Contour-selective sleeve and system for subterranean multi-stage valve actuation

Abstract

A slide valve has a valve body, a sleeve received in a longitudinal bore of the valve body, and a collet received in a longitudinal bore of the sleeve. The valve body has one or more fluid ports on a wellhead portion of a sidewall thereof. The sleeve is movable between a wellhead closed position that closes the one or more fluid ports and a downhole open position that opens the one or more fluid ports. The sleeve has a sleeve profile formed by at least one or more sleeve grooves and one or more sleeve ridges longitudinally distributed on an inner surface thereof. The collet has a flexible collet profile formed by at least one or more collet grooves and one or more collet ridges respectively corresponding to the sleeve grooves and the sleeve ridges. Each sleeve ridge or collet ridge has a length that is less than a length of a corresponding sleeve groove or collet groove.

Description

Technical Field

[0001] This disclosure generally relates to downhole tools and methods, and more particularly to a downhole tool with profile-selective casing for actuating multi-stage valves in underground systems. Background Technology

[0002] Downhole tools are widely used in the oil and gas industry. Many downhole tools include pressure-actuated valves. For example, a prior art ball-actuated spool valve includes a tubular valve body with an orifice in which a spool is received. The spool includes a ball seat at its wellhead end and is initially configured in a wellhead-closed position, blocking one or more fluid ports on the sidewall of the valve body. To actuate the spool valve, a ball needs to be dropped and seated on the ball seat of the spool. Fluid pressure is then applied to the ball, actuating the downhole spool to an open position to open the fluid ports on the valve body.

[0003] One or more ball-actuated spools can be used to fracture subsurface formations during fracturing. However, one problem with cascading multiple ball-actuated spools for fracturing is that the orifice of the downhole spool must be smaller than that of the wellhead spool to allow a smaller ball to pass through these wellhead spools and reach the target downhole spool. In other words, the orifices of the cascaded spools must decrease sequentially from the wellhead to the downhole to ensure successful operation, which results in reduced flow at the downhole end.

[0004] U.S. Patent 4,043,392 granted to Gazda teaches an oil well system for selectively locking downhole tools along a flow guide in a wellbore, and a tool string used in the flow guide, the tool string including a locking mandrel, a casing displacement device, and an oil well safety valve. The selective locking system has a seating and locking recess profile including upward and downward-facing stop shoulders. One form of locking system is arranged in a sliding sleeve valve, which includes a cam release shoulder to release a selector and a locking key as the sliding sleeve valve moves between spaced longitudinal positions. Another form of locking system may be arranged along a seating sub and requires disabling the drilling tool locked therein to release the selector and locking tool. The casing displacement device has means for opening and closing a sliding sleeve valve, which includes a key with upward and downward-facing stop shoulders and a recess profile compatible with the seating and locking recess profiles of the casing valve or the seating sub. The casing displacement device can also be used as a locking mandrel. Selectivity is provided through variations in the seating and locking profiles, as well as the key profiles.

[0005] In US 4,043,392, the profiles of spring-biased keys are mutually exclusive. The key profile will only engage with a sleeve having a matching internal profile.

[0006] U.S. Patent 4,436,152 to Fisher et al. teaches an improved displacement tool that can be attached to an oil well tool string and used to engage and position a sleeve in an oil well flow guide within a sleeve assembly. Selectively shaped displacement tool keys provide a better fit and a larger contact area between the key and the sleeve. When the engaged sleeve cannot move upwards and the displacement tool cannot disengage automatically, an emergency disengagement method can be used to completely disengage the tool from the sleeve assembly by applying enough force to the displacement tool to shear the key and cause a cam motion inwards at both ends of all the keys.

[0007] U.S. Patent 5,305,833 to Collins teaches a displacement tool for a sliding sleeve valve used in oil and gas wells, the tool having positioning claws for selectively positioning and engaging a shoulder within the valve. A primary key engages and selectively displaces the sleeve to a balanced position and prevents premature displacement to a fully open position. The displacement tool also includes means for selectively over-controlling the anti-displacement function after balancing. An auxiliary key guides the primary key along the displacement direction and engages with the casing, moving the casing to a fully open, latched position. The displacement tool can also be selectively disengaged from the casing valve for removal from the well. Furthermore, a method is disclosed for selectively and sequentially displacing the sleeve of a sliding sleeve valve from a closed position to a balanced position and then from the balanced position to a fully open position.

[0008] In particular, US 5,305,833 teaches two separate spring-biased keys, wherein the first of the two keys may be fitted into the profile of the second key. However, the second key may not be fitted into the profile of the first key.

[0009] U.S. Patent 5,309,988 to Shy et al. teaches a subsurface well flow control system comprising a series of movable casing-type flow control devices mounted in a flow conduit at multiple fluid-containing fracture zones, and a displacement tool that is movable within the conduit and operable to selectively move casing portions of any selected number of flow control devices in either direction between their open and closed positions without removing the tool from the conduit. Multiple sets of radially retractable anchoring keys and displacement keys are provided in sidewall openings of the tool body, and these keys are configured to lockably engage with multiple sets of inner surface grooves on the body and movable casing portions of any of the flow control devices. These key sets are spring-bent radially outward toward an extended position, and an electromechanical drive system disposed within the tool body is operable to radially retract these key sets and axially drive the displacement key sets toward or away from the anchoring key sets. This allows the tool to move into or through any of the flow control devices in either axial direction, lock onto the device, operate to move its sleeve portion fully or partially in either direction, then disengage from the flow control device and move to any other flow control device to displace its sleeve portion. The interlocking V-threads on the body and sleeve portion of each flow control device help to releasably hold the sleeve portion in the partially displaced position.

[0010] US 5,309,988 also teaches two mutually exclusive bond profiles.

[0011] U.S. Patent 5,730,224 to Williamson et al. teaches an underground structure for controlling the entry and exit of a tool in a horizontal wellbore extending from a wellbore. The underground structure includes a bushing located within the wellbore and adjacent to an opening in the horizontal wellbore, and having an entry / exit window through which the tool can enter and exit the horizontal well via the opening. The bushing also has a sliding entry / exit control device coaxially coupled thereto. The underground structure further includes a displacement device that engages with the sliding entry / exit control device to slide between an open position and a closed position, allowing the tool to pass through the window and opening and enter the horizontal wellbore in the open position, and preventing the tool from passing through the window and opening and entering the horizontal wellbore in the closed position. The patent also teaches a method for controlling the entry and exit of a tool in a horizontal wellbore extending from a wellbore. The preferred method includes the following steps: 1) placing a bushing in the wellbore near an opening in the transverse wellbore, the bushing having an access window through which a tool can enter and exit the transverse wellbore through the opening, the bushing also having a sliding access control device coaxially connected thereto; 2) engaging the sliding access control device with a displacement device to allow the sliding access control device to slide relative to the bushing; and 3) sliding the sliding access control device between an open position and a closed position, the open position allowing the tool to pass through the window and opening and enter the transverse wellbore, and the closed position preventing the tool from passing through the window and opening and entering the transverse wellbore.

[0012] US 5,730,224 teaches two key profiles, one of which is the opposite of the other.

[0013] U.S. Patents 7,325,617 and 7,552,779, granted to Murray, teach a system that allows for the sequential processing of segments of a region. Each segment can be accessed using a sleeve with a specific internal profile. A pump plug with a specific profile that latches onto a particular casing can be used. When latched, pressure on the plug allows the casing to be opened sequentially while isolating the affected area below. The pump plug has a channel that is initially blocked by material that eventually dissipates under the desired well conditions. Thus, once all segments of the region have been processed, the flow path is re-established through the individual latch plugs. The plug can also be blown off the sleeve after operation, and the plug may have a key that prevents rotation along its axis if milling is required later.

[0014] U.S. Patent 9,611,727 to Campbell et al. teaches an apparatus and method for fracturing a well in a hydrocarbon-bearing formation. The apparatus includes a valve subassembly assembled with a casing section to form a well casing for the well. The valve subassembly includes a sliding piston positioned to seal a port providing communication between the wellbore interior and the production zone of the formation. A dart with a cup-shaped seal can be inserted into the wellbore and pushed by pressurized fracturing fluid until the dart reaches the valve subassembly, blocking the wellbore below it. The force of the fracturing fluid acting on the dart and its cup-shaped seal forces the piston downward to shear the pin and open the port. Fracturing fluid can then flow out of the port, thereby fracturing the production zone of the formation.

[0015] U.S. Patent 9,739,117 to Campbell et al. teaches a method and apparatus for selectively actuating a downhole tool in a tubular conduit. The actuator tool has an actuator mandrel having an actuator bore, a bypass, and a profile key for selectively engaging the downhole tool. The downhole tool has one or more profile receivers adapted to actuate the downhole tool. If the profile key mates with a profile receiver, the actuator tool is delivered into the tubular conduit, and the actuator tool engages with the downhole tool; if the profile key does not mate with a profile receiver, the actuator tool and the downhole tool do not engage. Fluid can circulate through the actuator bore to flush or wash before the actuator tool.

[0016] Westgard's U.S. Patent Publication 2003 / 0173089 teaches a full-hole selective positioning and orientation system comprising a short section that can be mounted in a tubing string and has a known internal positioning and orientation configuration, and a positioning device that can operate within the tubing string and has a positioning and orientation configuration that engages with the internal configuration of the short section. A method for positioning and orienting a downhole tool includes mounting a tubular short section having a specific internal dimensional configuration in a tubing string, the tubing string operating a positioning device having a complementary external dimensional configuration to engage with the internal dimensional configuration and rotating the positioning device to a position where a biasing member extends from the positioning device into a recess in the tubular member.

[0017] Jani's U.S. Patent Publication 2015 / 0226034 teaches an apparatus and related method for selectively actuating a sliding sleeve in a sub-component placed downhole in a wellbore to open a port in such a sub-component, thereby allowing fracturing of the wellbore or detonation of explosives thereon, or both simultaneously. This reduces machining work on each component by using simplified darts and casing. The dart is preferably equipped with a coupling device to which a retrieval tool is engaged, allowing a bypass valve to operate to assist in the retraction of the dart from a valve fitting when the retrieval tool is so engaged. Upward movement of the retrieval tool allows a wedge-shaped member to disengage the dart component from the corresponding casing for dart retraction.

[0018] U.S. Patent Publication 2014 / 0209306 by Hughes et al. teaches a wellbore treatment tool for abutting a constraint wall, the tool being positioned within the constraint wall. The wellbore treatment tool includes a tool body comprising a first end and an opposite end formed to be connected to a tubing string; a stop key assembly including a tubular housing and a stop key, the tubular housing defining an inner bore extending along the length of the tubular housing and an outer surface with the stop key, the stop key being configured to lock the stop key and the tubular housing in a fixed position relative to the constraint wall, the tubular housing fitting over the tool body, the tool body being mounted within the inner bore of the tubular housing; and a sealing element surrounding the tool body and located between a first compression ring on the tool body and a second compression ring on the tubular housing, the sealing element being expandable to form an annular seal around the tool body by compression between the first and second compression rings.

[0019] U.S. Patent Publication 2015 / 0218916 to Richards et al. teaches a recirculating casing that can be opened, closed, and permanently closed. A completion system includes a completion string having a recirculating casing movably disposed therein, the recirculating casing having a locking profile defined on its outer radial surface and a displacement profile defined on its inner radial surface. The completion system also includes a service tool at least partially disposed within the completion string and including a displacement tool having one or more displacement keys configured to engage with the displacement profile. When the displacement keys position and engage with the displacement profile, an axial load applied to the service tool causes axial movement of the recirculating casing. A release shoulder assembly is disposed within the completion string, and the release shoulder assembly includes a release shoulder defining a channel configured to receive a locking mechanism blocked therein until the release shoulder has moved axially.

[0020] Canadian Patent 2,412,072 by Fehr et al. teaches a tubing assembly for fluid treatment of a wellbore. This tubing can be used for segmented wellbore fluid treatment, in which selected portions of the wellbore are treated while others remain sealed. The tubing can also be used in situations where a ported tubing needs to be fed in a pressure-sealed state and then used with the port open.

[0021] The fracturing industry has always been very interested in alternative and / or improved designs that enable consistent and reliable engagement and actuation of underground valves and improve sealing performance. Summary of the Invention

[0022] According to one aspect of this disclosure, a plurality of spool valves are provided. Each spool valve includes:

[0023] - A valve body having a longitudinal orifice extending therethrough and one or more fluid ports located on the wellhead portion of the valve body's sidewall; and

[0024] - A sliding sleeve, which is received in a longitudinal bore in the valve body and is movable between a wellhead closed position that closes the one or more fluid ports and a downhole open position that opens the one or more fluid ports, the sliding sleeve including the longitudinal bore;

[0025] The sliding sleeve includes a sleeve profile formed by at least first and second sleeve grooves and sleeve ridges therebetween, the first and second sleeve grooves and sleeve ridges being longitudinally distributed on the inner surface of the sliding sleeve; and

[0026] The longitudinal length S of the first and second casing grooves and casing ridges g1 S g2 and S r They are determined by the following formulas respectively:

[0027] S r =δL a +nL b ,

[0028] S g1 =m1L b +(1-δ)L a ,

[0029] S g2 =m2L b ,

[0030] m1+m2=K,

[0031] Among them, L a L b And δ are predetermined parameters, L a >0, L b>0 and 1≥δ≥0, n is an integer and n≥0, K is a positive integer and K>2, m1 and m2 are integers and m1≥1 and m2>1; and

[0032] The longitudinal length L of the casing profile s At least:

[0033] L s =L a +(n+K)L b .

[0034] In some embodiments, the slide valve further includes a stop shoulder.

[0035] In some embodiments, the stop shoulder is located on the downhole side of the casing profile.

[0036] In some embodiments, the stop shoulder is located within the sleeve profile.

[0037] In some embodiments, the stop shoulder is located on the wellhead side of the casing profile.

[0038] In some embodiments, L a =L b .

[0039] In some embodiments, t1 = t2 = t.

[0040] In some embodiments, 1>t>0.

[0041] In some embodiments, t is approximately 0.5.

[0042] In some embodiments, 0.9 > t ≥ 0.1.

[0043] In some embodiments, 0.8 > t ≥ 0.2.

[0044] In some embodiments, 0.7 > t ≥ 0.3.

[0045] In some embodiments, 0.6 > t ≥ 0.4.

[0046] In some embodiments, t = 0.

[0047] In some embodiments, t = 1.

[0048] According to one aspect of this disclosure, a plurality of chucks are provided, each chuck movable through one or more holes in a first sleeve and receivable in a second sleeve. Each chuck includes:

[0049] A flexible chuck profile formed by at least first and second chuck ridges and chuck grooves therebetween, wherein the first and second chuck ridges and chuck grooves correspond to the first and second sleeve grooves and sleeve ridges, respectively.

