Multi-zone actuation system using borehole arrows

Abstract

A method for determining a property of a production zone, comprising: Positioning a sliding sleeve tool within a borehole, the sliding sleeve tool having an electronics housing; Actuating the sliding sleeve tool, wherein the actuation is initiated at least in part based on one or more measurements received by an actuation sensor, the actuation sensor being disposed within the electronics housing; Stimulating a production zone with a stimulation fluid; Detecting one or more properties of the borehole based at least in part on one or more measurements received by a property sensor, the property sensor being disposed within the electronics housing; Determining a parameter of the stimulation fluid from at least one of the one or more properties and Determining a relative uptake of the stimulation fluid based at least in part on the parameter of the stimulation fluid.

Description

GENERAL STATE OF THE ART

[0001] The present disclosure relates generally to wellbore operations and, more particularly, to a multi-zone actuation system that detects wellbore arrows when performing multi-interval stimulation of a wellbore.

[0002] In the oil and gas industry, subterranean formations penetrated by a wellbore are often fractured or otherwise stimulated to enhance hydrocarbon production. Fracturing and stimulation operations are typically performed by strategically isolating various zones of interest (or intervals within a zone of interest) downhole using packers and the like, and then subjecting the isolated zones to a variety of treatment fluids at elevated pressure. In a typical fracturing operation for a lined wellbore, the casing cemented in the wellbore is first perforated to allow conduits for hydrocarbons within the surrounding subterranean formation to flow into the wellbore.However, before producing the hydrocarbons, treatment fluids are pumped through the perforations into the wellbore and the surrounding formation, which causes the drainage channels in the formation to open and enlarge, thereby improving the production capabilities of the wellbore.

[0003] Today, it is possible to stimulate multiple zones during a single stimulation operation using on-site stimulation fluid pumping equipment. In such applications, multiple packers are inserted into the wellbore, and each packer is strategically placed at predetermined intervals configured to isolate adjacent zones of interest. Each zone may include a sliding sleeve that is moved to enable zonal stimulation by redirecting flow through one or more tubing openings closed by the sliding sleeve. Once the packers are properly deployed, the sliding sleeves can be selectively opened using a ball and baffle system. The ball and baffle system involves the sequential launching of downhole projectiles from a surface location into the wellbore.The downhole projectiles, commonly referred to as "fracture balls," are predetermined sizes configured to seal against correspondingly sized baffles or seats located within the wellbore at corresponding zones of interest. The smaller fracture balls are introduced into the wellbore ahead of the larger fracture balls, with the smallest fracture ball intended to land on the baffle farthest downhole and the largest fracture ball intended to land on the baffle closest to the surface of the borehole. Accordingly, the fracture balls isolate the target sliding sleeves from the lowest sleeve moving out of the wellbore. Applying hydraulic pressure from the surface serves to move the target sliding sleeve to its open position.

[0004] Thus, the ball-and-baffle system acts as an actuating mechanism for moving the sliding sleeves to their open position in the wellbore. Once the fracturing operation is complete, the balls can either be hydraulically returned to the surface or reamed out along with the baffles to return the casing string to a full borehole diameter. As can be seen, at least one disadvantage of the ball-and-baffle system is that there is a limited maximum number of zones that can be stimulated due to the fact that the baffles have graduated sizes.

[0005] Additionally, real-time data, for example, data indicating a wellbore characteristic associated with one or more different zones of a fracture or the actuating sleeve, can provide valuable information to increase the efficiency of production operations. Configuring or removing one or more sensors for a downhole tool can provide real-time feedback regarding the production rate for a specific zone or area downhole. The one or more sensors can transmit data to surface or to other sensors associated with downhole tools. Current techniques that use fiber optics to monitor a fracture can be expensive to install and may not provide an accurate measurement of flow characteristics.Implementation of one or more sensors providing effective and real-time monitoring of wellbore characteristics would increase the efficiency in hydrocarbon production or stimulation and evaluation techniques of one or more fracture zones.

[0006] US 2004 / 0 256 113 A1, US 2016 / 0 145 972 A1, US 2010 / 0 126 730 A1, US 2014 / 0 083 689 A1 and US 2014 / 0 262 237 A1 are prior art which discloses devices which can be used in boreholes.

[0007] The invention is defined by the independent claims. BRIEF DESCRIPTION OF THE DRAWINGS

[0008] The following figures are intended to illustrate certain aspects of the present disclosure and are not to be considered exclusive embodiments. The disclosed subject matter is capable of considerable modifications, alterations, combinations, and equivalents in form and function without departing from the scope of this disclosure. Fig. 1 shows an exemplary drilling system for providing a downhole tool that utilizes a sliding sleeve and one or more sensors in accordance with one or more embodiments of the present disclosure. Fig. 2A and Fig. 2B illustrate an exemplary downhole projectile in the form of a downhole arrow according to one or more embodiments of the present disclosure. Fig. 3A, Fig. 3B and Fig. 3C illustrate cross-sectional side views of an exemplary sliding sleeve assembly according to one or more embodiments. Fig. Figure 4A is an enlarged view of the sliding sleeve and the actuating sleeve from the Fig. 3A and Fig. 3B according to one or more embodiments of the present disclosure. Fig. 4B is an enlarged view of an exemplary actuator according to one or more embodiments of the present disclosure. The Fig. 5A, Fig. 5B and Fig. 5C illustrate progressive cross-sectional side views of the assembly from the Fig. 3A and Fig. 3B according to one or more embodiments of the present disclosure. Fig. 6 is an enlarged view of a downhole dart mating with a sliding sleeve according to one or more embodiments of the present disclosure. The Fig. 7A, Fig. 7B and Fig. 7C are schematic views of a downhole sliding sleeve tool according to one or more embodiments of the present disclosure. Fig. 8 is a block diagram illustrating an information management system and other electronic components of a sliding sleeve tool according to one or more embodiments of the present disclosure. Fig. 9 is a flow diagram for altering a well treatment operation based at least in part on a calculated flow rate of the stimulation fluid, according to one or more embodiments of the present disclosure. DETAILED DESCRIPTION

[0009] The present disclosure relates generally to wellbore operations and, more particularly, to a multi-zone actuation system that detects wellbore arrows when performing multi-interval stimulation of a wellbore.

[0010] The embodiments described herein disclose sliding sleeve assemblies capable of detecting borehole arrows and actuating a sliding sleeve having arrow profiles defined thereon when a predetermined number of borehole arrows are detected.

[0011] Once a predetermined number of downhole darts have been detected, an actuating sleeve can be actuated to expose a sleeve connection profile defined on a sliding sleeve. After the sleeve connection profile has been exposed, a subsequent downhole dart inserted into the wellbore can locate its dart profile and connect with its mating sleeve profile. Upon application of fluid pressure in a direction toward the surface of the wellbore from the subsequent downhole dart, the sliding sleeve can then be moved to an open position, exposing flow ports and facilitating fluid communication with a surrounding subterranean environment for wellbore stimulation operations. The presently disclosed embodiments therefore provide non-interventional wellbore stimulation methods and systems.

[0012] With reference to Fig. 1 illustrates an exemplary drilling system 100 that may embody or otherwise employ one or more principles of the present disclosure in accordance with one or more embodiments. As illustrated, the drilling system 100 may include a drilling rig 102 disposed at the surface 104 and a borehole 106 extending therefrom and penetrating a subterranean formation 108. Although Fig. 1 depicts a land-based drilling rig 102, it should be understood that the embodiments of the present disclosure are equally well suited for use in other types of drilling rigs, such as offshore platforms or drilling rigs used in other geographic locations. In other embodiments, the drilling rig 102 may be replaced with a wellhead installation without departing from the scope of the disclosure.

[0013] The drilling rig 102 may include a drilling rig 110 and a rig floor 112. The drilling rig 110 may support or otherwise assist in manipulating the axial position of a workstring 114 extending within the wellbore 106 from the rig floor 112. As used herein, the term "workstring" refers to one or more types of connected lengths of tubing or pipe, such as drill pipe, drill string, landing string, production tubing, coiled tubing, combinations thereof, or the like. The workstring 114 may be used to drill, stimulate, complete, or otherwise service the wellbore 106, or various combinations thereof.

[0014] As illustrated, the borehole 106 may extend vertically from the surface 104 over a vertical borehole section. In other embodiments, the borehole 106 may otherwise deviate at any angle from the surface 104 over a deviated or horizontal borehole section. In other applications, sections or substantially all of the borehole 106 may be vertical, deviated, horizontal, curved, or any combination thereof.Furthermore, the use of directional terms such as above, below, upper, lower, upward, downward, above, below and the like is used with respect to the illustrative embodiments as shown in the figures, wherein the upward direction is directed towards the top of the corresponding figure and the downward direction is directed towards the bottom of the corresponding figure, towards the surface of the borehole to the surface of the borehole and in the borehole to the bottom of the borehole.

[0015] In one embodiment, the wellbore 106 may be at least partially lined with a casing string 116 or may otherwise remain at least partially unlined. The casing string 116 may be secured within the wellbore 106, for example, using cement 118. In other embodiments, the casing string 116 may be only partially cemented within the wellbore 106, or alternatively, the casing string 116 may be omitted from the wellbore system 100 without departing from the scope of the disclosure.

[0016] The work string 114 may be coupled to a completion assembly 120 that extends into a branch or lateral section 122 of the wellbore 106. As illustrated, the lateral section 122 may be an unlined or "free-hole" section of the wellbore 106. It is noted that, although Fig. 1 depicts the completion assembly 120 as being disposed within the lateral portion 122 of the wellbore 106, the principles of the apparatus, systems, and methods disclosed herein may be similarly applicable or otherwise suitable to fully vertical wellbore configurations.

[0017] Accordingly, the horizontal or vertical nature of the wellbore 106 should not be construed to limit the present disclosure to any particular configuration of the wellbore 106.

