Sleeve and dart assemblies and related completion systems and methods for hydraulic fracturing operations

Abstract

A method of actuating a plurality of sleeve assemblies in a tubing string, each of the sleeve assemblies including a tubular housing having one or more fluid ports into a formation and an actuatable inner sleeve within the tubular housing, the method comprising: activating an activation mechanism to shift an engagement mechanism of one of the sleeve assemblies from an inactive state into an active state, in which in the active state the engagement mechanism extends radially inward into the axial flow passage to form an annular shoulder, the annular shoulder being ductile and engageable with a fluid blocking device; running the fluid blocking device into sealing contact with the engagement mechanism; and opening the one or more fluid ports on the one of the sleeve assemblies by providing sufficient pressure to the fluid blocking device to shift the engagement mechanism into an open position.

Description

SLEEVE AND DART ASSEMBLIES AND RELATED COMPLETION SYSTEMS ANDMETHODS FOR HYDRAULIC FRACTURING OPERATIONSCROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This patent application claims priority to U.S. Provisional 63 / 614,427 filed on December 22, 2023, and U.S. Provisional 63 / 680,588 filed on August 7, 2024, both of which are herein incorporated by reference. The present disclosure describes improvements and modifications to the invention disclosed in international application no. PCT / CA2023 / 050876 filed June 23, 2023, which is hereby incorporated by reference. The aforementioned PCT application claims priority to U.S. Provisional Patent Application No. 63 / 354,987, filed June 23, 2022, and U.S. Provisional Patent Application No. 63 / 465,646, filed May 11, 2023, the entire contents of both of which are herein incorporated by reference.TECHNICAL FIELD

[0002] The present disclosure relates to downhole tool operations. More particularly, the present disclosure relates to sleeve assemblies and darts and related completion systems and methods for selectively actuating downhole tools in different sections of a wellbore.BACKGROUND

[0003] In staged horizontal wellbore completion operations, a wellbore is drilled into a subterranean formation and different zones of the formation are treated (e.g. stimulated and / or fractured) sequentially at different points along the wellbore.

[0004] Multiple technologies have been developed for multi-stage horizontal well stimulation. One such technology is a plug-and-perforation (“plug-and-perf ’) system that uses wireline services and / or coiled tubing (“CT”) services to run-in-hole a select-fire perforating gun with one or more bridge plugs so as to plug and perforate sections of cased horizontal wells for subsequent stimulation operations. Plug-and-perf systems are typically implemented on “pads” where multiple wells are drilled from one surface location, primarily because wireline services can be managed without downtime to fracturing operations. Plug-and-perf systems are not commonly used with single wells due to fracturing equipment cost inefficiencies.

[0005] Plug-and-perf systems typically require the bridge plugs to be milled out after the well is completed. Dissolvable bridge plugs (“DBPs”) have been investigated but commercially available DBPs have challenges with reliability and have not been widely accepted. DBPs oftencannot withstand the high-pressure fracturing environment and / or are designed with such rigid material that the DBP does not dissolve effectively. Due to these dissolvability issues, the DBPs may still need to be milled out after the well is completed.

[0006] Non-dissolvable bridge plugs are often used in combination with a dissolvable or non- dissolvable ball to achieve more reliable probability of fluid (Frac / Reserve fluid) flowblack without milling out the entire dissolvable bridge plug or bridge plug. The ball may be run with the bridge plug setting tool (“ball in place”) or not (“ball not in place”). Plug-and-perf applications using “ball in place” or “ball not in place” typically do not remove the bridge plug barrel, resulting in a permanent inner diameter (“ID”) restriction unless the bridge plug barrels are milled out during a workover.

[0007] Other completion systems use flow control valves such as sleeve assemblies to selectively establish fluid communication between a bore of the completion string and the formation. Conventional sleeve assemblies comprise a tubular housing with a plurality of flow ports and an inner sleeve configured to slide axially with respect to the tubular housing to open and close the flow ports. Multiple sleeve assemblies are typically spaced along the casing string to establish fluid communication with different zones of interest along the wellbore.

[0008] Sleeve assemblies may be actuated by dropping actuating objects (e.g. balls) into the wellbore to seat and shift the sleeve. Ball drop technologies can be used on both pad wells and single wells. However, ball drop systems are limited in terms of stages and the fracturing pump rate. Moreover, the ball seat is typically milled out after the stage is completed to avoid the wellbore being left with inner diameter (ID) restrictions. Standard ball drop designs use different sizes of balls for each stage.

[0009] An alternative to ball drop technologies are conveyance strings, such as coiled tubing, fit with mechanical shifting tools. Conveyed shifting tools may be configured for both opening and closing of sleeves for various purposes. However, shifting tool -based techniques typically require ID-restricting conveyance coiled tubing. In addition, the infrastructure and time for running the shifting tool in and out of the wellbore each time a sleeve is to be shifted may be costly. Coiled tubing-based systems of this type greatly restrict the fracture stimulation fluid placement rate, limiting its effectiveness. Coiled tubing -based systems of this type also restrict horizontal well length.

[0010] Dart-based systems typically involve an electronic dart device that senses an “activation sleeve” just above the target sleeve that the dart is intended to actuate. Once the dart passes the activation sleeve, it will typically activate a seal and locator collet to land in a shoulder of the target sleeve. However, the seal and locator collet may have reliability issues, leading tounreliable isolation of the target sleeve. Dissolvable darts have been developed but dissolvability also tends to be unreliable. In addition, such darts typically require a large shoulder in the sleeve to engage the locator collet, which reduces the ID of the finished wellbore after the dart dissolves. As an alternative to a fully dissolvable dart, some darts are made of aluminum or steel and have a dissolvable ball in the center like a DBP. However, this design may lead to similar well construction issues post-fracturing as DBPs generally produce a permanent wellbore ID restriction that can only be removed by milling the dart out. Darts have many moving parts that may decrease the reliability of dissolving.BRIEF DESCRIPTION OF THE FIGURES

[0011] Embodiments will now be described with reference to the figures, in which like reference characters denote like elements, by way of example, and in which:

[0012] Fig. 1 shows a side section view of an embodiment of a dart;

[0013] Fig. 2 shows a side section view of an embodiment of the dart of Fig. 1 in an expanded state;

[0014] Fig. 3 shows a simplified side section view of an embodiment of a tubing string;

[0015] Fig. 4 shows a simplified side section view of the embodiment of the tubing string of Fig. 3 with a dart therein;

[0016] Fig. 5 shows a simplified side section view of an embodiment of the tubing string of Fig. 3 with a dart expanded;

[0017] Fig. 6 shows a simplified side section view of an embodiment of the tubing string of Fig. 3 with a dart engaged with a dart engaging element;

[0018] Fig. 7 shows a simplified side section view of an embodiment of the tubing string of Fig. 3 with another dart therein;

[0019] Fig. 8 shows a simplified side section view of variations of embodiments of dart engaging elements;

[0020] Fig. 9 shows a side section view of an embodiment of a dart with a detachment mechanism;

[0021] Fig. 10 shows a side section view of the embodiment of the dart of Fig. 9 in an activated state;

[0022] Figs. 11A and 1 IB show simplified side section views of variations of embodiments of dart engaging elements;

[0023] Fig. 12 shows a simplified side section view of an embodiment of a tubing string;

[0024] Fig. 13 shows a simplified side section view of the embodiment of the tubing string shown in Fig. 12 with a dart connected to a wireline and BHA;

[0025] Fig. 14 shows a simplified side section view of the embodiment of the tubing string shown in Fig. 12;

[0026] Fig. 15 shows a simplified side section view of the embodiment of the tubing string shown in Fig. 12 with the dart expanded.

[0027] Figs. 16 and 17 show simplified side section views of the embodiment of the tubing string shown in Fig. 14 with the dart separated from the wireline and BHA;

[0028] Fig 18 shows a simplified side section view of the embodiment of the tubing string shown in Fig. 14 with the wireline removed;

[0029] Fig 19 shows a simplified side section view of the embodiment of the tubing string shown in Fig. 14 with another dart therein;

[0030] Figs. 20A and 20B show side section views of an embodiment of the dart wherein the dart is expanded by a setting tool;

[0031] Figs. 21A - 21C show side section views of the dart in operation with a detachment mechanism;

[0032] Fig. 22 shows a simplified side section view of an embodiment of a tubing string;

[0033] Fig. 23 shows a simplified side section view of the embodiment of the tubing string of Fig. 22 with a dart and a wireline;

[0034] Fig. 24 shows a simplified side section view of the embodiment of Fig. 23 with a dart being released within a tubing string;

[0035] Fig. 25 shows a simplified side section view of the embodiment of Fig. 24 with a dart engaging with a dart engaging element after being released from a wireline;

[0036] Fig. 26 shows a side section view of an embodiment of a sleeve assembly;

[0037] Fig. 27 shows a side section view of the embodiment of the sleeve assembly shown in Fig. 26 with an engagement mechanism in an active state;

[0038] Fig. 28 shows a side section view of the embodiment of the sleeve assembly shown in Fig. 27 with a fluid blocking device therein;

[0039] Fig. 29 shows a side section view of the embodiment of the sleeve assembly shown in Fig. 28 with open apertures;

[0040] Fig. 30A shows a side view of an embodiment of a fluid blocking device;

[0041] Fig. 30B shows a side section view of the embodiment of the fluid blocking device of Fig. 30A.

[0042] Fig. 31 shows a side section view of a portion of an embodiment of a sleeve assembly with an alternative embodiment of inner sleeve and engagement mechanism;

[0043] Fig. 32 shows an isolated side section view of a portion of the embodiment shown in Fig. 31 with an annular shoulder extended radially inward;

[0044] Fig. 33 shows a side section view of a portion of the embodiment shown in Fig. 32 with a fluid blocking element in contact with the extended annular shoulder;

[0045] Fig. 34 shows a side section view of a portion of the embodiment shown in Fig. 33 with the engagement mechanism shifted axially;

[0046] Fig. 35 shows a side section view of a portion of an embodiment of a sleeve assembly with an engagement mechanism in the inactive state;

[0047] Fig. 36 shows a side section view of a portion of an embodiment of a sleeve assembly with the engagement mechanism in an active state;

[0048] Fig. 37 shows a side section view of a portion of the embodiment of the sleeve assembly in Fig. 36 with a fluid blocking device therein;

[0049] Fig. 38 shows a side section view of a portion of the embodiment of the sleeve assembly in Fig. 37 with a connection point therein;

[0050] Fig. 39 shows a side section view of an embodiment of a sleeve assembly;

[0051] Fig. 40 shows a side section view of the embodiment shown in Fig. 39 with an annular shoulder therein;

[0052] Fig. 41 shows a side section view of the embodiment shown in Fig. 40 with a fluid blocking device engaged with the annular shoulder;

[0053] Fig 42 shows a side section view of the embodiment shown in Fig. 41 with the engagement mechanism shifted axially;

[0054] Fig. 43 shows a side view and a side section view of an embodiment of a fluid blocking device;

[0055] Fig. 44 shows a side section view of an embodiment of a sleeve assembly;

[0056] Fig. 45 shows a side section view of the embodiment shown in Fig. 44 with an annular shoulder therein;

[0057] Fig. 46 shows a side section view of the embodiment shown in Fig. 45 with a fluid blocking device engaged with the annular shoulder;

[0058] Fig 47 shows a side section view of the embodiment shown in Fig. 46 with the engagement mechanism shifted axially;

[0059] Fig. 48 shows a simplified side section view of an embodiment of a tubing string with sleeve assemblies and an ATS and annular shoulder activated by a pressure code;

[0060] Fig. 49 shows a simplified side section view of the embodiment shown in Fig. 48 with a fluid blocking device displaced therein;

[0061] Fig. 50 shows a simplified side section view of the embodiment shown in Fig. 49 with an annular shoulder activated by the fluid blocking device travel;

[0062] Fig. 51 shows a simplified side section view of the embodiment shown in Fig. 50 with the fluid blocking device engaged with an annular shoulder;

[0063] Fig. 52 shows a simplified side section view of the embodiment shown in Fig. 51 with the apertures opened;

[0064] Fig. 53 shows a simplified side section view of the embodiment shown in Fig. 52 with a fluid blocking device within a third stage sleeve assembly;

[0065] Fig. 54 shows a simplified side section view of the embodiment shown in Fig. 53 with the apertures of the third stage sleeve assembly opened;

[0066] Fig. 55 shows a simplified side section view of an embodiment of a tubing string with sleeve assemblies therein;

[0067] Fig. 56 shows a simplified side section view of the embodiment shown in Fig. 55 with the ATS opened by a pressure code;

[0068] Fig. 57 shows a simplified side section view of the embodiment shown in Fig. 55 with fluid flowing through the ATS to the surrounding formation;

[0069] Fig. 58 shows a simplified side section view of the embodiment shown in Fig. 57 with an activation ball traveling therethrough to activate an annular shoulder;

[0070] Fig. 59 shows a simplified side section view of the embodiment shown in Fig. 58 with a bottom hole assembly therein;

[0071] Fig. 60 shows a simplified side section view of the embodiment shown in Fig. 59 with perforations in the tubing string and a fluid blocking device engaging a first stage sleeve assembly;

[0072] Fig. 61 shows a simplified side section view of the embodiment shown in Fig. 60 with an activation ball activating a second sleeve assembly;

[0073] Fig. 62 shows a simplified side section view of the embodiment shown in Fig. 61 with a fluid blocking device engaged with a second stage sleeve assembly and perforations in the tubing string;

[0074] Fig. 63 shows a simplified side section view of the embodiment shown in Fig. 62 with a fluid blocking device engaged with a third stage sleeve assembly and perforations in the tubing string;

[0075] Fig. 64 shows a simplified side section view of an embodiment of a tubing string with sleeve assemblies therein;

[0076] Fig. 65 shows a simplified side section view of the embodiment shown in Fig. 64 with a pressure code that activated an ATS and an annular shoulder;

[0077] Fig. 66 shows a simplified side section view of the embodiment shown in Fig. 65 with the ATS sending fluid into the surrounding formation;

[0078] Fig. 67 shows a simplified side section view of the embodiment shown in Fig. 66 with a BHA therein and an activated second stage sleeve assembly;

[0079] Fig. 68 shows a simplified side section view of the embodiment shown in Fig. 67 with a fluid blocking device release on the first stage sleeve assembly;

[0080] Fig. 69 shows a simplified side section view of the embodiment shown in Fig. 68 with a BHA and a second fluid blocking device therein;

[0081] Fig. 70 shows a simplified side section view of the embodiment shown in Fig. 69 with a second fluid blocking device released from a BHA and engaged with the second sleeve assembly;

[0082] Fig. 71 shows a simplified side section view of the embodiment shown in Fig. 70 with a fracking operation occurring in stage three perforations in the tubing string;

[0083] Fig. 72 shows a simplified side section view of the embodiment shown in Fig. 71 with a third fluid blocking device engaged with a third stage sleeve assembly and stage four fracking operations occurring;

[0084] Fig. 73 shows a simplified side section view of an embodiment of a tubing string with sleeve assemblies therein;

[0085] Fig. 74 shows a simplified side section view of the embodiment shown in Fig. 73 with an ATS activated by a pressure pulse code;

[0086] Fig. 75 shows a simplified side section view of the embodiment shown in Fig. 74 with fracking operations occurring through the ATS;

[0087] Fig. 76 shows a simplified side section view of the embodiment shown in Fig. 75 with a BHA displaced therein;

[0088] Fig. 77 shows a simplified side section view of the embodiment shown in Fig. 76 with an activated stage one sleeve assembly;

[0089] Fig. 78 shows a simplified side section view of the embodiment shown in Fig. 77 with a perforation operation occurring;

[0090] Fig. 79. shows a simplified side section view of the embodiment shown in Fig. 78 with the BHA removed;

[0091] Fig. 80 shows a simplified side section view of the embodiment shown in Fig. 79 with a fluid blocking device therein and fluid flowing through the stage two perforations;

[0092] Fig. 81 shows a simplified side section view of the embodiment shown in Fig. 80 with additional perforations therein;

[0093] Fig. 82 shows a simplified side section view of the embodiment shown in Fig. 81with a fluid blocking device engaged with a second stage sleeve assembly and fluid flowing through stage three perforations;

[0094] Fig. 83 shows a simplified side section view of the embodiment shown in Fig. 82 with a fluid blocking device engaged with a third stage sleeve assembly and fluid flowing through the fourth stage perforations;

[0095] Fig. 84 shows a simplified side section view of an embodiment of a tubing string with sleeve assemblies;

[0096] Fig. 85 shows a simplified side section view of the embodiment shown in Fig. 84 with the ATS activated by a pressure code;

[0097] Fig. 86 shows a simplified side section view of the embodiment shown in Fig. 85 with fluid flowing through the ATS;

[0098] Fig. 87 shows a simplified side section view of the embodiment shown in Fig. 86 with a BHA within the tubing string;

[0099] Fig. 88 shows a simplified side section view of the embodiment shown in Fig. 87 with an activated first stage sleeve assembly;

[0100] Fig. 89 shows a simplified side section view of the embodiment shown in Fig. 88 with a released fluid blocking device;

[0101] Fig. 90 shows a simplified side section view of the embodiment shown in Fig. 89 with various exemplary fluids displaced within the tubing string shown in detail;

[0102] Fig. 91 shows a simplified side section view of the embodiment shown in Fig. 90 with a fluid blocking device engaged with a stage one sleeve assembly and fluid flowing through stage two perforations;

[0103] Fig. 92 shows a simplified side section view of the embodiment shown in Fig. 91 with all sleeve assemblies engaged with fluid blocking devices;