[0050] The length C of the first and second chuck ridges and chuck grooves is mentioned. r1 C r2 and C g They are determined by the following formulas respectively:

[0051] C r1 =(m1-t1)L b +(1-δ)L a -ε2,

[0052] C r2 =(m2-t2)L b ,

[0053] C g =δL a +(n+t2)L b +ε2,

[0054] m1+m2=K,

[0055] Among them, L a L b And δ are predetermined parameters, L a >0, L b >>0 and 1≥δ≥0, n is an integer and n≥0, K is a positive integer and K>2, m1 and m2 are integers and m1≥1 and m2>1; t1, t2 and ε2 are predetermined parameters, 1≥t1≥0, 1≥t2≥0 and ε2≥0; and

[0056] The longitudinal length L of the chuck profile c At least:

[0057] L c =L a +(n+K-t2)L b .

[0058] In some embodiments, at least one of the at least one clamp ridges is located on the downhole side of the stop shoulder and forms an obtuse angle between the upper edges of its downhole side.

[0059] According to one aspect of this disclosure, a tubing string is provided, the tubing string comprising a plurality of the aforementioned slide valves having 1>t>0;

[0060] The slide valves are arranged in the tubing according to the following rules:

[0061] (a) For any two of the plurality of spool valves, at least one of their n, K, and m1 is different;

[0062] (b) A spool valve with a smaller (n+K) is located on the wellhead side of a spool valve with a larger (n+K);

[0063] (c) For spool valves with the same (n+K), the spool valve with the larger n value is located on the wellhead side of the spool valve with the smaller n value; and

[0064] (d) Slide valves with the same n and the same K but different m1 can be arranged in any order.

[0065] According to one aspect of this disclosure, a tubing string is provided, the tubing string comprising: a plurality of the aforementioned slide valves having t=1;

[0066] The slide valves are arranged in the tubing according to the following rules:

[0067] (a) For any two of the plurality of spool valves, at least one of their n, K, and m1 is different;

[0068] (b) For any two of a plurality of spool valves having the same n and the same K, the difference between their m1 is greater than 1;

[0069] (c) A slide valve with a smaller (n+K) is located on the wellhead side of a slide valve with a larger (n+K);

[0070] (d) For spool valves with the same (n+K), the spool valve with the larger n value is located on the wellhead side of the spool valve with the smaller n value; and

[0071] (e) Slide valves with the same n and the same K but different m1 can be arranged in any order.

[0072] In some embodiments, the tubing is a casing tubing.

[0073] In some embodiments, the tubing string is a tubing string intended to be received in a wellbore with or without casing.

[0074] According to one aspect of this disclosure, a downhole system is provided, comprising: the aforementioned tubing string including a plurality of the aforementioned slide valves having 1>t>0; and one or more of the aforementioned clamps. Attached Figure Description

[0075] Now, other advantages and other embodiments of the invention will become apparent from the foregoing description and the following detailed description of several specific embodiments of the invention, given with reference to the accompanying drawings, each of which is non-limiting. In the drawings:

[0076] Figure 1 This is a cross-sectional view of a downhole tool in the form of a slide valve according to some embodiments of the present disclosure. The slide valve includes a valve body and a slide sleeve movable within the slide valve, wherein the slide sleeve is configured in a closed position. The protective casing used is further shown in the figure.

[0077] Figure 2 yes Figure 1 The diagram shows a cross-sectional view of the valve body of a downhole tool, without the protective casing.

[0078] Figure 3 yes Figure 1 The diagram shows a cross-sectional view of the sliding sleeve of a downhole tool, with an additional protective casing shown.

[0079] Figure 4 yes Figure 3 The cross-sectional view of the sleeve body of the sliding sleeve is shown.

[0080] Figure 5 yes Figure 3 The cross-sectional view of the protective sleeve of the sliding sleeve is shown.

[0081] Figure 6 yes Figure 3 The cross-sectional view of the retaining ring of the sliding sleeve is shown.

[0082] Figure 7 yes Figure 3 The exploded cross-sectional view of the sliding sleeve shown illustrates the assembly process of the sliding sleeve;

[0083] Figure 8 It is used to make Figure 1 The cross-sectional view of the collet for actuating the matching slide valve is shown.

[0084] Figures 9 to 12A yes Figure 8 The chuck and Figure 1 The cross-sectional view of the mating spool valve shown illustrates the process of the chuck entering the mating spool valve and locking into it.

[0085] Figure 12B yes Figure 12A An enlarged cross-sectional view of a portion shows the contour areas of the chuck and the mating slide valve when the chuck is locked into the mating sleeve;

[0086] Figure 13 It is shown Figure 8 The chuck shown is locked in Figure 1 A schematic cross-sectional view showing a matched spool valve in which a ball falls into the spool valve to actuate it to the open position;

[0087] Figure 14 It is shown Figure 13 A schematic cross-sectional view of the slide valve shown, in which the slide sleeve is actuated to the open position by the pressure of the ball and the collet to open the fluid port for fracturing;

[0088] Figure 15AThis is a schematic cross-sectional view showing a sliding valve sleeve of an alternative embodiment being pressure-actuated to an open position by a ball and a collet to open a fluid port for fracturing, wherein when wellhead fluid pressure is applied, the spline of the collet can be pressure-actuated to expand radially outward, and the compression of the collet causes the spline to expand radially outward, thereby further engaging with the sliding sleeve to enhance engagement and thus further enhance pressure resistance.

[0089] Figure 15B yes Figure 15A An enlarged cross-sectional view of a portion of the chuck shows the radially outwardly expanding chuck engaging with the sliding sleeve;

[0090] Figure 16 Some embodiments of this disclosure have multiple Figure 1 The diagram shows a sliding valve casing string extending into the wellbore to fracturing underground formations;

[0091] Figure 17A These are cross-sectional views of the chucks in some alternative embodiments;

[0092] Figure 17B yes Figure 17A A magnified cross-sectional view of a portion of the chuck shows the ball seat;

[0093] Figure 18 The cross-sectional view shows the reception in Figure 3 The sliding sleeve shown Figure 17A A specific example of a chuck is shown, and a ball received in the chuck, the ball being configured to expand radially outward in an expandable metal portion of the chuck, thereby forming an intermetallic seal between the chuck and the sleeve when the ball is seated on a ball seat in the chuck and wellhead fluid pressure is applied to the ball.

[0094] Figure 19 These are cross-sectional views of the chucks in some alternative embodiments;

[0095] Figures 20A to 20D This is a schematic diagram showing several sleeve profiles and their corresponding collet profiles of some alternative embodiments;

[0096] Figure 21A It is a schematic diagram showing the casing profile and the corresponding chuck profile to illustrate the parameters related to the design of these profiles;

[0097] Figure 21B This is a schematic diagram showing the fit between the sleeve profile and the chuck profile;

[0098] Figure 21C It is shown Figure 21B The diagram shows the collet profile and the sleeve profile, wherein the collet profile is received within the sleeve profile.

[0099] Figures 22 to 49This is a schematic diagram showing various designs of the outline area of ​​the slide and the chuck;

[0100] Figure 50 This is a schematic diagram illustrating an example of a tubular column with multiple slide valves, representing some embodiments of the present disclosure;

[0101] Figure 51 This is a schematic diagram illustrating a set of expanded sleeve and chuck profiles of some alternative embodiments of the present disclosure;

[0102] Figure 52 This is a schematic diagram illustrating a set of expanded sleeve and chuck profiles of some alternative embodiments of the present disclosure;

[0103] Figure 53 This is a schematic diagram illustrating a set of expanded sleeve and chuck profiles of some alternative embodiments of the present disclosure;

[0104] Figures 54 to 57 This is a schematic diagram illustrating a set of expanded sleeve and chuck profiles of some other embodiments of the present disclosure;

[0105] Figures 58 to 61 This is a schematic diagram illustrating a set of expanded sleeve and chuck profiles of some other embodiments of the present disclosure;

[0106] Figure 62 This is a schematic diagram illustrating a set of expanded sleeve and chuck profiles of some other embodiments of this disclosure; and

[0107] Figures 63A to 63F This is a schematic diagram showing the chuck profile on the chuck and the casing profile on the sleeve in some embodiments, wherein when wellhead fluid pressure is applied, the spline of the chuck can be pressure-actuated to expand radially outward, and the compression of the chuck causes the spline to expand radially outward, thereby further engaging with the sleeve to enhance engagement and thus further enhance pressure resistance. Detailed Implementation

[0108] Embodiments herein disclose a pressure-actuable spool valve. In the following description, the term "downhole" refers to the direction along the wellbore toward the end of the wellbore and may be consistent with (e.g., in a vertical wellbore) or inconsistent with (e.g., in a horizontal wellbore). The term "wellhead" refers to the direction along the wellbore toward the surface and may be consistent with (e.g., in a vertical wellbore) or inconsistent with (e.g., in a horizontal wellbore).

[0109] In some embodiments, the slide valve includes a valve body having a longitudinal bore and one or more fluid ports on its sidewalls. A sleeve is received in the bore and is movable between a wellhead closed position that blocks the fluid ports and a downhole open position that opens the fluid ports.

[0110] The sleeve includes a profiled region on its inner surface, which includes circumferential grooves and ridges forming the casing profile. The profiled region includes a stop shoulder located at its downhole end for locking a chuck assembly (also referred to as a "chuck" for ease of explanation), the stop shoulder having a matching chuck profile on its outer surface. Here, the term "matching" refers to the condition where the chuck profile matches the casing profile of the sleeve, such that the chuck's profiled region can be received within the sleeve's profiled region to lock the chuck in the sleeve of the valve.

[0111] In some embodiments, the wellhead surface of the stop ring is radially inward from the downhole to the wellhead, thereby forming a stop shoulder 194 with an acute angle α relative to the longitudinal axis of the stop ring.

[0112] In some embodiments, the stop shoulder is formed by a stop ring adjacent to the contour region of the slide sleeve.

[0113] In some embodiments, the stop ring is made of a high-strength material, such as tungsten carbide, cobalt-chromium alloy and / or similar materials.

[0114] In some embodiments, the chuck is in the form of a cage and includes a wellhead portion, a downhole portion, and a plurality of longitudinal splines mounted at their longitudinally opposite ends to the wellhead and downhole portions. One, more, or all of these longitudinal splines are flexible and are shaped to form the chuck profile.

[0115] In some embodiments, the wellhead portion of the chuck includes a ball seat for receiving a ball from the wellhead to actuate the slide valve.

[0116] In some embodiments, the chuck includes a radially expandable metal wellhead portion, such that when the chuck is received in a mating slide valve and the ball sits on the ball seat of the chuck, fluid pressure applied to the ball can force the expandable wellhead portion to expand radially outward and apply pressure to the inner surface of the slide, thereby forming an intermetallic seal at the interface between the slide and the chuck.

[0117] In some embodiments, the ball seat of the chuck includes an inclined surface.

[0118] In some embodiments, the tilt angle θ of the inclined ball seat surface relative to the longitudinal reference line is approximately 55°. In some embodiments, the tilt angle θ is approximately 35°. In some alternative embodiments, the tilt angle θ is approximately 50° to approximately 60°. In some alternative embodiments, the tilt angle θ is approximately 40° to approximately 70°. In some alternative embodiments, the tilt angle θ is approximately 30° to approximately 80°.

[0119] Please go to Figure 1The diagram illustrates a downhole tool, typically identified by reference numeral 100. In these embodiments, the downhole tool 100 is in the form of a downhole slide valve and includes a tubular valve body 102 having a longitudinal bore 104 and a slide sleeve 106 received within the bore 104. The slide sleeve 106 is locked in a closed position at the wellhead by one or more shear pins 108 to close one or more fluid ports 110 on the tubular body 102, and the slide sleeve 106 includes a longitudinal bore for receiving a mating chuck (described later). Using fluid pressure in the downhole direction, the chuck can actuate the slide sleeve 106 from the closed position to a downhole open position to open one or more fluid ports 110 for subsurface fracturing (described later).

[0120] like Figure 2 As shown, the tubular body 102 includes a tubular valve housing 112, releasably connected to a top connector 114 and a bottom connector 116 on its wellhead and downhole sides, respectively, via threads 118 and locking screws 120, and has a sealing ring 122 for sealing its connectors. In these embodiments, the downhole end of the top connector 114 and the wellhead end of the bottom connector 116 form wellhead and downhole stops 124 and 126, which are used to movably restrict the sleeve 106 between them.

[0121] In these embodiments, the top connector 114 includes a tapered inner surface 128 that gradually decreases from its orifice end to its downhole end, such that the inner diameter (ID) of the top connector 114 gradually decreases from its orifice end to its downhole end to facilitate the insertion of the chuck into the slide valve 100 (described later).

[0122] The valve housing 112 includes one or more fluid ports 110 on its sidewall near the wellhead end 132. These fluid ports are used to discharge high-pressure fracturing fluid into the subsurface formation when the sliding sleeve 106 is displaced from the closed position to the open position under actuation pressure. The valve housing 112 also includes one or more pin holes 136 and one or more shear pins 108 (see...). Figure 1 The pins 136 pass through these holes to lock the sleeve 106 in the closed position to close the port 110. The valve housing 112 also includes one or more ratchet threads 138 on its inner surface near its downhole end 136.

[0123] Figure 3 A cross-sectional view of a sleeve 106 with a bore 151 and a sleeve body 152 is shown. The sleeve 106 has an outer diameter (OD) equal to or slightly smaller than the inner diameter of the valve housing 112 to allow movement of the sleeve 106 within the valve housing 112. In these embodiments, the sleeve 106 includes a sleeve body 152 through a thread 156 on the inner surface of the sleeve body 152 (see [link to documentation]). Figure 4) and the corresponding thread 158 on the outer surface of the protective sleeve 154 (see Figure 5 The connection portion 153 of the protective casing 154 located on its downhole side is received therein for releasable connection to the protective casing 154.

[0124] like Figure 4 As shown, the sleeve body 152 may include one or more circumferential sealing rings 168 at appropriate locations on its outer surface (e.g., near the upper end 164 of the sleeve body 152) to seal the interface between the valve housing 112 and the sliding sleeve 106 (see Figure 158). Figure 1 ).

[0125] The casing body 152 also includes one or more pin holes or recesses 170 at a location corresponding to the pin hole 136 of the valve housing 112 to receive a shear pin 108 when the sleeve 106 is installed in the closed position in the hole 104 of the valve housing 112. The casing body 152 also includes one or more ratchet rings 172 around its downhole end 166 to engage with ratchet threads 138 on the inner surface of the valve housing 112 when the sleeve 106 is in the open position.

