-2 and Figure 4D-2a (shown as 1595.420), so that the injection hose 1595 of the internal system 1500 can "pump down" and "pump up" in the opposite direction along the longitudinal axis of the external system 2000 when running in the production sleeve 12.

[0316] The injection hose carrying section 400 also has an outer conduit 490. The outer conduit 490 is arranged along and connected to the inner conduit 420. In one aspect, the outer conduit 490 and the injection hose conduit 420 are concentric 2.500” OD and 1.500” ODHSt100 coiled tubing strings, respectively. The inner conduit or injection hose conduit 420 is sealed to and connected to the injection fluid passage 345 of the main control valve 300. When the valve 300 introduces high-pressure injection fluid into the injection fluid passage 345, the fluid flows directly and only into the injection hose conduit 420, and then into the injection hose 1595.

[0317] An annular region 440 exists between the inner (jet hose) conduit 420 and the surrounding outer conduit 490. The annular region 440 is also hydraulically tight, directly sealing and connecting to the hydraulic fluid passage 340 of the control valve 300. When the main control valve 300 introduces high-pressure jet fluid into the hydraulic fluid passage 340, the fluid flows directly into the conduit-bearing annular gap 440.

[0318] The jet hose carrier section 400 also includes a wiring chamber 430. The wiring chamber 430 has an upwardly curved rectangular axial cross-section and receives the wire 106 and data cable 107 from the conduit 310 of the main control valve 300. The liquid-tight chamber 430 not only separates, insulates, accommodates, and protects the wire 106 and data cable 107 along the entire length of the jet hose carrier section 400, but its bracket shape also supports and stabilizes the jet hose conduit 420. Note that the jet hose carrier section 400 wiring chamber 430 and the inner (jet hose) conduit 420 may or may not be attached to each other and / or to the outer conduit 490.

[0319] In addition to housing and protecting the wires 106 and data transmission cable 107, the wiring conduit 430 within the jet hose carrying system 400 also supports the horizontal axis of the jet hose conduit 420 at a location slightly above the horizontal axis that divides the outer conduit 490 into two parts. Given that its design constraints are significantly less stringent than those of the outer layers of CT-based delivery media, particularly in terms of chemical resistance and abrasion resistance, different types of materials can be used in its construction, as the exterior of the wiring conduit 430 will only be exposed to hydraulic fluid—never to jet or fracturing fluid.

[0320] If it is desired that the wiring conduit 430 be rigidly attached to the jet hose conduit 420 or the outer conduit 490, or both, additional design specifications can be imposed on the wiring conduit. In one aspect, the wiring conduit 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. It should be understood that other diameters and configurations of the wiring conduit 430 can vary depending on the design purpose, as long as the annular region 440 open to the flow of hydraulic fluid is retained.

[0321] Can still be Figure 4D-1 Mooring station 325 is seen in the diagram. Mooring station 325 is located downstream of the connection between the main control valve 300 and the injection hose support system 400. Mooring station 325 is rigidly attached to the interior of the injection hose conduit 420. Mooring station 325 is supported within the injection hose conduit 420 by diagonal supports. The diagonal supports are hollow, and their interiors serve as liquid-tight and pressure-tight conduits for introducing wires 106 and data cables 107 into the communication / control / electronic systems of mooring station 325. This is similar to the function of the battery pack support conduit 1560 of the internal system 1500. Whether connected to servo devices, transmitters, receivers, or other devices housed within mooring station 325, these devices are therefore "hardwired" via wires 106 and data cables 107 to the operator's control system (not shown) at ground 1.

[0322] Figure 4D-2 An enlarged longitudinal cross-sectional view of a portion of the jet hose carrying system 400 of the external system 2000 depicts its operative accommodation of the same length of the jet hose 1595. Figure 4D-2a Provides H-H' intercept along the line Figure 4D-2 Axial cross-sectional view of the jet hose support system 400. Note that, except for Figure 4D-1a The conduit 420 is "empty" to indicate that it is not shown except for the jet hose 1595. Figure 4D-2a cross-sectional view and Figure 4D-1a The cross-sectional views are similar.

[0323] The length of the injection hose conduit 420 is considerably long and should be approximately equal to the desired length of the injection hose 1595, thereby defining the maximum reachable distance of the injection nozzle 1600 orthogonal to the borehole 4, and the corresponding length of the micro-branch 15. The inner diameter specification defines the size of the micro-annular gap 1595.420 between the injection hose 1595 and the surrounding injection hose conduit 420. Its ID should be close enough to the OD of the injection hose 1595 to prevent the injection hose 1595 from bending or kinking, but must be large enough to provide sufficient annular area for the robust seal assembly 1580L through which hydraulic fluid can be pumped into the sealed micro-annular gap 1595.420 to help control the rate of deployment of the injection hose 1595 or to aid in hose retrieval.