[0104] Fig. 93 shows a simplified side section view of an embodiment of a tubing string with sleeve assemblies;

[0105] Fig. 94 shows a simplified side section view of the embodiment shown in Fig. 93 with an activated ATS and stage one sleeve assembly;

[0106] Fig. 95 shows a simplified side section view of the embodiment shown in Fig. 94 with fluid flowing through the ATS to the surrounding formation;

[0107] Fig. 96 shows a simplified side section view of the embodiment shown in Fig. 95 with a BHA within the tubing string;

[0108] Fig. 97 shows a simplified side section view of the embodiment shown in Fig. 96 with a fluid blocking device released and engaged with a stage one sleeve assembly;

[0109] Fig. 98 shows a simplified side section view of the embodiment shown in Fig. 97 with perforations formed in stage two;

[0110] Fig. 99 shows a simplified side section view of the embodiment shown in Fig. 98 with a BHA and fluid flowing through the stage two perforations;

[0111] Fig. 100 shows a simplified side section view of the embodiment shown in Fig. 99 with a fluid blocking device engaged with a stage two sleeve assembly;

[0112] Fig. 101 shows a simplified side section view of the embodiment shown in Fig. 100 with stage three perforations;

[0113] Fig. 102 shows a simplified side section view of the embodiment shown in Fig. 101 with a BHA within the tubing string;

[0114] Fig. 103 shows a simplified side section view of the embodiment shown in Fig. 102 with a fluid blocking device engaged with a stage three sleeve assembly;

[0115] Fig. 104 shows a side section view of the embodiment shown in Fig. 103 with fracking fluid flowing through the perforations;

[0116] Fig. 105 shows a simplified side section view of a portion of an embodiment of a sleeve assembly;

[0117] Fig. 106 shows a simplified side section view of a portion of the embodiment of the sleeve assembly of Fig. 105 with perforations therein;

[0118] Fig. 107 shows a side section view of an embodiment of a sleeve assembly;

[0119] Fig. 108 shows a side section view of the embodiment of the sleeve assembly of Fig. 107 with an annular shoulder formed;

[0120] Fig. 109 shows a side section view of the embodiment of the sleeve assembly shown in Fig. 108 with a fluid blocking device therein;

[0121] Fig. 110 shows a side section view of the embodiment of the sleeve assembly shown in Fig. 109 with open apertures;

[0122] Fig. I l l shows a side section view of the embodiment of the sleeve assembly shown in Fig. 110 with a catch device engaging with the fluid blocking device;

[0123] Fig. 112 shows a cross section view of the embodiment of the sleeve assembly shown in Fig. I l l;

[0124] Fig. 113 shows a side view of the embodiment of the sleeve assembly shown in Fig. 112;

[0125] Fig. 114 shows a side cross section view of an embodiment of a sleeve assembly;

[0126] Fig. 115 shows side perspective view of the internal components of an embodiment of an activation mechanism;

[0127] Fig. 116 shows a simplified side section perspective view of an embodiment of a tubing string and sleeve assemblies;

[0128] Fig. 117 shows a simplified side view of a portion of the embodiment shown in Fig. 116;

[0129] Fig. 118 shows a side section view of atoe port of the embodiment shown in Fig. 116;

[0130] Fig. 119 shows a side section view of a sleeve assembly of the embodiment shown in Fig. 116;

[0131] Fig. 120 shows a simplified side section perspective view of the embodiment shown in Fig. 116 with a pressure code sent through the tubing string;

[0132] Fig. 121 shows a simplified side section perspective view of the embodiment shown in Fig. 120 with the toe port activated;

[0133] Fig. 122 shows a side section view of the embodiment of the toe port shown in Fig. 121 with the activation mechanism in operation;

[0134] Fig. 123 shows a simplified side section perspective view of the embodiment shown in Fig. 121 with a fluid blocking device therein;

[0135] Fig. 124 shows a side section view of the embodiment of the sleeve assembly shown in Fig. 123 with a fluid blocking device therein;

[0136] Fig. 125 shows a side section view of the embodiment shown in Fig. 124 with the activation mechanism in operation;

[0137] Fig. 126 shows a side section view of the embodiment shown in Fig. 125 with the fluid blocking device engaged with an annular shoulder;

[0138] Fig. 127 shows a side section view of the embodiment shown in Fig. 126 with the apertures opened;

[0139] Fig. 128 shows a simplified side section perspective view of the embodiment shown in Fig. 124 with a subsequent fluid blocking device therein;

[0140] Fig. 129 shows a side section view of a sleeve assembly of the embodiment shown in Fig. 128 with a fluid blocking device therein;

[0141] Fig. 130 shows a side section view of the embodiment shown in Fig. 129 with the activation mechanism in operation;

[0142] Fig. 131A shows a side section view of an alternative embodiment to Fig. 130 where the fluid blocking device passes through the sleeve assembly;

[0143] Fig. 131B shows a side section view of the embodiment shown in Fig. 131A where the activation mechanism operates after the fluid blocking device passes;

[0144] Fig. 132 shows a side section view of the embodiment shown in Fig. 130 where the fluid blocking device engages an annular shoulder;

[0145] Fig. 133 shows a side section view of the embodiment shown in Fig. 132 where the apertures are opened;

[0146] Fig. 134 shows a side section view of the embodiment shown in Fig. 133 where the fluid flow is stopped;

[0147] Fig. 135 shows a side section view of the embodiment shown in Fig. 134 where the fluid flow is reversed;

[0148] Fig. 136 shows a simplified side section perspective view of an embodiment of a tubing string with sleeve assemblies therein;

[0149] Fig. 137 shows a side view of the embodiment shown in Fig. 136;

[0150] Fig. 138 shows a side section view of atoe port of the embodiment shown in Fig. 136;

[0151] Fig. 139 shows a side section view of a sleeve assembly of the embodiments shown in Fig. 136;

[0152] Fig. 140 shows a simplified side perspective section view of the embodiment shown in Fig. 136 with a pressure code applied;

[0153] Fig. 141 shows a side section view of atoe port of the embodiment shown in Fig. 140 with the activation mechanism in operation;

[0154] Fig. 142 shows a side section view of a sleeve assembly of the embodiment shown in Fig. 140 with the activation mechanism in operation;

[0155] Fig. 143 shows a side perspective section view of a sleeve assembly of the embodiment shown in Fig. 142 with a fluid blocking device therein;

[0156] Fig. 144 shows a simplified side perspective section view of the embodiment shown in Fig. 140 with a pressure code applied;

[0157] Fig. 145 shows a side section view of a sleeve assembly of the embodiment shown in Fig. 144;

[0158] Fig. 146 shows a side section view of the embodiment shown in Fig. 145 with the apertures opened;

[0159] Fig. 147 shows a side section view of the embodiment shown in Fig. 146 with fluid flow through the apertures;

[0160] Fig. 148 shows a side section view of a sleeve assembly of the embodiment shown in Fig. 144 with a fluid blocking device therein;

[0161] Fig. 149 shows a simplified side perspective section view of the embodiment shown in Fig. 144 with a pressure code applied;

[0162] Fig. 150 shows a side section view of a sleeve assembly of the embodiment shown in Fig.148 with the activation mechanism in operation;

[0163] Fig. 151 shows a side section view of the embodiment shown in Fig. 150 with the apertures open;

[0164] Fig. 152 shows a side section view of a sleeve assembly of the embodiment shown in Fig.149 with a fluid blocking device therein;

[0165] Fig. 153 shows a simplified side perspective section view of the embodiment shown in Fig. 149 with a pressure code applied;

[0166] Fig. 154 shows a side section view of an embodiment of a sleeve assembly of the embodiment shown in Fig. 153 with the activation mechanism in operation;

[0167] Fig. 155 shows a side section view of the embodiment shown in Fig. 154 with the apertures open;

[0168] Fig. 156 shows a side section view of the embodiment shown in Fig. 155 with fluid flow stopped;

[0169] Fig. 157 shows a side section view of the embodiment shown in Fig. 156 with fluid flow reversed;

[0170] Fig. 158 shows a simplified side section view of an embodiment of a setting tool;

[0171] Figs. 159 and 160 show side section views of portions of an embodiment of a sleeve assembly in combination with a setting tool;

[0172] Fig. 161 shows a front view of an embodiment of a setting tool;

[0173] Fig. 162 shows a side section view of a portion of an embodiment of a sleeve assembly in combination with a setting tool;

[0174] Fig. 163 shows a front view of the embodiment of the setting tool shown in Fig. 162;

[0175] Fig. 164 shows a side section view of a portion of an embodiment of a sleeve assembly in combination with a setting tool;

[0176] Fig. 165 shows a front view of the embodiment of the setting tool shown in Fig. 164;

[0177] Fig. 166 shows a side section view of a portion of an embodiment of a sleeve assembly activated by a setting tool;

[0178] Fig. 167 shows a front view of the embodiment of the setting tool shown in Fig. 166;

[0179] Fig. 168 shows a side section view of a portion of an embodiment of the setting tool releasing a fluid blocking device within a sleeve assembly;

[0180] Fig. 169 shows a front view of the embodiment of the setting tool shown in Fig. 168;

[0181] Fig. 170 shows a side section view of a portion of an embodiment of the setting tool releasing a fluid blocking device within a sleeve assembly;

[0182] Fig. 171 shows a front view of the embodiment of the setting tool shown in Fig. 170;

[0183] Fig. 172 shows a side section view of a portion of an embodiment of the sleeve assembly and the fluid blocking device;

[0184] Fig. 173 shows a side section view of a portion of an embodiment of the sleeve assembly engaging the fluid blocking device;

[0185] Fig. 174 shows a side section view of a portion of an embodiment of the sleeve assembly engaging the fluid blocking device and with an open aperture.

[0186] Fig. 175 shows a side section view of a conventional plug and perf wireline assembly;

[0187] Fig. 176 shows a side section view of a standard configuration of a gas activated bridge plug setting tool.

[0188] Figs. 177 and 178 show side section views of an embodiment of a sleeve assembly with electrodes;

[0189] Figs 179 and 180 show side section views of an embodiment of a sleeve assembly with rings;

[0190] Figs. 181 and 182 show side section views of an embodiment of a sleeve assembly with cantilever collets;

[0191] Figs. 183 and 184 show side section views of an embodiment of a sleeve assembly with collets; and

[0192] Figs. 185 and 186 show side section views of an embodiment of a sleeve assembly with an interference fit.SUMMARY

[0193] In an exemplary embodiment, there is a sleeve assembly for a wellbore. The sleeve assembly comprises: a tubular housing having one or more fluid ports into a formation; an actuatable inner sleeve within the tubular housing, the inner sleeve axially movable with respect to the tubular housing between a first position and a second position, wherein the tubular housing and the inner sleeve together define an axial flow passage through the sleeve assembly; an engagement mechanism for engaging a fluid blocking device, the engagement mechanism being activatable between: an inactive state; and an active state in which the engagement mechanismextends radially inward into the axial flow passage to form an annular shoulder, the annular shoulder being ductile and engageable with the fluid blocking device; in which axial movement of the inner sleeve from the first position to the second position activates the engagement mechanism from the inactive state to the active state; and in which the engagement mechanism is configured to open a fluid connection between the axial flow passage and the one or more fluid ports when the annular shoulder is engaged by the fluid blocking device.

[0194] In various embodiments, there may be included any one or more of the following features: an activation mechanism in a chamber between the tubular housing and the actuatable inner sleeve; the activation mechanism further comprises a sensor, an activator, and an expander; the sensor is a magnetic pickup or strain gauge; the activator is an ignitor; the expander is a gas generator; the actuatable inner sleeve is uphole relative to the engagement mechanism and in which movement of the inner sleeve into the second position pushes the engagement mechanism downhole into the active state; the actuatable inner sleeve is downhole relative to the engagement mechanism and in which movement of the inner sleeve into the second position pushes the engagement mechanism radially inward to form the annular shoulder; the actuatable inner sleeve and the engagement mechanism have interlocking elements which cooperate so that the actuatable inner sleeve and the inner sleeve move axially together after the engagement mechanism is moved into the active state; the annular shoulder formed in the active state of the engagement mechanism is cold-formed; the engagement mechanism is activated by a magnetic pick up; the sleeve assembly further comprises an impact device configured to impact with the fluid blocking device; the sensor is configured to sense the impact and the activation mechanism is configured to count the impact; an activation surface on the engagement mechanism; the activation surface is immediately downstream of a portion of the tubular housing having a larger internal diameter than an inner diameter of the activation surface thereby defining a locate cavity; the sleeve assembly in combination with a setting tool on a conveyance line, in which the setting tool is configured to move the engagement mechanism from the inactive state to the active state by engaging the activation surface; the setting tool further comprises a locating dog for seating in the locate cavity to move the engagement mechanism from the inactive state to the active state; the setting tool carries the fluid blocking device, and in which the fluid blocking device is a ball; the ball is made of a dissolvable material; the sleeve assembly further comprises a catch device configured to extend radially inward into the axial flow passage when the fluid connection is open between the axial flow passage and the one or more fluid ports.

[0195] In an exemplary embodiment, there is a dart for blocking fluid when engaged with an engagement mechanism. The dart comprises: an inner core; a ductile outer sleeve axiallymovable with respect to the inner core, the ductile outer sleeve being mounted externally to the inner core; a chamber formed between the inner core and ductile outer sleeve; an activation mechanism within the chamber, in which activation of the activation mechanism axially moves the ductile outer sleeve with respect to the ductile outer sleeve to expand radially outwardly.

[0196] In various embodiments, there may be included any one or more of the following features: the activation mechanism further comprises a sensor, an activator, and an expander; the sensor is a magnetic pickup or strain gauge; the activator is an ignitor; the expander is a gas generator; the ductile outer sleeve further comprises an inner wedge and the inner core further comprises an outer wedge, and in which the outer wedge and the inner wedge have cooperating sliding surfaces which allow the inner wedge to slide into an expanded radial outward position against the outer wedge; the ductile outer sleeve is made from a dissolvable material; the inner core is made from a dissolvable material; the dart is used in combination with a select fire perforating gun (“SFPG”) detachment mechanism; the SFPG detachment mechanism is shearable; the inner core comprises a flowback check valve; one or more of the inner core or the ductile outer sleeve includes a magnetic material.

[0197] In an exemplary embodiment, there is disclosed a dart for blocking fluid when engaged with an engagement mechanism. The dart comprises: a ductile outer sleeve; an inner core axially movable with respect to the ductile outer sleeve, which movement of the inner component within the ductile outer sleeve causes the ductile outer sleeve to expand radially outwardly; and a shearable detachment mechanism mounted to the ductile outer sleeve for receiving a setting tool.

[0198] In various embodiments, there may be included any one or more of the following features: the inner core is a ball; the inner core is a sleeve; the annular shoulder includes perforations permitting flow uphole when the annular shoulder is in contact with a fluid blocking element on a downstream end of the annular shoulder; the catch device includes openings to allow reverse flow when a fluid blocking device is contained within the catch device.

[0199] In an exemplary embodiment, there is a method of actuating a plurality of sleeve assemblies in a tubing string, each of the sleeve assemblies including a tubular housing having one or more fluid ports into a formation and an actuatable inner sleeve within the tubular housing, wherein the tubular housing and the inner sleeve together define an axial flow passage through the sleeve assembly. The method comprises: activating an activation mechanism to shift an engagement mechanism of one of the sleeve assemblies from an inactive state into an active state, in which in the active state the engagement mechanism extends radially inward into the axial flow passage to form an annular shoulder, the annular shoulder being ductile and engageable with a fluid blocking device; running the fluid blocking device into sealing contactwith the engagement mechanism; and opening the one or more fluid ports on the one of the sleeve assemblies by providing sufficient pressure to the fluid blocking device to shift the engagement mechanism into an open position.

[0200] In various embodiments, there may be included any one or more of the following features: activating the activation mechanism by using pressure pulses; the activation mechanism further comprises a sensor, an activator, and an expander, and in which the sensor is configured to detect the pressure pulses and cause the activator to expand the expander in response to the sensor detecting the pressure pulses; the activation mechanism is activated with a setting tool on a conveyance line; the setting tool is configured to move the engagement mechanism from the inactive state to the active state by engaging an activation surface on the engagement mechanism; the setting tool further comprises one or more shifting dogs for seating in a locate cavity defined by the activation surface to move the engagement mechanism from the inactive state to the active state; the setting tool carries the fluid blocking device, and in which the fluid blocking device is a ball; the ball is made of a dissolvable material; the fluid blocking device is released from the setting tool after the one or more shifting dogs moves the engagement mechanism into the active state.

[0201] In an exemplary embodiment, there is disclosed an activation mechanism in a sleeve assembly, the activation mechanism comprising a sensor, an activator, and an expander.

[0202] In various embodiments, there may be included any one or more of the following features: the sensor is a magnetic pickup or strain gauge; the activator is an ignitor; the expander is a gas generator; the impact device further comprises: a groove within an inner surface of the sleeve assembly, and a deformable material within the groove defining an annulus having an inner diameter smaller than an inner diameter of the inner surface; the groove is within an inner surface of the inner sleeve; the deformable material is rubber; the catch device has non-uniform inner diameter; the catch device further comprises a ball between an inner surface of the tubular housing and an outer surface of the engagement mechanism; the inner surface of the tubular housing has a smaller diameter in the direction that the engagement mechanism shifts when the annular shoulder is engaged by the fluid blocking device; a deformable wall within the engagement mechanism which is deformed by the ball when the annular shoulder is engaged by the fluid blocking device to reduce an inner diameter of an inner surface of the engagement mechanism; the sensor is an inductive sensor and the engagement mechanism is activated by detecting movement of the fluid blocking device in close proximity to the inductive sensor.