[0126] On its inner surface, the casing body 152 is made of a suitable material (e.g., steel) and includes a stop ring seat 180 facing downhole, which is located on the wellhead side of the thread 156 and accessible from the downhole end 166 of the casing body 152 to receive and support a high-strength stop ring 192. The casing body 152 also includes a contoured region 182 located on the wellhead side of the stop ring seat 180 and adjacent thereto (correspondingly, other inner surface regions of the sleeve 106 are represented as non-contoured regions).

[0127] The profiled region 182 on the casing body 152 includes one (preferably two or more) circumferential grooves 184, such as grooves 184A and 184B forming a distinctive locking profile (also referred to as a “casing profile”). Each groove 184 includes a wellhead wall that slopes radially inward from downhole at an obtuse angle relative to the longitudinal axis of the casing body 152. Each groove 184 also includes a downhole wall with a right or acute angle. That is, the downhole wall of each groove 184 is perpendicular to the longitudinal axis of the casing body 152, or slopes radially inward from downhole to wellhead and forms an acute angle relative to the longitudinal axis of the casing body 152. Using the grooves 184, the profiled region 182 can receive a chuck 200 with a matching outer surface profile 212 (referred to herein as a “matching chuck”) and allow a chuck 200 with a mismatching outer surface profile (referred herein as a “mismatching chuck”) to pass through it (described later).

[0128] Depending on the number of grooves 184, the inner diameter of the contour region 182 on the slide sleeve 106 can vary at different longitudinal positions due to the grooves 184 in the slide sleeve 106. However, the minimum inner diameter of the contour region 182, including the stop ring 192, is generally the minimum inner diameter of the slide sleeve 106. In other words, the minimum inner diameter of the slide sleeve 106 occurs in the region of the contour region 184 and the stop ring 192.

[0129] The outer diameter of the chuck profile 212 on the chuck 200 is larger than the minimum inner diameter of the profile region 182 on the sleeve body 152, so that the chuck profile 212 on the chuck 200 and the profile region 182 on the sleeve body 152 are initially minimally engaged when the chuck is matched. However, under the fluid pressure applied to the chuck 200, the outer diameter of the profile region 212 may significantly exceed the minimum inner diameter of the profile region 182 on the sleeve body 152, so that the profile region 212 on the chuck 200 and the profile region 182 are maximally engaged as described more fully below.

[0130] It should be noted that the outer diameter of the chuck 200 in the region of the ball seat 214 is initially smaller than the inner diameter of the bore 151 and the profile region 184 on the casing body 152. However, when wellhead fluid pressure is applied to the ball 242 sitting on the ball seat 214, the chuck 200 may expand radially outward in the region of the ball seat 214 in a manner more fully described below, causing its radial expansion (i.e., the increase in the outer diameter of the chuck 200 in the region of the ball seat 214) to become very close to or equal to the inner diameter of the bore 151 in the casing body 152, thus providing the benefits and advantages described more fully below.

[0131] The retaining ring 192 is made of a material with a hardness greater than that of the sliding sleeve material 106. For example, the retaining ring 192 is made of a high-strength material, such as tungsten carbide, cobalt-chromium alloy (e.g., Stellite alloy), steel nitride and / or other suitable high-strength alloys, or combinations thereof, to provide enhanced pressure resistance and wear resistance.

[0132] In some embodiments, at least the stop shoulder 194 of the stop ring 192 (described in more detail below) is hardened to a hardness greater than that of the material of the sleeve 106, or comprises a material with a hardness greater than that of the sleeve 106.

[0133] Figure 6A cross-sectional view of the high-strength stop ring 192 is shown. The outer diameter of the stop ring 192 is adapted to sit on the stop ring seat 180 of the casing body 152, and its cross-sectional height “h” is sufficient to extend radially inward beyond the inner edge of the stop ring seat 180. In these embodiments, the wellhead surface of the stop ring 192 is radially inward from downhole to wellhead, thereby forming a stop shoulder 194 at an acute angle α relative to the longitudinal axis of the slide valve 100 on the wellhead side edge. As further detailed later, when the chuck profile engages with the casing profile 182 and prevents the chuck member 200 from moving downhole relative to the slide sleeve, the stop shoulder 194 of the stop ring 192 is adapted to abut against a portion of the chuck profile and engage with the corresponding shoulder of the chuck. Therefore, the stop ring 192 can also be referred to as a “locking ring” for downward locking of the chuck.

[0134] like Figure 7 As shown, the sliding sleeve 106 can be assembled by inserting the stop ring 192 into the casing body 152 and allowing it to sit on the stop ring seat 180. Then, the protective casing 154 is "screwed" onto the downhole end of the casing body 152 by engaging the threads 158 of the protective casing 154 with the threads 156 of the casing body 152. The wellhead end 160 of the protective casing 154 presses the stop ring 192 against the stop ring seat 180 to securely clamp the stop ring 192 in place. Figure 3 The assembled sliding sleeve 106 is shown in the figure.

[0135] The slide valve 100 can then be assembled by inserting the slide sleeve 106 from either end of the slide valve 100 into the hole 104 of the valve housing 112 and into the closed position, locking the slide sleeve 106 in place by inserting the shear pin or shear screw 108 through the pin hole 136 of the valve housing 112 into the pin hole 170 of the sleeve housing 152, and then connecting the valve housing 112 to the top connector 114 and the bottom connector 116. Figure 1 The assembled slide valve 100 is shown in the figure.

[0136] like Figure 1 As shown, the longitudinal length of the sliding sleeve 106 is longer than the distance between the stops 124 and 126 of the valve housing 112, so that when the sliding sleeve 106 is in the closed position, the protective sleeve 154 contacts the inner surface of the bottom connector 116 to isolate the annulus 196, which is located radially between the valve housing 112 and the sliding sleeve 106 and longitudinally between the downhole end 166 of the sliding sleeve 106 and the stop shoulder 126, from the hole 104 to prevent cement from entering the annulus 196 and interfering with valve operation.

[0137] As described above, the slide valve 100 includes an irregularly shaped inner surface region 182 having a unique locking profile that can receive and lock a mating collet and allow a non-matting collet to pass through.

[0138] Figure 8 This is a cross-sectional view of the chuck 200, which in these embodiments is in the form of a cylindrical cage with a longitudinal bore 202. The chuck 200 typically has an outer diameter slightly smaller than the minimum inner diameter of the sleeve 106 (except for the protrusion 222 described later) and includes one or more circumferential sealing rings 204 arranged at necessary locations on its outer surface as needed to seal the interface between the chuck 200 and the sleeve 106 when the chuck 200 is locked in the sleeve 106.

[0139] As shown in the figure, the chuck 200 includes a cylindrical wellhead portion 206, a cylindrical downhole portion 208, and an intermediate portion 210, which includes a contour region 212 with a unique locking profile.

[0140] In these embodiments, the wellhead portion 206 includes a ball seat 214 on its inner surface for receiving a ball falling from the wellhead. The wellhead portion 206 also includes a sealing ring 216 on its inner surface for sealing the interface between the ball and the wellhead portion 206 of the chuck 200.

[0141] The intermediate portion 210 includes a plurality of circumferentially distributed longitudinal splines 218 connecting to the wellhead and downhole portions 206 and 208. In these embodiments, the chuck 200 is made of metal tubing by cutting, stamping or other means, forming a plurality of longitudinal slots 220 in the intermediate portion 210 to form the splines 218.

[0142] One, more, or all of the longitudinal splines 218 are made of a sufficiently elastic soft material and are shaped to include one or more protrusions 222 (e.g., protrusions 222A and 222B) in profile regions 212 extending radially outward from their outer surfaces, thereby forming a radially flexible locking profile (also referred to as a "clamp profile"). The protrusions 216 are positioned and sized such that the maximum outer diameter of the collet 200 is greater than the minimum inner diameter of the sleeve 106, and its collet profile matches the sleeve profile of the mating sleeve 106. Therefore, when the collet 200 enters the spool valve 100 with the mating sleeve 106 (e.g., the spool valve 100 is also referred to as the "matching spool valve 100"), the collet 200 can be locked in the mating sleeve 106. The protrusion 222B located at the deepest point downhole includes a shoulder 236 on its downhole side, which is at an acute angle α relative to the longitudinal axis of the slide valve 100, the same angle as the stop shoulder 194.

[0143] Figures 9 to 1 Figure 2 shows an example of actuating the chuck 200 from its wellhead position to the mating slide valve 100. (See figure 2 for an example.) Figure 9 As shown, when the chuck 200 enters the slide valve 100, the tapered inner surface 128 of the top connector 114 guides the chuck 200 into the hole 104.

[0144] like Figure 10 As shown, when the contour region of the chuck 200 enters the hole 104 and the maximum outer diameter of the chuck 200 is greater than the minimum inner diameter of the sleeve 106, the irregular spline 218 is biased inward and the chuck 200 continues to move downhole.

[0145] like Figure 11 As shown, when the contour region 212 of the collet 200 completely overlaps with the matching contour region 182 of the sleeve 106, the irregular spline 218 is not biased due to its elasticity. Therefore, the collet 200 is received downwards in the sleeve 106. Figure 12A and 12B As shown, the chuck 200 can be moved further downhole until the shoulder 236 of the protrusion 222B at its lowest downhole position engages with the stop shoulder 194 of the high-strength stop ring 192.

[0146] Figure 12B Enlarged views of the contour regions 182 and 212 of the slide sleeve 106 and the collet 200 are shown. As shown, the contour of each contour region 182, 212 includes staggered grooves and ridges (or protrusions). Figure 12B In the example shown, the contour of contour region 182 includes two grooves 184A and 184B, and a ridge 232 between them. The contour of contour region 212 includes two ridges / protrusions 222A and 222B, and a groove 234 between them. To ensure that contour regions 182 and 212 match each other, the width of the groove on one of the two contour regions 182 and 212 needs to be equal to or greater than the width of the corresponding ridge on the other contour region 182 and 212, in order to accommodate the corresponding ridge. Figure 12B In the example shown, the width of the groove (e.g., groove 184A, 184B, or 234) is sufficiently greater than the width of the corresponding ridge (e.g., ridge 222A, 232, or 222B) so that after the chuck 200 is locked downward in the sleeve 106, the chuck 200 can be moved further downhole until the protrusion 222B at the deepest point downhole engages with the high-strength stop ring 192.

[0147] like Figure 12BAs shown, the high-strength stop ring 192 engages with the protrusion / ridge 222B at the deepest point downhole under high pressure to enhance downhole locking between the sleeve 106 and the chuck 200. Furthermore, the stop ring 192 is shaped to have a wellhead stop shoulder 194 at an acute angle relative to the longitudinal axis of the spool valve 100, and the downhole side of the protrusion 222B at the deepest point downhole also forms a shoulder 236 with a matching acute angle, thereby increasing the strength of the engagement of shoulders 194 and 236 against downhole pressure applied to the chuck 200. In these embodiments, when shoulders 194 and 236 engage with each other, other corresponding ridges (e.g., ridges 222A and 232) of the chuck 200 and sleeve 106 engage to further increase the strength against downhole pressure applied to the chuck 200.

[0148] like Figure 13 As shown, after the collet 200 is locked in the sleeve 106, the ball 242 can fall off the surface and enter the spool valve 100. The ball 242 is made of a rigid material (e.g., ceramic or metal) and has dimensions suitable for sitting on the ball seat 214 of the collet 200.

[0149] After ball 242 engages with ball seat 214 and seals the orifice 202 of chuck 200, fluid pressure is applied from the wellhead to ball 214 and chuck 200. When chuck 200 is locked downwards onto sleeve 106, sleeve 106 is subsequently actuated, thereby shearing shear pin 108 and moving it downwards to the open position to open fluid port 110. Figure 14 As shown, the ratchet ring 172 on the sliding sleeve 106 engages with the ratchet thread 138 on the valve housing 112 to prevent the sliding sleeve 106 from moving toward the wellhead. High-pressure fracturing fluid can then be pumped downhole, and this high-pressure fracturing fluid is ejected from the fluid port 110 to fracture the formation.

[0150] Fracturing fluids are typically high-pressure, and any malfunction in the slide valve 100 can cause the fracturing process to fail. For example, if the engagement between the chuck 200 and the slide sleeve 106 fails, the high-pressure fracturing fluid may cause the chuck 200 to actuate further downhole, resulting in fracturing failure.

[0151] Those skilled in the art will understand that the slide valve 100 in the above embodiments includes a high-strength stop ring 192, which is used to strengthen the engagement between the clamp 200 and the slide sleeve 106, thereby significantly reducing the risk of failure.

[0152] In some embodiments, the outer diameter of the chuck 200 at its protrusions 222A and 222B is smaller than the inner diameter of the sleeve 106 at its grooves 184A and 184B. For example... Figure 15A and 15BAs shown, in these embodiments, after the high-pressure fracturing fluid is pumped downhole and actuates the sleeve 106 to the open position, the high-pressure fracturing fluid further actuates the chuck 200 slightly downhole, causing the spline 218 to expand radially outward, thereby further engaging the protrusions 222A and 222B of the chuck 200 with the grooves 184A and 184B of the sleeve 106, thus enhancing pressure resistance.

[0153] In some embodiments, a downhole fracturing system including a plurality of slide valves 100 can be used for underground formation fracturing. Figure 16 An example of fracturing a subsurface formation using slide valves 100 is shown. In this example, a horizontal well, including a horizontal wellbore portion 272, is drilled in the subsurface formation 274. A casing string 276, comprising multiple slide valves 100, is then extended into the wellbore portion 272. Each slide valve 100 includes a unique casing profile. The slide valves 100 can be spaced apart as needed via additional joints.

[0154] After casing string 276 is in place, cementing can be performed by pumping cement fluid down into casing string 276. As described above and as... Figure 1 As shown, in each slide valve 100, a protective casing 154 prevents cement from entering the annulus 196 and interfering with valve operation. After cementing, cleaning fluid can be pumped downhole to clean the joints, including the slide valve 100. An arc brush arm can also be used for cleaning if necessary.

[0155] In this example, the formation 274 surrounding the wellbore portion 278 is fracturing, and slide valves 100B and 100C need to be opened. Therefore, a first chuck (not shown) mated to slide valve 100C is pumped downhole through casing string 276. Because the first chuck is mismatched with slide valves 100A and 100B (i.e., the chuck profile of the first chuck is mismatched and cannot be received within the casing profile of slide valves 100A and 100B), the first chuck passes through slide sleeves 100A and 100B and is locked within slide valve 100C.