[0324] The hydraulic pressure within the sealed micro-annular gap 1595.420 keeps the segment of the injection hose (located above the internal traction system 700) straight and slightly taut. Similarly, the ID of the injection hose conduit 420 must not be too close to the OD of the injection hose 1595 to prevent unnecessarily high friction between them. The OD of the injection hose conduit 420 (plus the ID of the outer conduit 490, minus the external dimensions of the wiring chamber 430 of the injection hose carrier) defines an annular region 440 through which hydraulic fluid is pumped. Of course, if the O.D. of the inner conduit 420 of the injection hose carrier system is too large, it will therefore cause excessive frictional losses when pumping hydraulic fluid. However, if it is not large enough, then the inner conduit 420 will not have sufficient wall thickness to support the required internal or external operating pressure. Note that for the main equipment designed to be deployed in a 4.5” drill casing, the inner string comprises coiled tubing with an OD of 1.5” and an ID of 1.25” (i.e., a wall thickness of 0.125”). For example, if it is 1.84# / ft, HST110, then it will provide an internal minimum yield pressure rating of 16,700 psi. Similarly, the outer guide 490 can be constructed from standard coiled tubing. In one aspect, the outer guide 490 includes 2.50” OD and 2.10” ID, thus providing a wall thickness of 0.20”.

[0325] Once again moving from the surface to the downhole, the external system 2000, including the second cross connector 500, transitions to the injection hose isolation section 600. Figure 4E-1 An elongated cross-sectional view of the cross connector (or transition piece) 500 and the injection hose sealing section 600 is provided. Figure 4E-1a This is an enlarged perspective view highlighting the outer body shape of the transition piece 500, which transitions from a circular to a star shape. Axial section lines I-I' and J-J' show the outline of the transition piece 500, which at its beginning fits the dimensions of the outer wall 490 of the jet hose support system 400 and at its end fits the dimensions of the outer wall 690 of the packer section 600.

[0326] Figure 4E-2 It shows Figure 4E-1 The enlarged portion of the injection hose packer section 600, and particularly the sealing assembly 650. The transition piece 500 and the injection hose packer section 600 will be discussed together with reference to each of these views.

[0327] As its name suggests, the primary function of the injection hose isolation section 600 is to "isolate" or seal the annular space between the injection hose 1595 and the surrounding inner conduit 620. The injection hose isolation section 600 is a fixed component of the external system 2000. Passing through the transition piece 500 and partially through the isolation section 600 is a direct extension of the micro-annular gap 1595.420. This extension abuts against the inner surface of the sealing cup constituting the isolation sealing assembly 650 and terminates at the pressure / fluid seal of the injection hose 1595. Just before this termination is the position of the pressure regulating valve. Figure 4E-1 and Figure 4E-2 Component 610 is schematically shown. This valve 610 is used to connect the annulus 1595.420 or to isolate the annulus from the hydraulic fluid flowing through the entire external system 2000. The hydraulic fluid flows from the inner diameter of the coiled tubing transport medium 100 (specifically, from ID105.1 of the coiled tubing core 105) and proceeds through continuous hydraulic fluid channels 240, 340, 440, 540, 640, 740, 840, 940, 1040, and 1140, then through transition connector 1200 to the coiled tubing mud motor 1300, and finally terminates at the tractor 1350. (Alternatively, termination at some other conventional downhole application operating point such as a hydraulically installed retrievable bridge plug).

[0328] It is worth noting the cross connector 500 from the jet hose carrier system 400 to the packer section 600, for several reasons as follows:

[0329] First, within the transition section 500, the free flow of hydraulic fluid from the conduit-bearing annulus 440 of the injection hose bearing section 400 will be redirected and redivided within the upper (triangular) quarter of the star-shaped outer conduit 690. A pressure regulating valve 610 faces the upstream end of the inner conduit 620. The pressure regulating valve 610 provides increased or decreased hydraulic fluid (and, equally, hydraulic pressure) in the micro-annulus 1595.420 between the injection hose 1595 and the surrounding injection hose conduit 420. Operation of this valve 610 provides the internal system 1500 (and specifically, the injection hose 1595) to be "pumped downwards" along the longitudinal axis of the production sleeve 12 and then, in reverse, "pumped upwards."

[0330] A rectangular, upwardly curved, liquid-tight cavity 430, which separates, insulates, houses, and protects the wires 106 and data cables 107 along the length of the jet hose carrier body 400, transitions via a wiring chamber 530 into the lower (triangular) quarter 630 of the star-shaped outer body 690 of the packer section 600. This retains, insulates, houses, and protects the wires 106 and data cables 107 within the jet hose packer section 600. The star-shaped outer body 690 forms an annular gap between itself and the ID of the surrounding production sleeve 12.

[0331] Given that the distance between the tips of the four-pointed star-shaped outer guide tube 690 and their counterparts is only slightly less than the ID of the production casing 12, the packer section 600 is also used to approximately center the jet hose 1595 within the main borehole production casing 12. As will be explained later, this approximately centering will be translated through the inner traction system 700 to advantageously center the upstream end of the directional drilling assembly 1000.

[0332] Recall that the outer diameter of the upstream end of the injection hose 1595 is hydraulically sealed relative to the inner diameter of the inner conduit 420 of the injection hose support system 400 by the upper seal 1580U and lower seal 1580L of the injection hose forming a single sealing assembly 1580. The seals 1580U and 1580L, which are shaped to be attached to the injection hose 1595, travel up and down along the inner conduit 420. Similarly, the outer diameter of the downstream end of the injection hose 1595 is hydraulically sealed relative to the inner diameter of the inner conduit 620 of the partition section 600 by the sealing assembly 650 of the partition section 600. Therefore, when the internal system 1500 is "plugged in" (i.e., when the upstream battery pack end cap 1520 contacts the mooring station 325 of the external system), the distance between the two sealing assemblies 1580, 620 is approximately the full length of the injection hose 1595. Conversely, when the injection hose 1595 and injection nozzle 1600 have fully extended into the maximum length of the transverse bore (or UDP) 15 achievable through the injection assembly 50, the distance between the two sealing assemblies 1580, 620 is negligible. This is because, although the internal system's injection hose sealing assembly 1580 extends substantially the entire length of the external system 2000's injection hose support system 400, the sealing assembly 650 (of the partition section 600 in the external system 2000) is relatively fixed, as the sealing cups including the sealing assembly 650 must be positioned between opposing sealing cup stops 615.