[0203] These and other aspects of the device and method are set out in the claims.DETAILED DESCRIPTION

[0204] Immaterial modifications may be made to the embodiments described here without departing from what is covered by the claims.DART CONFIGURATION

[0205] As is shown in Figs. 1, 2, 9, 10 and 20A & 20B, there is disclosed an embodiment of a dart 10 for blocking fluid when engaged with a dart engaging element 12 on a sleeve assembly. The dart engaging element may be any component that can engage the dart such as a shoulder or a recess. The dart 10 operates to block fluid through a flow passage when engaged with an engagement mechanism 110 on a sleeve assembly such as shown in Fig. 26. The sleeve assembly is described in more detail later. As shown in these 1, 2, 9, 10 and 20A & 20B, the dart engagement element 12 is a shoulder. The dart 10 may be made from a dissolvable material. The dart 10 may include an inner core 14. The inner core 14 may include an outer wedge 16. The outer wedge creates a variation of the outer diameter of the inner core across its body. Any shape may be used in place of the outer wedge so long as it increases the outer diameter of the inner core 14 along its length. The inner core 14 may be formed of a solid material. The shape and material of the inner core 14 may allow only minimal to no deflection or change in shape under load. The inner core 14 may be made of a dissolvable material.

[0206] The dart 10 may comprise a ductile outer sleeve 18. The ductile outer sleeve 18 may be externally mounted around the inner core 14. The ductile outer sleeve 18 may comprise a ductile material that causes the ductile outer sleeve 18 to expand radially as it shifts axially relative to the inner core. The ductile outer sleeve 18 may be made of a dissolvable material. The ductile outer sleeve 18 may be made of a thin wall that allows for expansion of the ductile outer sleeve 18. The thin wall, however, should have sufficient strength to engage with a dart engaging element 12 without failing.

[0207] The dissolvable material referred to herein for any of the components, including portions of the dissolvable dart or ball and / or the sleeve assembly, may be a high elongation dissolvable alloy, for example, TerveAlloy™ 3334. The density of TerveAlloy™ 3334 is 1.71 g / cmA3. The dissolution of TerveAlloy™ 3334 is ROD Max.: 85 and Rod min: 30. The mechanical data for a 5” x 1” plate with a 40: 1 extrusion ratio of TerveAlloy™ 3334 is as follows: ultimate tensile strength (ksi): 27, yield strength (ksi): 16.5, and elongation (%): 17.2. The alloy may also be a TerveAlloy™ 3143 HD, 3241, 1331, 1132, 1530, or 1131.

[0208] One or more of the inner core 14 or the ductile outer sleeve 18 may include a magnetic material.

[0209] The inner surface of the ductile outer sleeve may include an inner wedge 20. A wedge or any other shape may be used that reduces the inner diameter of the inner surface as the ductile outer sleeve 18 is traversed in an axial direction relative to the inner core. The inner wedge 20 may be configured to engage with the outer wedge 16 of the inner core 14. The outer wedge and the inner wedge may have cooperating sliding surfaces which allow the inner wedge to slide into an expanded radial outward position against the outer wedge. Various other shapes may be used so long as the outer diameter of the ductile outer surface is increased as the inner core and outer sleeve move with respect to each other as shown in Figs. 1 and 2. In some embodiments, only one of the inner wedge or outer wedges may be necessary to increase the outer diameter of the dart.

[0210] There may be a dart chamber 22 formed between the inner core 14 and ductile outer sleeve 18. The dart chamber 22 may include an activation mechanism 24 within the dart chamber 22. Activation of the activation mechanism 24 may axially move the ductile outer sleeve 18 with respect to the ductile outer sleeve 18 to expand radially outward and increase the outer diameter of the dart. The activation mechanism is described in more detail later in this patent document.

[0211] The dart chamber 22 is formed between the inner core 14 and the ductile outer sleeve 18. The ductile outer sleeve 18 may be axially movable with respect to the inner core 14. The inner core 14 may be axially movable with respect to the ductile outer sleeve 18, so that movement of the inner component within the ductile outer sleeve 18 causes the ductile outer sleeve 18 to expand radially outwards. The ductile outer sleeve 18 may be mounted externally to the inner core 14. The activation of the activation mechanism 24 axially moves the ductile outer sleeve 18 with respect to the inner core 14 to expand the ductile outer sleeve 18 radially outward. The ductile outer sleeve 18 may expand radially outwardly as a result of the inner wedge 20 engaging the outer wedge 16. The ductile outer sleeve 18 may be held in the expanded state by friction between the inner wedge 20 and the outer wedge 16 or by the expander 26 in the dart chamber 22. Other mechanisms may be used to ensure that the dart remains in any expanded state.

[0212] In the expanded state as shown in Fig. 2, the ductile outer sleeve 18 may be configured to engage with a dart engaging element 12. The dart engaging element 12 may be, for example, a shoulder of a sleeve within a tubing string 32. As shown in Fig. 8, the dart engaging element 12 may be a shoulder stop that performs isolation only. The dart engaging element 12 may be a sleeve that includes a shoulder and performs sealing or isolation and also includes openable apertures for fluid connection with the formation surrounding the tubing string 32. The dart engaging element 12 may be a cluster sleeve which performs isolation and includes openable apertures, and further can release the dart 10 by removing its shoulder. The dart engagingelement 12 may be part of a sleeve assembly 100. The dart engaging elements 12 may include magnetic pickups for producing a magnetic field. The ductile outer sleeve 18 may be configured to form a seal between the dart engaging element 12 and the dart 10. The tubing string 32 may be an integral well bore that is 100% pressure contained.

[0213] The dart 10 may include a flowthrough passage 34. The flowthrough passage 34 may provide a fluid connection from a first end to a second end of the dart 10. The inner core 14 may comprise a flow back check valve 36 and the flowthrough passage 34 may be blocked by the check valve 36. The check valve may be a wedge shape or any other shape that blocks fluid flow through the flowthrough passage. The dart 10 may include a retainer ring 38. The retainer ring 38 may be configured to retain the check valve 36 within the dart 10 when flow is reversed through the flowthrough passage 34.DART EXPANSION WITH SETTING TOOL CONFIGURATION

[0214] In an embodiment of a dart, as shown in Fig. 20A, 20B, and 21A-21C, the dart may be expanded by a setting tool 140. The dart 10 may be activated by a gas generator or a setting tool 140. Embodiments of the darts disclosed herein may be configured so that they can be set by either a gas generator or a setting tool depending on operator preference. The setting tool 140 may apply a load to the inner core 14 by a rod 142. The rod 142 may shift the inner core 14 axially with respect to the ductile outer sleeve 18. After the shift, the dart 10 will be in an expanded state as shown in Fig. 20B, 21B and 21C. The dart 10 expands as a result of the engagement between the outer wedge 16 and the inner wedge 20.

[0215] In an embodiment shown in Fig. 21C, the inner core 14 may comprise a ball or a sleeve. In this embodiment, the inner core 14 does not allow flow therethrough. The inner core 14 may function as the check valve 36, allowing flow through the dart 10 in an uphole direction but not in a downhole direction.DART DETACHMENT CONFIGURATION

[0216] In an embodiment, as shown in Figs. 9, 10 and 20 and 21A, 21B, and 21C, the dart 10 may comprise a detachment mechanism 40. The detachment mechanism 40 may be configured to release from a bottom hole assembly (“BHA”) 134 upon activation of the activation mechanism 24. The BHA 134 may comprise any device used in downhole operations, including, for example, the end of a wireline 46, a select fire perforating gun 52, or a setting tool 140.

[0217] The detachment mechanism 40 may include a release point 44. The release point 44 may be a weaker point that shears from the BHA 134. The shearing occurs as a result of the axialmovement of the inner core 14 with respect to the ductile outer sleeve 18. The movement may be caused by the activation of the activation mechanism 24. The movement may also be caused by the load applied through the rod 142 (Fig. 21 A). The expansion of the dart may be accomplished through the application of a force by the rod in the same operation that also will disconnect the setting tool from the dart. Both the activation and separation can thereby occur in one motion. The separation of the dart from the setting tool will occur after the dart is expanded. The ductile outer sleeve 18 may contact the BHA 134 and apply load to a surface of the BHA 134. As shown in Fig. 10, the inner core 14 extends away from and applies tension on the release point 44. The tension applied causes the release point 44 to shear and separate upon reaching a certain loading condition.DART OPERATION

[0218] As shown in Figs. 3-7, in an embodiment, the dart 10 may be displaced by a fluid in a tubing string 32 that contains one or more dart engaging elements 12. The dart engaging elements 12 may include a magnetic signal or field that can be sensed by sensors 30 of the activation mechanism 24.

[0219] The one or more sensors 30 of the activation mechanism 24 may sense magnetic fields or pressure changes as the dart 10 travels through the tubing string 32. Upon sensing a specified number or strength of magnetic fields or a certain pressure or pressure code, the activation mechanism 24 may trigger the expander 26. The sensor 30 may also be configured to sense a specific code, provided by a magnet or otherwise, that is specific to the activation mechanism 24 in order to trigger the expander 26.

[0220] The dart 10 may be pumped in the tubing string 32 and pass by a number of dart engaging elements 12 without expanding radially and without engaging the dart engaging elements 12. For example, the dart 10 may pass a second dart engaging element 12 without expanding. The sensor 30 may sense the magnetic fields of the dart engaging elements 12 or other magnetic elements in the sleeve near the dart engaging elements. If the activation mechanism 24 is programmed to trigger the expander 26 upon sensing two magnetic fields, the activation mechanism 24 would activate after passing the first and second dart engaging element 12, causing the dart 10 to expand radially. The activation mechanism 24 may be programmed to sense any number of magnetic fields. In this way, the dart acts as a smart dart and can activate and engage with a chosen dart engaging element.

[0221] When triggered, the expander 26 moves the inner core 14 with respect to the ductile outer sleeve 18. The inner core 14 may also be moved by the rod 142 and setting tool. The innerwedge 20 and outer wedge 16 engage, causing the ductile outer sleeve 18 to expand radially. The dart 10 may engage with a dart engaging element 12 in the expanded state. The dart 10 may engage with a shoulder that extends radially inward on the dart engaging element 12, shown Fig 11A. The dart 10 may also engage with a shoulder or recess that extends radially outward or inward on the dart engaging element 12, shown in Fig. 1 IB.

[0222] In a further embodiment, the sensor 30 senses a first magnetic field, triggering the activation mechanism 24. The activation mechanism 24 causes the ductile outer sleeve 18 to expand radially. In the expanded state, the ductile outer sleeve 18 may engage with the shoulder of a second dart engaging element 12. The engagement causes a seal that prevents fluid from flowing through the second dart engaging element 12. The seal causes the pressure to increase in the up-hole direction of the tubing string 32. The dart engaging element 12 may be a sleeve that opens to allow the fluid to enter the formation surrounding the tubing string 32.

[0223] The dart 10 may be pumped into the tubing string 32 with a displacement fluid. After sealing the dart engaging element 12 with the dart 10, a fracking operation may be performed in the formation surrounding the tubing string 32 in the desired zone.

[0224] A second dart 10 may be pumped into tubing string 32. The second dart 10 may be pumped into the tubing string 32 with any fluid generally used in the fracking industry. In an embodiment, the second dart 10 may be pumped into the tubing string 32 with a displacement fluid, followed by an acid, a pad, and then frac sand. The activation mechanism 24 may be triggered by dart engaging element 12 or another magnetic device (not shown). This causes the ductile outer sleeve 18 of the second dart 10 to expand radially for engagement with an additional dart engaging element 12. The dart 10 and additional dart engaging element 12 form a seal and a fracking operation occurs uphole of the seal. Any number of darts 10 and dart engaging elements 12 may be used. Each dart 10 may be configured to expand and engage with a specific dart engaging element 12.DART RELEASE MACHANISM OPERATION

[0225] As shown in Figs. 12-19 and 22-25, in an embodiment, the end of the tubing string 32 may be opened to the formation surrounding the tubing string 32 by an access toe sub 50. The access toe sub 50 may open by receiving a pressure code signal. The access toe sub 50 may be used to allow fluid to flow through the tubing string 32 or may be used to perform fracking operations by pumping acid, pad, and frac sand into the access toe sub 50.

[0226] In the embodiment, a dart 10 may be pumped down the tubing string 32 and connected to a BHA 134 on a wireline 46. The BHA 134 may include a select fire perforating gun (“SFPG”)52. The dart 10 travels past a dart engaging element 12 and activates as a result of sensing the magnetic field. There may be provided a time delay between triggering the activation mechanism 24 and sensing the magnetic field. The time delay provides time for the dart 10 to engage with a downhole dart engaging element 12. The time delay may be instituted using a processor in the activation mechanism. For example, the time delay could be 30 seconds. The activation mechanism 24 triggers the dart 10 to expand radially and connects with the downhole dart engaging element 12. The setting tool 140 may also be used to expand the dart 10.

[0227] The BHA 134 may separate from the dart 10 by the detachment mechanism 40. The detachment mechanism 40 may be shearable. The detachment mechanism 40 may be mounted to the ductile outer sleeve for receiving a setting tool 140. The expander 26 causes the inner core 14 to move axially with respect to the ductile outer sleeve 18. The movement causes loading on the release point 44 causing shearing at the release point 44. The rod 142 may also apply the loading to the release point 44. The dart 10 is then disconnected from the BHA 134 within the tubing string 32.

[0228] The wireline 46 may be pooled as required to position the BHA 134. Once in position, the SFPG 52 operates to perforate the wall of the tubing string 32 uphole of the downhole dart engaging element 12. Hydraulic fracturing may now be initiated using the perforations 128 in the tubing string 32.

[0229] A wireline 46 connected to a BHA 134 and an additional dart 10 may be pumped into the tubing string 32. The same process described above may occur. The dart 10 may activate to expand and engage with a dart engaging element 12. The dart 10 may release from the BHA 134. The SFPG 52 may then be positioned and perform a perforation operation. The formation surrounding the tubing string 32 may then be hydraulically fractured.

[0230] The dart 10 may be pumped into the well with a displacement fluid, or an acid, followed by a pad, and then a frac sand.

[0231] This provides the advantages of continuous pumping without the need to stop pumping operations between zones.ACTIVATION MECHANISM

[0232] The activation mechanism 24 described herein may be used in various different components of the system, including the dart 10 assembly and the sleeve assembly 100. An exemplary activation mechanism is shown in Fig. 115. Depending on the location and purpose ofthe activation mechanism, different components may be used. In general, the activation mechanism described herein comprises a sensor 30, which may include a magnetic pickup or pressure sensor or strain gauge or any combination of those, batteries, electronics, which may include a processor and a transient memory storage, and an expander 26, such as a gas generator. The activator may also include an ignitor. The activation mechanism 24 may be configured to trigger the expander 26 by igniting the ignitor. The activation mechanism 24 may sit in an annular space between nested inner and outer sleeves, which causes the two sleeves to shift relative to each other when the expander is activated. For example, the sleeve assembly 100 may comprise an activation mechanism 24 in a chamber between the tubular housing 104 and the actuatable inner sleeve 102. The sensor 30 may include an inductive sensor for sensing the ball itself. The ball may be made from nonferrous materials such as aluminum or magnesium alloys, which is the typical composition of dissolvable metallic balls.

[0233] The activation mechanism 24 may be able to detect pressure changes in the tubing string. Commercially available pressure transducers may be costly and there may be limited space to place them within the sleeve assembly 100 or dart 10. Instead, a strain gauge may be affixed to the outer diameter of the inner core 14 or actuatable inner sleeve 102. Other locations on the sleeve assembly 100 that allow the strain gauge to sense distortion within the tubing string may be used. Pressure changes in the well may distort these components which in turn distorts the strain gauge. Measuring a voltage change across the strain gauge gives an indication of pressure change. A commercial strain gauge from Micro Flextronics (FBR3-1000P-PC11) may be used, but other commercially available options are also contemplated. Adhering the stain gauge to the inner core 14 or actuatable inner sleeve 102 assists with keeping the strain gauge securely fixed for an extended period of time (e.g. up to a year) at elevated temperature (e.g. up to 150°C). This is currently done with an adhesive, although an alternative like a strain gauge that is pre-mounted on a metal backing that can be spot welded is also contemplated.

[0234] As discussed above, the activation mechanism 24 may comprise an ignitor and an activator. The ignition or expansion chemicals may be BKNO3 with a binder. BKNO3 may be stable at temperatures of 150°C for years.

[0235] In other devices, known ignition materials are used to actuate downhole tools in a well only a short time (e.g. several hours) after the tool has been introduced into the well. In contrast, the BKNO3 used herein may be in the well for several months or even up to a year or more before being activated (ignited). BKNO3 remains stable at the elevated temperatures encountered in certain wells (in excess of 150°C). Typical manufacturers of BKNO3 list its lifespan in hoursat 150°C. Investigations have been performed to determine how the product degrades over extended periods (e.g. weeks or months) at elevated temperatures.

[0236] Commercially available known igniters may cause issues when used with BKNO3. The limited space within the sleeve assembly 100 or dart 10 may be too small for commercially available ignitors. Other commercial igniters used in the demolition and pyrotechnics industries that would fit the limited space began to fail if stored at high temperature for an extended period of time (e.g. more than a week). The energetic material used, or the protective coating, would crack and flake off. To resolve the issue, an embodiment herein uses ignitors using a bridge wire and BKNO3. An embodiment herein may also use a commercially available igniter with an additional coating that resists high temperatures to keep the original materials in place.