[0018] The completion assembly 120 may be deployed within the lateral section 122 of the wellbore 106 using one or more packers 124 or other wellbore isolation devices known to those skilled in the art. The packers 124 may be configured to seal an annulus 126 defined between the completion assembly 120 and the inner wall of the wellbore 106. As a result, the subterranean formation 108 may be effectively divided into multiple intervals or "performance zones" 128 (shown as intervals 128a, 128b, and 128c), which may be independently stimulated, generated, or any combination thereof via isolated portions of the annulus 126 defined between adjacent pairs of packers 124.

[0019] While in Fig. 1 only three intervals 128a, 128b and 128c are shown, those skilled in the art will readily appreciate that any number of intervals 128a, 128b and 128c may be defined or otherwise used in the wellbore system 100, including a single interval, without departing from the scope of the disclosure.

[0020] The completion assembly 120 may include one or more sliding sleeve assemblies 130 (shown as sliding sleeve assemblies 130a, 130b, and 130c) disposed in, coupled to, or otherwise forming integral portions of the workstring 114. As illustrated, at least one sliding sleeve assembly 130a-c may be disposed in each interval 128a, 128b, and 128c; however, those skilled in the art will recognize that more than one sliding sleeve assembly 130a, 130b, and 130c may be disposed in each interval 128a, 128a, and 128c without departing from the scope of the disclosure. It should be noted that while the sliding sleeve assemblies 130a, 130b, and 130c are shown in Fig. 1 as deployed in a free-hole portion of the wellbore 106, the principles of the present disclosure apply equally to completed or cased portions of the wellbore 106. In such embodiments, a cased wellbore 106 may be perforated at predetermined locations in each interval 128a, 128b, and 128c to facilitate fluid conduction between the interior of the workstring 114 and the surrounding intervals 128a, 128b, and 128c of the formation 108.

[0021] Each sliding sleeve assembly 130a, 130b, and 130c is operable to provide fluid communication between the interior of the workstring 114 and the annulus 126 adjacent each corresponding interval 128a, 128b, and 128c. As illustrated, each sliding sleeve assembly 130a, 130b, and 130c may include a sliding sleeve 132 that is axially movable within the workstring 114 to expose one or more openings 134 defined by the workstring 114. The sliding sleeve 132 may include one or more actuators 109. When exposed, the openings 134 can facilitate fluid communication between the ring 126 and the interior of the workstring 114 so that stimulation and production operations can be performed in each corresponding interval 128a, 128b and 128c of the formation 108.

[0022] In accordance with the present disclosure, to move the sliding sleeve 132 of a particular sliding sleeve assembly 130a, 130b, and 130c to its open position and thereby expose the corresponding openings 134, one or more downhole darts 136 (shown as a first downhole dart 136a and a second downhole dart 136b) may be inserted into the workstring 114 and advanced downhole to the sliding sleeve assemblies 130a, 130b, and 130c. The downhole darts 136 may be advanced through the workstring 114 and to the completion assembly 120 by any known technique.

[0023] For example, the downhole arrows 136 may be dropped from the surface 104 through the workstring 114, pumped by flowing fluid through the interior of the workstring 114, self-propelled, conveyed by wireline, slickline, coiled tubing, etc.

[0024] Each downhole dart 136 may be detectable by one or more sensors 138 (shown as sensors 138a, 138b, and 138c) associated with each sliding sleeve assembly 130a, 130b, and 130c. In some embodiments, for example, the downhole darts 136 may have known magnetic properties, produce a known magnetic field, pattern, or combination of magnetic fields, or any combination thereof, that may be detected by the sensors 138a, 138b, and 138c. In such cases, each sensor 138a, 138b, and 138c may be capable of detecting the presence of the magnetic field(s) generated by the downhole darts 136, one or more other magnetic properties of the downhole darts 136, or both. Suitable magnetic sensors 138a, 138b and 138c may include, but are not limited to, magnetoresistive sensors, Hall effect sensors, conductive coils, combinations thereof, and the like.In some embodiments, permanent magnets may be combined with one or more of the sensors 138a, 138b, and 138c to create a magnetic field that is perturbed by the borehole arrows 136, and a detected change in the magnetic field may be an indication of the presence of the borehole arrows 136.

[0025] Furthermore, in some embodiments, each sensor 138a, 138b, and 138c may include a barrier (not shown) positioned between the sensors 138a, 138b, and 138c and the borehole arrows 136. The barrier may comprise a material with relatively low magnetic permeability and may be configured to allow magnetic signals to pass through and isolate the pressure between the sensors 138a, 138b, and 138c and the borehole arrows 136. Additional information regarding such a barrier as used in magnetic detection is included in U.S. Patent Pub. No. 2013 / 0264051.In other embodiments, a magnetic shield (not shown) may be positioned either on the downhole arrows 136 or near the sensors 138a, 138b, and 138c to "short-circuit" magnetic fields emitted by the downhole arrows 136, thereby reducing the amount of residual magnetic fields that may be detectable by the sensors 138a, 138b, and 138c. In such embodiments, the magnetic field may be attracted to materials having high magnetic permeability, effectively shielding the sensors 138a, 138b, and 138c from the residual magnetic fields.

[0026] In other embodiments, one or more of the sensors 138a, 138b, and 138c may be capable of detecting radio frequencies emitted by the downhole arrows 136. In such embodiments, the sensors 138a, 138b, and 138c may be radio frequency (RF) sensors or readers capable of detecting a radio frequency identification (RFID) tag attached to or otherwise forming part of the downhole arrows 136. The RF sensors 138a, 138b, and 138c may be configured to detect the RFID tags when the downhole arrows 136 traverse the workstring 114 and encounter the RF sensors 138a, 138b, and 138c. In at least one embodiment, the RF sensors 138a, 138b, and 138c may be microelectromechanical systems (MEMS) or devices capable of sensing radio frequencies.In such cases, the MEMS sensors may include or otherwise enclose an RF coil and thereby be used as sensors 138a, 138b, and 138c. Alternatively, the RF sensor 138a, 138b, and 138c may be a near-field communication (NFC) sensor capable of establishing radio communication with a corresponding dummy tag disposed on the borehole arrows 136. When the dummy tags come into proximity with the RF sensors 138a, 138b, and 138c, the RF sensors 138a, 138b, and 138c may detect the presence of the borehole arrows 136.

[0027] In still other embodiments, the sensors 138a, 138b, and 138c may be some type of mechanical switch or the like that can be mechanically manipulated by physical contact with the downhole arrows 136 as they traverse the workstring 114. In some cases, the mechanical sensors 138a, 138b, and 138c may be, for example, ratchet or mechanical counter devices or switches located near each sleeve 132. Upon physical contact and other interaction with the downhole arrows 136, the mechanical sensors 138a, 138b, and 138c may be configured to generate and transmit corresponding signals to an adjacent actuating device (in Fig. 1 not shown), as described below. In some embodiments, the mechanical sensors 138a, 138b, and 138c may be spring-loaded or otherwise configured so that the switch can autonomously reset after the downhole arrow 136 has passed (or after a certain period of time thereafter). It should be understood that such a resettable embodiment may allow the mechanical sensors 138a, 138b, 138c to physically interact with multiple downhole arrows 136.

[0028] Each sensor 138a, 138b and 138c can be connected to an associated electronic circuit (in Fig. 1 not shown) configured to determine whether the associated sensor 138a, 138b, and 138c has positively detected a borehole arrow 136. For example, in the case where the sensors 138a, 138b, and 138c are magnetic sensors, the sensors 138a, 138b, and 138c may detect a particular or predetermined magnetic field or pattern or combination of magnetic fields or other magnetic properties of the borehole arrows 136, and the associated electronic circuitry may have the predetermined magnetic field(s) or other magnetic properties programmed into non-volatile memory for comparison.Similarly, in the case where sensors 138a, 138b, and 138c are RF sensors, sensors 138a, 138b, and 138c may detect a particular RF signal from borehole arrows 136, and the associated electronic circuitry may either count the RF signals or compare the RF signals to RF signals programmed into the non-volatile memory.

[0029] Once a borehole arrow 136 is positively detected by the sensors 138a, 138b and 138c, the associated electronic circuit can confirm and count the detection instance and, if necessary, initiate the actuation of the corresponding sliding sleeve assembly 130a, 130b and 130c using one or more associated actuation devices (in Fig. 1 not shown). For example, in some embodiments, actuation of the associated sliding sleeve assembly 130a, 138b, and 138c may not be triggered until a predetermined number or combination of downhole darts 136 has been detected by the given sensors 138a, 138b, and 138c. Accordingly, each sensor 138a, 138b, and 138c records and counts the passage of each downhole dart 136, and once a predetermined number of downhole darts 136 are detected by a given sensor 138a, 138b, and 138c, the corresponding sliding sleeve assembly 130a, 130b, and 130c may then be actuated in response.

[0030] The completion assembly 120 may include as many sliding sleeve assemblies 130a, 130b, and 130c as necessary to perform a desired fracturing or stimulation operation in the subterranean formation 108. The electronic circuitry of each sliding sleeve assembly 130a, 130b, and 130c may be programmed with a predetermined "number" of downhole arrows 136. Upon reaching or otherwise registering the predetermined number of downhole arrows 136, each sliding sleeve assembly 130a, 130b, and 130c may then be actuated.In particular, the electronic circuitry associated with the third sliding sleeve assembly 130c may require the detection and counting of one borehole dart 136 before actuating the third sliding sleeve assembly 130c; the electronic circuitry associated with the second sliding sleeve assembly 130b may require the detection and counting of two borehole darts 136 before actuating the second sliding sleeve assembly 130b; and the electronic circuitry associated with the first sliding sleeve assembly 130a may require the detection and counting of three borehole darts 136 before actuating the first sliding sleeve assembly 130a.