[0156] To open the fluid port of slide valve 100C, the ball is dropped and engages with the ball seat of the first chuck, blocking the orifice of the first chuck. Then, fluid pressure is applied to actuate the engaged ball, the first chuck, and the slide sleeve to shear the shear pin of slide valve 100C and move the slide sleeve downhole to the open position to open the fluid portion of slide sleeve 100C.

[0157] After slide valve 100C is opened, a second chuck, matched with slide valve 100B, is pumped downhole to lock onto slide valve 100B. Then, a ball is dropped to engage with the second chuck, and fluid pressure is applied to open slide valve 100B.

[0158] After opening all slide valves 100B and 100C in wellbore section 278, the balls in these slide valves are removed by drilling, dissolution, and surface recovery, except for the balls in the slide valves located at the lowest point downhole. Figure 16 In the example shown, the ball in slide valve 100C is held in place, while the ball in slide valve 100B is removed. High-pressure fracturing fluid is then pumped into the casing string 276, and the high-pressure fracturing fluid is ejected from the fluid ports of slide valves 100B and 100C to fracture the formation 274.

[0159] In the above examples, wellbore isolation devices (such as packers) can be used to isolate the wellbore section to be fracturing, which is known in the art and therefore omitted here.

[0160] As can be seen from the examples above, the fracturing process can utilize multiple sleeves 100 with orifices 104 of approximately the same size to ensure consistent fluid flow. The chuck 200 and ball 242 can also have the same dimensions, thereby simplifying logistics and reducing completion costs.

[0161] In such Figures 3 to 7 In the embodiments shown above, the protective sleeve 154 is releasably connected to the sleeve body 152 via engagement threads 158 and 156. In some alternative embodiments, the protective sleeve 154 may be connected to the sleeve body 152 by other suitable means. For example, in one embodiment, the protective sleeve 154 may be permanently connected to the sleeve body 152 by welding.

[0162] In the above embodiments, the chuck 200 is in the form of a cylindrical cage having multiple splines mounted on the cylindrical wellhead portion 206 and the cylindrical downhole portion 208, thereby eliminating the need for external devices (such as springs) to radially actuate or deform the chuck 200 to engage with and lock it in the sleeve. In another particular embodiment, a flexible spline is mounted at its longitudinally opposite ends to the wellhead and downhole portions 206 and 208, and the chuck is further configured such that the spline is located in the inner profile 184 within the sleeve 106 during initial engagement, advantageously causing the spline to bend further radially on the chuck 200 when wellhead fluid pressure is applied to the ball in the ball seat 214 of the chuck 200, thereby further and more extensively engaging the spline with the chuck profile 212 within the sleeve 184, thereby reducing the risk of the chuck 200 not engaging with the selected casing, or reducing the risk that the mating profile on the chuck 200 may disengage from the mating profile 184 on the sleeve 106 when fracturing pressure is applied at the wellhead, and in the event of a failure, this prevents the injection of fracturing fluid into the well at the open port 110 under high pressure.

[0163] In some alternative embodiments, a downhole fracturing system comprising a tubing string having one or more slide valves 100 may be used to fracturing wellbore sections. The wellbore may be a casing wellbore or a non-casing wellbore.

[0164] Although Figure 16 In the example shown, the slide valve 100 is used for fracturing a horizontal wellbore section; however, those skilled in the art will understand that in some alternative embodiments, the slide valve 100 can be used for fracturing a vertical wellbore section.

[0165] In the above embodiments, the chuck 200 may include one or more sealing rings 204 on its outer surface for sealing the interface between the chuck 200 and the sleeve 106 when the chuck 200 enters the slide valve 100. However, when the chuck 200 moves within the sleeve 106, such sealing rings 204 may wear and fail during the pumping of the chuck downhole, potentially causing the slide valve 100 to fail. Moreover, when pumping the chuck through a mismatched sleeve, a large fluid pressure is typically required to overcome the friction caused by the movement of the sealing rings 204 along the inner surface of the sleeve 106.

[0166] In some alternative embodiments, the chuck 200 does not need to include any sealing ring 204 on its outer surface. In these embodiments, the slide valve 100 and Figure 1 The same applies as shown, and the outer diameter of the non-contour region of the chuck 200 is slightly smaller than the minimum inner diameter of the slide sleeve 106, thereby avoiding friction caused by the sealing ring 204 and thus allowing the chuck 200 to pass through the mismatched slide valve 100 at a lower fluid pressure.

[0167] In these embodiments, the sliding sleeve is made of a suitable metal (e.g., steel). Figure 17A and 17B As shown, the wellhead portion 206 of the chuck 200 is configured to have a metal portion 206' that can expand radially outward, and the ball seat 214 includes a ball seat surface 282 that is radially inward from the wellhead toward the downhole at an acute angle relative to the longitudinal axis 284 of the chuck 200.

[0168] After the chuck 200 is locked in the slide valve 100, the appropriately sized ball 242 is pushed onto the ball seat 214 under downhole fluid pressure. When downhole fluid pressure is applied to the wellhead side of the ball 242, the ball 242 presses against the inclined surface 282 of the ball seat 214, thereby converting the downhole fluid pressure into radial outward pressure and causing the expandable metal portion 206' of the chuck 200 to expand radially to sufficiently reduce the gap between the chuck 200 and the slide 106, or even force the outer surface of the expandable metal portion 206' to tightly engage with the inner surface of the slide 106, thereby forming an intermetallic seal at the interface between the chuck 200 and the slide 106.

[0169] like Figure 17B As shown, the surface 282 of the ball seat 214 is inclined at an angle θ relative to the longitudinal reference direction 284. In some embodiments, this angle θ is approximately 55°. For a metal collet with an elastic modulus of American Petroleum Institute (API) N80 grade steel, the nominal diameter of the ball seat 214 on the collet 200 is 4.555 inches, the nominal thickness of the collet is 0.23 inches, the pressure on the ball 242 with a nominal diameter of 4.250 inches is approximately 1500 psi, and initially, before radial expansion, the clearance between the collet 200 and the inner diameter of the sleeve 106 is in the range of 0.004 to 0.014 inches (see Embodiment A and below). Figure 18 For this type of chuck, an angle of approximately 55° is satisfactory, at which the necessary radial outward force can be transmitted to the chuck 200 to allow the chuck 200 to expand radially sufficiently, thereby forming a adequate intermetallic seal with the sleeve 106.

[0170] In other embodiments where the collet 200 may be made of a more or less elastic material (i.e., with a higher modulus of elasticity), and / or have a greater thickness, and / or the initial gap between the collet diameter 200 and the slide diameter 106 is greater than 0.004 to 0.014 inches, and / or the pressure on the ball 242 is less than 1500 psi, the tilt angle θ needs to be reduced to approximately 35° so that the ball seat 214 can transmit sufficient radial outward force to allow the collet diameter 200 to increase sufficiently radially to achieve the desired metal-to-metal seal with the bore.

[0171] In some alternative embodiments, the tilt angle θ is approximately 50° to approximately 60°. In some alternative embodiments, the tilt angle θ is approximately 40° to approximately 70°. In some alternative embodiments, the tilt angle θ is approximately 30° to approximately 80°.

[0172] Therefore, with the chuck 200 constructed to allow for radial enlargement, this advantageously reduces the overall outer diameter of the chuck 200. This reduction in diameter in the region of the ball seat 214 and in the profile region 212 of the chuck makes it easier for the chuck 200 and the profile region 212 to pass through, and causes less disturbance to the profile regions 184 of the individual wellhead sleeves 106 that are not desired to be actuated, thereby reducing frictional wear on such profile regions 212 of the chuck 200, while still maintaining the ability of the chuck 200 to eventually form a seal in the region of the ball seat 214 upon arrival, and further enabling the chuck profile region 212 thereon to engage with the intended downhole casing 106 and the corresponding desired mating profile 184 thereon.

[0173] Specifically, it is important that this radial expansion capability of the chuck 200 reduces wear on the chuck profile 212, thereby maintaining the integrity of the chuck profile 212 and ensuring that the corresponding profile 212 on the chuck 200 fully and reliably engages when the chuck 200 reaches the sleeve 106 to be actuated, while forming an initial intermetallic seal to allow pressure to accumulate on the wellhead side of the ball 242. The pressure on the wellhead side of the ball 242 increases when the chuck 200 locks into engagement with the sleeve 106, causing a domino effect. This pressure accumulation leads to (further) radial expansion of the chuck 200, which in turn strengthens the intermetallic seal. This strengthening of the intermetallic seal causes further pressure accumulation, which in turn leads to increased radial expansion, further strengthening the intermetallic seal. The wellhead pressure accumulates in this way until the shear pin 108 holds the sleeve 106 in position for shearing, then allows the sleeve 106 to move downhole in the valve 100 to open the port 110.

[0174] Figure 18 An example of a chuck 200 of the present invention, slidably received in a sleeve 106, is shown. This chuck 200 is the chuck of the preferred embodiment described above. Specifically, in such a preferred embodiment, the thickness, material, and initial radial clearance of the chuck 200 in the region of the ball seat 214, and its initial radial clearance to the bore 151 of the sleeve body 152, are such that when the ball 242 is seated in the ball seat 214 and a fluid pressure of at least 150 psi is applied thereto, the radial outward expansion of its outer diameter is greater than 0.09%, providing sufficient intermetallic seal between the outer diameter of the chuck 200 in the region of the ball seat 214 and the bore 151 of the sleeve body 152. Specifically, the outer diameter of the chuck 200 in the region of ball seat 214 is capable of radially expanding outward when fluid pressure is applied to the ball 242 seated therein, preferably by at least 0.09%, and more preferably by at least 0.2%, and more preferably by at least 0.3%, when a wellhead fluid pressure of at least 150 psi is applied. This improves the initial clearance of the profile region 212 on the chuck 200 with a mismatched profile, but when engaged with the desired profile region 184 on the selected sleeve 106, it forms a sufficient seal between the sleeve and the chuck 200 in the region of ball seat 214, resulting in a "domino effect" and allowing the chuck 200 to expand further radially to strengthen the intermetallic seal. Thus, the radial expansion and intermetallic seal are sufficient to allow sufficient pressure to be applied to shear the shear pin 108.

[0175] In the above embodiments, the chuck 200 is made of a metal tube by cutting, stamping or other means, and a plurality of longitudinal slots 220 are formed in the middle portion 210 to form a spline 218. In some alternative embodiments, the spline 218 may be connected to the wellhead portion 206 and the downhole portion 208 by other suitable means (e.g., welding, screw connection, etc.).

[0176] Example 'A'

[0177] As mentioned above, Figure 18 An example of the chuck 200 of the present invention is shown, which is slidably received in a sleeve 106. The chuck 200 is configured to have a radially expandable portion 206" in the region of the ball seat 214.

[0178] Specifically, in this example, in the region of ball seat 214, the collet 200 is formed of API NP 80 grade steel with an elastic modulus of 29,000,000 and a Poisson's ratio of 0.29. The sleeve 106 is also formed of API N80 grade steel.

[0179] In this selected example, the initial radial clearance at the interface between the radial outer periphery of the collet 200 and the inner bore 151 of the sleeve body 152 in the region of the ball seat 214 is 0.002 to 0.007 inches, which is determined by applying the material tolerance of the collet 200 (i.e., the difference between the maximum and minimum dimensional tolerances between the outer diameter of the collet 200 and the inner diameter of the inner bore 151 of the sleeve 106 [i.e., (4.567-4.553) / 2 and (4.562-4.558) / 2]).

[0180] The nominal thickness of the chuck 200 in the area of ​​the ball seat 214 (i.e., on the wellhead side of the ball seat 214) is 0.149 to 0.1515 inches [i.e., (4.553-4.255) / 2 to (4.558-4.255) / 2], and the nominal thickness on the downhole side of the ball seat 214 is 0.2305 to 0.233 inches [i.e., (4.553-4.092 / 2 to (4.558-4.092) / 2],

[0181] The tilt angle θ of the ball seat 214 of the chuck 200 is 55°. The nominal diameter of the ball 242 is 4.250 inches.

[0182] After ball 242 is seated in ball seat 214, when a fluid pressure of 1500 psi is applied to ball 242 at the wellhead side, the aforementioned initial radial clearance of 0.002-0.007 inches is sufficient to initially partially block fluid flow through the interface. As fluid continues to be injected under pressure, this partial initial blockage causes fluid pressure to accumulate accordingly at the wellhead side of ball 242. Due to the tilt angle θ of ball seat 214, the radially expandable portion 206' of chuck 200 generates a radially outward force on the tubular chuck 200 in the region of ball seat 214 in response to the force applied to ball 242 by the applied fluid pressure. This applied radially outward force causes the metal portion 206' to expand radially outward, thereby ultimately eliminating or significantly reducing the aforementioned 0.002 to 0.007 inch radial clearance and forming an intermetallic seal at the interface between chuck 200 and sleeve 106.

[0183] Specifically, when the outer diameter of the radially expandable metal portion 206' is at most 4.558 inches and the inner diameter of the sleeve bore is at least 4.558 inches (i.e., 4.562-4.558 / 4.558), the radial expansion amount of the radially expandable metal portion 206' is at least 0.09%, and when the nominal outer diameter of the radially expandable metal portion 206' is 4.555 inches and the nominal inner diameter of the sleeve bore is 4.565 inches (i.e., 4.56... In the case of 5-4.555 / 4.555, the nominal radial expansion is 0.02%. In the case of the outer diameter of the radially expandable metal portion 206' being at least 4.553 inches and the inner diameter of the sleeve being at most 4.567 inches (i.e., 4.567-4.553 / 4.553), the radial expansion is at least 0.03%. Therefore, in all cases, this results in a reduction in radial clearance, thereby forming an intermetallic seal between the chuck 200 and the sleeve 106.

[0184] It will be apparent to those skilled in the art that some of the parameters described above can be modified to achieve the desired result, namely, that the radially expandable chuck can advantageously reduce contact with the wellhead sleeve as it reaches the desired sleeve 106 through the wellhead sleeve, thereby maintaining the dimensional tolerances of the chuck 200 (especially the outer diameter in its profile region 212 and the ball seat region 214), and flowing more easily downhole due to the reduced diameter, but can be “enlarged” to maintain an effective seal when engaging with the desired selected casing and applying fluid pressure, and allowing pressure to accumulate sufficient to shear the shear screw 108.

[0185] In this example, the sleeve 106 and the collet 200 are made of API N80 grade steel. Those skilled in the art will understand that in various alternative embodiments, the sleeve 106 and the collet 200 may be made of other suitable materials with similar elastic modulus (e.g., API P110 grade steel) to achieve similar radial expansion when a pressure of 1500 psi is applied.