[0237] A commercially available ignitor, for example, an MJG™ ignitor, may be used so long as it is compatible with high temperature use. The ignitor may use a battery as a power source. The ignitor may use a finer wire with a shorter length, and a capacitor bank. The ignitor may be operable at 100°C, 125 °C, and 150°C. The ignitor may be modified to be operable at special high temperature conditions.

[0238] Pellets may be formed into a shape to provide a structural element to the ignition chemicals. The pellets may be aligned with the rest of the ignition materials to ensure proper ignition. The raw materials may be combined in a slurry with acetone. The ignition chemicals may be ignited by using an electronic match. Long battery life is important in order to allow the activation mechanism to be useful for a long period of time. The expander 26 may operate by producing gas in response to a signal from the activation mechanism 24. The increase in pressure caused by the gas generator can move the nested inner and outer sleeves relative to each other. The electronics in the activation mechanism may be idle and use very little power when the activation mechanism has not yet been activated. This will allow for longer battery life. The strain gauge may be used as a replacement for a pressure transducer to detect signals in the wellbore. The strain gauge may be used to detect deformations in the wellbore housing.

[0239] A number of batteries may be used, for example, the Tadiran TLH-245 which is rated for 125°C, and Engineered Power LAAA-HT which is rated for 150°C. Other batteries could be used so as long as they fit the space requirements and energy density required. The activation mechanism 24 is designed to remain mostly asleep, using almost no power, waking up periodically to take a pressure measurement and then decide based on that measurement and previous ones whether anything needs to be done. The use of a hibernation or sleep mode will increase battery life.

[0240] The sleeve chamber 106, such as shown in the embodiments shown in Figs. 26 and 107 may include the activation mechanism 24 as described above. The activation mechanism 24 may comprise a magnetic pickup or strain gauge, batteries, electronics, one or more sensors 30, and an expander 26, such as a gas generator. The expander 26 may be configured to shift or move the inner sleeve 102 axially. The expander 26 may operate by producing gas in response to a signal from the activation mechanism 24. The gas may expand in the sleeve chamber 106 and apply load against a seal or edge 28, actuating the inner sleeve 102 from the first position to the second position.

[0241] The sensors 30 may be any sensors that are configured to sense an occurrence. For example, the sensors 30 may be pressure sensors, inductive sensors or sensors that sense a magnetic field. The sensors 30 may be used to count a number of magnetic objects passing the sensors 30. The sensors 30 may be one or more strain gauges. The sensors 30 may be configured to detect pressure changes in the tubing string 32. The sensors may be any of the various sensors described herein.SLEEVE CONFIGURATION

[0242] As shown Figs 26-29, 31-38, 39-42, 44-47, 107-111, 113 and 114 there is disclosed a sleeve assembly 100 for a tubing string 32 or a wellbore. The sleeve assembly 100 may comprise a tubular housing 104. The sleeve assembly 100 may have an outer diameter that is 5.75” or other appropriate diameter to hold the components and provide adequate flow and deformation clearance. A diameter of 5.75” may allow for a 0.375” diametrical clearance for cementing. The sleeve assembly 100 geometry or dimensions may be the same for 3 casing weights and materials (L80 and Pl 10). A material stock of 5.75” x 3.75” may be used. Other sizes and geometries may be used.

[0243] The sleeve assembly 100 may further comprise an actuatable inner sleeve 102 within the tubular housing 104 as shown in Fig. 107, wherein the tubular housing 104 and the inner sleeve 102 together define an axial flow passage through the sleeve assembly 100. The inner sleeve 102 may be axially movable with respect to the tubular housing 104 between a first position and a second position.

[0244] As shown in Fig. 107, a sleeve chamber 106 may be included between the inner sleeve 102 and the tubular housing 104. The sleeve chamber 106 may house the activation mechanism 24. The activation of the activation mechanism 24 actuates the inner sleeve 102 from the first position to the second position.

[0245] As shown in Figs. 107-110, an impact device 200 may be included in the sleeve assembly 100. The impact device 200 may be configured to impact with the fluid blocking device 114. The pressure changes caused by the movement of the fluid blocking device across the impact device may be used to establish a count of the number of fluid blocking devices that have passed that location. The impact device 200 may further comprise a groove within an inner surface of the sleeve assembly 100, and a deformable material within the groove defining an annulus having an inner diameter smaller than an inner diameter of the inner surface. The groove may be within an inner surface of the inner sleeve 102 as shown in Fig. 107. The deformable material may be rubber. The impact device 200 may be a component capable of receiving impacts from the fluid blocking device 114 as it passes through the sleeve assembly. The fluid blocking device 114 impacts the impact device 200 as the fluid blocking device 114 travels through the sleeve assembly 100. The impact device 200 is configured to impact the fluid blocking device 114 but not to capture the fluid blocking device 114 or fully stop the travel of the fluid blocking device 114. The impact device 200 may be made of rubber or other deformable and resilient material which sits within a recess or groove within the inner sleeve 102. For example, the impact device 200 may be a rubber gasket. The rubber gasket or insert may be any size so long as it does not fully stop the fluid blocking device. The gasket may be a size 1502 insert between the inner diameters of the two tubulars. The impact device 200 may be made of a rubber or a plastic or other resilient material. In another embodiment, the elastomer in the impact device may be a similar type of elastomer as used in a hammer union in a fracturing iron. The impact device may also or alternatively detect impacts using a switch. The inner diameter defined by the deformable material is smaller than the inner diameter of the sleeve within which the recess sits. This difference in diameters causes the fluid blocking device 114 to create a variation in pressure within the wellbore when the fluid blocking device 114 passed through the impact device 200. Other mechanisms may be used to detect movement of the fluid blocking device through the sleeve assemblies, as described in Figs. 177-186.

[0246] As shown in Fig. 107-110, the impact device 200 sits within the inner sleeve 102. The impact device 200 may be connected by any other method that allows the impact device 200 to transfer the impact to the inner sleeve 102, allowing the sensor 30 to sense or count the impact. The sensor 30 may be configured to sense the impact and the activation mechanism 24 is configured to count the impact. The sensor 30 may be an inductive sensor and the engagement mechanism 110 is activated by detecting movement of the fluid blocking device 114 in close proximity to the inductive sensor. The sensors 30 may also be configured to sense a pressure pulse increase created as a result of the fluid blocking device 114 moved across and contactingthe impact device 200. The pressure pulse may be any increase that can be sensed, for example, 1 or 2 MPA.

[0247] The activation mechanism 24 (Fig. 115) may be configured to trigger the expander 26 upon the detection of a signal to activate, after which the engagement mechanism will move into the active position as shown in Fig. 108. An activation signal may be provided in various ways, including by detecting magnetic devices that pass the magnetic sensor, by sending pressure pulses or by counting the number of impacts at the impact device. These signals may be sensed by the sensor 30.

[0248] The activation signal may be provided by increasing wellbore pressure above standard wellbore pressure in a pattern which will be recognized by the sensor. The pressure code can be provided to activate the activation mechanism at a pressure between wellbore pressure and the pressure at which the fluid blocking device 114 and engagement mechanism 110 shift to open the apertures, which, for example, could be 21 MPA over well bore pressure. For example, if the normal wellbore pressure is 10 MPA, then any pressure between 10 MPA and 31 MPA may be used to activate the activation mechanism. Other variations from wellbore pressure can be used and other activating pressure can be used depending, for example, on the wellbore pressure for a particular application. The activation mechanism 24 may be configured to trigger the expander 26 on sensing a specific code provided by any suitable increase or pattern of increases in wellbore pressure. The activation mechanism 24 within the sleeve chamber 106 has the same characteristics and operation as the activation mechanism within the dart 10, described above. The activation mechanism 24 may be configured to activate the expander 26 immediately or after a time delay. The engagement mechanism 110 may be activated by magnetic pick up.

[0249] The sleeve assembly 100 may further comprise an engagement mechanism 110 for engaging a fluid blocking device 114. The engagement mechanism 110 may be activatable between an inactive state and an active state. Axial movement of the inner sleeve 102 from the first position to the second position may activate the engagement mechanism 110 from the inactive state (as shown in Fig. 107) to the active state (as shown in Fig. 108). The actuatable inner sleeve 102 may be uphole relative to the engagement mechanism 110 and movement of the inner sleeve 102 into the second position pushes the engagement mechanism 110 downhole into the active state as shown in Fig. 108. The actuatable inner sleeve 102 may also be downhole relative to the engagement mechanism 110 (as shown in Fig. 36) and movement of the inner sleeve 102 into the second position pushes the engagement mechanism 110 radially inward to form the annular shoulder 116.

[0250] In the active stage, the engagement mechanism 110 is in position to engage the fluid blocking device 114 which will allow the sleeve to shift when sufficient pressure is applied. When sufficient pressure is applied, the sleeve shifts, revealing the apertures 124 as shown in Fig. 110.

[0251] In the inactive state as shown in Figs. 26, 31, 35, 39, 44, 107, 131A and 13 IB the engagement mechanism 110 is not in a position to engage with the fluid blocking device 114, and the fluid blocking device 114 may travel through the tubular housing 104 unobstructed by the engagement mechanism 110. This allows the fluid blocking device to pass unobstructed through sleeve assemblies in sections of the wellbore that remain closed to the formation and in which the corresponding engagement mechanisms remain in the inactive state.

[0252] In the active state as shown in Figs. 27-29, 32-34, 36-38, 40-42, 45-47, 108, 109 the engagement mechanism 110 may extend radially inward into the axial flow passage to form an annular shoulder 116. The annular shoulder 116 is ductile and may be configured to receive the fluid blocking device 114 and form a seal therebetween as shown in Fig. 110. The annular shoulder 116 may cold form a shoulder, meaning that no heat is involved in the deformation of the shoulder. The annular shoulder 116 may have an inner diameter of 3.25” or any other diameter or shape that allows an adequate seal to form when engaged with the fluid blocking device 114. The annular shoulder 116 may be steel.

[0253] The annular shoulder 116 of the engagement mechanism 110 may be formed by various methods. The annular shoulder may be a ductile material. The annular shoulder 116 may be formed as a result of axial movement of the inner sleeve 102. Axial movement of the inner sleeve 102 from the first position to the second position activates the engagement mechanism 110 from the inactive state to the active state. The axial movement of the inner sleeve 102 may apply axial load to the engagement mechanism 110. The inner sleeve 102 may comprise a contact surface 118 (as shown in Figs. 35 and 107) that contacts the engagement mechanism 110. The contact surface 118 may be tapered as shown in Fig. 35. The axial load applied between the contact surface 118 and the engagement mechanism 110 may translate into inward radial movement of the engagement mechanism 110 to form the annular shoulder 116 as shown in Fig. 36. As discussed above, the annular shoulder 116 formed in the active state of the engagement mechanism 110 may be cold formed.

[0254] In an embodiment, the contact surface 118 may be flat as shown in Fig. 107. In this embodiment, the annular shoulder 116 is formed by an annular wedge ring 120 with an inward radial edge in the tubular housing 104 as shown in Figs. 26, 27 and 108. In this embodiment, thecontact surface 118 pushes the engagement mechanism 110 into position so that it can engage with the fluid blocking device to shift into position for hydraulic fracturing.

[0255] The engagement mechanism 110 is configured to open a fluid connection between the axial flow passage and the one or more fluid ports when the annular shoulder 116 is engaged by the fluid blocking device 114.

[0256] As shown in Fig. 109, when the fluid blocking device 114 engages the annular shoulder 116 it creates a seal which blocks the flow through the tubing string. The sleeve assembly can then be opened to the formation by increasing the pressure in the tubing string to shift the sleeve to uncover the apertures 124. As shown in Fig. 110, the movement of the engagement mechanism 110 axially downhole also pushes an annular wedge ring 120 with an inward radial edge until it engages a smaller inner diameter portion of the tubular, for example, adjacent to the threading on the downhole end of the sleeve assembly. The inward radial edge provides a rigid support against which the annular shoulder 116 engages. The annular wedge ring 120 provides structural support which allows for a strong seal between the fluid blocking device and the inner diameter of the engagement mechanism 110. The annular wedge ring 120 may be held in place initially by a shear device 126 (as shown in Figs. 107 and 108) before it is shifted into the engaged position.

[0257] In the active state, the engagement mechanism 110 and the inner sleeve 102 may be further configured to be rigidly connected together by interlocking elements 122 as shown in Fig. 36. In this embodiment, each of the actuatable inner sleeve 102 and the engagement mechanism 110 have interlocking elements 122 which cooperate so that the actuatable inner sleeve 102 and the engagement mechanism 110 move axially together after the engagement mechanism 110 is moved into the active state. The interlocking elements 122 may be a latch-type connection. When connected, the engagement mechanism 110 and the inner sleeve 102 may be configured to form a singular component. In an embodiment, the interlocking elements 122 may not be included and the engagement mechanism 110 and inner sleeve 102 may remain separable after contact. In the embodiment shown in Fig. 110, the inner sleeve 102 and the engagement mechanism 110 are separate components that are not interlocked. Movement of the inner sleeve through activation of the activation mechanism moves the engagement mechanism into position for engagement with the fluid blocking device.

[0258] The tubular housing 104 comprises one or more apertures 124 (Figs. 29, 35-38, and 110- 114, 127), also described as frac ports or fluid ports, into a formation which form a fluid connection between the interior and the exterior of the tubular housing 104. There may be one or more apertures 124, for example, eight apertures may be used. The apertures 124 may provide 14inA2 flow area. This matches 11.6 ppf casing nominal flow area even with a plugged aperture and seven apertures open. The apertures 124 are initially covered, and the fluid connection closed by the inner sleeve 102 or the engagement mechanism 110. The apertures 124 may be uncovered, and the fluid connection opened by axial movement of the engagement mechanism 110 or inner sleeve 102. When the apertures are open, there is provided a fluid connection between the inside of the tubing string 32 and the formation surrounding the tubing string 32 to allow for hydraulic fracturing.

[0259] The engagement mechanism 110 and the inner sleeve 102 may be shifted axially by engagement with the fluid blocking device 114. For example, the fluid blocking device 114 may be a dart or a ball or other device which can engage and seal with the engagement mechanism 110 when the engagement mechanism 110 is in an active state.

[0260] As shown, for example, in Figs. 36 and 107, a shear device 126 may be disposed between the engagement mechanism 110 or the inner sleeve 102 and the tubular housing 104. The shear device may be a shear pin or snap ring or another similar device. The shear device 126 may be configured to shear upon reaching a specified loading condition. The shear device maintains the inner sleeve or engagement mechanism or both in position in an inactive state within the tubular housing 104 before it is moved to an active state. Shear devices are used to ensure that activatable sleeves and other components are not accidentally activated.

[0261] As shown, for example, in Fig. 43, the fluid blocking device 114 may be a dart 10. The fluid blocking device 114 may also be a plug, a dart commonly known in industry, a dissolvable dart, isolation ball, or large dissolvable ball, or a ball, or other method of blocking fluid. A ball may have an outer diameter of 3.5” or other diameter or shape that allows for an adequate seal with the annular shoulder 116. In an embodiment, the fluid blocking device 114 may be made of a dissolvable material. The dissolvable material may be, for example, TerveAlloy™ 3334 in the embodiment shown in Fig. 43 or, for example, TerveAlloy™ Tax-IOOE, a high strength dissolvable magnesium, or other alloy in the embodiments that include a dissolvable ball. The fluid blocking device 114 may be configured to allow flow in a first direction, but not in a second direction. The fluid blocking device 114 may comprise a check valve 36 or ball cage that allows flow in the first direction but prevents flow in the second direction.

[0262] The fluid blocking device 114 may be configured to be releasable from the annular shoulder 116 in a first fluid flow direction, but not in a second fluid flow direction.

[0263] As shown in Fig. 106, the annular shoulder 116 may include perforations 150 that allow fluid to flow uphole when in contact with a fluid blocking device 114 that is downstream from the annular shoulder 116 as shown in Fig. 106. This design allows for flowback where the ballfrom a lower sleeve does not seat in the upper sleeve in the well during reverse flow. The perforations 150 may be positioned so that they do not prevent sealing of the fluid blocking device 114 against the sleeve when the fluid blocking device 114 is seated on the annular shoulder 116 as shown in Fig. 105. This may be accomplished, for example, by placing the perforations at the downstream end of the annular shoulder 116 below the contact point where the fluid blocking device seals against the annular shoulder 116. This may provide cost advantages. In this way, the annular shoulder 116 immediately uphole of a fluid blocking device may function as a cage for that fluid blocking device 114 during uphole flow. The fluid blocking device 114 may be a dissolvable ball. A dissolvable ball may provide cost savings over a dart.