[0031] In the illustrated embodiment, the first downhole dart 136a has been inserted into the workstring 114 and passed past each of the sensors 138a, 138b, and 138c, such that each sensor 138a, 138b, and 138c is capable of detecting the downhole dart 136a and incrementing the downhole dart count by one. Since the electronic circuitry associated with the third sliding sleeve assembly 130c is preprogrammed with a predetermined downhole dart count, upon detection of the first downhole dart 136a, the sliding sleeve 132 of the third sliding sleeve assembly 130c can be actuated to the open position. When the second downhole arrow 136b is advanced into the work string 114, the first and second sensors 138a, 138b may detect the second downhole arrow 136b and increase their respective “number” of downhole arrows to two.Since the electronic circuitry associated with the second sliding sleeve assembly 130b is pre-programmed with a predetermined "count" of two downhole arrows, upon detection of the second downhole arrow 136b, the sliding sleeve 132 of the second sliding sleeve assembly 130b can be actuated to the open position. When a third downhole arrow (not shown) is advanced into the workstring 114, the first sensor 138a can detect the third downhole arrow and increase its "count" of downhole arrows to three. Since the electronic circuitry associated with the first sliding sleeve assembly 130a is pre-programmed with a predetermined "count" of three downhole arrows, upon detection of the third downhole arrow, the sliding sleeve 132 of the first sliding sleeve assembly 130a can be actuated to the open position.

[0032] With reference to the Fig. 2A and Fig. 2B illustrates an exemplary borehole arrow 200 according to one or more embodiments of the present disclosure. The borehole arrow 200 may be similar to the borehole arrows 136 of Fig. 1. They may therefore be configured to be inserted into the borehole to interact with the sensors 138a-c of the sliding sleeve assemblies 130a, 130b, and 130c. Fig. 2A shows an isometric view of the borehole arrow 200 and Fig. Figure 2B shows a cross-sectional side view of the downhole dart 200. As illustrated, the downhole dart 200 may include a generally cylindrical body 202 having a plurality of collet fingers 204 that either form part of the body 202 or extend longitudinally therefrom. The body 202 may be constructed from a variety of materials, including, but not limited to, iron and iron alloys, steel and steel alloys, aluminum and aluminum alloys, magnesium and magnesium alloys, copper and copper alloys, plastics, composites, and any combination thereof. In other embodiments, as described in more detail below, all or a portion 202 of the body may be constructed from a degradable or soluble material without departing from the scope of the disclosure. In one or more embodiments, the downhole dart 200 may have a spherical or sphere-like body.

[0033] In at least one embodiment, the collet fingers 204 may be flexible axial extensions of the body 202 separated by elongated channels 206. An arrow profile 208 may be defined on the outer radial surface of the body 202, such as on the collet fingers 204. The arrow profile 208 may include or otherwise provide various features, constructions, configurations, and any combination thereof that enable the downhole arrow 200 to connect to a corresponding sleeve connection profile (not shown) formed on a desired sliding sleeve (e.g., the sliding sleeves 132 of Fig. 1) is defined.

[0034] The wellbore dart 200 may further include a dynamic seal 210 disposed around the outer or exterior surface of the body 202 at or near its wellbore end 212. As used herein, the term "dynamic seal" is used to refer to a seal that provides pressure, fluid isolation, or both between elements having relative displacement therebetween, for example, a seal that seals against a displacement surface or a seal carried on one element that seals against the other element. In some embodiments, the dynamic seal 210 may be disposed within a groove 214 defined on the outer surface of the body 202. The dynamic seal 210 may be made of a material selected from the following: elastomeric materials, non-elastomeric materials, metals, composites, rubbers, ceramics, derivatives thereof, and any combination thereof.In some embodiments, as in . Fig. 2B, the dynamic seal 210 may be an O-ring or the like. However, in other embodiments, the dynamic seal 210 may be a set of V-rings or CHEVRON® packing rings, or other suitable sealing configurations (e.g., seals that are round, V-shaped, U-shaped, square, oval, T-shaped, etc.) as is well known to those skilled in the art, or any combination thereof. As further described below, the dynamic seal 210 may be configured to "dynamically" seal against a sealing bore of a sliding sleeve (not shown).

[0035] The borehole arrow 200 may further include or otherwise include one or more detectable sensor components 216. As used herein, the term “sensor component” refers to any mechanism, device, element, or substance capable of communicating with the sensors 138a, 138b, and 138c of the sliding sleeve assemblies 130a, 130b, and 130c of Fig. 1 and thus confirm that the downhole dart 200 has come into proximity with a given sensor 138a, 138b, and 138c. For example, in some embodiments, the sensor components 216 may be magnets configured to interact with the magnetic sensors 138a, 138b, and 138c, as described above. However, in other embodiments, the sensor components 216 may be RFID tags (active or passive) that can be read or otherwise detected by a corresponding RFID reader associated with or otherwise including the sensors 138a, 138b, and 138c.

[0036] In some embodiments, the sensor components 216 may be arranged around the circumference of the borehole arrow 200, for example, positioned on one or more of the collet fingers 204. As best shown in Fig. 2B, the sensor components 216 can be seen in corresponding recesses 218 ( Fig. 2B) defined in the collet fingers 204. However, in other embodiments, the sensor components 216 may be attached to the outer radial surface of the collet fingers 204. In still other embodiments, the sensor components 216 may be positioned on the body 202 at or near the borehole end 212 or positioned on a combination of the body 202 and the collet fingers 204. In still further embodiments, the downhole dart 200 itself may be or otherwise include the sensor component 216. Stated differently, in some embodiments, the downhole dart 200 itself may be made of a material (e.g., magnets) or may otherwise include a mechanism, device (e.g., an RFID tag), element, or substance that communicates with the sensors 138a-c of the sliding sleeve assemblies 130a, 130b, and 130c of Fig. 1 and thus confirm that the borehole arrow 200 has come close to the given sensor 138a, 138b and 138c.

[0037] With reference to the Fig. 3A and Fig. 3B illustrates cross-sectional side views of an exemplary sliding sleeve assembly 300 according to one or more embodiments. Referring to the cross-sectional angle indicator provided in the center of the page, Fig. 3A is a cross-sectional side view of the sliding sleeve assembly 300 (hereinafter “the assembly 300”) along a vertical line and Fig. Figure 3B provides a cross-sectional view of the assembly 300 along a line offset 35° from the vertical (as in Fig. 3C). The assembly 300 may in some respects resemble one of the sliding sleeve assemblies 130a, 130b, 130c of Fig. 1. As illustrated, the assembly 300 may include an elongated completion body 302 defining an internal flow passage 304. The completion body 302 may have a first end 306a coupled to an upper unit 308a and a second end 306b coupled to a lower unit 308b. The assembly 300 may be part of a wellbore completion, such as the completion assembly 120 of Fig. 1. Accordingly, the upper and lower units 308a, 308b may be used to couple the completion body 302 to corresponding upper and lower portions of the completion bodies 120, the drive train 114, or both ( Fig. 1).

[0038] In some embodiments, the completion body 302 may include an electronics unit 310 and a terminal unit 312. The electronics unit 310 may be threaded or otherwise mechanically attached to the terminal unit 312 such that the completion body 302 forms a continuous, elongated, cylindrical structure. In other embodiments, the electronics unit 310 and the terminal unit 312 may be integrated as a monolithic structure without departing from the scope of the disclosure.

[0039] How best in Fig. 3A, the electronics unit 310 may define or otherwise provide an electronics cavity 314 in which the electronic circuitry 316, one or more sensors 318, and one or more batteries 320 (three shown) are housed. As best shown in Fig. 3B, the electronics unit 310 may further provide an actuating element 322 ( Fig. 3B). Batteries 320 may provide energy to operate electronic circuitry 316, sensors 318, and actuator 322. Sensors 318 may be similar to sensors 138a, 138b, and 138c of Fig. 1 and may therefore be capable of detecting a borehole arrow (not shown) traversing the assembly 300 via the internal flow passage 304.

[0040] The unit 312 with connections may include a sliding sleeve 324, one or more connections 326 ( Fig. 3A) and an actuating sleeve 328. The sliding sleeve 324 can be similar to the sliding sleeves 132 of Fig. 1 and can be movably arranged in the unit 312 with terminals. The terminals 326 can be similar to the terminals 134 of Fig. 1 and may be defined by the ported unit 312 to enable fluid communication between the inner flow passage 304 and an exterior of the ported unit 312, such as a surrounding subterranean formation (for example, the formation 108 of Fig. 1). In the Fig. 3A and Fig. 3B, the sliding sleeve 324 is shown in a closed position, in which the sliding sleeve 324 generally closes the openings 326, thereby preventing fluid communication therethrough. However, as described below, the sliding sleeve 324 can be moved axially within the ported unit 312 to an open position in which the ports 326 are exposed, thereby facilitating fluid communication therethrough.

[0041] With reference to Fig. 4A is an enlarged view of the sliding sleeve 324 and the actuating sleeve 328, as shown in Fig. 3B. In some embodiments, the sliding sleeve 324 may be secured in the closed position with one or more shearable devices 332 (one shown). In the illustrated embodiment, the shearable devices 332 may include one or more shear pins extending from the terminal assembly 312 (e.g., the completion body 302) into corresponding blind bores 402 defined on the outer surface of the sliding sleeve 324. In other embodiments, the shearable devices 332 may be a shear ring or other device or mechanism configured to shear or otherwise fail upon receiving a predetermined shear load applied to the sliding sleeve 324.

[0042] The sliding sleeve 324 may further include one or more dynamic seals 404 (two shown) disposed between the outer surface of the sliding sleeve 324 and the inner surface of the ported assembly 312. The dynamic seals 404 may be configured to provide fluid isolation between the sliding sleeve 324 and the ported assembly 312, thereby preventing fluid migration through the openings 326 ( Fig. 3A) and into the inner flow passage 304 when the sliding sleeve 324 is in the closed position. The dynamic seals 404 can be connected to the dynamic seal 210 from the Fig. 2A and Fig. 2B and therefore will not be described again. In at least one embodiment, as illustrated, one or both of the dynamic seals 404a, b may be an O-ring.