[0333] Also note how the alignment of the two sets of opposing sealing cups, including the sealing assembly 650 (e.g., an upstream set facing upstream and a downstream set facing downstream, placed back-to-back), provides a pressure / fluid seal against pressure differentials from the upstream or downstream direction. Figure 4E-2In the enlarged view, these opposing sealing cup assemblies, including sealing assembly 650, are shown in longitudinal cross-section with spray hose 1595 passing concentrically through them.

[0334] As described, the pressure maintained by the pressure regulating valve 610 in the micro-annular gap 1595.420 provides the hydraulic action of "pumping the hose down the borehole" or conversely, "pumping the hose up the borehole." These annular hydraulic pressures also serve to mitigate other potentially harmful forces that may be applied to the injection hose 1595, such as bending forces when pushing the hose 1595 downstream, or internal burst forces during injection. Therefore, in combination with the upper hose sealing assembly 1580 and the injection hose conduit 420, the injection hose sealing section 600 is used to maintain the injection hose 1595 in a substantially taut state. Thus, the diameter of the hose 1595 that can be used will be limited only by the bending radius imposed by the ID of the production casing 12 of the borehole and by the equivalent pressure rating of the hose 1595. Meanwhile, the length of the hose 1595 that can be used is, of course, preferably several hundred feet.

[0335] Note that the most likely limitation on the length of hose 1595 is not anything imposed by the external system 2000, but rather the hydraulic horsepower that can be distributed to the rearward thrust nozzles 1613 / 1713, allowing sufficient horsepower to remain focused forward for rock excavation. As one would expect, the length (and equivalent volume) of the micro-channels that can be ejected ultimately relates to the rock strength in the subsurface formation. This length limitation is quite different from the system proposed in U.S. Patent No. 6,915,853 (Bakke et al.) that attempts to transport the entire ejection hose within the device itself in a continuous manner downhole. That is, in Bakke et al.'s patent, the hose is stored and transported in a horizontally stacked, 360° coil housed within the device's interior. In this case, the bend radius / pressure hose limitation is not imposed by the casing's ID (among other limitations), but by the device's own ID. This results in a significantly smaller hose ID / OD, and therefore, geometrically less horsepower that can be delivered to Bakke's ejection nozzles.

[0336] In operation, after UDP15 has been formed and the main control valve 300 has been set to shut off the flow of hydraulic fluid to the internal system 1500 and then supply hydraulic fluid to the external system 2000, the pressure regulating valve 610 can feed flow in the opposite direction into the micro-annular gap 1595.420. This downstream-to-upstream force “pumps” the assembly back into the borehole 4 and “on the well” because the bottom-facing cup 1580L of the sealing assembly 1580 suppresses the flow (and pressure) below the cup.

[0337] The next component within the external system 2000 (again, from the surface to the downhole) is the optional internal traction system 700. Figure 4F-1 An elongated cross-sectional view of the traction system 700 downstream of the injection hose isolation section 600 is provided. Figure 4F-2 It shows Figure 4F-1 The amplification section of the traction system 700. Figure 4F-2a It is along Figure 4F-1 and Figure 4F-2 The axial cross-sectional view of the internal traction system 700, taken from line K-K'. Finally, Figure 4F-2b yes Figure 4F-2a An enlarged half-view of a portion of the internal traction system 700. The internal traction system 700 will be discussed together with reference to each of these four drawings.

[0338] First, it can be seen that there are two known types of traction systems: wheeled traction systems and so-called creeping traction systems. All of these traction systems are "external" systems, meaning they have clamps designed to engage the inner wall of the surrounding casing (or, if in a bare well, the borehole wall). In the oil and gas industry, traction systems are primarily used to advance logging cables or coiled tubing strings (and attached downhole tools) up or down a horizontal (or highly deviated) borehole.

[0339] In this component 50, a unique traction system employing an "internal" clamp has been developed. This means that the clamp assembly 750 is inwardly aligned to facilitate the forward or retraction of the injection 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 within the borehole 4c. The outwardly aligned electric drive wheel of a conventional ("external") traction machine is replaced by an inwardly pointing concave clamp 756. The result is that the inwardly pointing concave clamp 756 frictionally attaches to the injection hose 1595, with subsequent rotation of the clamp 756 advancing the injection hose 1595 in a direction corresponding to the direction of rotation.

[0340] Specifically note the following result of this reversal: In a conventional system, the relative movement that occurs is the relative movement of the rigid clamp attachment body (i.e., coiled tubing) relative to the fixed friction attachment body (i.e., borehole wall). Conversely, the internal traction system is rigidly attached to the fixed body (i.e., external system 2000), and the clamp 756 rotates to move the injection hose 1595. Therefore, when the internal traction system 700 is actuated, the directional drilling component 1000 will already be in its set and operating position; for example, the sliding element of the directional drilling component 1000 will engage with the inner wall of the casing 12. Thus, when the external system 2000 is fixed itself and stationary within the production casing 12, all the forward / retraction of the injection hose 1595 by the traction system 700 will occur.