[0264] The sleeve assembly 100 may allow flow in the reverse direction as a result of the fluid blocking device 114 releasing from the annular shoulder 116 during uphole flow. An exemplary embodiment of this is shown in Fig. 135. To prevent the fluid blocking device 114 from traveling a distance uphole in the tubing string 32, a catch device 210 may be used. As shown in Fig. 110 and 174, the catch device 210 in the sleeve assembly is configured to extend radially inward into the axial flow passage when the fluid connection is open between the axial flow passage and the one or more fluid ports. The catch device 210 may include openings to allow reverse flow when a fluid blocking device 114 is contained within the catch device 210. The catch device 210 may have non-uniform inner diameter. The catch device 210 may further comprise a ball between an inner surface of the tubular housing 104 and an outer surface of the engagement mechanism 110. The inner surface of the tubular housing 104 may have a smaller diameter in the direction that the engagement mechanism 110 shifts when the annular shoulder 116 is engaged by the fluid blocking device 114. The sleeve assembly 100 may further comprise a deformable wall within the engagement mechanism 110 which is deformed by the ball when the annular shoulder 116 is engaged by the fluid blocking device 114 to reduce an inner diameter of an inner surface of the engagement mechanism 110. The catch device 210 may be a component that reduces a portion of the diameter of the bore of the sleeve assembly 100 uphole of the annular shoulder 116 after the engagement mechanism 110 is shifted into an active position. In an embodiment, the catch device 210 may be a ball, pin, or other equivalent component that is contained between the tubular housing 104 and the engagement mechanism 110. The catch device 210 may be configured to move with the engagement mechanism 110. For example, the catch device 210 may be held in a pocket or groove formed on the outer diameter the engagement mechanism 110. A wall of the groove or pocket of the engagement mechanism 110 that contacts the catch device 210 may be deformable. The bottom of the groove or pocketmay be open to the bore of the sleeve assembly 100. This deformable wall or opening allows the catch device 210 to shift radially inward with respect to the engagement mechanism 110.

[0265] As shown in Fig. 107 and 174, the tubular housing 104 may include a larger diameter portion and a smaller diameter portion with a taper between where the catch device moves as the engagement mechanism is shifted from the inactive to active position. The inner diameter of the housing narrows as the catch device moves with the engagement mechanism as the engagement mechanism moves into the active position. The catch device 210 initially is held against the larger diameter portion by the engagement mechanism 110. When the fluid blocking device 114 is seated against the annular shoulder 116 and the engagement mechanism 110 shifts axially to expose the apertures 124, the catch device 210 also shifts into a portion of the tubular housing 104 with a smaller inner diameter. This movement causes the catching device 210 to deform a portion of the engagement mechanism thereby reducing the inner bore diameter of a portion of the sleeve assembly 100, which extends radially inward into the axial flow passage. The catch device may plastically deform the inner diameter of the engagement mechanism 110 as shown in Fig. 112. As a result of the narrower bore diameter, the fluid blocking device 114 is held from flowing uphole by the catch device 210.

[0266] One or more catch devices 210 may be used within a sleeve assembly 100. The catch devices act as a cage to allow flowback from the well area.

[0267] There may be openings 205 (Fig. 112) or dimples between the fluid blocking device 114 and the engagement mechanism when the fluid blocking device is held in place by the catch device 210 as shown in Fig. 112. Any number of openings may be used that allow adequate flow. For example, three openings may be provided. These openings may be the equivalent of a 1.25” bore hole diameter. Other sizes are also possible, such as 1 / 2" or larger. These openings allow for flowback of fluid within the tubing string while the ball remains within the sleeve assembly 110 as shown in Fig. 157. Other sizes and shapes or openings or protrusions may be used so long as flowback of fluid is facilitated around the ball while it remains in the cage defined by the catch device in the sleeve assembly.

[0268] In order to hold the engagement mechanism 110 and apertures 124 open when the flow travels uphole, the sleeve assembly 100 may comprise a lock device 220 as shown for example in Fig. 110. The lock device 220 may be a device that holds the engagement mechanism 110 in an axial shifted position where the apertures 124 of the sleeve assembly 100 are open to the bore. The lock device may be for example a spring pin or a retaining pin. In operation, the lock device 220 may be held within the tubing housing and biased against an outer diameter of the engagement mechanism 110. When the engagement mechanism 110 shifts to open the apertures124, the lock device 220 may lock into a groove within the outer diameter of the engagement mechanism 110. Upon locking into the groove, the engagement mechanism 110 is held from shifting axially.

[0269] The fluid blocking device 114 may include a magnetic particle or magnetic pickup that produces a magnetic field. The fluid blocking device 114 may also provide a code, by magnet or other known method to the sensor 30. The sensor 30 may be configured to recognize an individual code. The sensors 30 may be configured to sense the magnetic particles of the dart. The activation mechanism may also be configured to count the number of magnetic fluid blocking devices that move past each sleeve assembly.SENSOR DETECTION METHODS

[0270] As shown in Figs. 177-186, various embodiments of sensors 30 are shown which may be used in any of the embodiments having sensors herein. These embodiments may provide an advantage of allowing continuous pumping operations.

[0271] The sensors may detect conductivity. As shown in Figs. 177-178, an embodiment of a sleeve assembly 100 and sensor 30 is shown. In this embodiment, the sensor may comprise one or more electrodes that measure the conductivity of the wellbore or treatment fluid. The electrodes are placed so that the ends of the electrodes are in contact with the ball or other fluid blocking element as it passes through the wellbore. The electrodes are connected to electronics that sense the reduction in electrical resistance when the ball or other fluid blocking element, which is highly conductive compared with the various fluids in the wellbore environment, becomes part of the electrical circuit.

[0272] The sensors may detect magnetic flux strength (field density). The sensor 30 may comprise one or more magnetic sensors such as a hall effect sensor or magnetometer. The fluid blocking devices 114 which may be dissolvable or made from other materials, and may comprise frac balls, present a magnetic signature with sufficient strength that the amplitude can be detected by the magnetic sensor(s) when passing through. The magnetic signature may be provided by embedded magnets in the ball, or the ball is of a magnetic material (mixture or alloy).

[0273] The sensor may detect magnetic flux direction. The sensor 30 may comprise one or more magnetic sensors such as a hall effect sensor or magnetometer. The fluid blocking device 114 may comprise frac balls, which are dissolvable or other material, that present a magnetic signature with sufficient strength that the change in direction of the field lines can be detected bythe magnetic sensor(s) when passing through. The magnetic signature is provided by embedded magnets in the ball, or the ball is of a magnetic material (mixture or alloy).

[0274] The sensors may provide inductive sensing. The sensor 30 may comprise one or more inductive sensors. The inductive sensor is based on an oscillation circuit in which energy loss caused by the induction current flowing in the target affects the change of the oscillation frequency. When a nonferrous-metal target such as a magnesium-based or aluminum-based dissolvable ball, or other type of fluid blocking device, passes by the inductive sensor, the oscillation frequency increases.

[0275] As shown in Figs. 179-186, there may be embodiments of a contact type sensing, where the fluid blocking device 114 comes in physical contact with an inner sleeve 102 of the sleeve assembly 100 and imparts a force or multiple, sequential forces to the inner sleeve 102 and thereby the activation mechanism 24 and sensor 30. Several force input methods and force detection methods are discussed.

[0276] As shown in Figs. 179-180, the impact device 200 may comprise one or more elastomeric rings that are bonded or affixed to an inner sleeve 102 such that the inner diameter (ID) of the ring is less than the outer diameter (OD) of the fluid blocking device 114, such as a frac ball, that is pumped through. The interference of the fluid blocking device 114 and the ring causes a force to be imparted on the inner sleeve 102. The amplitude of the force is proportional to the degree of interference. The force can cause strain in the inner sleeve 102 or a displacement or impact, depending on the retention method used, which is sensed by the sensor 30.

[0277] As shown in Figs. 179-180, the impact device 200 may comprise one or more polymer rings are bonded or affixed to an inner sleeve 102 such that the ID of the ring is less than the OD of the fluid blocking device 114, such as a frac ball, that is pumped through. The interference of the fluid blocking device 114 and the ring causes a force to be imparted on the inner sleeve 102. The amplitude of the force is proportional to the degree of interference. The force can cause strain in the inner sleeve 102 or a displacement or impact, depending on the retention method used, which is sensed by the sensor 30.

[0278] As shown in Figs. 181-182, the impact device 200 may comprise one or more cantilever collets that are attached to or are incorporated into the inner sleeve 102 such that the ID of the extremity of the collet fingers is less than the OD of the fluid blocking device 114 that is pumped through. The interference of the fluid blocking device 114, such as a frac ball, and the collet fingers causes a force to be imparted on the inner sleeve 102. The amplitude of the force is proportional to the degree of interference. The force can cause strain in the inner sleeve 102 or a displacement or impact, depending on the retention method used, which is sensed by the sensor30. The collet could have a filler material behind the collet to prevent cement or wellbore debris from contaminating the volume behind the flexible fingers and reducing their effectiveness.

[0279] As shown in Figs. 183-184, the impact device 200 may comprise one or more collets that are attached to or are incorporated into the to an inner sleeve 102 such that the ID of the rib at or near the mid-section of the collet fingers is less than the OD of the fluid blocking device 114, such as a frac ball, that is pumped through. The interference of the fluid blocking device 114 and the collet fingers causes a force to be imparted on the inner sleeve 102. The amplitude of the force is proportional to the degree of interference. The force can cause strain in the inner sleeve or a displacement or impact, depending on the retention method used, which is sensed by the sensor 30. The collet could have a filler material behind the collet to prevent cement or wellbore debris from contaminating the volume behind the flexible fingers and reducing their effectiveness.

[0280] As shown in Figs. 185-186, the impact device 200 may be one or more areas of an inner sleeve 102 that have IDs which are less than the OD of the fluid blocking device 114 that is pumped through. The interference of the fluid blocking device and the reduced ID areas or ribs causes a force to be imparted on the inner sleeve 102. The amplitude of the force is proportional to the degree of interference. The force can cause strain in the inner sleeve or a displacement or impact, depending on the retention method used, which is sensed by the sensor 30.

[0281] The sensor 30 may sense these forces or impacts in various ways. The sensor 30 may be one or more strain gauges can be used to measure the strain resulting from the force or sequence of forces imparted on the inner sleeve 102 by the interaction with the fluid blocking device 114.

[0282] The sensor 30 may be one or more accelerometers can be used to measure the impact or sequence of impacts resulting from the force or sequence of forces imparted on the inner sleeve 102 by the interaction with the fluid blocking device 114. The inner sleeve 102 would be retained such that a resilient member 340 such as a spring or flexible feature would hold the inner sleeve 102 in the uphole position. The force of the interaction with the fluid blocking device 114 would overcome the resilient member 340 causing the inner sleeve 102 to impact a hard-stop at the end of the stroke allowed by the resilient member 340. The impact would result in a large deceleration that would be measured by the accelerometer.

[0283] The sensor 30 may be one or more switches can be used to measure the displacement or sequence of displacements resulting from the force or sequence of forces imparted on the inner sleeve 102 by the interaction with the fluid blocking device 114. The inner sleeve 102 would be retained such that a resilient member 340 such as a spring or flexible feature would hold the inner sleeve 102 in the uphole position. The force of the interaction with the fluid blockingdevice 114 would overcome the resilient member 340 causing the inner sleeve 102 to move in the downhole direction to a hard-stop at the end of the stroke allowed by the resilient member 340. The displacement would be sufficient to activate a switch. The change of state of the switch would be measured by the electronic circuits of the activation mechanism 24.

[0284] The sensor 30 may be a plurality of sensors that can detect both pressure pulses and any combination of other sensing methods described herein. The use of more than one type of sensor 30 may provide the following advantages in some embodiments: to save battery life, wherein the entire wellbore can be in sleep mode until fracking occurs, wherein a pressure code can be pumped to wake the activation mechanism 24 to operate at a higher frequency detection which uses more power and allows the activation mechanism 24 to be more sensitive; to save battery life, wherein the entire wellbore can be placed back into sleep mode with a pressure code to save battery life by reducing the detection frequency of the activation mechanism 24 and sensors 30; to re-sequence the count schedule, wherein for example, the count of the sensors 30 or activation mechanism 24 needs to be reset because a fluid blocking device 114 has had a problem downhole and is not operating as it should be and a second fluid blocking device 114 must be sent downhole in its place, wherein in this case a pressure pulse may be sent which re-sequences the well and specific codes can be pumped to resume operations depending on the next required stage; other additional advantages that provide flexibility of the activation mechanism 24, sensors 30, sleeve assembly 100, and fluid blocking devices 114.SMART SLEEVE MICRO OPERATION

[0285] In operation, the sleeve assembly 100 may operate to seal flow through a tubing string 32 and simultaneously open the apertures 124 in the tubular housing 104. Initially, the sensors 30 of the activation mechanism 24 may sense the occurrence of a condition. On sensing the condition, the system triggers the expander 26. The expander 26 operates and causes the inner sleeve 102 to shift from a first position to a second position. This movement of the inner sleeve 102 causes the engagement mechanism 110 to axially shift into the active position. As this occurs, the engagement mechanism 110 and the sleeve may become rigidly connected to one another by operation of the sleeve connection point or interlocking elements 122 as shown in Figs. 35-38. Alternatively, the engagement mechanism and the inner sleeve 102 may contact one another without becoming rigidly connected.

[0286] The fluid blocking device 114 travels through the string and lands on the annular shoulder 116 of the engagement mechanism 110 if in the active position. The fluid blocking device 114 and the annular shoulder 116 form a seal, preventing fluid from passing through thetubular housing 104. As a result of the seal, wellbore pressure may be used to apply an axial load to the engagement mechanism 110. The shear device 126 may shear upon reaching a specific loading condition. The shearing allows the combination of the engagement mechanism 110 and the inner sleeve 102 to move axially, opening and uncovering the apertures 124. Wellbore pressure may also be used to create pressure pulses to activate upstream sleeve assemblies.

[0287] An embodiment may include the following features. The sensor 30 may be configured to sense the magnetic field of the fluid blocking device 114, pressure pulses, or impacts of fluid blocking devices 114. A number of fluid blocking devices 114 may pass through the tubular housing 104 and past the sensor 30, with or without activating the activation mechanism 24. After the sensor 30 counts a specified number of fluid blocking devices 114, the activation mechanism 24 may activate the expander 26.

[0288] As shown in Figs. 107-110, in an embodiment, the shear device 126 may hold the engagement mechanism in the inactive state. Upon sensing the occurrence of a condition, the activation mechanism 24 may trigger the expander 26 causing the shearing device 126 to shear. This allows the engagement mechanism 110 to shift axially into the active state and form the annular shoulder 116. The size of the annular shoulder 116 may be controlled by the allowable travel distance of the edge 28 within the tubular housing 104.

[0289] There may be a second shearing device 126 that holds the inward radial edge of the annular wedge ring 120 to the tubular housing 104. The fluid blocking device 114 may travel through the sleeve assembly 100 and seat against the annular shoulder 116. Pressure may build up as a result of the seal between the annular shoulder 116 and the fluid blocking device 114. Upon reaching a certain loading condition, the second shearing device 126 may shear causing the engagement mechanism and inward radial edge of the annular wedge ring 120 to shift axially, opening apertures 124.

[0290] The shearing device 126 may be designed to shear under a specific loading condition. For example, the loading condition may be, for example, 10 tons of force. The shearing device 126 may be designed to shear under any other loading condition. The shearing device 126 may be designed to shear at a pressure of over 21 MPA over well bore pressure. The shearing device 126 may be a steel ring.

[0291] The sleeve assembly 100 embodiments disclosed herein provide various advantages. For example, any number of stages of sleeve assemblies 100 may be used as required for the fracking operation. Additionally, the flow rate is not limited by progressively smaller diameters of seat sizes throughout the well bore, wherein a large seat may be used for all stages and large frac ports or apertures 124 may be used for each stage. Further, the pressure in the well bore is notlimited by the pressure rating of the sleeve assembly 100, wherein the pressure rating of the sleeve assembly 100 meets or exceeds the liner rating. Further still, the embodiments do not require drill outs, allowing for long well bore distances. Moreover, the embodiments are compatible with many types of liners, for example, cemented or open hole liners. In addition, the embodiments may use various types of launchers, including, for example, a standard ball launcher. Additionally, the embodiments do not require a specific ball launch order or sequencing. Further, the embodiments are not limited by screen outs, wherein flow back or uphole flow contribution is provided by all fractured stages below.

[0292] The sleeve assembly 100 embodiments disclosed herein may also be used in various applications and may be used in conjunction with other fracturing systems. For example, the sleeve assemblies 100 may be used in full well bores with plug and perf operations at the heel and multiple stages of the sleeve assemblies described herein at the toe. The sleeve assemblies described herein can be used in conjunction with traditional ball drop systems at the toe, and with multiple stages of sleeve assemblies described herein at the heel. The sleeve assemblies described herein can be used with coiled tubing shiftable sleeves at the heel and with embodiments of the sleeve assembles described herein with multiple stages at the toe. In this way, the sleeve assembly 100 may be used in various hybrid applications, in combination with other known fracturing techniques. The sleeve assemblies 100 may be used in various sequences within well bore operations in combination with the standard sleeves and well bore operations.

[0293] Further, the sleeve assemblies 100 may be used in place of a bridge plug during perf and plug operations. Bridge plugs can have issues with proper sealing because of casing deformation in various operations including plug and perf operations. The use of the sleeve assemblies 100 may remove issues of inadequate sealing caused by casing deformations. The sleeve assemblies and fluid blocking devices can replace the bridge plug in plug and perf operations.

[0294] Further still, casing deformations may cause issues with ball or plug devices becoming stuck. The fluid blocking device 114 may be dissolvable which allows operators to remove the stuck component without needing to stop operations in order to drill out a stuck component. This provides for reliable isolation. Further still, the sleeve assembly 100 may be used with any size of tubing string 32 and any weight of casing. This allows the sleeve assemblies to operate in all casing lengths.

[0295] The sleeve assembly 100 may be used as a ball drop system replacement.