[0043] In some embodiments, the sliding sleeve 324 may further include a locking ring 406 disposed or positioned within a locking ring groove 408 defined in the sliding sleeve 324. The locking ring 406 may, for example, be an expandable C-ring that expands upon locating a locking ring mating groove 410 ( Fig. 3A and Fig. 3B). Accordingly, when the sliding sleeve 324 moves to its open position, as described below, the locking ring 406 may be located in the locking ring counter groove 410 and expand, thereby preventing the sliding sleeve 324 from moving back to the closed position.

[0044] The sliding sleeve 324 may further provide a sealing bore 412 and a sleeve connection profile 414 defined on the inner radial surface of the sliding sleeve 324. As illustrated, the sealing bore 412 may be disposed in a direction into the borehole from the sleeve connection profile 414, but may equally be disposed at either end (or at an intermediate location) of the sliding sleeve 324 without departing from the scope of the disclosure. As described below, the arrow profile 208 of the borehole arrow 200 of the Fig. 2A and Fig. 2B may be configured to match or otherwise correspond to the sleeve connection profile 414 of the sliding sleeve 324.

[0045] The actuating sleeve 328 may also be movable within the unit 312 with connections between an inlet configuration as shown in the Fig. 3A and Fig. 3B and Fig. 4A, and arranged in an actuated configuration as shown in the Fig. 5A, Fig. 5B and Fig. 5C. In some embodiments, a hydraulic cavity 416 may be defined between the actuating sleeve 328 and the unit 312 with ports (e.g., the completion body 302) and sealed at each end with suitable sealing devices 418, such as O-rings or the like. In such embodiments, the hydraulic cavity 416 may be fluidly connected to the electronics cavity 314 ( Fig. 3A). The hydraulic cavity 416 may be filled with a hydraulic fluid such as silicone oil and maintained at an elevated pressure relative to the electronics cavity 314, which may be at ambient pressure.

[0046] The actuating sleeve 328 may include or otherwise provide an axial extension 422 that extends within at least a portion of the sliding sleeve 324. When the actuating sleeve 328 is in its run-in configuration, as shown in Fig. 4A, the axial extension 422 may be configured to cover or otherwise close the sleeve connection profile 414. As a result, wellbore darts passing through the inner flow passage 304 may not connect with the sleeve connection profile 414. A wiper ring 424, such as an O-ring or the like, may be disposed between the axial extension 422 and the inner radial surface of the sliding sleeve 324 to protect the sleeve connection profile 414 by preventing dirt and sand from entering the sleeve connection profile 414.

[0047] With reference to the Fig. 4B is an enlarged view of the actuator 322 as shown in Fig. 3B. The actuator 322 may be any mechanical, electromechanical, hydraulic, or pneumatic actuating device that can manipulate the configuration or position of the actuating sleeve 328. Accordingly, the actuator 322 may be any device that can be used or otherwise triggered to move the actuating sleeve 328 from its run-in configuration ( Fig. 3A and Fig. 3B and Fig. 4A) into its actuated configuration ( Fig. 5A, Fig. 5B and Fig. 5C). In the illustrated embodiment, the actuating element 322 is an electro-hydraulic piston lock that includes a motor 426 and a frangible element 428. The frangible element 428 may be, for example, a rupture disc or a pressure barrier that prevents the pressurized hydraulic fluid within the hydraulic cavity 416 from escaping via the hydraulic line 420 ( Fig. 3B and Fig. 4A) into the electronics cavity 314 ( Fig. 3A). Accordingly, a pressure differential is maintained between the electronic and hydraulic cavities 314, 416 across the frangible element 428 while it is intact.

[0048] The engine 426 can be communicatively connected to the electronic circuit 316 ( Fig. 3A), which, as described above, is communicatively coupled to the sensors 318. When the sensor(s) 318 positively detect a borehole arrow or a predetermined number of borehole arrows, the electronic circuit 316 can send an actuation signal to the actuation element 322.

[0049] The actuation element 322 may include a chemical charge 430 that is triggered upon receipt of the actuation signal, and the ignition of the chemical charge 430 may force the thruster 426 into the frangible element 428 to rupture or penetrate the frangible element 428. Upon rupture of the frangible element 428, the pressurized hydraulic fluid within the hydraulic cavity 416 may escape via the hydraulic line 420 into the electronics cavity 314 to achieve pressure equilibrium.

[0050] With further reference to Fig. 3B, when the pressurized hydraulic fluid within the hydraulic cavity 416 seeks pressure equilibrium by rushing into the electronics cavity 314, a pressure differential is created across the actuating sleeve 328. This created pressure differential may cause the actuating sleeve 328 to move toward the surface of the wellbore into the actuated configuration (for example, to the left in Fig. 3B), as in the Fig. 5A, Fig. 5B and Fig. 5C. Moving the actuating sleeve 328 into the actuated configuration may cause the sleeve connection profile 414 ( Fig. 4A).

[0051] With further reference to Fig. 3A and in addition to the Fig. 5A, Fig. 5B and Fig. 5C, an exemplary operation of the assembly 300 is provided. In particular, the Fig. 3A and Fig. 5A, Fig. 5B and Fig. 5C show progressive cross-sectional views of the assembly 300 during actuation of the sliding sleeve 324 as it moves between its closed and open positions. It is understood that the operation of the assembly 300 may include the operation of one of the sliding sleeve assemblies 130a, 130b, and 130c. Fig. 1 can describe equally.

[0052] In Fig. 3A, the assembly 300 is shown in a “gate” or closed configuration, with the sliding sleeve 324 generally closing the ports 326 defined in the completion body 302 of the assembly 300.

[0053] In Fig. 5A, a first borehole arrow 502a is depicted as being inserted into the work string 114 ( Fig. 1) and conveyed to and through the assembly 300. The first borehole arrow 502a may be associated with the borehole arrow 200 of the Fig. 2A and Fig. 2B and will therefore not be described again. As illustrated, the first borehole arrow 502a has passed through the inner flow passage 304 in the borehole from the sensor 318 and is extending in a direction extending into the borehole (e.g., to the right in Fig. 5A). In some embodiments, the first borehole arrow 502a may be projected from the surface 104 ( Fig. 1) using hydraulic pressure to the assembly 300. In other embodiments, the first downhole arrow 502a may be pumped through the work string 114 ( Fig. 1) be dropped from the surface 104 until it locates the assembly 300. In still other embodiments, the first downhole dart 502a may be conveyed through the workstring 114 by wireline, slickline, coiled tubing, etc., or it may be self-propelled until it locates the assembly 300. In still other embodiments, any combination of the above techniques may be used to convey the first downhole dart 502a to the assembly 300.

[0054] When the first borehole arrow 502a passes or is in close proximity to the sensor 318, the sensor 318 may detect the presence of the first borehole arrow 502a and send a detection signal to the electronic circuit 316 indicating the same. The electronic circuit 316 may, in turn, register a "count" of the first borehole arrow 502a and a total count of how many borehole arrows (including the first borehole arrow 502a) have passed the assembly 300. When a predetermined number of borehole arrows (including the first borehole arrow 502a) have been counted, the electronic circuit 316 may be programmed to actuate the assembly 300. In particular, when the predetermined number of borehole arrows has been detected and otherwise registered, the electronic circuit 316 may send an actuation signal to the actuating element 322 ( Fig. 3B and Fig. 4B) that the actuating sleeve 328 from the inlet configuration as shown in Fig. 3A, moved into the actuated configuration as shown in the Fig. 5A, Fig. 5B and Fig. 5C.

[0055] In some embodiments, as mentioned above, the actuator 322 may be any mechanical, electromechanical, hydraulic, or pneumatic actuator capable of translating the actuator sleeve 328 from the inlet configuration to the actuated configuration. However, in other embodiments, as mentioned above with reference to Fig. 4B, the actuating element 322 may be an electro-hydraulic piston lock that includes the thruster 426 and the frangible element 428, which provides a pressure barrier between the electronics cavity 314 and the hydraulic cavity 416. Upon receiving the actuation signal, the thruster 426 penetrates the frangible element 428, and the pressurized hydraulic fluid within the hydraulic cavity 416 escapes via the hydraulic line 420 into the electronics cavity 314 while seeking pressure equilibrium. As the hydraulic fluid escapes from the hydraulic cavity 416, a pressure differential is created across the actuating sleeve 328, urging the actuating sleeve 328 to move into the actuation configuration.

[0056] With reference to Fig. 5A, as the actuating sleeve 328 moves into its actuating configuration, the sleeve connection profile 414 is gradually exposed to the internal flow passage 304 as the axial extension 422 of the actuating sleeve 328 moves toward the surface of the wellbore. With the sleeve connection profile 414 exposed, each subsequent wellbore dart inserted into the internal flow passage 304 can mate with the sleeve connection profile 414.

[0057] Fig. 5B shows a second borehole arrow 502b inserted into the work string 114 ( Fig. 1) and transported to the assembly 300. Similar to the first borehole arrow 502a ( Fig. 5A), the second borehole arrow 502b can correspond to the borehole arrow 200 of the Fig. 2A and Fig. 2B and will therefore not be described again. Furthermore, the first and second borehole arrows 502a, 502b may have the same arrow profile (for example, the arrow profile 208 of Fig. 2A and Fig. 2B). Upon locating the assembly 300, the second borehole arrow 502b may be configured to connect to the sliding sleeve 324.

[0058] With brief reference to Fig. 6 is an enlarged view of the second borehole arrow 502b illustrating how it connects to the sliding sleeve 324, as shown in the dashed area of Fig. 5B, according to one or more embodiments. Upon locating the assembly 300, the wellbore end 212 of the second wellbore arrow 502b may be configured to enter the sealing bore 412 provided on the inner radial surface of the sliding sleeve 324. The dynamic seal 210 of the second wellbore arrow 502b may be configured to engage and seal against the sealing bore 412, thereby allowing the fluid pressure behind the second wellbore arrow 502b to increase.