[0341] Secondly, it can be seen that the internal traction system 700 preferably maintains the star-shaped profile of the injection hose sealing system 600. The star-shaped profile of the internal traction system 700 and its four points help to center the traction system 700 within the production sleeve 12. This is advantageous because when the traction system 700 is operated, the sliding element of the skewing device 1000 (positioned relatively close to the traction system 700 because of the short lengths of the third cross connector (or transition piece) 800 and the upper swivel 900, discussed below) will engage, meaning that the centering of the traction system 700 is used to align the path of the injection hose 1595 and prevent any improper torque at the connection with the injection hose skewing device 1000. Figure 4F-1 and Figure 4F-2a As can be seen, the position of the injection hose 1595 is approximately centered within the traction system 700 and thus within the production sleeve 12. This positions the hose 1595 optimally in the feed into or retracts from the injection hose skewer 1000.

[0342] In addition to centering the hose 1595, the star-shaped profile of the traction system 700 provides another function: it offers internal space for housing two opposing clamp assemblies 750. Specifically, the clamp assemblies 750 are located in the "dry" working chambers of the two side chambers, while providing separate sealed chambers for the wires 106 and data cables 107 (shown in the lower chamber 730) and hydraulic fluid (in the upper chamber 740). Meanwhile, sufficient cross-sectional flow area is maintained between the traction system 700 and the ID of the production casing 12 within their respective annular regions 700.12 for conducting fracturing fluid.

[0343] As shown, within the 4.5” production sleeve 12, the annular area open to the flow is approximately 10.74 in 700.12. 2This is equivalent to a 3.69-inch equivalent tube diameter (ID). Recall that the design objective was to maintain the annular flow area at or greater than the internal area of ​​a typical 3.5” OD (2.922” ID, 10.2# / ft.) fracturing column, which is 6.706 inches. 2 Then note that if the tip-to-tip dimension of the relative points of the "star" is, for example, 3.95 inches, and (in order to obtain additional internal volume in the four chambers of the traction system 700) the star is transformed into a perfect square, then the external area of ​​the square will be 7.801 inches. 2 Furthermore, the remaining annular area (open to the flow of fracturing fluid) in the 4.00” ID production casing will be 4.765 inches. 2 This corresponds to a 2.463” tube ID. Therefore, while the base of each triangular cavity within the star shape can be extended to some extent to provide additional internal volume or wall thickness, the outer perimeter does not need to be perfectly square and still meet the preferred 3.5” fracturing column criterion. However, note that there is no reason why the triangular dimensions of each chamber must remain symmetrical; for example, the dimensions can be varied individually to accommodate the internal volume requirements of each chamber, as long as the 3.5” fracturing column requirement is still preferably met.

[0344] Each of the clamping assemblies 750 includes a miniature motor 754 and a motor mount 755 that secures the motor 754 to the outer wall 790. Furthermore, each of the clamping assemblies 750 includes a pair of shafts. These represent a clamping shaft 751 and a clamping motor shaft 753. Finally, each of the clamping assemblies 750 includes a clamping gear 752.

[0345] The traction system 700 also includes a bearing system 760. The bearing system 760 is positioned along the length of the inner wall 720. The bearing system 760 isolates the frictional forces acting on the injection hose 1595 at the contact points of the clamp 756 and eliminates unwanted frictional forces acting on the inner wall 720.

[0346] The rearward rotation of clamp 756 is used to advance hose 1595, while the forward rotation of clamp 756 is used to retrieve hose 1595. The propulsive force provided by clamp 756 assists the advance of the injection hose 1595 by pulling it through the injection hose support system 400, transition member 500 and packer section 600, and by pushing the injection hose 1595 into the transverse borehole 15 itself.

[0347] Figure 4F-1The diagram only depicts two sets of opposing clamp assemblies 750. However, depending on compression, torsion, and horsepower limitations, clamp assemblies 750 can be added to accommodate jet hoses 1595 of virtually any length and configuration. Additional clamp assemblies 750 should increase traction, which may be desirable for extended transverse boreholes 15. While it is speculated that this is true when the paired clamp assemblies 750 are placed axially opposite each other in the same plane (e.g., ...). Figure 4F-2 When shown in .a), the maximum clamping force will be obtained, that is, the "clamping" force on the jet hose 1595 will be maximized, but other arrangements / placements of the clamping system 750 are also within the scope of this aspect of the invention.

[0348] Optionally, the internal traction system 700 also includes a tension meter. This tension meter provides real-time measurements of the tensile force on the upstream section of the hose 1595 and the pushing compressive force on the downstream section of the hose 1595. Similarly, a mechanism may be included that allows the compressive force of each set of clamps 756 to be applied individually to the jet hose 1595 to compensate for uneven wear of the clamps 756.

[0349] The main components of the external system 2000, from upstream to downstream, will be described again. Figure 4G-1 A longitudinal cross-sectional view of the internal traction machine to the (or third) upper swivel (cross connection) 800 and the upper swivel (900) itself is shown. Figure 4G-1a A perspective view of the cross connector 800 between its upstream and downstream ends, represented by lines L-L' and M-M' respectively, is depicted. Figure 4G-1b The axial cross-sectional view is presented within the upper rotating ring 90° along line N-N'. Combined with... Figure 4G-1 and Figure 4G-1a Let's discuss the third transition piece 800 and the upper rotating ring 900 together.