[0296] There are various other advantages provided by the sleeve assembly 100. For example, the embodiments do not require any other specialized equipment on the surface or any additional operator training because the operation of the invention is similar to the operation of a standardball drop. This will improve the ease at which new adopters will be able to understand the operation of the technology. Further, there are not any flow restrictions in the tubing string 32 over the life of the well because no milling of ball seats or bridge plugs is required. Additionally, the use of a single size of fluid blocking device 114 allows for the use of a ball which is several sizes smaller than the typical largest sized balls used in standard ball drop operations. The largest sized balls can become stuck due to casing deformations because of the limited clearance in the casing.

[0297] The sleeve assembly allows for a reduction in cost because two separate subs are not required. Only one sub is required with a single set of electronics. In previous embodiments of this technology, a first sub included ports that were opened with electronics / gas-generator, etc. and a second sub had a ball seat that was formed using electronics / gas-generator, etc. The present sleeve assembly performs both functions within a single sub by forming the seat with the activation mechanism and then landing a fluid blocking device such as a ball or dart on the seat and opening the ports using pressure. Using a single sub can create cost savings in material, machining, and electronics, gas-generator, etc.SLEEVE MACRO OPERATION

[0298] As shown in Figs. 48-54 and Figs. 136-157, the sleeve assembly 100 may be used in a tubing string 32. The tubing string 32 may be used for hydraulic fracturing operations. One or more sleeve assemblies 100 may be used on the tubing string 32.

[0299] The activation mechanism 24 may be in a battery saving state until a pressure code is sent through the tubing string 32, placing the activation mechanism into a higher power consumption state with more data readings.

[0300] In an embodiment, a pressure code may be sent through the tubing string 32 and read by the access toe sub 50 (“ATS”). The ATS 50 may be fracked by pumping acid, pad fluid, and sand. This may be considered a stage.

[0301] The first sleeve assembly 100 may be defined as the first closest sleeve assembly 100 uphole from the ATS 50 within the tubing string 32. The second closest sleeve assembly 100 uphole from the ATS 50 may be defined as a second sleeve assembly 100. The remaining sleeve assemblies 100 may be defined in the same manner. Each sleeve assembly may have the same features or there may be multiple types of sleeve assemblies described herein used in the same tubing string.

[0302] In some embodiments, a first sleeve assembly 100 on the tubing string 32 may be activated by the pressure code or by a device with a magnetic field sent through the string andthrough the sleeve assembly 100. In response, the activation mechanism 24 may activate, placing the engagement mechanism 110 in the active position.

[0303] A fluid blocking device 114 is sent into the tubing string 32, passing a number of sleeve assemblies 100 as it travels through the tubing string 32. The fluid blocking device 114 may be transported through the bore with displacement fluid or fracking fluid. The fluid blocking device 114 may activate one or more uphole sleeve assemblies 100 as it passes through them. As shown for example in Fig. 143, the fluid blocking device 114 lands on the annular shoulder 116 of the first sleeve assembly 100. As a result of the axial load applied to the sleeve by the fluid blocking device 114, the sleeve assembly 100 opens the apertures 124. The open apertures 124 allow fracking fluid to flow in the formation surrounding the tubing string 32 and a hydraulic fracturing operation to occur. This may be considered a stage. Prior to opening the apertures 124 and after the fluid blocking device is in contact with the engagement mechanism 110, a pressure code may be pumped through the tubing string 32 at a pressure that is low enough so as to not cause the shearing device 126 of the first sleeve assembly 100 to shear to open the apertures 124. This pressure code may cause the second sleeve assembly 100 to activate, which places its engagement mechanism 110 in an active position or state. An example of pressure codes being used in this manner is shown, for example, in Fig. 144.

[0304] The sleeve assemblies 100 may be programmed to count the number of pressure codes that have been pumped through the tubing string 32 and activate on a specific count for each sleeve assembly 100. For each sleeve assembly in an active state, the fluid blocking device may be placed in position against the annular shoulder of the engagement mechanism and the immediately upstream sleeve assembly may then be moved into an active state through pressure pulses applied to the tubing string prior to the engagement mechanism being moved into position to allow for fracturing. This allows any number of balls, each of the same size, to be used for fracturing.

[0305] A second fluid blocking device 114 may then be sent into the tubing string 32. The fluid blocking device 114 may travel through the tubing string 32 and may or may not provide a magnetic signal to sensors 30 of one or more additional sleeve assemblies 100. This may place their engagement mechanism 110 in an active state. The second fluid blocking device 114 may engage an engagement mechanism 110 that was previously activated by a previous fluid blocking device 114 or by a pressure code count. The fluid blocking device 114 and annular shoulder 116 form a seal and open apertures 124, allowing an additional fracking operation to occur as described previously. Any number of sleeve assemblies 100 may be operated in this manner. Alternative stage naming / numbering may also be used. Any number of stages mayoccur as required. In general, the number of pressure pulses necessary to activate each sleeve assembly will be one greater than the number required to activate the sleeve immediately downhole.

[0306] After the required number of sleeve assemblies 100 have been fracked, the flow may be reversed to an uphole direction as shown in Figs. 135 and 157. The fluid blocking device 114 may release from the annular shoulder 116 and land on the catch device 210. In doing so, the openings between the engagement mechanism 110 and the fluid blocking device 114 allow flow to travel uphole.

[0307] Embodiments described herein may provide the advantage of continuous pumping, without the need to stop the operations to perform the isolation, perforation, and frac. Embodiments described herein may further allow reverse flow from all stages to aid in screen out recovery. Embodiments described herein may provide higher pressure integrity. Embodiments described herein may operate using only one set of electronics and similar dissolvable reliability as a dissolvable ball. Embodiments herein may be more cost effective than current methods. The use of continuous pumping, flow back and uniform ball size can provide various advantages.

[0308] There are various numbers of components that may be used in operation. Examples of some numbers of components are as follows: one dissolvable ball (3.5”) or fluid blocking device 114 per stage, one remote activated seat or annular shoulder 116 per stage, one toe port 50 per well. Other numbers of components may also be used.METHOD FRACTURING #1

[0309] As shown in Figs. 116-135, the sleeve assembly 100 may be used in a tubing string 32. The tubing string 32 may be used for fracking operations. One or more sleeve assemblies 100 may be used on the tubing string 32. The activation mechanism 24 may be in a low battery saving state until a pressure code is sent through the tubing string 32, placing the activation mechanism into a higher power consumption state with more data readings.

[0310] In an embodiment, a pump pressure code may be sent through the tubing string 32 and read by the access toe sub 50 (“ATS”) as shown in Fig. 121. The ATS 50 may be fracked by pumping acid, pad fluid, and sand.

[0311] The first sleeve assembly 100 may be defined as the first closest sleeve assembly 100 uphole from the ATS 50 within the tubing string 32. The second closest sleeve assembly 100 uphole from the ATS 50 may be defined as a second sleeve assembly 100. The remaining sleeve assemblies 100 may be defined in the same manner.

[0312] Fig. 120 shows each of the sleeve assemblies 100 and the ATS 50 prior to the first activation signal. When the first activation signal as represented by the pressure code is sent, each of the counters in the sleeve assemblies 100 and ATS 50 are iterated by one count. The access toe sub is then shifted into the open position, allowing access through the apertures 124 into the formation. Hydraulic fracturing can then be conducted at the initial stage in the formation surrounding the access toe sub 50.

[0313] The same initial pressure code activation signal used to activate the access toe sub 50 can also move the first sleeve assembly 100 into an active state to receive a fluid blocking device as shown in Fig. 126. In this embodiment, the same size frac balls may be used as fluid blocking devices 114 to isolate each stage. Displacement volume may be monitored to confirm that the ball has landed at the correct stage. Once the fluid blocking device 114 has reached the first sleeve assembly, as shown in Figs. 125 and 126, the sleeve is moved into the open position with the apertures 124 open to the formation and hydraulic fracturing can be conducted in the formation surrounding the first sleeve assembly as represented in Fig. 127.

[0314] The next sleeve assembly may be activated into the active state either through additional pressure codes or by tracking the number of fluid blocking devices that pass each activation sleeve. The number of fluid blocking devices passing each activation sleeve can be tracked by various means, including detecting the number of impacts or detecting magnetic fields if the fluid blocking device is magnetic. The sensor may also be an inductive sensor which detects the movement of the fluid blocking devices as they pass in close proximity to the sensor. The number of fluid blocking devices passing through the sleeve assembly may not need to be tracked if pressure pulses are uses to activate the engagement mechanism 110.

[0315] As shown in Figs. 125-132, the sleeve assemblies may detect the number of impacts from fluid blocking devices that are sent downhole. As shown in Figs. 125 and 126, the first sleeve assembly 100 may have been previously activated into the active state by a pressure pulse. The pressure pulse that activates the first sleeve assembly may be the same pressure pulse that activated the access toe sub 50. The fluid blocking device 114 is then sent downhole and engages with the first sleeve assembly 100 thereby shifting the sleeve into an open position and providing fluid access to the formation through the apertures 124. This stage of the formation may now be fractured.

[0316] After fracturing of the first sleeve assembly is completed, the next fluid blocking device may be introduced into the tubing string. As shown in Figs. 129-130 and 132, the impact of the fluid blocking device may cause the second sleeve assembly to move into the active position through activation of the activation mechanism 24. The fluid blocking device can then engagewith the annular shoulder to open the sleeve and expose the apertures 124. The next stage of fracturing can now be conducted through the second sleeve assembly.

[0317] The same process for opening consecutive sleeve assemblies can be repeated for any desired number of stages. In other embodiments, as shown in Figs. 131A and 13 IB, a sleeve assembly 100 may be configured to include a delay before activating after a fluid blocking device 114 passes through the impact device 200. The delay will allow the upstream sleeve assembly to shift into the active position after the fluid blocking device has passed the sleeve assembly. This will allow the next downstream sleeve assembly to be engaged with the fluid blocking device without the upstream sleeve assembly also being engaged.

[0318] A fluid blocking device 114 may be sent through the tubing string 32 and impact the impact device 200 of the sleeve assemblies 100 as it travels. The activation mechanisms 24 may count the number of fluid blocking devices 114 that travel through the tubing string 32 by the number of impacts. Upon reaching a certain number of impacts for each sleeve assembly 100, that sleeve assembly 100 will activate, placing the engagement mechanism 110 in an active state. The number of impacts needed to activate may be different for each sleeve assembly in the tubing string 32.

[0319] When the first fluid blocking device 114 is sent downhole, it may only cause the first stage sleeve assembly 100 to activate and all the others count the impact as it travels. The fluid blocking device 114 lands on the annular shoulder 116 of the first sleeve assembly, causing the apertures 124 to open. The area surrounding these apertures 124 may then be pumped with fracking fluids.

[0320] A second fluid blocking device 114 may be sent downhole, causing the plurality of sleeve assemblies 100 to each count further impacts as it travels. The second sleeve assembly 100 may have reached the specified number of impacts, causing its engagement mechanism to activate and capture the fluid blocking device 114 on the annular shoulder 116. The pressure behind the fluid blocking device 114 causes the engagement mechanism to shift axially to open the apertures 124. Fracking fluids may then be pumped through the apertures 124 of the second sleeve assembly 100.

[0321] The above process may continue for an N number of fluid blocking devices 114 and an N number of sleeve assemblies 100, where N is a whole number. After the required number of sleeve assemblies 100 have been fracked, the flow may be reversed to an uphole direction as shown in Fig 135.

[0322] As shown in Figs. 136-156, each of the sleeve assemblies 100 may be moved into an active state through pressure codes. As shown in Fig. 140, an initial pressure code may be sentwhich activates the access toe sub 50 into an open position. Each of the sleeve assemblies 100 will also receive the pressure code and iterate the count. The first sleeve assembly 100 will also move into the active state as shown in Fig. 142 after the initial pressure code is transmitted. After the formation surrounding the access toe sub 50 is fractured, a fluid blocking device 114, in the form of a ball, will be sent downhole. The displacement volume may be used to confirm that the ball lands at the correct stage. After the first fluid blocking device 114 engages the first sleeve assembly 100 and the first stage is fractured, then the next fluid blocking device can be sent downhole.

[0323] In this embodiment, further pressure codes are used to activate the subsequent stages. As shown in Fig. 144, a second pressure pulse is sent, and each of the counts for each sleeve assembly is iterated. The second sleeve assembly 100 is now shifted into the active position. The first sleeve assembly may be engaged to shift the sleeve and opening the apertures to the formation after the second pressure pulse is sent as shown in Fig. 146. The formation surrounding the first sleeve assembly can be fractured. The next fluid blocking device can then be moved into the position against the second sleeve assembly as shown in Fig. 148. The next pressure pulse can then be sent downhole with the fluid blocking device sealing against the corresponding engagement mechanism 110 and the third sleeve assembly can be activated. The count for the fourth sleeve assembly and any subsequent sleeve assemblies will be iterated at the same time. The next fluid blocking device 114 can be introduced downhole as shown in Fig. 152, and the next pressure code can be sent as shown in Fig. 153. This process can be repeated for any desired number of stages.METHOD OF FRACKING #2

[0324] As shown in Figs. 55-63, a method of fracking using a sleeve assembly 100 is provided. In operation, a tubing string 32 may comprise an ATS 50 at the end of the tubing string 32. The ATS 50 may be activated by a pump pressure code to open fluid connections to the formation surrounding the tubing string 32. The ATS 50 may be any known mechanical or electronic component. The open ATS 50 may be fracked as a first stage or merely used to allow fluid to flow through the tubing string 32 as shown in Fig. 56. When fracking as a first stage as shown in Fig. 57, the pad and frac fluid is pumped through the openings in the ATS 50 and into the formation surrounding the tubing string 32.

[0325] An activation ball 130 may be used to activate the activation mechanism 24 of each sleeve assembly 100. The activation ball 130 may include magnets to activate the sleeve assemblies 100 or other technology to communicate with the sleeve assemblies 100. Theactivation ball 130 could code to a specific sleeve assembly 100, removing the requirement for an electronic counter in the activation mechanism 24, or to all sleeve assemblies 100. The activation ball 130 may be a relatively small ball that can traverse through the tubing string 32 without obstructing the tubing string 32 or impeding flow exiting the tubing string 32. The activation ball 130 could be any other object that can traverse through the tubing string in this way and communicate with the sleeve assemblies 100.

[0326] After fracking stage one, the activation ball 130 may be pumped through the tubing string 32 to the ATS 50 as shown in Fig. 58. The activation ball 130 may activate a first sleeve assembly 100 to cause the annular shoulder 116 to form on the sleeve assembly 100. The first stage frac may be displaced by pumping fluid into the tubing string 32. A wireline 46 connected to a bottom hole assembly (“BHA”) 134 may be pumped down the tubing string 32 with the displacement fluid as shown in Fig. 59. The BHA 134 may include various known components used in fracking operations. The BHA 134 may comprise an SFPG 52. In this embodiment, the BHA 134 does not interact with the sensors 30 of the activation mechanism 24. At a location uphole of the first sleeve assembly 100 but downhole of a second sleeve assembly 100, a perforation may be performed by the SFPG 52 to create one cluster of perforations 128 or multiple clusters of perforations as shown in Fig. 59. The wireline 46 is then pulled uphole.

[0327] The sleeve assembly may not include apertures 124 and instead the fluid may flow into the formation surrounding the tubing string 32 by the perforations 128. In an embodiment, the perforations 128 may not be necessary where the apertures 124 are included and opened on the sleeve assembly 100.

[0328] A fluid blocking device 114 is displaced into the tubing string 32, followed by an acid, a pad, and a frac fluid. The fluid in front of the ball displaces out of stage one. After the fluid blocking device 114 seats in the first sleeve assembly 100 as shown in Fig. 60, the acid, pad, and frac fluid flows out of the perforations 128 into the formation surrounding the tubing string 32. This may be considered the fracking of stage two.

[0329] An activation ball 130 may be sent downhole of a second sleeve assembly 100, to activate the second sleeve assembly 100 as shown in Fig. 61. The second sleeve assembly 100 forms an annular shoulder 116 upon activation. The same steps for stage two occur to frac stage three. A SFPG 52 perforates uphole of the second sleeve assembly 100 and a fluid blocking device 114 is sent to isolate the stage by engaging with the annular shoulder 116 of the second sleeve assembly 100. An acid, pad, and frac fluid follow the fluid blocking device 114 to frac the third stage as shown in Fig. 62. The same steps are repeated in order to frac the fourth stage as shown in Fig. 63.

[0330] In this method, a select fire gun may be used for cluster perforation.METHOD OF FRACKING #3

[0331] As shown in Figs. 64-72, a method of fracking using a sleeve assembly 100 is provided. In operation, a tubing string 32 may comprise an ATS 50 at the end of the string. The ATS 50 may be activated and opened by pumping a pressure code to open fluid connections to the formation surrounding the tubing string 32. At the same time the ATS 50 is activated, the pressure code may simultaneously activate a first sleeve assembly 100 activation mechanism 24 as shown in Fig. 65. The sleeve assembly 100 forms an annular shoulder 116 as a result of the activation. The same pressure code could also activate additional sleeve assemblies 100. The sleeve assemblies 100 may be activated through various methods, such as by a pressure code or magnets on a fluid blocking device 114 or a component of the BHA 134.

[0332] The open ATS 50 may be fracked by pumping pad and frac fluid into the tubing string 32 as shown in Fig. 66. This may be considered stage one. Alternatively, the ATS 50 may not be fracked and instead allow fluid to exit the tubing string 32.