[0059] The arrow profile 208 of the second borehole arrow 502b may be configured to mate with or otherwise correspond to the sleeve connection profile 414 of the sliding sleeve 324. Accordingly, upon locating the assembly 300, the arrow profile 208 may connect and otherwise engage the sleeve connection profile 414, effectively stopping the progression into the borehole of the second borehole arrow 502b. Once the arrow profile 208 is axially and radially aligned with the sleeve mating profile 414, the collet fingers 204 of the second borehole arrow 502b may be configured to spring radially outward, thereby connecting the second borehole arrow 502b to the sliding sleeve 324.

[0060] With reference again to the Fig. 5A, Fig. 5B and Fig. 5C and in particular Fig. 5C, when the arrow profile 208 is successfully connected to the sleeve connection profile 414, an operator can increase the fluid pressure within the work string 114 ( Fig. 1) and the inner flow passage 304 above the second borehole arrow 502b to move the sliding sleeve 324 to the open position.

[0061] The dynamic seal 210 ( Fig. 6) of the second wellbore arrow 502b may be configured to substantially prevent the migration of high-pressure fluids past the second wellbore arrow 502b in the direction into the wellbore. As a result, the fluid pressure above the second wellbore arrow 502b may be increased. Furthermore, the one or more shearable devices 332 may be configured to maintain the sliding sleeve 324 in the closed position until a predetermined shear load is assumed. As the fluid pressure within the inner flow passage 304 increases, the increased pressure acts on the second wellbore arrow 502b, which in turn acts on the sliding sleeve 324 via the connecting engagement between the arrow profile 208 and the sleeve connecting profile 414. Accordingly, increasing the fluid pressure within the workstring 114 ( Fig. 1) serve to increase the shear load assumed by the shearable devices 332 that hold the sliding sleeve 324 in the closed position.

[0062] The fluid pressure may increase until a predetermined pressure threshold is reached, resulting in the absorption of the predetermined shear load by the shearable devices 332 and their subsequent failure. Once the shearable devices 332 fail, the sliding sleeve 324 may be free to slide axially within the ported unit 312 to the open position, as shown in Fig. 5C. When the sliding sleeve 324 is in the open position, the ports 326 are exposed, and a well operator can then perform one or more downhole operations, such as stimulating a surrounding formation (for example, the formation 108 of Fig. 1).

[0063] Following stimulation operations, in at least one embodiment, a drill or mill (not shown) may be introduced into the wellbore to drill out the second wellbore arrow 502b, thereby facilitating fluid communication past the assembly 300. While important, those skilled in the art will appreciate that this process requires valuable time and resources. However, according to the present disclosure, the wellbore arrows may be made at least partially from a soluble or degradable material to avoid the time-consuming requirement of drilling wellbore arrows to facilitate fluid communication therethrough.As used herein, the term “degradable material” refers to any material or substance capable of or otherwise configured to degrade or dissolve after a predetermined period of time or after interaction with a particular wellbore environment (e.g., temperature, pressure, wellbore fluid, etc.), treatment fluid, etc.

[0064] With further reference to Fig. 2B, in some embodiments, the entire borehole arrow 200 may be made of a degradable material. In other embodiments, only a portion of the borehole arrow 200 may be made of the degradable material. For example, in some embodiments, all or a portion of the borehole end 212 of the body 202 may be made of the degradable material. For example, as illustrated, the body 202 may further include a tip 220 that forms an integral part of the body 202 or is otherwise coupled thereto. In the illustrated embodiment, the tip 220 may be threadedly coupled to the body 202. However, in other embodiments, the tip 220 may alternatively be welded, soldered, glued, or mechanically attached to the body 202 without departing from the scope of the disclosure.Upon completion of the stimulation processes, the degradable material may be configured to dissolve or degrade, thereby forming a full bore inner diameter through the sliding sleeve assemblies 130a, 130b and 130c (. Fig. 1) remains without the need for milling or drilling.

[0065] Suitable degradable materials that may be used according to embodiments of the present disclosure include borate glasses, polyglycolic acid, and polylactic acid. Polyglycolic acid and polylactic acid tend to degrade by hydrolysis as temperature increases. Other suitable degradable materials include oil-degradable polymers, which may be either natural or synthetic polymers and include, among others, polyacrylates, polyamides, and polyolefins such as polyethylene, polypropylene, polyisobutylene, and polystyrene. Other suitable oil-degradable polymers include those that have a melting point such that they dissolve at the temperature of the subterranean formation into which they are introduced.

[0066] In addition to oil-degradable polymers, other degradable materials that may be used in connection with embodiments of the present disclosure include, but are not limited to, degradable polymers, dehydrated salts, or mixtures of the two. For degradable polymers, a polymer is considered "degradable" if the in situ degradation is due to a chemical or radical process such as hydrolysis, oxidation, or UV radiation. Suitable examples of degradable polymers that may be used according to embodiments of the present invention include polysaccharides such as dextran or cellulose; chitins; chitosans; proteins; aliphatic polyesters; poly(lactides); poly(glycolides); poly(ε-caprolactones); poly(hydroxybutyrates); poly(anhydrides); aliphatic or aromatic polycarbonates; poly(orthoesters); poly(amino acids); poly(ethylene oxides); and polyphosphazenes.Of these suitable polymers, as mentioned above, polyglycolic acid and polylactic acid may be preferred.

[0067] Polyanhydrides are another type of particularly suitable degradable polymer useful in embodiments of the present invention. Polyanhydride hydrolysis proceeds in situ via free carboxylic acid chain ends, yielding carboxylic acids as the final degradation products. The erosion time can be varied over a wide range of changes in the polymer backbone. Examples of suitable polyanhydrides include poly(adipic anhydride), poly(suberic anhydride), poly(sebacic anhydride), and poly(dodecanedioic anhydride). Other suitable examples include, but are not limited to, poly(maleic anhydride) and poly(benzoic anhydride).

[0068] Mixtures of certain degradable materials may also be suitable. One example of a suitable material mixture is a mixture of polylactic acid and sodium borate, although mixing an acid and a base could result in a neutral solution where desirable. Another example would include a mixture of poly(lactic acid) and boron oxide. The choice of degradable material may also depend, at least in part, on wellbore conditions, such as the wellbore temperature. For example, lactides have been found to be suitable for lower-temperature wells, including those in the 60°F to 150°F range, and polylactides have been shown to be suitable for wellbore temperatures above this range. Poly(lactic acid) may also be suitable for higher-temperature wells.Some stereoisomers of poly(lactide) or mixtures of such stereoisomers may be suitable for applications at even higher temperatures. Dehydrated salts may also be suitable for drilling at higher temperatures.

[0069] In other embodiments, the degradable material may be a galvanically corrodible metal or a material configured to be degraded via an electrochemical process in which the galvanically corrodible metal corrodes in the presence of an electrolyte (e.g., brine or other saline fluids in a borehole). Suitable galvanically corrodible metals include, but are not limited to, gold, gold-platinum alloys, silver, nickel, nickel-copper alloys, nickel-chromium alloys, copper, copper alloys (e.g., brass, bronze, etc.), chromium, tin, aluminum, iron, zinc, magnesium, and beryllium.

[0070] Fig. 7A shows a section of a horizontal wellbore with a production tubular 610. One or more packers 604a, 604b, 604c, and 604d and one or more sliding sleeve tools 606a, 606b, and 606c may be arranged or positioned on or around the production tubular 610. In one or more embodiments, sliding sleeve tools may include a sliding sleeve 132 and may be deployed downhole, as shown in Fig. 1. The one or more packers 604a, 604b, 604c, and 604d (collectively referred to as packer 604) and one or more sliding sleeve tools 606a, 606b, and 606c (collectively referred to as sliding sleeve tools 606). The packers 604 and the sliding sleeve tools 606 may be arranged in an alternating pattern as shown in Fig. 7A, or another suitable configuration. Sliding sleeve tools 606 may include nodes 615a, 615b, and 615c (collectively, node 615). In one or more embodiments, nodes 615a, 615b, and 615c may be electrical or telecommunications connectors.

[0071] The wireline 710 may be coupled to one or more sliding sleeve tools 606, for example, sliding sleeve tools 606a, 606b, and 606c, via one or more nodes 615, for example, nodes 615a, 615b, and 615c. The wireline 710 may transmit an electrical signal from one node 615 to another node 615, for example, from node 615a to node 615b or node 615b to node 615c, or any combination thereof. In one or more embodiments, the wireline 710 may be coupled to one or more tools on the surface (such as surface 104), for example, the information management system 804 of Fig. 8. The wireline 710 may comprise a fiber optic cable, an electrical cable, a network cable, a communications cable, or any other type of cable used to transmit power, a signal, or both. In one or more embodiments, one or more nodes 615 may be coupled via the signal path 712. The signal path 712 may be any mode for wirelessly coupling one or more nodes 615, for example, an RFID signal, an acoustic signal, or any other form of wireless transmission.