[0350] The transition section 800 functions similarly to the preceding transition sections (200, 500) of the external system 2000 discussed herein. For example, the transition section 800 includes an inner wall 820 and a surrounding outer wall 890 and defines a hydraulic fluid passage 840 located between the inner and outer walls. In short, the primary function of the transition section 800 is to convert the axial profile of the star-shaped internal traction machine system 700 back to the concentric circular profile used for the swivel 900, and to perform this conversion within the ID limit of the 3.5” fracturing column test.

[0351] The upper rotating ring 900 performs three important functions simultaneously:

[0352] (1) First, it allows the indexing mechanism to rotate the connected slant generator component 1000 without twisting any upstream component of the system 50.

[0353] (2) Second, it provides rotation of the skewing device 1000 while maintaining a straight path for the wires 106 and data cables 107 through the wiring chamber 930 between the transition member 800 and the skewing device member 1000.

[0354] (3) Third, it provides a horseshoe-shaped hydraulic fluid chamber 940 that adapts to the rotation of the skewer component 1000 while maintaining a continuous hydraulic flow path between the transition piece 800 and the skewer component 1000.

[0355] Two sets of bearings, 960 (inner bearing) and 965 (outer bearing), are required to simultaneously meet the above design standards. On one hand, the upper slewing ring 900 has an OD of 2.6 inches.

[0356] The outer wall 990 of the upper rotating ring 900 maintains the circular profile achieved by the outer wall 890 of the transition piece 800. Similarly, concentric circular profiles are obtained in the intermediate body 950 and inner wall 920 of the upper rotating ring 900. These three consecutive and concentric smaller cylinders (990, 950, and 920) provide an inner set of circumferential bearings 960 (between the inner wall 920 and the intermediate body 950) and an outer set of circumferential bearings 965 (between the intermediate body 950 and the outer wall 990). The larger cross-sectional area of ​​the intermediate body 950 allows it to accommodate the placement of the horseshoe-shaped hydraulic fluid chamber 940 and the arcuate wiring chamber 930. Bearings 960 and 965 facilitate relative rotation of the three consecutive and concentric smaller cylindrical bodies 990, 950, and 920. Bearings 960 and 965 also provide the skewing device component 1000 in its set and operating position within the upper rotating ring 900 (also in... Figure 4G-1 The rotatable movement below (shown in the diagram) provides for changing the orientation of subsequent lateral boreholes ejected from the main borehole 4 at a given set depth. In other words, the upper swivel ring 900 allows the indexing mechanism (described in the relevant U.S. Patent No. 8,991,522, the entire contents of which are incorporated herein) to rotate the directional drilling component 1000 without twisting any upstream component of the external system 2000.

[0357] It can also be observed that the upper rotating ring 900 provides rotation for the directional drilling component 1000 while maintaining a straight path for the wires 106 and the data cable 107. The upper rotating ring 900 also allows the horseshoe-shaped hydraulic fluid chamber 940 to provide rotation for the directional drilling component 1000 while maintaining a continuous hydraulic flow path down to and beyond the directional drilling component 1000.

[0358] Return to Figure 4As described above, the external system 2000 includes a directional directional generator component 1000. The jet hose directional directional generator component 1000 is a fully reorientable, reconfigurable, and retrievable directional directional generator device, similar to those described in previous works: U.S. Provisional Patent Application No. 61 / 308,060, filed February 25, 2010; U.S. Patent No. 8,752,651, filed February 23, 2011; and U.S. Patent No. 8,991,522, filed August 5, 2011. Because these applications reiterate their discussions of directional generator setup, actuation, and repositioning, and are incorporated herein by reference, a detailed discussion of the jet hose directional directional generator device 1000 will not be repeated here.

[0359] Figure 4 H.1 provides Figure 2 A longitudinal cross-sectional view of a portion of borehole 4. Specifically, the jet hose directional drilling assembly 1000 can be seen. The jet hose directional drilling assembly 1000 is in its set position, wherein the upper curved surface 1050.1 of the directional drilling assembly 1050 receives the jet hose 1595. The jet hose 1595 bends across a hemispherical channel defining the surface 1050. The surface 1050.1 engages with the inner wall of the production casing 12 to form the only possible path within which the jet hose 1595 can be pushed through the casing outlet “W” and the transverse borehole 15, and subsequently retract from the casing outlet “W” and the transverse borehole.

[0360] exist Figure 4 H.1 also shows a nozzle 1600. The nozzle 1600 is disposed at the end of the jetting hose 1595. Jet fluid is dispersed through the nozzle 1600 to initiate the formation of a micro-lateral borehole penetrating the formation. The jetting hose 1595 extends downward from the inner wall 1020 of the jetting hose directional drilling member 1000 to deliver the nozzle 1600 to the directional drilling member 1050.