[0333] A wireline 46 connected to a BHA 134 and fluid blocking device 114 may be pumped into the tubing string 32 as shown in Fig. 67. The BHA 134 may comprise a Select Fire Perforating Gun (SFPG) 52. The fluid blocking device 114 may be placed on the annular shoulder 116 of the first sleeve assembly 100 to isolate stage two. A pressure pulse code may then be pumped into the tubing string 32 to activate a second sleeve assembly 100 and form an annular shoulder 116 as shown in Fig. 68. The pressure code may be pumped by the same pump or a different pump. With the fluid blocking device 114 seated, the tubing string 32 may be pressure tested.

[0334] The fluid blocking device 114 may be released on the annular shoulder 116. The fluid blocking device 114 may be released by the detachment mechanism 40 or other release method known in industry. The detachment mechanism 40 may use gas expansion to release from the BHA. The SFPG 52 is placed in its desired location by the wireline 46 and used to perforate the tubing string 32 as shown in Fig. 68. The wireline 46 is then pooled. Acid, pad, and frac fluid are pumped into the perforations 128 of stage two.

[0335] A wireline 46 connected to the BHA 134 and an additional fluid blocking device 114 are displaced into the tubing string 32 as shown in Fig. 69. This displacement may or may not include acid and special pad volume to save casing volume above the additional isolation ball. By not having to displace acid separately from the fluid blocking device 114 displacement. Thisfeature may not be available with a BHA 134 being run without the fluid blocking device 114 connected.

[0336] The additional fluid blocking device 114 is released on the annular shoulder 116 of the second sleeve assembly 100 as shown in Fig. 70. A pressure code may then be pumped into the tubing string 32, to activate a third sleeve assembly 100 to form an annular shoulder 116 as shown in Fig. 70. The wireline 46 is pooled to a desired position and the SFPG 52 perforates on or more perforation clusters as shown in Fig. 70. The wireline 46 and BHA 134 is then pooled out of the tubing string. Acid, pad, and frac fluid are pumped into the tubing string 32 to perform a frac operation on stage three as shown in Fig. 71. Stage four may be fracked in the same manner by repeating the same steps as shown in Fig. 72. In an embodiment, stage four may not be perforated uphole of the third sleeve assembly 100 and instead the isolated section of the tubing string 32 may be pressure tested to perform a wellbore integrity test.METHOD OF FRACKING #4

[0337] As shown in Figs. 73-83, a method of fracking using a sleeve assembly 100 is provided. In operation, a tubing string 32 may comprise an ATS 50 at the end of the string. The ATS 50 may be activated and opened by pumping a pressure code to open fluid connections to the formation surrounding the tubing string 32 as shown in Fig. 74. The open ATS 50 may be fracked by pumping pad and frac fluid into the tubing string 32 as shown in Fig. 75. This may be considered stage one. Alternatively, the ATS 50 may not be fracked and instead allow fluid to exit the tubing string 32.

[0338] The frac fluid may be displaced into the ATS 50. A wireline 46 connected to a BHA 134 may also be pumped down the tubing string 32 as shown in Fig. 76. The BHA 134 may comprise an SFPG 52. The BHA 134 may include a device for activating the activating mechanism 24 of the sleeve assembly 100. The device may be a magnet, magnet assembly or similar device. Another magnetic source or other device may be used. The BHA 134 passes through and downhole of a first sleeve assembly 100. The BHA 134 is then pooled uphole of the first sleeve assembly 100 as shown in Fig. 77. The activation mechanism 24 of the first sleeve assembly 100 senses the activation device and counts the passes and activates the sleeve assembly 100 to form the annular shoulder 116.

[0339] There may be an electronic counter included in the activation mechanism 24. The electronic counter may perform any number of counts to trigger the expander 26. For example, the counter may count a downhole and uphole pass through the sleeve assembly 100 as a singlecount. The counter may count only a downhole pass through the sleeve assembly 100 as a single count. The counter may count only an uphole pass through the sleeve assembly 100 as a count.

[0340] The SFPG 52 may then perforate one or more clusters of perforations 128 uphole of the first sleeve assembly 100 as shown in Fig. 78. The wireline 46 is pooled and the BHA 134 removed from the tubing string 32 as shown in fig. 79. A fluid blocking device 114 is displaced into the tubing string 32 followed by acid, pad, and frac fluid as shown in Fig. 80. The fluid in front of the fluid blocking device 114 displaces out of stage one. A spacer fluid may or may not be used in front of the fluid blocking device 114. When the fluid blocking device 114 seats on the annular shoulder 116 of the first sleeve assembly 100, the acid, pad, and frac may discharge through the perforations 128 into the formation surrounding the tubing string 32. This may be considered stage two.

[0341] These steps may be repeated for stages 3 and 4 as shown in Fig. 82 and 83, respectively.

[0342] Any number of stages may be fracked using the embodiments disclosed herein.METHOD OF FRACKING #5

[0343] As shown in Figs. 84-92, a method of fracking using a sleeve assembly 100 is provided. In operation, a tubing string 32 may comprise an ATS 50 at the end of the string. The ATS 50 may be activated and opened by pumping a pressure code to open fluid connections to the formation surrounding the tubing string 32 as shown in Fig. 85. The pressure code may not activate sleeve assemblies 100 in the tubing string 32. The open ATS 50 may be fracked by pumping acid, pad, and frac fluid into the tubing string 32 as shown in Fig. 86. This may be considered stage one. Alternatively, the ATS 50 may not be fracked and instead allow fluid to exit the tubing string 32.

[0344] This stage may be displaced by pumping a wireline 46 connected to a BHA 134 and fluid blocking device 114 into the tubing string 32 as shown in Fig. 87. The BHA 134 may comprise an SFPG 52. The fluid used to pump may be an acid followed by a pad. When the BHA 134 is downhole of a first sleeve assembly 100, the pumping is stopped. The BHA 134 is then pooled through and uphole of the first sleeve assembly 100 as shown in Fig. 88. This action actives the activation mechanism 24 of the first sleeve assembly 100 to form an annular shoulder 116. The fluid blocking device 114 may then be released by detachment mechanism 40 or other known method in the industry. The SFPG 52 is positioned and perforates the tubing string 32 for stage two as shown in Fig. 89. The wireline 46 and BHA 134 are pooled out of the tubing string 32. The acid and pad already in the tubing string 32 may then be used to pump and frac stage two asshown in Fig. 91. This provides the advantage of displacing wellbore volume on subsequent stages of the fracture and saves water.

[0345] The fracturing fluids do not travel past the fluid blocking device 114 seated on the annular shoulder 116 of the first sleeve assembly 100 because of sealing created.

[0346] The second frac fluid is displaced with a BHA 134 and fluid blocking device 114 and stacked acid and pad fracking fluid following thereafter for stage three.

[0347] These steps may be repeated for stages three and four as shown Fig. 92 or for any further number of stages.METHOD OF FRACKING #6

[0348] As shown in Figs. 93-104, a method of fracking using a sleeve assembly 100 is provided. In operation, a tubing string 32 may comprise an ATS 50 at the end of the string. The ATS 50 may be activated and opened by pumping a pressure code to open fluid connections to the formation surrounding the tubing string 32. At the same time the ATS 50 is activated, the pressure code may simultaneously activate a first sleeve assembly 100 activation mechanism 24 as shown in Fig. 94. The sleeve assembly 100 forms an annular shoulder 116 as a result of the activation.

[0349] The open ATS 50 may be fracked by pumping acid, pad, and frac fluid into the tubing string 32 as shown in Fig. 95. This may be considered stage one. Alternatively, the ATS 50 may not be fracked and instead allow fluid to exit the tubing string 32.

[0350] A wireline 46 connected to a BHA 134 and fluid blocking device 114 may be pumped into the tubing string 32 as shown in Fig. 96. The BHA 134 may comprise an SFPG 52. The pumped fluid may displace the stage one fluid. A spacer fluid in front of the BHA 134 may or may not be used to displace the stage one fluid. An acid and a pad may be pumped behind the fluid blocking device 114, wireline 46, and BHA 134. The BHA 134 and fluid blocking device 114 may be pumped to the first sleeve assembly 100 or just uphole of it. The fluid blocking device 114 may be released from the BHA 134 and wireline 46 as shown in Fig. 97. The fluid blocking device 114 may be pumped until the fluid blocking device 114 seats on the annular shoulder 116 of the first sleeve assembly 100 as shown in Fig. 97. A pressure code may now be pumped to activate a second sleeve assembly 100 to form an annular shoulder 116 as shown in Fig. 97. The SFPG 52 may create perforations 128 as shown in Fig. 98. The fluid blocking device 114 may be released from the BHA 134 by detachment mechanism 40 or other known method. Note, with the fluid blocking device 114 disconnected from the BHA 134 and wireline46, the BHA 134 and wireline 46 may now be pooled through the activated second sleeve assembly 100 shoulder. The outer diameter of the BHA 134 and wireline 46 may be smaller than the outer diameter of the fluid blocking device 114 or the annular shoulder 116 of the sleeve assemblies 100.

[0351] The BHA 134 and wireline 46 may now be pooled out of the tubing string 32. The stage two acid and pad are already in the well from displacing the first fluid blocking device 114 in position, so the stage two frac may be pumped.

[0352] The stage two frac may be displaced with the wireline 46 connected to the BHA 134 and an additional fluid blocking device 114 as shown in Fig. 99. A displacement fluid or spacer fluid may be pumped ahead of the wireline 46, BHA 134, and fluid blocking device 114.Alternatively, no displacement or spacer fluid may be used and the fluid already in the tubing string 32 may be displaced by the stage three fluids.

[0353] The wireline 46, BHA 134, and fluid blocking device 114 may be pumped to a second sleeve assembly 100 or just uphole of it as shown in Fig. 99. The wireline 46, SFPG 52, and fluid blocking device 114 may be followed into the tubing string 32 by an acid and pad frac fluid. The fluid blocking device 114 may be released as shown in Fig. 100. The fluid blocking device 114 may be pumped until it seats on the second sleeve assembly 100. A pressure code may now be pumped to activate a third sleeve assembly 100 and form an annular shoulder 116 as shown in Fig. 100.

[0354] The SFPG 52 may now perforate the third stage as shown in Fig. 101. The BHA 134 and wireline 46 may be pooled uphole through the third annular shoulder 116 because the outer diameter of these components is smaller than the outer diameter of the annular shoulder 116.

[0355] The wireline 46 and BHA 134 may be pooled out of the tubing string 32. The acid and pad already in the tubing string 32 may be used to frack stage three.

[0356] The stage three frac may be displaced with the wireline 46, BHA 134, and an additional fluid blocking device 114 as shown in Fig. 102. A spacer displacement fluid may be pumped downhole of the BHA 134 and additional fluid blocking device 114. A spacer fluid may also not be pumped downhole of the BHA 134 and fluid blocking device 114. The BHA 134 and fluid blocking device 114 may be followed into the tubing string 32 by an acid and pad fluid. These components may be displaced to at or above the third sleeve assembly 100. The fluid blocking device 114 may be released and pumped until it seats on the annular shoulder 116 of the third sleeve assembly 100 as shown in Fig. 103. A wellbore test may occur on the isolated portion of the well uphole of the third sleeve assembly 100.

[0357] Afterwards, the SFPG 52 may perforate the tubing string 32 to form a fourth stage. The fourth stage may be fracked using the acid and pad fluid already in the well. The frac is pumped and may then be displaced as shown in Fig. 104.SETTING TOOL SLEEVE ASSEMBLY ACTIVATION

[0358] In some embodiments the sleeve assembly may be activated by a setting tool run downhole. The setting tool can be run in hole by any known method, including wireline or coiled tubing or other running string. As shown in Figs. 159 and 160, the sleeve assembly 100 may further comprise an activation surface 300 on the engagement mechanism 110. The activation surface 300 may be immediately downstream of a portion of the tubular housing 104 having a larger internal diameter than an inner diameter of the activation surface 300 thereby defining a locate cavity 302. The activation surface may be a portion of the sleeve assembly that is capable of receiving a force in the downhole direction from the setting tool. In the embodiment shown in Fig. 160, the activation surface is the uphole end of the sleeve assembly where it is adjacent to an open area where the tubular housing has a larger internal diameter, and the pocket above the sleeve assembly forms a locate cavity 302.

[0359] As shown in Fig. 159, 160, 162, 164, 166, 168, and 170, the sleeve assembly 100 may be used in combination with a setting tool 140 on a conveyance line 322, in which the setting tool 140 is configured to move the engagement mechanism 110 from the inactive state to the active state by engaging the activation surface 300. This embodiment describes an alternative method to move the engagement mechanism into the active state, for example, without the need for internal electronics within the sleeve assemblies. Otherwise, the operation of the sleeve assemblies for each fracturing stage is similar to those described in other embodiments herein in which the electronics are contained within the sleeve assemblies.

[0360] The conveyance line 322 may comprise a wireline or coil tubing or other running string. The setting tool 140 may comprise various electronics and a computer readable memory and a processor. The electronics may be programable to sequence various actions. The setting tool 140 may be electrically powered, electrically activated, battery powered, and / or action programmable. As shown in Fig. 158, the setting tool 140 may comprise a bottom hole assembly (BHA) including various components, an electrical setting tool 320 and an activation tool, which can also be described as a Seat Locating, Forming, and Ball Release tool 346. In the embodiments shown herein, the functions of seat locating, seat forming and ball releasing are provided in a single tool. In other embodiments, the operations of locating the locate cavity, engaging the locate cavity to move an engagement mechanism into an active state and releasinga fluid blocking device, such as a ball, from the tool may be provided by multiple different tools which collectively form the activation tool. In other embodiments, the activation tool may provide only one of those functions or a different subset of the functions, with the other functions being provided by other embodiments of the tools described herein.

[0361] As shown in Figs. 160-171, the setting tool 140, and in particular, the activation tool 346, may further comprise one or more shifting dogs 312, which may include locating dogs 313 for seating in the locate cavity 302 to move the engagement mechanism 110 from the inactive state to the active state. The shifting dogs 312 may include seat forming dogs 315 for moving the engagement mechanism 110 from the inactive state to the active state. The one or more shifting dogs 312 may be any mechanism that can locate the locate cavity 302 and shift the engagement mechanism into the active state.

[0362] The setting tool 140, and in particular, the activation tool 346, may carry the fluid blocking device 114, and in which the fluid blocking device 114 is a ball. The ball may be made of a dissolvable material.

[0363] The electrical setting tool 320 may be a Kaseum™ K-Set Electrical Plug setting tool (K- set) as shown in Fig 162. The K-Set 320 may comprise a battery section, a drive stroke mechanical section, an electronic section. The K-set 320 comprises a mandrel that may move axially. Other setting tools that function in any equivalent manner may also be used as the electrical setting tool.

[0364] As shown in Figs. 159-174, the setting tool 140 operates in the following manner. The setting tool 140 is placed in a tubing string 32. The setting tool 140 may be placed in a location where the locating dogs 313 are downhole of the locate cavity 302 as shown in Fig. 160. The setting tool 140 may comprise shifting dogs 312 which comprise locating dogs 313 and seat forming dogs 315. The locating dogs 313 and seat forming dogs 315 may be radially extended outward from the setting tool 140 and contracted from the setting tool 140. The seat forming dogs 315 may also be configured to shift axially.

[0365] The setting tool 140 may be placed in any location where the locating dogs 313 can engage with the locate cavity 302. The K-set 320 may be activated to activate one or more of the locating dogs 313 as shown in Fig. 161. The locating dogs 313 may be activated wherein the locating dogs 313 extend radially outward from the setting tool 140. The locating dogs 313 may be extended radially by translating the axial movement of the electrical setting tool 320 into radially movement. Other methods for radially extending the locating dogs 313 may be used also. The locating dogs 313 may be spring loaded or resilient to enable them to remain in a radially biased position to lock into the locate cavity 302. The setting tool 140 is moved until alocating dog 313 finds a locate cavity 302 as shown in Fig. 162. Once located, there may be a time delay after which the K-set 320 operates to cold form the annular shoulder 116 by activating the activation tool 346. The activation tool 346 operates to expand the seat forming dogs 315 as shown in Fig. 165 to engage with the activation mechanism 300. The seat forming dogs 315 move axially to form the annular shoulder 116 as shown in Fig. 166. The seat forming dogs 315 may be radially extended in a similar way as the locating dogs 313. The seat forming dogs 315 may operate to also move axially in order to form the annular shoulder 116. The seat forming dogs 315 may move axially by transferring axially force provided by the electronic setting tool 320 through the seat forming dogs 315 to the engagement surface 300. The locating dogs 313 may hold the setting tool 140 within the locate cavity 302 and prevent axial movement during the operation of forming the annular shoulder 116. The K-set 320 may apply a force required to form the annular shoulder 116 by activating the activation tool 346. For example, the force may be 20t or other appropriate force to overcome the yield point in order to cold form the annular shoulder 116. Once the annular shoulder 116 is formed, the fluid blocking device 114 may be disconnected from the setting tool 140 as shown in Fig 168. The setting tool 140 then disengages from the sleeve assembly 100 by retracting or collapsing the locating dogs 313 and seat forming dogs 315 as shown in Fig. 170 and 171. The fluid blocking device 114 then engages with the annular shoulder 116 to form a fluid seal as shown in Fig. 173. Once a fluid pressure is reached within the tubing string 32, the engagement mechanism 110 moves axially, opening the apertures 124, and extending the catch device 210 as shown in Fig. 174. The engagement mechanism will move axially after the shear device 126 shears and the engagement mechanism shifts axially as shown Fig. 174. These operations are discussed in more detail below.