[0072] The Fig. 7B and Fig. 7C are detailed views of the sliding sleeve tool 606a. Fig. Figure 7B illustrates the sliding sleeve tool 606a in a closed configuration, while Fig. 7C shows the sliding sleeve tool 606a in an open configuration. Since the sliding sleeve tools 606a, 606b, and 606c are the same, substantially the same, or function or operate in the same or similar manner, the following description of the structure and operation of the sliding sleeve tool 606a similarly applies to the sliding sleeve tools 606b and 606c. As in Fig. 7B, the sliding sleeve tool 606a includes an actuation element 614 and an electronic device 608. The electronic device 608 may include an actuation sensor 609. The actuation sensor 609 may be configured to detect one or more flow rate signals. A flow rate signal may be selected by the operator, the information management system 804, Fig. 8 or both to control the rate of fluid flow in the wellbore. One or more sliding sleeve tools 606 may be controlled by one or more flow rate signals. For example, each sliding sleeve tool 606 may be responsive to a different flow rate signal. In one or more embodiments, a flow rate signal may indicate a command to multiple sliding sleeve tools 606. The sliding sleeve tool 606a may include a collapsible baffle 615. A chamber 616 may be disposed or positioned over or around an outer surface 618 of the sliding sleeve tool 606a. The chamber 616 may be coupled to the sliding sleeve tool 606a. In one or more embodiments, the chamber 616 may be coupled to a downhole sliding sleeve tool 606a within a wellbore 106 of Fig. 1. In one or more embodiments, the actuating element 614 may be arranged or positioned within or around the chamber 616. For example, the chamber 616 may receive the actuating element 614. The collapsible baffle 615 may collapse when fluid is introduced into a chamber 616.

[0073] The sliding sleeve tool 606a may include one or more of the communication ports 620 arranged or positioned circumferentially around the sliding sleeve tool 606a. The communication ports 620 allow the fluid 702 to flow between the workstring 114 and the formation 108 when the sliding sleeve tool 606a is in an open configuration, as shown in Fig. 7C. In one or more embodiments, the sliding sleeve tool 606a may include a sliding sleeve 622. The sliding sleeve 622 may transition from a closed configuration to an open configuration based at least in part on one or more flow rate signals.

[0074] By configuring the sliding sleeve tools 606 as shown in the Fig. 7A, Fig. 7B and Fig. 7C, the sliding sleeve tools 606 may be opened or closed sequentially. The sequential opening of the sliding sleeve tools 606 provides for the sequential completion of the production zones 120a-120f adjacent to each sliding sleeve tool 606. In one or more embodiments, a ball 624 may be dropped, injected, fired, or otherwise disposed or positioned into the wellbore to move the sliding sleeve 622 from a closed configuration to an open configuration. In one or more embodiments, one or more flow rate signals may move the sliding sleeve 622 from a closed position to an open position. When the baffles 615 are in an open configuration, a ball 624 may pass through the sliding sleeve tool 606a and then to a distal end of the wellbore.When the baffle plate 615 is folded, a ball 624 may be caught, trapped, or otherwise detected by the baffle plate 615. The ball 624 may form a seal against the baffle plate 615.

[0075] As fluid 702 is pumped into wellbore 106 and through sliding sleeve 622, ball 624 prevents fluid 702 from flowing distally or end-to-end through sliding sleeve tool 606a, causing a buildup of hydraulic pressure behind ball 624. The hydraulic pressure exerts a force on ball 624 and baffle plate 615. Once the pressure reaches a threshold, sliding sleeve 622 is forced into an open configuration, exposing ports 620 to the wellbore.

[0076] In one or more embodiments, baffles 615 may be deployed in one or more sliding sleeve tools 606 based at least in part on one or more flow rate signals. Extending one or more baffles 615 may include passing over or otherwise landing a ball 624 or otherwise positioning or disposing a ball on one or more of the baffles 615. In one or more embodiments, one or more sliding sleeve tools 606 may be opened, closed, or both based at least in part on one or more flow rate signals. In one or more embodiments, the sliding sleeve tools 606 are translated by the one or more flow signals or the ball 624.In one or more embodiments, one or more of a sliding sleeve tool 606 may transition to open and a lower sliding sleeve tool 606 may transition to closed based at least in part on one or more flow rate signals. In one or more embodiments, one or more of the sliding sleeve tools 606 may open and a flapper valve may close based at least in part on the one or more flow rate signals. In one or more embodiments, one or more baffles 615 and one or more sliding sleeve tools 606 may be deployed based at least in part on one or more flow rate signals.

[0077] In one or more embodiments, a completion operation may require only one flow rate signal per sliding sleeve tool 606. In one or more embodiments, sliding sleeve tools 606 may be required to perform additional functions, and additional flow rate signals may be required.

[0078] In one or more embodiments, the electronic device 608 may further include a property sensor 610. In one or more embodiments, the property sensor 610 may be battery-operated and may not require a wired connection. The property sensor 610 may include one or more magnetic sensors, temperature sensors, fluid flow sensors, pressure sensors, and other types of sensors that can measure one or more properties of a zone associated with the sliding sleeve 622, the production tubing 610, the actuator 614, the wellbore 106, or any combination thereof. The electronic device 608 may include a housing 612 that isolates the property sensor 610 from a fluid, a gas, a particle, another fluid or material, or any combination thereof.The property sensor 610 may measure or sense one or more flow properties, temperature properties, or other properties or characteristics associated with the wellbore 106, the production tubing 610, the actuator 614, a portion of any of the aforementioned properties associated with the property sensor 610, or any combination thereof. For example, in one or more embodiments, the property sensor 610 may include a thermometer that monitors the temperature of a fluid 702 flowing into a formation 108 of a particular zone 128 of the wellbore 106. In one or more embodiments, the thermometer may be a device for measuring the temperature or temperature change within the wellbore 106.In one or more embodiments, the thermometer may be a thermocouple, an optical thermometer, a digital thermostat, integrated circuit temperature devices, a thermistor, a resistance thermometer, a thermoelectric sensor, or any other device capable of measuring a temperature.

[0079] In one or more embodiments, the flow rate of a fluid 702 may be determined by measuring a cooling effect. During an injection process, one or more stimulation fluids, for example, fluid 702, may reduce the temperature around the thermometer in a wellbore. As one of skill in the art would appreciate, by measuring the extent of temperature cooling and the duration of the temperature cooling, the amount of fluid stimulation fluid injected into a wellbore 106 or a particular zone 128 of a wellbore 106 may be estimated. Comparing the extent of temperature cooling, the duration of the temperature cooling, or both between thermometers in one or more zones 128 may enable a determination of the relative uptake of one or more fluids 702 into the one or more zones 128. The relative uptake of one or more fluids 702 may be a function of the operational states of the stimulation.For example, during early production, a zone that has received more stimulation fluid may have a reduced temperature (because the stimulation fluid has cooled the formation) compared to a zone that has received less stimulation fluid. In later production, the production of fluids may result in a local temperature change due to the Joule-Thomson effect. The magnitude and sign (direction) of the Joule-Thomson effect may vary for different fluids and may be used as a relative estimate of the composition of a produced fluid. In one or more embodiments, an operator may use the absolute temperature indicated by the thermometer or the relative temperature change between flowing and non-flowing conditions to estimate one or more parameters associated with a fluid 702.The estimated parameter can be a flow rate, the total injected fluid volume, or any other parameter associated with the fluid flow.

[0080] In one or more embodiments, the electronic device 608 may further include a transceiver 611. The transceiver 611 may be coupled either directly or indirectly to the property sensor 610. The transceiver 611 may receive one or more measurements from the property sensor 610. The transceiver 611 may transmit a signal based on the one or more measurements received from the sensor 610 to the surface or to another transceiver, for example, a transceiver 611 associated with the sliding sleeve tool 606. The transceiver 611 may transmit the signal via an acoustic wave or via an electromagnetic wave. In one or more embodiments, the transceiver 611 may be a piezoelectric transducer that generates an acoustic wave that propagates through the tubular, the formation, the wellbore fluids, or any combination thereof.In one or more embodiments, transceiver 611 transmits a signal from one sleeve portion to a second sleeve portion, for example, from sleeve tool 606a to sleeve tool 606b. In one or more embodiments, transceiver 611 transmits a signal from one sleeve portion, for example, sleeve tool 606a, to a wireline tool being advanced through the interior of the tubing string. The signal may be received by an information management system, for example, information handling system 804. Fig. 8. The information management system 804 may calculate or determine a flow rate of a fluid 702 associated with the sliding sleeve tool 606a based at least in part on one or more signals received from the transceiver 611, wherein the one or more signals are associated with one or more further measurements received from a sensor 610. In one or more embodiments, the electronic device 608, the property sensor 610, the transceiver 611, or any combination thereof may be battery-operated.

[0081] Fig. 8 is a block diagram illustrating an information management system 804 and other electronic components of a sliding sleeve tool 606 according to one or more embodiments of the present disclosure. In one or more embodiments, the information management system 804 communicates with one or more actuators 810 to operate the sliding sleeve tool 606a. The information management system 804 may send a signal to one or more sliding sleeve tools 606 to change a configuration, position, mode, or any combination thereof of the one or more sleeve tools 606.In one or more embodiments, one or more actuators 810 may comprise any suitable actuator, including an electromagnetic device such as a motor, a gearbox, a linear screw, a magnetic actuator, a piezoelectric actuator, a hydraulic pump, a chemically activated actuator, a heat-activated actuator, a pressure-activated actuator, or any combination thereof.

[0082] The information management system 804 may be coupled either directly or indirectly to one or more transceivers 611. In one or more embodiments, the information management system 804 may be coupled to only one transceiver, for example, the transceiver 611 associated with a sliding sleeve tool 606. In one or more embodiments, the information management system 804 may be coupled to one or more transceivers 611 associated with one or more sliding sleeve tools 606. The information management system 804 may be connected to one or more transceivers 611 either by an electrical line, for example, a wireline 710, or wirelessly, for example, via a signal path 712.The information management system 804 may include a memory 808 for storing information from one or more transceivers 611, for example, one or more measurements received by a transceiver 611 from the property sensor 610. The information management system 804 may further include a processor 806 for processing the information. For example, the information delivery system 804 may include a processor for calculating a flow rate of the fluid 702 associated with one or more sliding sleeve tools 606.