[0186] However, in order to reduce the pumping pressure while achieving a similar radial increase (i.e., 0.02% of the nominal radial increase), the collet 200 can also be made of a material with a modulus of elasticity lower than that of API NP 80 grade steel (i.e., 1 / 10 of the modulus of elasticity of API NP 80 grade steel). This would result in the applied pressure being only 1 / 10 of the applied pressure described above (i.e., 150 psi), while still achieving the desired 0.02% nominal radial increase.

[0187] Similarly, such as Figure 18 As shown, by decreasing or increasing the tilt angle θ of the ball seat 214 of the chuck 200, the effective radial outward force on the outer periphery of the chuck 200 in the region of the ball seat 214 applied by the ball 242 can be effectively changed, thereby increasing or decreasing the magnitude of the radial force applied to the chuck 200 respectively.

[0188] Therefore, for example, at a constant fluid pressure of 1500 psi, reducing the tilt angle θ from 55° to 30° will increase the applied force, while reducing the required fluid pressure from 1500 psi or using a material with a proportionally reduced elastic modulus (i.e., using a less stiff material with a larger radial deformation under a unit applied force) can achieve a similar increase in radial expansion (nominal value of 0.02%).

[0189] Now, we will further demonstrate to those skilled in the art other permutations and combinations of the above-mentioned variables used to achieve the radial increase described above.

[0190] For example, if the tilt angle θ is increased from 55° to 80° to reduce the effective radial outward force applied to the chuck 200 under normal conditions, then to achieve a similar radial expansion of the chuck 200 (nominal value of 0.02%), one or more of the following measures are required:

[0191] (i) Modify the material of the clamp 200 to a material with a lower elastic modulus (i.e., lower stiffness);

[0192] (ii) Increase the 1500 psi fluid pressure applied to ball 242 to achieve the same tangential force as when the tangential force was previously applied using a 55° tilt angle θ; or

[0193] (iii) Reduce the thickness of the chuck 200 in the region of the ball seat 214 (assuming that the applied pressure and the generated radial force do not exceed the yield stress of the chuck 200 in the region of the ball seat 214);

[0194] Further explanation

[0195] Figure 19 The chuck 200 is shown in some alternative embodiments. In these embodiments, the slide valve 100 is... Figure 1 The slide valve shown is the same.

[0196] like Figure 19 As shown in these embodiments, the chuck 200 includes a closed wellhead end 284. The other portions of the chuck 200 are... Figure 8 The same as shown.

[0197] In these embodiments, the slide valve 100 does not require ball 242 for actuation. Instead, to actuate the slide valve 100, a mating chuck 200 is pumped downhole and locked in the slide valve 100. Fluid pressure is applied to the closed wellhead end 284 of the chuck 200, thereby shearing the shear pin 108 and actuating the slide sleeve 106 of the slide valve 100 to move downhole to the open position. As described above, the high-strength retaining ring 192 provides enhanced pressure resistance and abrasion resistance.

[0198] In the above embodiments, the sleeve 106 includes a high-strength stop ring 192 at its downhole end in the profile region 182, forming a stop shoulder 194 for locking the mating chuck 200. In some alternative embodiments, the stop ring 192 is made of the same material as the sleeve 106, but preferably of a higher strength and / or hardened and / or nitrided material, such as, but not limited to, tungsten carbide. In some embodiments, at least the stop shoulder 194 of the stop ring 192 is hardened to or includes a hardness substantially or substantially equal to the downhole portion of the chuck profile of the mating chuck 200.

[0199] In some alternative embodiments, the sleeve 106 does not include any stop ring 192. Instead, the wellhead end of the protective casing 154 forms a stop shoulder 194 for locking the mating chuck.

[0200] In some alternative embodiments, the sleeve body 152 and the protective sleeve 154 are integrated to form the slide sleeve 106 and include a radially inwardly extending circumferential ridge that forms a stop shoulder 194. Therefore, in these embodiments, the slide sleeve 106 does not include any stop ring 192.

[0201] In some alternative embodiments, the sleeve 106 includes only the sleeve body 152 and does not include any protective sleeve 154. In these embodiments, the stop ring 192 is welded, mounted, or otherwise integrated into the sleeve body 152.

[0202] In some embodiments, multiple casing profiles and chuck profiles may be obtained, and the multiple casing profiles and chuck profiles may be used on the same string in a downhole fracturing system.

[0203] For example, Figures 20A to 20D The four sleeve profiles 182-1 to 182-4 (generally indicated by reference numeral 182) on the inner surfaces of the sleeves 106-1 to 106-4 are shown, as well as the collet profiles 212-1 to 212-4 (generally indicated by reference numeral 212) on the outer surfaces of the collets 200-1 to 200-4 corresponding to these sleeve profiles.

[0204] As shown in the figure, each sleeve profile 106-1 to 106-4 includes at least two grooves 184A and 184B (hereinafter also referred to as “sleeve grooves”) and a ridge 232 located longitudinally between the two grooves 184A and 184B (hereinafter also referred to as “sleeve ridge”).

[0205] Accordingly, each chuck profile 200-1 to 200-4 includes at least two ridges 222A and 222B (hereinafter also referred to as "chuck ridges") and a groove 234 (hereinafter also referred to as "chuck groove") located between the two ridges 222A and 222B. Furthermore, the length of each groove 184A, 184B, 234 is greater than or equal to the length of each ridge 222A, 222B, 232, such that the chuck profiles 200-1 to 200-4 can be received in the corresponding sleeve profiles 106-1 to 106-4.

[0206] By varying the lengths of grooves 184A and 184B and ridge 232, multiple unique independent sleeve profiles (and corresponding unique independent chuck sleeves) can be obtained. In these embodiments, the length difference between two sleeve profiles (e.g., the length difference between sleeve profiles 182-2 and 182-3) is a predetermined design parameter L. b Integer multiples of L, where L b >0. Furthermore, the length difference between corresponding grooves or ridges of the two sleeve profiles (e.g., the length difference of groove 184A between sleeve profiles 182-1 and 182-2, or the length difference of groove 184B between sleeve profiles 182-1 and 182-2) is also a predetermined design parameter L. b Integer multiples of L, where L b >0.

[0207] Please refer to Figure 21A The following parameters (all greater than zero) are used for sleeve profile 182:

[0208] L s Longitudinal length of the sleeve profile 182;

[0209] S g1 The longitudinal length of groove 184A in sleeve profile 182;

[0210] S r The longitudinal length of the ridge 232 of the sleeve profile 182; and

[0211] S g2 The longitudinal length of groove 184B in sleeve profile 182.

[0212] Parameter L s S g1 S r and S g2 Measured at the innermost point in the radial direction of the sleeve profile 182.

[0213] The following parameters (all greater than zero) are used for chuck profile 182:

[0214] L c :Longitudinal length of chuck profile 212;

[0215] C r1 The longitudinal length of the ridge 222A of the chuck profile 212;

[0216] C g The longitudinal length of the slot 234 in the chuck profile 212; and

[0217] C r2 : The longitudinal length of the ridge 222B of the chuck profile 212.

[0218] Parameter L c C r1 C g and C r2 It is also measured at the point on the innermost radial side of the chuck profile 212.

[0219] As described above, in a pair of matching chuck profiles and sleeve profiles, the length of the groove (including the length S of sleeve grooves 184A and 184B and chuck groove 234) g1 S g2 and C g The length of the corresponding ridge (including the lengths of the clamp ridges 222A and 222B and the sleeve ridge 232) must be greater than or equal to the length of the ridge. r1 C r2 and S r ), that is, S g1 ≥C r1 S g2 ≥C r2 And C g ≥S r So that the chuck profile 212 can be received in the matching sleeve profile 182.

[0220] In these embodiments, the wellhead surfaces of casing grooves 184A and 184B and stop ring 192 are inclined such that they extend radially inward toward the wellhead. The wellhead surfaces of chuck ridges 222A and 222B and the downhole surface of chuck ridge 222B are inclined such that they extend radially outward toward the downhole. These inclinations affect how casing ridge 232 and chuck ridges 222A and 222B are received in chuck groove 234 and casing grooves 184A and 184B.

[0221] For ease of explanation, in these embodiments, the chamfers of the wellhead side surfaces of the casing grooves 184A, 184B, the stop ring 192, and the chuck ridges 222A, 222B, as well as the downhole side surface of the chuck ridge 222B, are substantially the same.

[0222] like Figure 21B and 21C As shown, due to the aforementioned chamfer, after the chuck profile 212 is fitted onto the matching casing profile 182, the chuck 200 can expand radially outward and move further downhole a short distance ε1 (this distance is a design parameter predetermined by the aforementioned chamfer and engagement degree) and be received into the casing profile 182 until the downhole side surface of the chuck ridge 222B engages with the stop shoulder 194 of the stop ring 192.

[0223] Please refer to this again. Figure 21A On the sleeve profile 182, the length S of the ridge 232 r Defined as:

[0224] S r =δL a +nL b (1)

[0225] Where 1≥δ≥0 are predetermined design parameters, L a It is a predetermined design parameter and L a >0, n is an integer and n≥0, L b It is a predetermined design parameter and L b >0. Therefore, when n=0, ridge 232 has a minimum length S. r =δL a .

[0226] The lengths S of slots 184A and 184B g1 and S g1 Defined as:

[0227] S g1 =m1L b +(1-δ)L a (2)

[0228] S g2 =m2L b(3)

[0229] Where m1 is an integer and m1≥1, and m2 is an integer and m2>1. Furthermore,

[0230] m1+m2=K, (4)

[0231] Where K>2 is a positive integer, so for the same sleeve profile with the same K, increasing m1 will decrease m2, thereby effectively changing the position of ridge 232 on the sleeve profile.

[0232] The length L of the sleeve profile 182 s yes:

[0233] L s =S r +S g1 +S g2 =L a +(n+K)L b (5)

[0234] Because of L a and L b These are predetermined design parameters, therefore, by selecting different n and K, different lengths L can be obtained. s Multiple sleeve profiles 182.

[0235] On the chuck profile 212, the length C of the ridges 222A and 222B and the chuck groove 234 is... r1 C r2 C g Defined as:

[0236] C r1 =S g1 -t1L b -ε2=(m1-t1)L b +(1-δ)L a -ε2, (6)

[0237] C r2 =S g2 -t2L b =(m2-t2)L b (7)

[0238] C g =S r +S g2 -C r2 +ε2=S r +t2L b +ε2=δL a +(n+t2)L b +ε2. (8)

[0239] Where t1, t2, and ε2 are predetermined design parameters, and 1 ≥ t1 ≥ 0, 1 ≥ t2 ≥ 0, and ε2 ≥ 0. The length L of the chuck profile 212... c yes:

[0240] L c =C r1 +C r2 +C g =L s -t2L b =L a +(n+K-t2)L b (9)

[0241] The parameter ε2 determines only whether the downhole side surface of the chuck ridge 222A engages with the downhole side surface of the casing groove 184A. In some embodiments, ε2 = 0, so that when the chuck 200 engages with the casing 106 under pressure applied from the wellhead, the downhole side surface of the chuck ridge 222A engages with the downhole side surface of the casing groove 184A, and the downhole side surface of the chuck ridge 222B engages with the stop shoulder 194, thereby providing enhanced pressure resistance. In some other embodiments, ε2 > 0, which, along with other conditions (described later), allows the flexible spline 218 to further expand and bend radially outward under fluid pressure to enhance the engagement between the chuck 200 and the sleeve 106.

[0242] Please refer to this again. Figure 21A In the embodiment where ε2 = 0, when t1 = 1, the sleeve groove 184A and the chuck ridge 222A have the maximum length difference L. b When t1 = 0, the sleeve groove 184A and the chuck ridge 222A have the same length. Similarly, when t2 = 1, the sleeve groove 184B and the chuck ridge 222B have the maximum length difference L. b When t2 = 0, the sleeve groove 184B and the chuck ridge 222B have the same length.

[0243] At this point, the parameters of the sleeve profile 182 become: In some embodiments, the design parameter is predetermined as L. a =L b t1 = t2 = t, and 1 ≥ t ≥ 0. At this point, the parameters of the sleeve profile 182 become:

[0244] S r =(n+δ)L b (10)

[0245] S g1 =(m1+1-δ)L b (11)

[0246] S g2 =m2L b(12)

[0247] m1+m2=K, (13)

[0248] L s = (n+K+1)L b (14)

[0249] The parameters of the chuck profile 212 become:

[0250] C r1 =S g1 -tL b -ε2, (15)

[0251] C r2 =S g2 -tL b (16)

[0252] C g =(n+t+δ)L b +ε2, (17)

[0253] L c = (n+K+1-t)L b (18)

[0254] Given ε2, the parameter t determines the length difference between the groove and its corresponding ridge. If t = 0, the sleeve profile 182 and the chuck profile 212 have the same length. If t = 1, the sleeve profile 182 and the chuck profile 212 have the maximum length difference L. b In the embodiment where ε2 = 0, if t = 0, the groove and its corresponding ridge have the same length. If t = 1, the maximum length difference between the groove and its corresponding ridge is L. b .

[0255] Various casing and chuck profiles can be obtained. For ease of explanation, casing and chuck profiles are organized into profile groups, and profile groups are further organized into profile categories. In the following text, casing profiles are represented in the form "S({category letter}{group number}-{profile number})", where "{category letter}" can be A, B, C, ..., indicating the profile category to which the casing profile belongs; "{group number}" can be 1, 2, 3, ..., indicating the profile group to which the casing profile belongs; and "{profile number}" can be 1, 2, 3, ..., indicating the order of the casing profile within the profile group. For example, casing profile "S(A1-1)" represents the first casing profile in group A1.

[0256] Similarly, the sleeve profile is represented in the form of "C({category letter}{group number}-{profile number})". For example, the chuck profile "C(B2-3)" represents the third chuck profile in group B2.

[0257] It can be seen that multiple sleeve profiles 182 and chuck profiles 212 can be generated by changing the values ​​of n, K and m1. Therefore, for ease of explanation, the sleeve profile can also be represented as S[n,K,m1] and the chuck profile can also be represented as C[n,K,m1].

[0258] In these embodiments, for a given L b The sum of (n+K) determines the length L of the casing profile. s and the length L of the chuck profile c In particular, the sleeve profiles in each profile category (e.g., "A") have the same length L. s = (n+K+1)L b Furthermore, the chuck profiles within the same profile category have the same length L. c = (n+K+1-t)L b .

[0259] The parameter n determines the length of the sleeve ridge 232 and the length of the chuck groove 234. Therefore, the sleeve profiles in each profile group (e.g., "A1") have the same ridge 232 length S. r =(n+δ)L b Furthermore, the chuck profiles in the same profile group have the same groove length C 234. g =(n+t+δ)L b +ε2.