[0366] As shown in Fig. 159, the setting tool 140 is lowered to partially below the sleeve assembly 100 of interest. A command signal is sent through the setting tool 140 from the surface to active the K-set 320. The K-set 320 comprises a mandrel that moves axially under preprogrammed time sequences via battery power or other power source. The initial activation will operate the activation tool 346 to bias the locating dogs 313 radially outwards. The locating dog 313 or seat forming dogs 315 may be in a first contracted configuration and a second radially extended configuration. The locating dogs 313 or seat forming dogs 315 may be biased radially outwards by a spring or other method.

[0367] The K-set tool 320 moves the mandrel axially and this acts upon the activation tool 346. The mandrel movement dictates the action to be executed in the activation tool 346 under programmed timing through battery power in the setting tool 140 or the activation tool 346.

[0368] After the first command is given, the setting tool 140 and K-set tool 320 may operate under battery power or other power method without further commands from the surface. The initial command from the surface may be a one-time event. All other commands and steps of the setting tool 140 may be initiated undertime commands that are preprogrammed within the setting tool 140. The commands may also be provided from the surface for all steps or certain steps with other steps being preprogrammed.

[0369] The activation tool 346 extends one or more of the locating dogs 313 as shown in Fig. 140. The setting tool 140 may then be pooled (POOH) until the locating dogs 313 find the locate cavity 302. This may be done under timed sequence, for example, the setting tool 140 may be programmed to allow 60 seconds for this location operation to occur. Any other appropriate amount of time may be used for this operation to be completed. When the locating dogs 313 find the locate cavity 302, the POOH will be stopped, and surface tension will be realized.

[0370] As shown in Fig. 164-165, the locating dogs 313 are now fully extended in the locate cavity 302. The shifting dogs 312 may further comprise seat forming dogs 315 or locating dogs 313. The seat forming dogs 315 may also now be extended into the locate cavity 302. The setting tool 140 is programmed to extend the seat forming dogs after any set time, for example, 10 seconds.

[0371] As shown in Figs. 166-167, the seat forming dogs 315 may travel axially within the locate cavity 302 to apply load to the activation surface 300 to move the engagement mechanism 110 axially and form the annular shoulder 116. This may also be preprogrammed to occur at a time interval, such as 70 seconds after the initial command signal. The axial force applied by the seat forming dogs may be 70t, wherein the force is applied through the K-set tool 320. For example, 90 seconds after the initial command, the annular shoulder 116 may be formed. Other appropriate time intervals may also be used. During this process, the tension in the string, for example, wireline, from the surface to the setting tool 140 is maintained.

[0372] As shown in Fig. 166, the fluid blocking device 114 may be attached to the setting tool 140 with a holding mechanism 316 which forms part of the activation tool 346. The holding mechanism 316 may comprise fingers. As shown in Fig. 168, the setting tool 140 may release the fluid blocking device 114. This detachment may take a time interval, for example, 10 seconds or any other appropriate time. The holding mechanism 316 may be any mechanism which can initially hold the fluid blocking device in place and subsequently release it.

[0373] As shown in Figs 170-171, the K-set tool 320 activates to radially retract the shifting dogs 312 from the locate cavity 302. This operation may take a time interval, for example, 20seconds or other time for the operation to occur. When the shifting dogs 312 are retracted as shown in Fig. 171, the wireline tension falls off.

[0374] The total time from activating the K-set tool 320 from the surface, creating an annular shoulder 116, releasing the fluid blocking device 114, to retracting the shifting dogs 312 may be any time interval, for example, 120 seconds.

[0375] The setting tool 140 may be pulled at any time to start select fire perforating a stage. If the operator wants to select fire perforate a stage, overbalanced well bore pressure may be applied to a specific level defined by the shear screw load set in the ball cage cold forming device in the sleeve assembly 100.

[0376] As shown in Figs. 172 -173, the fluid blocking device 114 is moving against the annular shoulder 116 to form a seal. The well is open below to allow this action. The seal formed by the fluid blocking device 114 and annular shoulder 116 will withstand a wellbore pressure defined by the shear device 126. The shear device 126 may be a shear screw. The shear screw load is selected to open the sleeve assembly 100 to the reservoir. In this example the shear screws are set for 7mPa. The overbalanced perforating may be achieved as long as the shear device 126 load is not exceeded. This way the pressure integrity of the wellbore is not lost before that loading point.

[0377] As shown in Fig 174, pressuring up the well will form a seal between the annular shoulder 116 and fluid blocking device 114. Once the pressure exceeds the allowable load of the shear device 126, the engagement mechanism 110 and inner sleeve 102 will move axially which extends the catch device 210 radially inward and opens the apertures 124.

[0378] The activation tool 346 works with an existing electrical stroke tool to accomplish the following tasks without the need for electronics in the sleeve assembly 100: locate a sleeve assembly 100, radially extend seat forming dogs 315, actuate seat forming dogs 315 to form the annular shoulder 116, release the fluid blocking device 114, release the shifting dogs 312 from the locate cavity 302.

[0379] In some embodiments, as shown in Figs. 159-174, the sleeve assembly 100 may not contain electronics. Instead, the electronics may be contained in the setting tool 140.

[0380] These embodiments provide various advantages including: providing more reliable isolation than bridge plugs, especially in wells exposed to casing deformation; overcoming the deficiencies of composite and dissolvable bridge plugs; casing deformation in a manufacture sleeve is less likely to occur, thereby mitigating isolation reliability; maximum ID of the wellbore is available for fracking; only one cold formed seat is exposed to only one frac therefore minimal erosion and virtually zero pressure loss; large ball seat for maximum pressurecontainment; large seat also mitigates debris or casing deformation interference for the ball to travel from surface to seat; the fingers on the activation tool protect the ball travelling into the well so there are no wear marks on the ball; unlimited number of stages; maximum pump rates are available in the horizontal section; most mitigated isolation device in the completions industry for eliminating “Post Well Intervention” to drill isolation devices; no flow restriction post frac without well intervention; and less complicated operations.

[0381] Subsequent stages for a full wellbore can be used. Any number of stages can be used and operate in the manner described herein.

[0382] As shown in Figs. 159-174, there is disclosed a method of actuating a plurality of sleeve assemblies 100 in a tubing string 32, each of the sleeve assemblies 100 including a tubular housing 104 having one or more fluid ports into a formation and an actuatable inner sleeve 102 within the tubular housing 104, wherein the tubular housing 104 and the inner sleeve 102 together define an axial flow passage through the sleeve assembly 100. The method may comprise activating an activation mechanism 24 to shift an engagement mechanism 110 of one of the sleeve assemblies 100 from an inactive state into an active state, in which in the active state the engagement mechanism 110 extends radially inward into the axial flow passage to form an annular shoulder 116 (as shown in Fig. 166), the annular shoulder 116 being ductile and engageable with a fluid blocking device 114. The method may further comprise running the fluid blocking device 114 into sealing contact with the engagement mechanism 110. The method may further comprise opening the one or more fluid ports on the one of the sleeve assemblies 100 by providing sufficient pressure to the fluid blocking device 114 to shift the engagement mechanism 110 into an open position. In the embodiments described in Figs. 159-174, the activation mechanism 24 may be activated with the setting tool 140 on the conveyance line 322. The setting tool 140 may be configured to move the engagement mechanism 110 from the inactive state to the active state by engaging an activation surface 300 on the engagement mechanism 110. The setting tool 140 may further comprise one or more shifting dogs 312 for seating in a locate cavity 302 defined by the activation surface 300 to move the engagement mechanism 110 from the inactive state to the active state. The setting tool 140 may carry the fluid blocking device 114, and in which the fluid blocking device 114 may be a ball. The ball may be made of a dissolvable material. The fluid blocking device 114 may be released from the setting tool 140 after the locating dog 313 moves the engagement mechanism 110 into the active state.

[0383] As shown in Fig. 176, a standard or conventional cable setting device or a bridge plug setting device is a one time activation tool and does not contain electronics in the sleeve. Fig. 175 shows a conventional plug and perf wireline assembly.

[0384] In the claims, the word “comprising” is used in its inclusive sense and does not exclude other elements being present. The indefinite articles “a” and “an” before a claim feature do not exclude more than one of the feature being present. Each one of the individual features described here may be used in one or more embodiments and is not, by virtue only of being described here, to be construed as essential to all embodiments as defined by the claims.

Claims

CLAIMS1. A sleeve assembly for a wellbore, comprising: a tubular housing having one or more fluid ports into a formation; an actuatable inner sleeve within the tubular housing, the inner sleeve axially movable with respect to the tubular housing between a first position and a second position, wherein the tubular housing and the inner sleeve together define an axial flow passage through the sleeve assembly; an engagement mechanism for engaging a fluid blocking device, the engagement mechanism being activatable between: an inactive state; and an active state in which the engagement mechanism extends radially inward into the axial flow passage to form an annular shoulder, the annular shoulder being ductile and engageable with the fluid blocking device; in which axial movement of the inner sleeve from the first position to the second position activates the engagement mechanism from the inactive state to the active state; and in which the engagement mechanism is configured to open a fluid connection between the axial flow passage and the one or more fluid ports when the annular shoulder is engaged by the fluid blocking device.

2. The sleeve assembly of claim 1 further comprising an activation mechanism in a chamber between the tubular housing and the actuatable inner sleeve.

3. The sleeve assembly of claim 1 in which the activation mechanism further comprises a sensor, an activator, and an expander.

4. The sleeve assembly of claim 3 in which the sensor is a magnetic pickup or strain gauge.

5. The sleeve assembly of claim 3 or 4 in which the activator is an ignitor.

6. The sleeve assembly of any one of claim 3 to 5 in which the expander is a gas generator.

7. The sleeve assembly of any one of claims 2 to 6 in which the actuatable inner sleeve is uphole relative to the engagement mechanism and in which movement of the inner sleeve into the second position pushes the engagement mechanism downhole into the active state.

8. The sleeve assembly of any one of claims 2 to 6 in which the actuatable inner sleeve is downhole relative to the engagement mechanism and in which movement of the inner sleeve into the second position pushes the engagement mechanism radially inward to form the annular shoulder.

9. The sleeve assembly of claim 8 in which each of the actuatable inner sleeve and the engagement mechanism have interlocking elements which cooperate so that the actuatable inner sleeve and the inner sleeve move axially together after the engagement mechanism is moved into the active state.

10. The sleeve assembly of any one of claims 1 to 9 in which the annular shoulder formed in the active state of the engagement mechanism is cold formed.

11. The sleeve assembly of any one of claims 1 to 10 in which the engagement mechanism is activated by a magnetic pick up.

12. The sleeve assembly of any one of claims 1 to 11 in which the sleeve assembly further comprises an impact device configured to impact with the fluid blocking device.

13. The sleeve assembly of claim 12 wherein the sensor is configured to sense the impact and the activation mechanism is configured to count the impact.

14. The sleeve assembly of claim 1 further comprising an activation surface on the engagement mechanism.

15. The sleeve assembly of claim 14 in which the activation surface is immediately downstream of a portion of the tubular housing having a larger internal diameter than an inner diameter of the activation surface thereby defining a locate cavity.

16. The sleeve assembly of any one of claims 14 and 15 in combination with a setting tool on a conveyance line, in which the setting tool is configured to move the engagement mechanism from the inactive state to the active state by engaging the activation surface.

17. The sleeve assembly in combination with the setting tool of claim 16 as dependent on claim 15 in which the setting tool further comprises a locating dog for seating in the locate cavity to move the engagement mechanism from the inactive state to the active state.

18. The sleeve assembly in combination with the setting tool of claim 16 or 17 in which the setting tool carries the fluid blocking device, and in which the fluid blocking device is a ball.

19. The sleeve assembly in combination with the setting tool of claim 18 in which the ball is made of a dissolvable material.

20. The sleeve assembly of any one of claims 1-19 in which the sleeve assembly further comprises a catch device configured to extend radially inward into the axial flow passage when the fluid connection is open between the axial flow passage and the one or more fluid ports.

21. A dart for blocking fluid when engaged with an engagement mechanism, the dart comprising: an inner core; a ductile outer sleeve axially movable with respect to the inner core, the ductile outer sleeve being mounted externally to the inner core; a chamber formed between the inner core and ductile outer sleeve; an activation mechanism within the chamber, in which activation of the activation mechanism axially moves the ductile outer sleeve with respect to the ductile outer sleeve to expand radially outwardly.

22. The dart of claim 21 in which the activation mechanism further comprises a sensor, an activator, and an expander.

23. The dart of claim 22 in which the sensor is a magnetic pickup or strain gauge.

24. The dart of claim 22 or 23 in which the activator is an ignitor.

25. The dart of any one of claim 22 to 24 in which the expander is a gas generator.

26. The dart of any one of claims 21 to 25 in which the ductile outer sleeve further comprises an inner wedge and the inner core further comprises an outer wedge, and in which the outer wedge and the inner wedge have cooperating sliding surfaces which allow the inner wedge to slide into an expanded radial outward position against the outer wedge.

27. The dart of any one of claims 21 to 26 in which the ductile outer sleeve is made from a dissolvable material.

28. The dart of any one of claims 21 to 27 in which the inner core is made from a dissolvable material.

29. The dart of any one of claims 21 to 28 used in combination with a select fire perforating gun (“SFPG”) detachment mechanism.

30. The dart of claim 29 in which the SFPG detachment mechanism is shearable.

31. The dart of any one of claims 21 to 30 in which the inner core comprises a flowback check valve.

32. The dart of any one of claims 21 to 30 in which one or more of the inner core or the ductile outer sleeve includes a magnetic material.

33. A dart for blocking fluid when engaged with an engagement mechanism, the dart comprising: a ductile outer sleeve; an inner core axially movable with respect to the ductile outer sleeve, which movement of the inner component within the ductile outer sleeve causes the ductile outer sleeve to expand radially outwardly; and a shearable detachment mechanism mounted to the ductile outer sleeve for receiving a setting tool.

34. The dart of claim 33 in which the inner core is a ball.

35. The dart of claim 33 in which the inner core is a sleeve.

36. The sleeve assembly of any one of claims 1-13 in which the annular shoulder includes perforations permitting flow uphole when the annular shoulder is in contact with a fluid blocking element on a downstream end of the annular shoulder.

37. The sleeve assembly of claim 20 in which the catch device includes openings to allow reverse flow when a fluid blocking device is contained within the catch device.

38. A method of actuating a plurality of sleeve assemblies in a tubing string, each of the sleeve assemblies including a tubular housing having one or more fluid ports into a formation and an actuatable inner sleeve within the tubular housing, wherein the tubular housing and the inner sleeve together define an axial flow passage through the sleeve assembly, the method comprising: activating an activation mechanism to shift an engagement mechanism of one of the sleeve assemblies from an inactive state into an active state, in which in the active state the engagement mechanism extends radially inward into the axial flow passage to form an annular shoulder, the annular shoulder being ductile and engageable with a fluid blocking device; running the fluid blocking device into sealing contact with the engagement mechanism; and opening the one or more fluid ports on the one of the sleeve assemblies by providing sufficient pressure to the fluid blocking device to shift the engagement mechanism into an open position.

39. The method of claim 38 further comprising activating the activation mechanism by using pressure pulses.

40. The method of claim 39 in which the activation mechanism further comprises a sensor, an activator, and an expander, and in which the sensor is configured to detect the pressure pulses and cause the activator to expand the expander in response to the sensor detecting the pressure pulses.

41. The method of claim 39 in which the activation mechanism is activated with a setting tool on a conveyance line.

42. The method of claim 41 in which the setting tool is configured to move the engagement mechanism from the inactive state to the active state by engaging an activation surface on the engagement mechanism.

43. The method of claim 42 in which the setting tool further comprises one or more shifting dogs for seating in a locate cavity defined by the activation surface to move the engagement mechanism from the inactive state to the active state.

44. The method of claim 43 in which the setting tool carries the fluid blocking device, and in which the fluid blocking device is a ball.

45. The method of claim 44 in which the ball is made of a dissolvable material.

46. The method of claims 44 or 45 in which the fluid blocking device is released from the setting tool after the one or more shifting dogs moves the engagement mechanism into the active state.

47. An activation mechanism in a sleeve assembly, the activation mechanism comprising a sensor, an activator, and an expander.

48. The activation mechanism of claim 47 in which the sensor is a magnetic pickup or strain gauge.

49. The activation mechanism of claim 47 or 48 in which the activator is an ignitor.

50. The activation mechanism of any one of claim 47 to 49 in which the expander is a gas generator.

51. The sleeve assembly of claim 12 in which the impact device further comprises: a groove within an inner surface of the sleeve assembly; anda deformable material within the groove defining an annulus having an inner diameter smaller than an inner diameter of the inner surface.

52. The sleeve assembly of claim 51 in which the groove is within an inner surface of the inner sleeve.

53. The sleeve assembly of claim 41 or 42 in which the deformable material is rubber.

54. The sleeve assembly of claim 20 in which the catch device has non-uniform inner diameter.

55. The sleeve assembly of claim 20 in which the catch device further comprises a ball between an inner surface of the tubular housing and an outer surface of the engagement mechanism.

56. The sleeve assembly of claim 55 in which the inner surface of the tubular housing has a smaller diameter in the direction that the engagement mechanism shifts when the annular shoulder is engaged by the fluid blocking device.

57. The sleeve assembly of claim 56 further comprising a deformable wall within the engagement mechanism which is deformed by the ball when the annular shoulder is engaged by the fluid blocking device to reduce an inner diameter of an inner surface of the engagement mechanism.

58. The sleeve assembly of claim 3 in which the sensor is an inductive sensor and the engagement mechanism is activated by detecting movement of the fluid blocking device in close proximity to the inductive sensor.

Images