[0361] As discussed in U.S. Patent No. 8,991,522, the directional drilling assembly 1000 is configured with hydraulically controlled actuation of the jet hose. In one aspect, hydraulic pulse technology is used for hydraulic control. Release of the sliding element is achieved through tension on the tool. These actuations are designed in the directional drilling assembly 1000 to comply with the general limitations of the delivery medium (conventional coiled tubing) 100, which can deliver force both hydraulically (e.g., by manipulating surface hydraulic pressure and thus downhole hydraulic pressure) and mechanically (i.e., by tensioning the coiled tubing or by utilizing the compressive force of the coiled tubing's own descending weight).

[0362] In this document, the jet hose directional drilling assembly 1000 is designed to accommodate the further delivery of the electrical wire 106 and data cable 107 downhole. For this purpose, a wiring chamber 1030 (conducting the electrical wire 106 and data cable 107) is provided. Power and data are supplied from an external system 2000 to conventional logging facilities 1400, such as gamma-ray-casing coupling locators, which mate with rotary tools. This will be directly attached below the conventional mud motor 1300 and the coiled tubing tractor 1350. Therefore, for this embodiment, hydraulic transmission from the directional drilling assembly 1000 is required to operate the immediately below conventional (“external”) hydraulic-electric coiled tubing tractor 1350, and electrical (preferably fiber optic) transmission is required to operate the logging probe 1400 below the coiled tubing tractor 1350. Figure 4H-1a and Figure 4H-1b The wiring chamber 1030 is shown along the following lines: Figure 4H-1 Cross-sectional views of lines O-O' and P-P'.

[0363] Note that the traction machine 1350 is positioned below the operating point of the injection nozzle 1600, and therefore never requires the transmission of the injection hose 1595 or high-pressure injection fluid to form the casing outlet “W” or subsequent lateral borehole. Therefore, there are no ID restrictions on this (bottom) coiled tubing traction machine 1350, except for the borehole itself. The coiled tubing traction machine 1350 can be of conventional wheel (“external roller”) type or clamp (“creep”) type.

[0364] A hydraulic fluid chamber 1040 is also provided along the injection hose directional drilling component 1000. The wiring chamber 1030 and the fluid chamber 1040 bifurcate as they transition from a semi-circular profile (roughly matching their counterparts 930 and 940 corresponding to the upper swivel 900) to a profile in which each chamber occupies a separate end segment of a rounded rectangle (spanning the directional drilling component 1050). Once sufficiently downstream of the directional drilling component 1050, the chambers can recombine into their original circular pattern, ready to mirror their respective dimensions and alignment in the lower swivel 1100. This enables the transport of electricity, data, and high-pressure hydraulic fluid through the directional drilling component 1000 (via their respective wiring chambers 1030 and hydraulic fluid chambers 1040) down to the mud motor 1300.

[0365] Below the swashplate component 1000 and nozzle 1600 but above the traction machine 1350 is an optional lower swashplate 1100. Figure 4I-1 This is a longitudinal cross-sectional view of the lower rotating ring 1100 located between the jet hose skewing component 1000 and the cross connector 1200 and within the production sleeve 12. The sliding member 1080 is shown as being disposed within the sleeve 12. Figure 4I-1a It is the lower rotating ring 1100 edge Figure 4The axial cross-sectional view taken from line Q-Q' of I.1. (Refer to...) Figure 4I-1 and Figure 4I-1a Let's discuss the 1100 rotating ring.

[0366] The lower swivel 1100 is essentially a mirror image of the upper swivel 900. Like the upper swivel 900, the lower swivel 1100 includes an inner wall 1120, an intermediate body 1150, and an outer wall 1190. In a preferred embodiment, the outer conduit has an OD of 2.60” or slightly less. The OD limit for the outer conduit 1190 is a self-imposed 3.5” fracturing column equivalent test.

[0367] The intermediate body 1150 also houses the wiring chamber 1130 and the hydraulic fluid chamber 1140. The fluid chamber 1140 transports hydraulic fluid to the cross connector 1200 and ultimately to the mud motor 1300.

[0368] The lower swivel 1100 also includes a wiring chamber 1130 for housing the electrical wires 106 and data cables 107. Continuous electrical and / or fiber optic transmission may be required when real-time transmission of logging data (e.g., gamma ray and casing collar locator "CCL" data) or directional data (e.g., gyroscope data). Furthermore, continuous electrical and / or fiber optic transmission capability enables the manipulation of downhole components to be directly guided from the surface 1 in response to received real-time data.

[0369] Note that the inner conduit 920 of the upper swivel 900 is sized sufficiently to receive and conduct the hollow core of the jet hose 1595, while the lower swivel 1100 does not have this requirement. This is because, in the design of component 50 and its method of use, the jet hose 1595 is not intended to travel downwards beyond a point beyond the directional drilling component 1050. Therefore, the innermost diameter of the lower swivel 1100 can actually be constructed from a solid core, such as... Figure 4I-1a As depicted in the text, this adds additional strength and mass.

[0370] The lower swivel 1100 is located between the jet hose directional drilling assembly 1000 and any necessary cross-connections 1200, as well as downhole tools such as the mud motor 1300 and coiled tubing tractor 1350. Logging tools 1400, packers, or bridge plugs (preferably retrievable, not shown) may also be installed. Note that depending on the length of the horizontal portion 4c of the borehole 4, the size of the delivery medium 100 and the production casing 12, and the resulting friction, more than one mud motor 1300 and / or CT tractor 1350 may be required.