[0260] Each profile group includes (K-2) sleeve profiles and (K-2) corresponding chuck profiles with the same n and the same K, wherein all (K-2) sleeve profiles have the same length L. s = (n+K+1)L b and the same S r =(n+δ)L b And all (K-2) chuck profiles have the same length L. c = (n+K+1-t)L b and the same C g =(n+t+δ)L b +ε2.

[0261] Those skilled in the art will understand that if t is equal to or close to 0, the chuck profile is completely or almost completely consistent with the sleeve profile. Therefore, there may be a risk that the chuck profile cannot be fitted into the matching sleeve profile. This may be due, for example, to large manufacturing tolerances of the chuck profile and / or the sleeve profile and / or to the chuck 200 entering the slide sleeve 106 at high speed, which would result in insufficient time for the biased chuck profile to return to the unbiased state before the chuck 200 moves out of the slide sleeve 106.

[0262] On the other hand, if t is equal to or close to 1, then the grooves and their corresponding ridges have the maximum length difference L. b There is a risk that the chuck profile may be incorrectly fitted into a mismatched sleeve profile (described later).

[0263] In some embodiments, t may be chosen to be sufficiently greater than zero and sufficiently less than one to ensure that:

[0264] (i) A chuck profile corresponding to a certain sleeve profile in the group is easily rejected by any other sleeve profile in the same group; and

[0265] (ii) The length difference between the slot and its corresponding ridge (e.g., the length difference between the sleeve slot 184A and the chuck ridge 222A, the length difference between the chuck slot 234 and the sleeve ridge 232, or the length difference between the sleeve slot 184B and the chuck ridge 222B) is sufficient to ensure that the ridge can be easily received into the slot.

[0266] For example, in one embodiment, t may be selected as 0.9 ≥ t ≥ 0.1. In some alternative embodiments, t may be selected as 0.8 ≥ t ≥ 0.2. In some alternative embodiments, t may be selected as 0.7 ≥ t ≥ 0.3. In some alternative embodiments, t may be selected as 0.6 ≥ t ≥ 0.4. In some alternative embodiments, t may be selected as approximately 0.5.

[0267] Figure 22 Group A1 shows four casing profiles and four corresponding chuck profiles when n = 0 and K = 6, where the casing profiles have the same length L. s =7L b .

[0268] Figure 23 Group B1 shows six casing profiles and six corresponding chuck profiles when n = 0 and K = 8, where the casing profiles have the same length L. s =9L b .

[0269] Figure 24 This shows a group C1 of eight casing profiles and eight corresponding chuck profiles when n = 0 and K = 10, where the casing profiles have the same length L. s =11L b .

[0270] Figure 25 This shows group D1 of ten casing profiles and ten corresponding chuck profiles when n = 0 and K = 12, where the casing profiles have the same length L. s =13L b .

[0271] Figure 26Group A2 shows three casing profiles and three corresponding chuck profiles when n=1 and K=5, where the casing profiles have the same length L. s =7L b .

[0272] Figure 27 Group B2 shows five casing profiles and five corresponding chuck profiles when n=1 and K=7, where the casing profiles have the same length L. s =9L b .

[0273] Figure 28 Group C2 shows seven casing profiles and seven corresponding chuck profiles when n=1 and K=9, where the casing profiles have the same length L. s =11L b .

[0274] Figure 29 This shows group D2 of nine casing profiles and nine corresponding chuck profiles when n=1 and K=11, where the casing profiles have the same length L. s =13L b .

[0275] Figure 30 Group A3 shows two sleeve profiles and two corresponding chuck profiles when n=2 and K=4, where the sleeve profiles have the same length L. s =7L b .

[0276] Figure 31 Group B3 shows four casing profiles and four corresponding collet profiles when n=2 and K=6, where the casing profiles have the same length L. s =9L b .

[0277] Figure 32 Group C3 shows six casing profiles and six corresponding collet profiles when n=2 and K=8, where the casing profiles have the same length L. s =11L b .

[0278] Figure 33 Group D3 shows eight casing profiles and eight corresponding chuck profiles when n=2 and K=10, where the casing profiles have the same length L. s =13L b .

[0279] Figure 34 Group A4 shows a casing profile and a corresponding chuck profile when n=3 and K=3, where the casing profile has a length L. s =7Lb .

[0280] Figure 35 Group B4 shows three casing profiles and three corresponding chuck profiles when n=3 and K=5, where the casing profiles have the same length L. s =9L b .

[0281] Figure 36 Group C4 shows five casing profiles and five corresponding chuck profiles when n=3 and K=7, where the casing profiles have the same length L. s =11L b .

[0282] Figure 37 Group D4 shows seven casing profiles and seven corresponding chuck profiles when n=3 and K=9, where the casing profiles have the same length L. s =13L b .

[0283] Figure 38 Group B5 shows two casing profiles and two corresponding chuck profiles when n=4 and K=4, where the casing profiles have the same length L. s =9L b .

[0284] Figure 39 Group C5 shows four casing profiles and four corresponding collet profiles when n=4 and K=6, where the casing profiles have the same length L. s =11L b .

[0285] Figure 40 Group D5 shows six casing profiles and six corresponding collet profiles when n=4 and K=8, where the casing profiles have the same length L. s =13L b .

[0286] Figure 41 Group B6 shows a casing profile and a corresponding chuck profile when n=5 and K=3, wherein the casing profile has a length L. s =9L b .

[0287] Figure 42 The diagram shows a group C6 of three casing profiles and three corresponding collet profiles when n=5 and K=5, wherein the casing profiles have the same length L. s =11L b .

[0288] Figure 43Group D6 shows five casing profiles and five corresponding chuck profiles when n=5 and K=7, where the casing profiles have the same length L. s =13L b .

[0289] Figure 44 The diagram shows a set C7 of two sleeve profiles and two corresponding chuck profiles when n = 6 and K = 4, wherein the sleeve profiles have the same length L. s =11L b .

[0290] Figure 45 Group D7 shows four casing profiles and four corresponding collet profiles when n=6 and K=6, where the casing profiles have the same length L. s =13L b .

[0291] Figure 46 This shows a set C8 of a sleeve profile and a corresponding chuck profile when n=7 and K=3, wherein the sleeve profile has a length L. s =11L b .

[0292] Figure 47 The diagram shows group D8 of three casing profiles and three corresponding collet profiles when n=7 and K=5, where the casing profiles have the same length L. s =13L b .

[0293] Figure 48 The diagram shows group D9 of two casing profiles and two corresponding collet profiles when n = 8 and K = 4, where the casing profiles have the same length L. s =13L b .

[0294] Figure 49 This shows group D8, which represents a casing profile and a corresponding chuck profile when n = 9 and K = 3, wherein the casing profile has a length L. s =13L b .

[0295] Table 1 below summarizes Figures 22 to 49 The outline shown is an example of this. It can be seen that by limiting the sleeve outline length to 7L... b 9L b 11L b and 13L b A total of 122 casing profiles and 122 corresponding chuck profiles can be obtained and used for downhole fracturing.

[0296] Table 1

[0297]

[0298]

[0299] In embodiments where two or more slide valves 100 having the above-described sleeve profiles are used for tubing, the order of the sleeve profiles needs to be arranged as follows:

[0300] (a) The spool valves should have different sleeve profiles; in other words, for any two spool valves, at least one of n, K and m1 should be different.

[0301] (b) Length L s Shorter spool valves should be installed in length L. s The longer slide valve should be located on the wellhead side; in other words, the slide valve with a smaller (n+K) value should be located on the wellhead side of the slide valve with a larger (n+K) value.

[0302] (c) For length L s The same spool valve, S r Larger spool valves should be installed in S r The smaller slide valve should be located on the wellhead side; in other words, for slide valves with the same (n+K), the slide valve with the larger n should be located on the wellhead side of the slide valve with the smaller n; and

[0303] (d) Slide valves with the same profile group (i.e., slide valves with the same n and the same K but different m1) can be arranged in any order.

[0304] In other words, spool valves with a "lower" category letter (e.g., "A") (i.e., those with a shorter sleeve profile length L) s The spool valve should be located in the category of a spool valve with a "higher" category letter (e.g., "D") (i.e., with a longer sleeve profile length L). s The wellhead side of the slide valve. For slide valves with the same category letter (i.e., with the same casing profile length L). s For spool valves, those with a smaller group number (e.g., "A1") should be located on the downhole side of the spool valve with a larger group number (e.g., "A3"). Figure 50 An example of a tubing string (e.g., casing string or tubing string) having a plurality of spool valves 100 arranged as described above is shown.

[0305] In some alternative embodiments, t is equal to or close to 1, and the groove and its corresponding ridge have a maximum length difference L. b Therefore, the two "adjacent" sleeve profiles and chuck profiles do not exclude each other.

[0306] In other words, the chuck profile can be accommodated not only in matching sleeve profiles, but also in sleeve profiles with the same category letter, the same group number, and "adjacent" profile numbers (i.e., differing by 1). For example, the chuck profile C(A1-2) (i.e., C[0,6,2]) can be fitted into the preceding and following sleeve profiles S(A1-1) and S(A1-2) (i.e., S[0,6,1] and S[0,6,3]), but cannot be fitted into other sleeve profiles in profile group A1 (e.g., S(A1-4)).

[0307] In other words, the chuck profile can be fitted into the preceding and following sleeve profiles in the same profile group, but cannot be fitted into other sleeve profiles in the same profile group. That is, the chuck profile C[n,K,i] can be fitted into sleeve profiles S[n,K,i+1] and S[n,K,i-1], but cannot be fitted into other sleeve profiles (i.e., sleeve profile S[n,K,j]), where j≠i, j≠i+1 and j≠i-1).

[0308] Therefore, at t=1 and using a tube with such Figures 22 to 49 In embodiments of two or more slide valves 100 with the shown sleeve profiles, the order of the sleeve profiles needs to be arranged as follows:

[0309] (a) The spool valves should have different sleeve profiles; in other words, for any two spool valves, at least one of n, K and m1 should be different.

[0310] (b) In each profile group, if |j1-j2|≤1, then two sleeve profiles S[n,K,j1] and S[n,K,j2] cannot be used on the same string; in other words, for any two spools with the same n and the same K, the difference between their m1 must be greater than 1.

[0311] (c) Length L s Shorter spool valves should be installed in length L. s The longer slide valve should be located on the wellhead side; in other words, the slide valve with a smaller (n+K) value should be located on the wellhead side of the slide valve with a larger (n+K) value.

[0312] (d) For length L s The same spool valve, S r Larger spool valves should be installed in S r The smaller slide valve should be located on the wellhead side; in other words, for slide valves with the same (n+K), the slide valve with the larger n should be located on the wellhead side of the slide valve with the smaller n; and

[0313] (e) Slide valves of the same profile group (i.e., slide valves with the same n and the same K but different m1) can be arranged in any order.

[0314] In some alternative embodiments, the above-described sleeve profile and chuck profile can be connected in series or cascaded with other suitable profiles to obtain an extended profile. For example, Figure 51 This illustrates a set of extended sleeve and chuck profiles obtained by connecting the same profile 286 between the profile in profile group A1 and the stop ring 192. (See diagram) Figure 52 As shown, in some embodiments, the same profile 286 can be cascaded on the wellhead side of the profile in group A1 to obtain an extended profile.

[0315] In some embodiments, contours within the same group can be concatenated with different contours to obtain extended contours. For example, Figure 53 The outline of group A1 is shown to be concatenated with the first four outlines in group B2 to obtain an extended outline.

[0316] In the above embodiment, the casing profile is located on the inner surface of the casing body 152, so that the stop shoulder 194 of the stop ring 192 is located on its downhole side. Figures 54 to 56 In some alternative embodiments shown, the sleeve profile includes a profile portion on the inner surface of the sleeve body 152 as described above and a profile portion on the inner surface of the protective sleeve 154, such that the stop shoulder 194 of the stop ring 192 is located within the sleeve profile.

[0317] Accordingly, the chuck 200 may have a chuck profile extending on the casing body 152 and the protective casing 154 for matching the casing profile. To ensure that the front or downhole portion of the chuck 200 passes smoothly through the stop ring 192, each protrusion 292 on the chuck 200 that matches the profile on the protective casing 154 has an obtuse angle on its downhole side.

[0318] The profile on the protective sleeve 154 can have any suitable shape and can be combined with any suitable profile of the sleeve body 152, for example... Figures 22 to 49 Any of the contours shown. For example, Figures 54 to 57 It shows a length of 2L b The protective sleeve 154 of the groove 294, and respectively with Figures 22 to 25 The shown profiles A1, B1, C1, and D1 are combined. Correspondingly, the chuck profile of the chuck 200 includes a length of L. b The protrusion or ridge 292 is used to match the groove 294.

[0319] In some embodiments, slot 294 may have other suitable lengths. For example, Figures 58 to 61 It shows a length of 3L b The protective sleeve 154 of the groove 294, and respectively with Figures 22 to 25 The shown profiles A1, B1, C1, and D1 are combined. Correspondingly, the chuck profile of the chuck 200 includes a length of 2L. bThe protrusion or ridge 292 is used to match the groove 294.

[0320] In some embodiments, the profile on the protective sleeve 154 may include one or more grooves and / or one or more ridges.

[0321] In some embodiments, the profile on the protective sleeve 154 may be from... Figures 22 to 49 The contour selected from the shown contours. For example, an extended set of contours can be obtained by concatenating the contours in contour group A1 with the first four contours in contour group B2, wherein the first four contours in contour group B2 are located on the downhole side of the stop ring 192 or on the protective casing 154.

[0322] like Figure 62 As shown, in some alternative embodiments, the casing profile (e.g., the casing profile in profile group A1) may be located on the downhole side of the stop ring 192. Therefore, the stop shoulder 194 is located on the wellhead side of the casing profile. In these embodiments, each protrusion on the chuck 200 has an obtuse angle on its downhole side to ensure smooth passage of the chuck 200 through the stop ring 192.

[0323] As mentioned above and as Figure 15A and 15B As shown, the slide sleeve 126 of the slide valve 100 can be pressure-actuated to the open position by the ball 242 and the collet 200 to open the fluid port for fracturing. When fluid pressure is applied, the spline 218 of the collet 200 can be pressure-actuated to expand radially outward, and when the collet profile 212 engages with the shoulder 194 of the stop ring 192, the compression of the collet causes the spline 218 to expand radially outward, thereby further engaging with the slide sleeve 106 to enhance the engagement and further improve the pressure resistance. Figures 63A to 63F More details of the radially outward-expanding chuck profile 212 are shown.

[0324] Please refer to Figure 63A For ease of explanation, sleeve grooves 184A and 184B are considered to have the same inner diameter, and chuck ridges 222A and 222B are considered to have the same outer diameter.