[0083] The information management system 804 may determine or calculate one or more properties or characteristics of a fracture 144 at or near a property sensor 610, based at least in part on information received from an associated transceiver 611. For example, a property or characteristic determined or calculated by the information management system 804 may be associated with an area or zone at a threshold distance from the property sensor 610, for example, up to 30 feet from the property sensor 610. In one or more embodiments, the property sensor 610 measures one or more properties of the fluid as it flows past the property sensor 610.In one or more embodiments, the information management system 804 may determine or calculate a flow rate of a fluid 702, a pump-down time, a production estimate, or any combination thereof based at least in part on information from the transceiver 611. The information management system 804 may change or adjust operation of a sliding sleeve tool 606. For example, the information management system 804 may send a signal to actuate a sliding sleeve tool 606 based at least in part on a determined or calculated property or characteristic. In one or more embodiments, the information management system 804 may send a signal to one or more actuators 614 to disable or cease actuation of a sliding sleeve tool 606.

[0084] In one or more embodiments, a production operation may be changed or adjusted based at least in part on one or more flow rate characteristics of one or more production zones 120 determined or calculated by the information management system 804. For example, the optimal zone for production may be determined by comparing the flow rate characteristics of each production zone 120. Single-point entry techniques or multi-point entry techniques may then be used, based at least in part on the comparison of the flow rate characteristics of one or more production zones 120. A production operation may be set or changed manually by an operator or automatically by the information management system 804, or both.For example, in one or more embodiments, one or more flow rate characteristics determined or calculated by the information management system 804 may be output to an operator. In one or more embodiments, a control signal may be transmitted or communicated from the information management system 804 to the sliding sleeve tool 606 to change, increase, decrease, adjust, or otherwise alter the amount or rate of fluid 702, for example, a stimulation fluid, injected into the production tubing 610 or the wellbore 106. For example, an operator may enter a command based at least in part on one or more determined or calculated flow rate characteristics that cause the information handling system 804 to send the control signal.In one or more embodiments, the information management system 804 may automatically send a control signal to change, increase, decrease, adjust, or otherwise alter the amount or rate of fluid 702 injected into the production tubing 610 or the wellbore 106.

[0085] Fig. 9 is a flowchart of a method 900 according to one or more embodiments of the present disclosure. The steps of method 900 may be performed by various computer programs or non-transitory computer-readable media, which may include one or more instructions that are executable or capable of performing one or more steps described below when executed by a processor. The computer programs and computer-readable media may be configured to instruct a processor or other suitable device to retrieve and execute the instructions from the computer-readable media.

[0086] In step 902, one or more sliding sleeve tools, for example, the sliding sleeve tool 606a, may be positioned or arranged in a borehole 106. The sliding sleeve tool 606a may be connected by a wireline or cable, for example, the wireline 140 of Fig. 1, positioned or arranged as understood by one of ordinary skill in the art. For example, the sliding sleeve tool 606a can be used in well stimulation operations such as multi-entry sliding sleeves, single-entry sliding sleeves, and ground sleeves.

[0087] At step 904, the sliding sleeve 622 may be actuated within the wellbore 106. In one or more embodiments, the sliding sleeve 622 may be actuated in response to one or more flow rate signals via the baffle 615, as described with respect to the Fig. 7A, Fig. 7B and Fig. 7C. One or more flow signals may cause a baffle 615 to extend. The extension of one or more baffles 615 may cause a ball 624 to land against a baffle 615. When fluid, for example, fluid 702, is pumped into the wellbore 106, the ball 624 prevents the fluid 702 from flowing through the sliding sleeve tool 606a, causing hydraulic pressure to build up behind the ball 624. The hydraulic pressure exerts a force on the ball 624 and the baffle 615. Once the pressure reaches a threshold, the sliding sleeve 622 is forced into an open configuration, exposing ports 620 to the wellbore 106. In one or more embodiments, the sliding sleeve 622 may be actuated in response to one or more wellbore arrows 502a, as discussed with respect to the Fig. 5A, Fig. 5B and Fig. 5C. The sliding sleeve 622 may be activated at least in part based on the detection of a predetermined number of borehole arrows, for example, borehole arrow 200 of Fig. 2A or borehole arrow 502a from Fig. 5A can be operated.

[0088] In step 906, a production zone 120 associated with a fracture 144 of the wellbore 106 may be stimulated. In one or more embodiments, a stimulation fluid, for example, fluid 702, may be automatically injected into the wellbore 106 when the sliding sleeve 622 is actuated in step 904. In one or more embodiments, an operator may manually initiate the stimulation process upon actuation of the sliding sleeve 622. Stimulation of a production zone 120 may be accomplished via one or more methods as understood by one of ordinary skill in the art.

[0089] In step 908, one or more properties of a production zone 120 may be measured via a property sensor 610. As shown in the Fig. 7B and Fig. 7C, the property sensor 610 may be a magnetic sensor, a temperature sensor, a fluid flow sensor, a pressure sensor, or another type of sensor capable of measuring a property or characteristic of a particular production zone 120 of the wellbore 106. The property sensor 610 may determine a flow rate, temperature, or any other element, characteristic, or property of the production zone 120.

[0090] In step 910, a property or feature measured by the property sensor 610 may be stored and transmitted to the surface 104, for example, to the information management system 804 of Fig. 8. Borehole information, for example, one or more measurements associated with a property sensor 610, may be transmitted to the surface 104 via the transceiver 611, as shown in the Fig. 7B and Fig. 7C. Transceiver 611 may be coupled directly or indirectly to property sensor 610. In one or more embodiments, electronic device 608 may include memory for storing the information downhole. Downhole or surface memory may consist of RAM, ROM, solid-state memory, hard-disk-based memory, or other memory as understood by one of ordinary skill in the art.

[0091] In step 912, information received at the surface from information management system 804 may be processed by a processor. The processor may be communicatively coupled to memory. The processor may include, for example, a microprocessor, a microcontroller, a digital signal processor, an application-specific integrated circuit, or other digital or analog circuitry configured to process the information. Information management system 804 may process the information to determine or calculate an output, for example, the flow rate of the stimulation fluid, as shown in step 914. A property or characteristic of a fracture 144 or a production zone 120 may be calculated or determined based at least in part on a flow rate of stimulation fluid, for example, fluid 702.For example, the flow rate of the stimulation fluid may be correlated with the size of a fracture 144 or another property or characteristic of the fracture 144.

[0092] In step 916, a well treatment or production operation may be modified based at least in part on the calculated or determined flow rate of the stimulation fluid in step 914. As described above with respect to Fig. 8, the well treatment or production operation may be changed manually by an operator or automatically by the information management system 804. For example, the operator or the information management system 804 may send a control signal to change, increase, decrease, adjust, or otherwise alter the pressure or velocity of the stimulation fluid injected into the production tubing 610 or the wellbore 106. Embodiments disclosed herein include the following:

[0093] A. A sliding sleeve assembly comprising: a completion body defining an internal flow channel and one or more openings allowing fluid communication between the internal flow channel and an exterior of the completion body; a sliding sleeve disposed within the completion body and having a sleeve connection profile defined on an interior surface of the sliding sleeve, the sliding sleeve movable between a closed position in which the sliding sleeve closes the one or more ports and an open position in which the sliding sleeve is moved to expose the one or more ports; a plurality of downhole darts each having a body and an arrow profile defined on an exterior surface of the body, the arrow profile of each downhole dart being connectable to the sleeve connection profile;one or more sensors positioned on the completion body to detect the plurality of wellbore arrows traversing the internal flow channel; and an actuating sleeve disposed within the completion body and movable between an inlet configuration, in which the actuating sleeve closes the sleeve connection profile, and an actuated configuration, in which the actuating sleeve is moved to expose the sleeve connection profile.

[0094] B. A method comprising: inserting one or more downhole arrows into a workstring extended within a wellbore, the workstring providing a sliding sleeve assembly including a completion body defining an internal flow channel and one or more ports enabling fluid communication between the internal flow channel and an exterior surface of the completion body, the sliding sleeve assembly further including a sliding sleeve disposed within the completion body and defining a sleeve connection profile on an interior surface of the sliding sleeve; detecting the one or more downhole arrows with one or more sensors positioned on the completion body, the one or more downhole arrows each having a body and an arrow profile defined on an exterior surface of the body;Moving an actuating sleeve disposed in the completion body from an inlet configuration to an actuated configuration when the one or more sensors detect a predetermined number of the one or more wellbore arrows, exposing the sleeve connection profile when the actuating sleeve moves to the actuated configuration, locating one of the one or more wellbore arrows on the sliding sleeve when the arrow profile of the one or more wellbore arrows connects with the sleeve connection profile, increasing fluid pressure within the drill string above the one or more wellbore arrows, and moving the sliding sleeve from a closed position in which the sliding sleeve closes the one or more ports to an open position in which the one or more ports are exposed.;

[0095] Each of embodiments A and B may include one or more of the following elements in any combination: Element 1: further comprising an electronic circuit communicatively coupled to the one or more sensors, and an actuating element communicatively coupled to the electronic circuit, wherein when the one or more sensors detect a predetermined number of the plurality of downhole darts, the electronic circuit sends an actuating signal to the actuating element to move the actuating sleeve into the actuated configuration. Element 2: wherein the actuating element is selected from the group consisting of a mechanical actuator, an electromechanical actuator, a hydraulic actuator, a pneumatic actuator, and any combination thereof. Element 3: wherein the actuating element is an electrohydraulic piston lock.Element 4: wherein each downhole arrow has a known magnetic property detectable by the one or more sensors. Element 5: wherein each downhole arrow emits a radio frequency detectable by the one or more sensors. Element 6: wherein the one or more sensors are mechanical switches that are mechanically manipulated by physical contact with the plurality of downhole arrows as each downhole arrow traverses the internal flow channel. Element 7: wherein at least a portion of the body of each downhole arrow is made from a material selected from the group consisting of iron, an iron alloy, steel, a steel alloy, aluminum, an aluminum alloy, copper, a copper alloy, plastic, a composite material, a degradable material, and any combination thereof.Element 8: wherein the degradable material is a material selected from the group consisting of a borate glass, a galvanically corrodible metal, polyglycolic acid, polylactic acid, and any combination thereof. Element 9: wherein the actuating sleeve has an axial extension extending within at least a portion of the sliding sleeve to close the sleeve connection profile.