[0371] exist Figure 4J The final attached image is shown in the image. Figure 4JThe final transition component 1200, conventional mud motor 1300, and (external) coiled tubing tractor 1350 are depicted. In addition to the tools listed above, the operator can also choose to use a logging probe 1400 consisting of a gamma ray-casing coupling locator and a gyroscope logging tool. The gyroscope logging tool provides real-time data that describes not only the precise downhole position of the build-up face 1050.1 of the preceding jet hose build-up assembly 1000, but also its initial alignment. This data is used to determine:

[0372] (1) To guide the initial transverse drilling along its preferred orientation, how many degrees of alignment and realignment are required via the directional drilling face 1050.1?

[0373] (2) After the first transverse borehole is ejected, guide the subsequent transverse boreholes by how many degrees to align along their respective preferred orientations.

[0374] When preparing for subsequent hydraulic fracturing in the main horizontal borehole 4c, an initial borehole 15 will be ejected substantially perpendicularly to or near the same horizontal plane as the main borehole 4c, and a second lateral borehole will be ejected at an azimuth 180° rotation from the first borehole (again, perpendicularly to or near the same horizontal plane as the main borehole 4c). However, in thicker formations, particularly considering the ability to steer the ejector nozzle 160° in the desired direction, more complex lateral boreholes may be required. Similarly, in a given “perforation group” designed to receive a single hydraulic fracturing stage, multiple lateral boreholes (from multiple set points typically clustered together) may be required. The complexity of the design of each lateral borehole typically reflects the hydraulic fracturing characteristics of the main reservoir rock in production area 3. For example, the operator may design lateral boreholes with individually set profiles within a given “group” to help keep the hydraulic fracturing primarily within the “layer.”

[0375] This paper presents an improved downhole hydraulic injection assembly 50. Assembly 50 includes an internal system 1500 consisting of a guideable injection hose and a rotary injection nozzle that can inject casing outlet and subsequent lateral boreholes in a single step. Assembly 50 also includes an external system 2000, which, among other components, includes a carrier device that can accommodate, transport, deploy, and retract the internal system to repeatedly construct the required lateral boreholes during a single trip to and from the main borehole 4 (regardless of its inclination). The external system 2000 provides annular fracturing treatment (i.e., pumping fracturing fluid down the annulus between the coiled tubing deployment string and the production casing 12) to treat the newly injected lateral boreholes. When combined with staged isolation provided by a packer and / or positioning temporary or retrievable plugs to thus provide a repeatable sequence of plug-UDP-fractures, the completion of the entire horizontal section 4c can be completed in a single trip.

[0376] On one hand, when forming the bend radius 1599 of the injection hose 1595, component 50 can utilize the full ID of the production sleeve 12, thereby allowing the operator to use the injection hose 1595 with the maximum diameter. This, in turn, allows the operator to pump the injection fluid at a higher pumping rate, thereby generating higher hydraulic horsepower at the injection nozzle 1600 at a given pumping pressure. This will significantly increase the electrical output at the injection nozzle, which will achieve:

[0377] (1) Optionally, a large-diameter transverse borehole is drilled into the target formation;

[0378] (2) Optionally, a longer lateral length can be achieved;

[0379] (3) Optionally, a larger erosion penetration rate can be achieved; and

[0380] (4) Achieve higher intensity and threshold pressure (δ) M and P Th It can erode and penetrate oil / gas production areas that are considered inaccessible by existing hydraulic jetting technology.

[0381] Importantly, the internal system 1500 allows for the advancement of the injection hose 1595 and the connected injection nozzle 1600 unaffected by the mechanical downhole transport medium. Instead of a rigid working column attached to "push" the hose and connected nozzle 1600, the injection hose 1595 utilizes a hydraulic system that allows the hose and nozzle to travel longitudinally within the external system 2000 (in both upstream and downstream directions). This transformation enables the main system 1500 to overcome the inherent limitation of "unpush rope" in all other hydraulic injection systems to date. Furthermore, because the main system does not rely on gravity for propulsion or alignment of the injection hose / nozzle, system deployment and hydraulic injection can occur at any angle and at any point within the main borehole 4 where the assembly 50 can be "pulled" into place.

[0382] Downhole hydraulic jetting assemblies allow for the formation of multiple extended and directional micro-runways or boreholes from a single main borehole. Each micro-runway can extend from 10 feet to 500 feet or more from the main borehole. When applied to horizontal borehole completions in preparation for subsequent hydraulic fracturing (“frac”) treatments in certain geological formations, these small lateral boreholes can yield significant benefits in optimizing and enhancing fracture (or fracture network) geometry and subsequent hydrocarbon generation and reserve production. By achieving: (1) better extension of supported fracture length; (2) better constraint of fracture height within the production area; (3) better placement of proppant within the production area; and (4) further extension of the fracture network before cross-stage breakthrough, lateral boreholes can significantly reduce the necessary fracturing fluids, fluid additives, proppant, hydraulic horsepower, and thus associated fracturing costs previously required to achieve the desired fracture geometry (if achievable). Furthermore, for a fixed input of fracturing fluid, additives, proppant, and horsepower, creating lateral boreholes in the production area prior to fracturing can generate significantly larger reservoir volumes, to the point that it can increase the well spacing within a given oilfield. In other words, fewer wells may be needed in a given oilfield, resulting in significant cost savings. Moreover, in conventional reservoirs, the enhanced discharge obtained from the lateral boreholes themselves may be sufficient to eliminate the need for subsequent hydraulic fracturing.