[0325] Depth H of wellhead casing groove 184A sg1 It is measured radially between its outermost surface (i.e., its "bottom surface") and its innermost wellhead edge (i.e., its wellhead "top" edge). The height H of casing ridge 232. sr It is measured radially between its innermost surface (i.e., its "top surface") and its outermost edge (i.e., its "bottom" edge). The depth H of the downhole casing groove 184B. sg2 It is measured radially between the outermost surface and the innermost downhole edge, and its innermost downhole edge is also the innermost edge of the stop shoulder 194.

[0326] Similarly, the height H of the wellhead clamp ridge 222A cr1 The depth H of the chuck groove 234 is measured radially between its outermost surface (i.e., its "top surface") and its innermost wellhead edge (i.e., its wellhead "bottom" edge). cg It is measured radially between its innermost surface (i.e., its "bottom surface") and its outermost edge (i.e., its "top" edge). The height H of the downhole clamp ridge 222B. cr2 It is measured radially between its outermost surface (i.e., its "top surface") and its innermost downhole edge (i.e., its downhole "bottom" edge).

[0327] In such Figures 63A to 63C In some of the embodiments shown, H sg1 =H sg2 =H sr =H s And H cr1 =H cr2 =H cr Please refer to this. Figure 63B To allow the chuck profile 212 to expand radially outward when it engages with the sleeve profile 182, a gap needs to be maintained between each of the sleeve grooves 184A and 184B and the chuck groove 234 and each of the corresponding chuck ridges 222A and 222B and the sleeve ridge 232. In other words, H s -H cr >0、H cg -H cr >0 and ε2>0. Therefore, in these embodiments, H s >H cr H cg >H cr And ε2>0.

[0328] In some embodiments, H sg1 =H sg2 =H sr =H s And H cr1 =H cr2 =H cr Furthermore, the chuck groove 234 is located around the longitudinal center of the chuck profile 212, and the chuck groove 234 is the part where the expansion is most pronounced when the spline 218 expands or bends radially outward (see [reference]). Figure 63C In these embodiments, H is required. s >H cr H cg >H crAnd ε2>0. Preferably, the gap between the chuck groove 232 and the sleeve ridge 232 is greater than or equal to the gap between the sleeve groove 184A / 184B and the corresponding chuck ridge 222A / 222B. In other words, H s -H cr >0、H cg -H cr >0、H cg -H cr ≥H s -H cr And ε2>0. Therefore, in these embodiments, H cg ≥H s >H cr And ε2>0. In some embodiments, H is preferred. cg =H s >H cr And ε2>0, so when the chuck profile 212 expands radially outward in the sleeve profile 182, the chuck ridge 234 can fully engage with the sleeve ridge 232 and eliminate the gap between them.

[0329] like Figure 63B and 63C As shown, after the chuck 200 engages with the sleeve 106, further pressure from its wellhead side can further drive the chuck 200 downhole, forcing the spline 218 to expand or bend radially outward and further engage with the sleeve 106 to a greater extent.

[0330] In such Figures 63D to 63F In some embodiments shown, the depth of the wellhead casing groove 184A is the same as the height of the casing ridge 232. However, the depth of the downhole casing groove 184B is greater than the depth of the wellhead casing groove 184A. That is, H sg1 =H sr =H s And H sg2 >H s The heights of the chuck ridges 222A and 222B, and the depth of the chuck groove 234, are the same. That is, H... cr1 =H cr2 =H cr .

[0331] Please refer to Figure 63E In these embodiments, H cg +H sg2 -H cr -H s >0、H sg2 -H cr >0 and ε2>0, to allow the chuck profile 212 to expand radially outward when the chuck profile 212 engages with the sleeve profile 182.

[0332] In some embodiments, H sg1 =H sr =H s H sg2 >H s H cr1 =H cr2 =H cr Furthermore, the chuck groove 234 is located around the longitudinal center of the chuck profile 212, and when the spline 218 expands radially outward, the chuck groove 234 is the part where the expansion is most pronounced (see [reference]). Figure 63E ).

[0333] In these embodiments, H cg +H sg2 -H cr -H s >0、H sg2 -H cr >0 and ε2>0. Preferably, the gap between the chuck groove 232 and the sleeve ridge 232 is greater than or equal to the gap between the sleeve groove 184A / 184B and the corresponding chuck ridge 222A / 222B. In other words, H cg +H sg2 -H cr -H s ≥H sg2 -H cr Therefore, in these embodiments, H sg2 >H cr H cg ≥H s And ε2>0. In some embodiments, H is preferred. sg2 >H cr H cg =H s And ε2>0, so when the chuck profile 212 expands radially outward in the sleeve profile 182, the chuck ridge 234 can fully engage with the sleeve ridge 232 and eliminate the gap between them.

[0334] Although some embodiments have been described above with reference to the accompanying drawings, those skilled in the art will understand that various changes and modifications can be made without departing from the scope of the invention.

[0335] For a complete definition of the invention and its intended scope, please refer to the detailed description and appendices herein for illustrative purposes. Figure 1 Please read and consider the Summary of the Invention section and the appended claims.

Claims

1. Multiple spool valves, each spool valve comprising: A valve body having a longitudinal hole therethrough and one or more fluid ports located on a wellhead portion of the sidewall of the valve body; and A sliding sleeve, received in a longitudinal bore of the valve body, and movable between a wellhead closed position for closing the one or more fluid ports and a downhole open position for opening the one or more fluid ports, the sliding sleeve including the longitudinal bore; The sliding sleeve includes a sleeve profile formed by at least first and second sleeve grooves and sleeve ridges therebetween, the first and second sleeve grooves and the sleeve ridges being longitudinally distributed on the inner surface of the sliding sleeve around a longitudinal hole; and The longitudinal length S of the first and second sleeve grooves and the sleeve ridge g1 S g2 and S r They are determined by the following formulas respectively: S r =δL a +nL b ,S r >0, S g1 =m1L b +(1-δ)L a , S g2 =m2L b , m1+m2=K, Where L a L b And δ are predetermined parameters, L a >0, L b >0 and 1≥δ≥0, n is an integer and n≥0, K is a positive integer and K>2, m1 and m2 are integers and m1≥1 and m2>1, when n=0, δ>0, and when δ=0, n>0; The longitudinal length L of the sleeve profile s At least: L s =L a +(n+K)L b ; For any two of the plurality of spool valves, at least one of n, K, and m1 is different; and The second set of pipe trench S g2 The lowest part of the well is composed of a radially inwardly protruding portion of a stop ring member, which is formed independently of the sliding sleeve and forms a stop shoulder, wherein the stop ring member is connected to the lowest part of the sliding sleeve; and The plurality of slide valves are components of a sliding sleeve system for injecting fluid into a hydrocarbon formation, and the sliding sleeve system further includes a chuck comprising: - A flexible chuck profile formed by at least a first wellhead chuck ridge and a second downhole chuck ridge and a chuck groove therebetween, with a radially outwardly projecting stop shoulder formed on the downhole side of the second downhole chuck ridge abutting the chuck groove to accommodate abutting a radially inwardly projecting portion of the stop ring member; and -wherein, the first wellhead chuck ridge is a first set of tubing S that matches one of a plurality of slide valves. g1 Short T1L b L b ≥t1L b ≥0 is a design parameter that includes tolerances, and the design parameter is represented by the length L. b Part of the second downhole chuck ridge is the second casing groove S of one of a plurality of spool valves that matches the spool valve. g2 Short t2L b L b ≥t2L b ≥0 is a second design parameter that includes another tolerance, and the second design parameter is represented by the length L. b The other part.

2. The plurality of slide valves according to claim 1, wherein L a =L b .

3. The plurality of slide valves according to claim 2, wherein t1 = t2 = t.

4. The plurality of slide valves according to claim 3, wherein 1>t>0.

5. The plurality of slide valves according to claim 3, wherein t is 0.

5.

6. The plurality of slide valves according to claim 3, wherein 0.9 > t ≥ 0.

1.

7. The plurality of slide valves according to claim 3, wherein 0.8 > t ≥ 0.

2.

8. The plurality of slide valves according to claim 3, wherein 0.7>t≥0.

3.

9. The plurality of slide valves according to claim 3, wherein 0.6 > t ≥ 0.

4.

10. The plurality of slide valves according to claim 3, wherein t = 0.

11. The plurality of slide valves according to claim 3, wherein t = 1.

12. A downhole system, comprising: A tubular column including a sliding sleeve system having a clamp for mates one of a plurality of spool valves; and Multiple chucks for downhole use, each chuck movable through one or more holes in a first sliding sleeve and received in a second sliding sleeve, each chuck comprising: The flexible chuck profile is formed by at least a first wellhead chuck ridge and a second downhole chuck ridge and the chuck groove therebetween. A stop shoulder that protrudes radially outward is formed on the downhole side of the second downhole chuck ridge that abuts against the chuck groove. The first wellhead chuck ridge, the second downhole chuck ridge and the chuck groove correspond to the first and second casing grooves and the casing ridge, respectively. The length C of the first wellhead chuck ridge, the second downhole chuck ridge, and the chuck groove is... r1 C r2 and C g They are determined by the following formulas respectively: C r1 =(m1-t1)L b +(1-δ)L a -ε2,C r1 >0, C r2 =(m2-t2)L b ,C r2 >0, C g =δL a +(n+t2)L b +ε2,C g >0, m1+m2=K, Where L a L b And δ are predetermined parameters, L a >0, L b >0 and 1≥δ≥0, n is an integer and n≥0, K is a positive integer and K>2, m1 and m2 are integers and m1≥1 and m2>1; t1, t2 and ε2 are predetermined parameters, 1≥t1≥0, 1≥t2≥0 and (m1-t1)L b +(1-δ)L a >ε2≥0; and The longitudinal length L of the chuck profile c At least: L c =L a +(n+K-t2)L b ; Furthermore, for any two of the plurality of chucks, at least one of n, K, and m1 is different; and The stop shoulder forms an acute angle between the upper edge of the second downhole chuck ridge and the radially inwardly projecting surface on its downhole side edge, suitable for locking engagement of the stop ring member at a corresponding angle on the wellhead side; Each of the slide valves has: A valve body having a longitudinal bore therethrough and one or more fluid ports located on a wellhead portion of the sidewall of the valve body; and A sliding sleeve, received in a longitudinal bore of the valve body, and movable between a wellhead closed position for closing the one or more fluid ports and a downhole open position for opening the one or more fluid ports, the sliding sleeve including the longitudinal bore; The sliding sleeve includes a sleeve profile formed by at least first and second sleeve grooves and sleeve ridges therebetween, the first and second sleeve grooves and sleeve ridges therebetween being longitudinally distributed on the inner surface of the sliding sleeve around a longitudinal hole; and The longitudinal length S of the first and second sleeve grooves and the sleeve ridge g1 S g2 and S r They are determined by the following formulas respectively: S r =δL a +nL b ,S r >0, S g1 =m1L b +(1-δ)L a , S g2 =m2L b , m1+m2=K, Where L a L b And δ are predetermined parameters, L a >0, L b >0 and 1≥δ≥0, n is an integer and n≥0, K is a positive integer and K>2, m1 and m2 are integers and m1≥1 and m2>1, when n=0, δ>0, and when δ=0, n>0; The longitudinal length L of the sleeve profile s At least: L s =L a +(n+K)L b ; For any two of the plurality of spool valves, at least one of n, K, and m1 is different; and The second set of pipe trench S g2 The lowest part of the well is composed of a radially inwardly protruding portion of a stop ring member, which is formed independently of the sliding sleeve and forms a stop shoulder, wherein the stop ring member is connected to the lowest part of the sliding sleeve; Where L a =L b ; The collet of the sliding sleeve system includes: - A flexible chuck profile formed by at least a first wellhead chuck ridge and a second downhole chuck ridge and a chuck groove therebetween, forming a radially outwardly protruding stop shoulder against the downhole side of the second downhole chuck ridge of the chuck groove. -wherein, the first wellhead chuck ridge is a first set of tubing S that matches one of a plurality of slide valves. g1 Short T1L b L b ≥t1L b ≥0 is a design parameter that includes tolerances, and the design parameter is represented by the length L. b Part of the second downhole chuck ridge is the second casing groove S of one of a plurality of spool valves that matches the spool valve. g2 Short t2L b L b ≥t2L b ≥0 is a second design parameter that includes another tolerance, and the second design parameter is represented by the length L. b The other part; Where t1 = t2 = 1; and The slide valves are arranged in the tubing according to the following rules: (a) For any two of the plurality of spool valves, at least one of their n, K, and m1 is different; (b) For any two of a plurality of spool valves having the same n and the same K, the difference between their m1 is greater than 1; (c) A slide valve with a smaller (n+K) is located on the wellhead side of a slide valve with a larger (n+K); (d) For spool valves with the same (n+K), the spool valve with the larger n value is located on the wellhead side of the spool valve with the smaller n value; and (e) Spool valves with the same n and the same K but different m1 are arranged in any order.

13. Multiple spool valves, each spool valve comprising: A valve body having a longitudinal hole therethrough and one or more fluid ports located on a wellhead portion of the sidewall of the valve body; and A sliding sleeve, received in a longitudinal bore of the valve body, and movable between a wellhead closed position for closing the one or more fluid ports and a downhole open position for opening the one or more fluid ports, the sliding sleeve including the longitudinal bore; The sliding sleeve includes a sleeve profile formed by at least first and second sleeve grooves and sleeve ridges therebetween, the first and second sleeve grooves and the sleeve ridges being longitudinally distributed on the inner surface of the sliding sleeve around a longitudinal hole; and The longitudinal length S of the first and second sleeve grooves and the sleeve ridge g1 S g2 and S r They are determined by the following formulas respectively: S r =δL a +nL b ,S r >0, S g1 =m1L b +(1-δ)L a , S g2 =m2L b , m1+m2=K, Where L a L b And δ are predetermined parameters, L a >0, L b >0 and 1≥δ≥0, n is an integer and n≥0, K is a positive integer and K>2, m1 and m2 are integers and m1≥1 and m2>1, when n=0, δ>0, and when δ=0, n>0; and The longitudinal length L of the sleeve profile s At least: L s =L a +(n+K)L b ; For any two of the plurality of spool valves, at least one of n, K, and m1 is different; and For each sliding sleeve, the first set of tubular grooves S g1 and the second set of pipe trench S g2 The outermost edge of the wellhead consists of a linearly inclined portion, the radially outward portion of which lies below the wellhead portion that is more radially inward. The first set of pipe trench S g1 The lowest edge of the well corresponds to the casing ridge S r The outermost edge of the wellhead, the first casing groove S g1 The lowest edge of the well extends radially inward to form a linear shoulder, which is substantially perpendicular to the longitudinal axis of the sleeve. The second set of tube grooves S in each sliding sleeve g2 The lowest edge portion of the well consists of a radially inwardly projecting stop shoulder, which, when engaged by the chuck assembly, is adapted to prevent the chuck assembly from moving further downhole relative to the sliding sleeve of the plurality of spool valves.

14. The plurality of spool valves according to claim 13, wherein the stop shoulder is composed of a linearly inclined portion, and the radially inward portion of the stop shoulder is located on the wellhead side of the radially outward portion further downhole of the stop shoulder.

15. The plurality of slide valves according to claim 13, wherein the stop shoulder is formed by the wellhead side edge of the stop ring member.

16. The plurality of spool valves according to claim 13, wherein L a =L b .

17. A sliding sleeve system having a collet for mating one of a plurality of spool valves as claimed in claim 16, the collet of the sliding sleeve system comprising: A flexible chuck profile formed by at least a first wellhead chuck ridge and a second downhole chuck ridge and a chuck groove therebetween forms a radially outward protruding stop shoulder against the downhole side of the second downhole chuck ridge of the chuck groove. The first wellhead chuck ridge is matched with the first set of tubing S of one of a plurality of slide valves. g1 Short T1L b L b ≥t1L b ≥0 is a design parameter that includes tolerances, and the design parameter is represented by the length L. b Part of the second downhole chuck ridge is the second casing groove S of one of a plurality of spool valves that matches the spool valve. g2 Short t2L b L b ≥t2L b ≥0 is a second design parameter that includes another tolerance, and the second design parameter is represented by the length L. b The other part.

18. The sliding sleeve system according to claim 17, wherein t1 = t2 = t.

19. The sliding sleeve system according to claim 18, wherein 1>t>0.

20. The sliding sleeve system according to claim 19, wherein t is 0.

5.

21. The sliding sleeve system according to claim 18, wherein 0.9 > t ≥ 0.

1.

22. The sliding sleeve system according to claim 18, wherein 0.8 > t ≥ 0.

2.

23. The sliding sleeve system according to claim 18, wherein 0.7 > t ≥ 0.

3.

24. The sliding sleeve system according to claim 18, wherein 0.6 > t ≥ 0.

4.

25. The sliding sleeve system according to claim 18, wherein t = 0.

26. The sliding sleeve system according to claim 18, wherein t = 1.

27. A plurality of chucks for downhole use, each chuck being movable through a hole in one or more first sleeves and being received in a second sleeve, each chuck comprising: Composed of at least the first wellhead clamp head ridge C r1 Second well downhole clamping head ridge C r2 And the chuck groove C sandwiched in between g The formed flexible chuck profile abuts against the chuck groove C. g The second downhole clamp ridge C r2 The downhole side edge forms a radially outwardly projecting stop shoulder. When the chuck profile engages with the second sliding sleeve, the stop shoulder is adapted to engage with the downhole edge of the second casing groove in the sliding sleeve or the wellhead edge of the stop ring component forming the downhole edge of the second casing groove in the second sliding sleeve, thereby preventing further downhole movement of the chuck relative to the second sliding sleeve. The first wellhead chuck ridge C of the chuck profile... r1 Second well downhole clamping head ridge C r2 and chuck groove C g The first set of tube grooves S, respectively inside or on the second sliding sleeve g1 The second set of pipe trenches S g2 and the septal ridge S between them r Matching and joining; For each chuck profile, the first wellhead chuck ridge C r1 and the second downhole clamp ridge C r2 Each of the wellhead edges has a linearly inclined portion, the radially outward portion of which lies below the more radially inward portion of the wellhead, the first wellhead chuck ridge C r1 The lowest edge of the well extends radially inward to form a shoulder, which is substantially perpendicular to the longitudinal axis of the chuck; The length C of the first wellhead chuck ridge, the second downhole chuck ridge, and the chuck groove is... r1 C r2 and C g They are determined by the following formulas respectively: C r1 =(m1-t1)L b +(1-δ)L a -ε2,C r1 >0, C r2 =(m2-t2)L b ,C r2 >0, C g =δL a +(n+t2)L b +ε2,C g >0, m1+m2=K, Where L a L b And δ are predetermined parameters, L a >0, L b >0 and 1≥δ≥0, n is an integer and n≥0, K is a positive integer and K>2, m1 and m2 are integers and m1≥1 and m2>1; t1, t2 and ε2 are predetermined parameters, 1≥t1≥0, 1≥t2≥0 and (m1-t1)L b +(1-δ)L a >ε2≥0; and The longitudinal length L of the chuck profile c At least: L c =L a +(n+K-t2)L b ; Furthermore, for any two of the plurality of chucks, at least one of n, K, and m1 is different.

28. The plurality of chucks according to claim 27, wherein t1 = t2 = t.

29. The plurality of chucks according to claim 27, wherein 1>t>0.

30. The plurality of chucks according to claim 27, wherein t is 0.

5.

31. The plurality of chucks according to claim 27, wherein 0.9 > t > 0.

1.

32. The plurality of chucks according to claim 27, wherein 0.8 > t > 0.

2.

33. The plurality of chucks according to claim 27, wherein 0.7 > t > 0.

3.

34. The plurality of chucks according to claim 27, wherein 0.6 > t > 0.

4.

35. The plurality of clamps according to claim 27, wherein t = 0.

36. The plurality of chucks according to claim 27, wherein t = 1.

37. The plurality of chucks according to claim 28, wherein the stop shoulder on each of the chucks is at the second downhole chuck ridge C. r2 The upper edge forms an acute angle with the radially inwardly projecting surface on its downhole side edge, and is linearly inclined, so that its innermost radial portion is located on the wellhead side of the more downhole portion.

38. A tubular column, comprising: The plurality of slide valves as described in claim 13; The slide valve is arranged in the tubing according to the following rules: (a) For any two of the plurality of spool valves, at least one of their n, K, and m1 is different; (b) A spool valve with a smaller (n+K) is located on the wellhead side of a spool valve with a larger (n+K); (c) For spool valves with the same (n+K), the spool valve with the larger n value is located on the wellhead side of the spool valve with the smaller n value; and (d) Spool valves with the same n and the same K but different m1 are arranged in any order.

39. A tubular column, comprising: The plurality of slide valves as described in claim 16; The slide valve is arranged in the tubing according to the following rules: (a) For any two of the plurality of spool valves, at least one of their n, K, and m1 is different; (b) A spool valve with a smaller (n+K) is located on the wellhead side of a spool valve with a larger (n+K); (c) For spool valves with the same (n+K), the spool valve with the larger n value is located on the wellhead side of the spool valve with the smaller n value; and (d) Spool valves with the same n and the same K but different m1 are arranged in any order.

40. A tubular column, comprising: The sliding sleeve system as described in claim 26; The slide valves are arranged in the tubing according to the following rules: (a) For any two of the plurality of spool valves, at least one of their n, K, and m1 is different; (b) For any two of a plurality of spool valves having the same n and the same K, the difference between their m1 is greater than 1; (c) A slide valve with a smaller (n+K) is located on the wellhead side of a slide valve with a larger (n+K); (d) For spool valves with the same (n+K), the spool valve with the larger n value is located on the wellhead side of the spool valve with the smaller n value; and (e) Spool valves with the same n and the same K but different m1 are arranged in any order.

41. The tubing string according to claim 38, 39 or 40, wherein the tubing string is a sleeve string.

42. The tubing string according to claim 38, 39 or 40, wherein the tubing string is for reception in a wellbore.

43. A downhole system, comprising: A tubing string containing multiple slide valves; and Multiple chucks according to any one of claims 27 to 36; Each of the slide valves includes: A valve body having a longitudinal bore therethrough and one or more fluid ports located on a wellhead portion of the sidewall of the valve body; and A sliding sleeve, received in a longitudinal bore of the valve body, and movable between a wellhead closed position for closing the one or more fluid ports and a downhole open position for opening the one or more fluid ports, the sliding sleeve including the longitudinal bore; The sliding sleeve includes a sleeve profile formed by at least first and second sleeve grooves and sleeve ridges therebetween, the first and second sleeve grooves and the sleeve ridges being longitudinally distributed on the inner surface of the sliding sleeve around a longitudinal hole; and The longitudinal length S of the first and second sleeve grooves and the sleeve ridge g1 S g2 and S r They are determined by the following formulas respectively: S r =δL a +nL b ,S r >0, S g1 =m1L b +(1-δ)L a , S g2 =m2L b , m1+m2=K, Where L a L b And δ are predetermined parameters, L a >0, L b >0 and 1≥δ≥0, n is an integer and n≥0, K is a positive integer and K>2, m1 and m2 are integers and m1≥1 and m2>1, when n=0, δ>0, and when δ=0, n>0; and The longitudinal length L of the sleeve profile s At least: L s =L a +(n+K)L b ; For any two of the plurality of spool valves, at least one of n, K, and m1 is different; and The second set of pipe trench S g2 The lowest part of the well is composed of a radially inwardly protruding portion of a stop ring member, which is formed independently of the sliding sleeve and forms a stop shoulder, wherein the stop ring member is connected to the lowest part of the sliding sleeve; The slide valve is arranged in the tubing according to the following rules: (a) For any two of the plurality of spool valves, at least one of their n, K, and m1 is different; (b) A spool valve with a smaller (n+K) is located on the wellhead side of a spool valve with a larger (n+K); (c) For spool valves with the same (n+K), the spool valve with the larger n value is located on the wellhead side of the spool valve with the smaller n value; and (d) Spool valves with the same n and the same K but different m1 are arranged in any order.

44. A downhole system, comprising: A tubing string containing multiple slide valves; and Multiple chucks according to any one of claims 27 to 36; Each of the slide valves includes: A valve body having a longitudinal bore therethrough and one or more fluid ports located on a wellhead portion of the sidewall of the valve body; and A sliding sleeve, received in a longitudinal bore of the valve body, and movable between a wellhead closed position for closing the one or more fluid ports and a downhole open position for opening the one or more fluid ports, the sliding sleeve including the longitudinal bore; The sliding sleeve includes a sleeve profile formed by at least first and second sleeve grooves and sleeve ridges therebetween, the first and second sleeve grooves and the sleeve ridges being longitudinally distributed on the inner surface of the sliding sleeve around a longitudinal hole; and The longitudinal length S of the first and second sleeve grooves and the sleeve ridge g1 S g2 and S r They are determined by the following formulas respectively: S r =δL a +nL b ,S r >0, S g1 =m1L b +(1-δ)L a , S g2 =m2L b , m1+m2=K, Where L a L b And δ are predetermined parameters, L a >0, L b >0 and 1≥δ≥0, n is an integer and n≥0, K is a positive integer and K>2, m1 and m2 are integers and m1≥1 and m2>1, when n=0, δ>0, and when δ=0, n>0; and The longitudinal length L of the sleeve profile s At least: L s =L a +(n+K)L b ; For any two of the plurality of spool valves, at least one of n, K, and m1 is different; and The second set of pipe trench S g2 The lowest part of the well is composed of a radially inwardly protruding portion of a stop ring member, which is formed independently of the sliding sleeve and forms a stop shoulder, wherein the stop ring member is connected to the lowest part of the sliding sleeve; Where L a =L b ;and The slide valve is arranged in the tubing according to the following rules: (a) For any two of the plurality of spool valves, at least one of their n, K, and m1 is different; (b) A spool valve with a smaller (n+K) is located on the wellhead side of a spool valve with a larger (n+K); (c) For spool valves with the same (n+K), the spool valve with the larger n value is located on the wellhead side of the spool valve with the smaller n value; and (d) Spool valves with the same n and the same K but different m1 are arranged in any order.

45. A downhole system, comprising: A tubular column including a sliding sleeve system having a clamp for accommodating a plurality of spool valves; and Multiple chucks according to any one of claims 27 to 37; Each of the slide valves includes: A valve body having a longitudinal bore therethrough and one or more fluid ports located on a wellhead portion of the sidewall of the valve body; and A sliding sleeve, received in a longitudinal bore of the valve body, and movable between a wellhead closed position for closing the one or more fluid ports and a downhole open position for opening the one or more fluid ports, the sliding sleeve including the longitudinal bore; The sliding sleeve includes a sleeve profile formed by at least first and second sleeve grooves and sleeve ridges therebetween, the first and second sleeve grooves and the sleeve ridges being longitudinally distributed on the inner surface of the sliding sleeve around a longitudinal hole; and The longitudinal length S of the first and second sleeve grooves and the sleeve ridge g1 S g2 and S r They are determined by the following formulas respectively: S r =δL a +nL b ,S r >0, S g1 =m1L b +(1-δ)L a , S g2 =m2L b , m1+m2=K, Where L a L b And δ are predetermined parameters, L a >0, L b >0 and 1≥δ≥0, n is an integer and n≥0, K is a positive integer and K>2, m1 and m2 are integers and m1≥1 and m2>1, when n=0, δ>0, and when δ=0, n>0; and The longitudinal length L of the sleeve profile s At least: L s =L a +(n+K)L b ; For any two of the plurality of spool valves, at least one of n, K, and m1 is different; and The second set of pipe trench S g2 The lowest part of the well is composed of a radially inwardly protruding portion of a stop ring member, which is formed independently of the sliding sleeve and forms a stop shoulder, wherein the stop ring member is connected to the lowest part of the sliding sleeve; Where L a =L b ; The collet of the sliding sleeve system includes: A flexible chuck profile formed by at least a first wellhead chuck ridge and a second downhole chuck ridge and a chuck groove therebetween forms a radially outward protruding stop shoulder against the downhole side of the second downhole chuck ridge of the chuck groove. Among them, the first wellhead clamp ridge is matched with the first set of tubing S of one of the multiple slide valves. g1 Short T1L b L b ≥t1L b ≥0 is a design parameter that includes tolerances, and the design parameter is represented by the length L. b Part of the second downhole chuck ridge is the second casing groove S of one of a plurality of spool valves that matches the spool valve. g2 Short t2L b L b ≥t2L b ≥0 is a second design parameter that includes another tolerance, and the second design parameter is represented by the length L. b The other part; Where t1 = t2 = 1; and The slide valve is arranged in the tubing according to the following rules: (a) For any two of the plurality of spool valves, at least one of their n, K, and m1 is different; (b) For any two of a plurality of spool valves having the same n and the same K, the difference between their m1 is greater than 1; (c) A slide valve with a smaller (n+K) is located on the wellhead side of a slide valve with a larger (n+K); (d) For spool valves with the same (n+K), the spool valve with the larger n value is located on the wellhead side of the spool valve with the smaller n value; and (e) Spool valves with the same n and the same K but different m1 are arranged in any order.

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