[0383] As an added benefit, the downhole hydraulic jetting assembly 50 and method described herein allow operators to apply radial hydraulic jetting technology without “damaging” the main borehole. Furthermore, operators can jet radial lateral boreholes from the horizontal main borehole as part of a new well completion. Additionally, the jetting hose can utilize the entire ID of the production casing. Moreover, reservoir engineers or field operators can analyze the geomechanical properties of the target reservoir and then design fracture networks originating from customized structures derived from directional drilling lateral boreholes.

[0384] Hydraulic injection in lateral boreholes can be performed during well completion to enhance fracturing and acidizing operations. As described, in fracturing operations, fluids are injected into the formation at pressures sufficient to separate or fracture the rock matrix. In contrast, in acidizing, the acidic solution is pumped at a bottom-hole pressure lower than that required to fracture or fracturing a given production area. (However, in acid fracturing, the pumping pressure is intentionally higher than the formation fracturing pressure). Examples where pre-production enhancement injection in lateral boreholes may be beneficial include:

[0385] (a) Before hydraulic fracturing (or acid fracturing), to help limit the propagation of fractures (or fracture networks) within the production area and to establish a fracture (network) length at a considerable distance from the main borehole before any boundary layer rupture or before any cross-stage fracturing may occur; and

[0386] (b) Before the acid can be “consumed” and before the pumping pressure approaches the formation splitting pressure, use lateral boreholes to enhance the production of matrix acid treatment far beyond the area near the borehole.

[0387] The downhole hydraulic injection assembly 50 and method described herein also allow the operator to predetermine the injection path of the lateral borehole. This borehole can be controlled in terms of length, direction, or even shape. For example, curved boreholes or groups of curved boreholes can be intentionally shaped to further enhance the SRV exposure of formation 3 to borehole 4c. The borehole can optionally be shaped into a helical form to further expose formation 3 to borehole 4c.

[0388] The downhole hydraulic jetting assembly 50 and method described herein also allow operators to re-enter existing boreholes that have been completed in unconventional formations and to “re-fracture” the borehole by creating one or more transverse boreholes using hydraulic jetting technology. The hydraulic jetting process can utilize the hydraulic jetting assembly 50 in any embodiment of this invention. No workover rig, ball dropper / ball catcher, drillable base, or sliding sleeve assembly is required.

Claims

1. A spray hose carrying system, wherein, The jetting hose carrier system comprises: an elongated inner conduit sized to slidably receive a jetting hose and to serve as a jetting hose carrier, wherein a microannulus is formed between the jetting hose and the surrounding inner conduit, wherein the microannulus is sized to prevent the jetting hose from buckling; an elongated outer conduit surrounding the inner conduit, wherein an annular region is formed between the inner conduit and the surrounding outer conduit, the outer conduit sized to extend into a production casing string within a wellbore while accommodating a stimulation treatment between the outer conduit and the surrounding production casing; a wiring chamber housing electrical wires, data cables, or both, in the annular region between the inner conduit and the outer conduit, extending along the length of the outer conduit; a fluid chamber formed within the annular region; a master control valve having a jetting fluid valve passage, a hydraulic fluid valve passage, and an electric motor driving the master control valve between (i) a first position directing jetting fluid through the jetting fluid valve passage and into the inner conduit, and (ii) a second position directing hydraulic fluid through the hydraulic fluid valve passage and into the fluid chamber of the annular region formed between the inner conduit and outer conduit; a surface-controlled fluid pressure regulating valve arranged such that (i) when the master control valve is in the second position, the hydraulic fluid can be injected from the fluid chamber into the microannulus through the fluid pressure regulating valve to advance the jetting hose in an upstream direction, and (ii) when the master control valve is in the first position, the hydraulic fluid can be released from the microannulus to the fluid chamber through the fluid pressure regulating valve to control advancement of the jetting hose in a downstream direction; a whipstock member disposed below a lower end of the elongated outer conduit, the whipstock member having an arcuate face; wherein the jetting hose is transferred out of the jetting hose carrier system against the arcuate face of the whipstock when transferred by a transfer force, and then the jetting hose is pulled back into the jetting hose carrier system after a lateral borehole is formed; a jetting hose isolation system for sealing the annular space between the jetting hose and the elongated inner conduit; and an internal tractor system downstream of the jetting hose isolation system, the internal tractor system including at least two sets of clamp assemblies, the star-shaped profile of the internal tractor system providing internal space for placement of the clamp assemblies; Each of the clamp assemblies includes a micro motor, a motor mount securing the micro motor to an outer wall of the internal tractor system, a clamp shaft, and a clamp motor shaft, the clamp assemblies being aligned inwardly and including inwardly directed concave clamps that frictionally attach to the spray hose, wherein subsequent rotation of the concave clamps propels the spray hose in a direction corresponding to the direction of rotation to advance or retract the spray hose.

2. The spray hose carrier system of claim 1, wherein, The hose carrier system further includes an upper seal assembly at an upstream end of the spray hose, the upper seal assembly including one or more seals that are securely attached to an outer diameter of the spray hose, wherein the upper seal assembly is slidably movable within the inner conduit and forms an upstream boundary of the micro annulus; and The spray hose isolation system includes a series of fixed seals at a downstream end of the inner conduit, the fixed seals forming a downstream boundary of the micro annulus.

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