[0096] Element 10: wherein the sliding sleeve assembly further includes electronic circuitry communicatively coupled to the one or more sensors, and wherein detecting the one or more downhole arrows with the one or more sensors comprises sending a detection signal to the electronic circuitry with the one or more sensors upon detecting each downhole arrow and counting with the electronic circuitry how many downhole arrows were detected by the one or more sensors based on each received detection signal.Element 11: wherein the sliding sleeve assembly further includes an actuation element communicatively coupled to the electronic circuit, and wherein moving the actuation sleeve further comprises sending an actuation signal to the actuation element with the electronic circuit when the one or more sensors detect the predetermined number of the one or more downhole darts, and actuating the actuation sleeve with the actuation element into the actuated configuration upon receiving the actuation signal. Element 12: wherein detecting the one or more downhole darts with the one or more sensors comprises detecting a known magnetic property exhibited by the one or more downhole darts.Element 13: wherein detecting the one or more downhole arrows with the one or more sensors comprises detecting a radio frequency emitted by the one or more downhole arrows. Element 14: wherein the one or more sensors are mechanical switches, and wherein detecting the one or more downhole arrows with the one or more sensors comprises physically contacting the one or more sensors with the one or more downhole arrows as the one or more downhole arrows traverse the internal flow channel.Element 15: wherein increasing the fluid pressure within the workstring above the subsequent one or more wellbore arrows further comprises creating a pressure differential across the one of the one or more wellbore arrows and thereby transmitting an axial load to the sliding sleeve and one or more shearable devices securing the sliding sleeve in the closed position, and receiving a predetermined axial load with the one or more shearable devices such that the one or more shearable devices fail and thereby allow the sliding sleeve to move to the open position. Element 16: further comprising introducing a treatment fluid into the workstring, injecting the treatment fluid into a surrounding subterranean formation via the one or more openings, and releasing the fluid pressure within the workstring.Element 17: wherein at least a portion of the one or more downhole arrows is made of a degradable material selected from the group consisting of a borate glass, a galvanically corrodible metal, polyglycolic acid, polylactic acid, and any combination thereof, the method further comprising enabling the degradable material to be degraded. Element 18: further comprising inserting a drill bit into the workstring and advancing the drill bit to one of the one or more downhole arrows, and drilling out the one or more downhole arrows with the drill bit.

[0097] For example, embodiment A can be used with elements 1, 2, and 3; with elements 1, 7, and 8; with elements 1, 7, 8, and 10; with elements 1, 4, and 5, etc.

[0098] As a further example, embodiment B can be used with elements 12 and 13; with elements 12, 13 and 14; with elements 15 and 16; with elements 16, 17 and 18, etc.

[0099] C. A method for determining a property of a production zone, comprising: positioning a sliding sleeve tool within a wellbore, actuating the sliding sleeve tool, wherein the actuation is initiated at least in part based on one or more measurements received by an actuation sensor; stimulating a production zone with a stimulation fluid, detecting one or more properties of the wellbore based at least in part on one or more measurements received by a property sensor; determining a parameter of the stimulation fluid from at least one of the one or more properties.

[0100] D. A system for determining a property of a production zone, comprising: a sliding sleeve tool, wherein the sliding sleeve tool is disposed on a production tubular, and wherein the sliding sleeve tool further comprises: an actuation sensor, a property sensor; and a transceiver coupled to the property sensor; an information management system communicatively coupled to the transceiver, the information management system comprising a processor and non-transitory memory coupled to the processor, the non-transitory memory comprising one or more instructions that, when executed by the processor, cause the processor to position the sliding sleeve tool within a wellbore;Actuating a sliding sleeve tool based at least in part on one or more measurements received from the actuation sensor, stimulating a production zone with a stimulation fluid, detecting one or more properties of the wellbore based at least in part on one or more further measurements received from the property sensor, and determining a parameter of the stimulation fluid;

[0101] E. A non-transitory computer-readable storage medium storing one or more instructions that, when executed by the processor, cause the processor to: position a sliding sleeve tool within a wellbore, actuate the sliding sleeve tool based at least in part on one or more measurements received by an actuation sensor, stimulate a production zone with a stimulation fluid, detect one or more properties of the wellbore based at least in part on one or more measurements received by the property sensor, and determine a flow rate of the stimulation fluid.

[0102] Each of embodiments C, D, and E may comprise one or more of the following elements in any combination: Element 1: wherein the property sensor is disposed adjacent to the sliding sleeve tool. Element 2: wherein the property sensor is a battery-operated sensor. Element 3: wherein the one or more measurements received by the property sensor is a temperature measurement. Element 4: wherein the parameter of the stimulation fluid is a flow rate or a total volume of the stimulation fluid. Element 5: further comprising altering a well treatment operation based at least in part on the flow rate of the simulation fluid. Element 6: further comprising storing the one or more measurements received by the property in a memory.Element 7: further comprising wirelessly transmitting the one or more measurements received by the property sensor to the surface, to a downhole tool within the borehole, or both. Element 8: further comprising determining a relative acceptability of the stimulation fluid based at least in part on the parameter of the stimulation fluid. Element 9: wherein the information management system is wirelessly communicatively coupled to the transceiver. Element 10: wherein the one or more instructions, when executed by the processor, further cause the processor to store the one or more measurements received by the property sensor in a memory.

[0103] Therefore, the disclosed systems and methods are well suited to achieving the stated and inherent goals and advantages. The particular disclosed embodiments are illustrative only, and the teachings of the present disclosure may be modified and practiced in different but equivalent ways as will be apparent to one skilled in the art having the benefit of the present teachings. Furthermore, no limitations are intended with respect to the details of the construction or embodiment shown herein other than those described in the following claims. It is thus to be understood that the particular illustrative embodiments disclosed above may be changed, combined, or modified, and that all such variations are considered to be within the scope of the present disclosure.The systems and methods illustratively disclosed herein may be conveniently practiced omitting any elements not specifically disclosed herein and any optional elements disclosed herein. Although compositions and methods have been described as "comprising," "containing," or "including" various components or steps, the compositions and methods may also "consist essentially of" or "consist" of the various components and steps. All of the numbers and ranges disclosed above may vary by some amount. Whenever a numerical range having a lower limit and an upper limit is disclosed, each number and range included therein that falls within that range is also expressly disclosed.In particular, any range of values disclosed herein (of the form "from about a to about b" or equivalently "from about a to b" or equivalently "from about ab") is deemed to include any number or range falling within the broader range of values. Furthermore, unless expressly and clearly defined otherwise by the patentee, the terms in the claims are to have their plain, ordinary meaning. The indefinite articles "a," "an," "an," "an" in the claims are defined to mean one or more of the elements to which they are prefixed.

Claims

[1] A method for determining a property of a production zone, comprising: Positioning a sliding sleeve tool within a borehole, the sliding sleeve tool having an electronics housing; Actuating the sliding sleeve tool, wherein the actuation is initiated at least in part based on one or more measurements received by an actuation sensor, the actuation sensor being disposed within the electronics housing; Stimulating a production zone with a stimulation fluid; Detecting one or more properties of the borehole based at least in part on one or more measurements received by a property sensor, the property sensor being disposed within the electronics housing; Determining a parameter of the stimulation fluid from at least one of the one or more properties and Determining a relative uptake of the stimulation fluid based at least in part on the stimulation fluid parameter. [2] The method of claim 1, wherein the property sensor is disposed adjacent to the sliding sleeve tool. [3] Method according to one of the preceding claims, wherein the property sensor is a battery-operated sensor. [4] A method according to any one of the preceding claims, wherein the one or more measurements received by the property sensor is a temperature measurement. [5] A method according to any one of the preceding claims, wherein the parameter of the stimulation fluid is a flow rate or a total volume of the stimulation fluid. [6] The method of claim 5, further comprising: Modifying a well treatment operation based at least in part on the flow rate of the simulation fluid. [7] A method according to any one of the preceding claims, further comprising: Storing the one or more measurements received by the property in a memory. [8] A method according to any one of the preceding claims, further comprising: Transmitting the one or more measurements received by the property sensor wirelessly to the surface, to a downhole tool within the borehole, or to both. [9] System for determining a characteristic of a production zone, comprising: a sliding sleeve tool, wherein the sliding sleeve tool is arranged on a production pipe and wherein the sliding sleeve tool further comprises: an electronics housing, an actuation sensor arranged within the electronics housing; a property sensor arranged within the electronics housing; and a transceiver coupled to the property sensor; an information management system communicatively connected to the transceiver, the information management system comprising: a processor; and a non-transitory memory coupled to the processor, the non-transitory memory comprising one or more instructions that, when executed by the processor, cause the processor to: Positioning the sliding sleeve tool within a borehole; Actuating the sliding sleeve tool based at least in part on one or more measurements received by the actuation sensor; Stimulating one or more production zones with a stimulation fluid; Detecting one or more properties of the borehole based at least in part on one or more measurements received by the property sensor; Determining a parameter of the stimulation fluid, and Determining a relative uptake of the stimulation fluid for the one or more production zones based at least in part on the stimulation fluid parameter. [10] The system of claim 9, wherein the property sensor is disposed adjacent to the sliding sleeve tool. [11] The system of claim 9 or 10, wherein the property sensor is battery powered. [12] The system of any one of claims 9 to 11, wherein the parameter of the stimulation fluid is a flow rate or a total volume of the stimulation fluid. [13] The system of claim 12, wherein the one or more instructions, when executed by the processor, further cause the processor to alter a well treatment operation based at least in part on the flow rate of the stimulation fluid. [14] The system of any one of claims 9 to 13, wherein the information management system is wirelessly communicatively coupled to the transceiver. [15] Non-transitory computer-readable storage medium that stores one or more instructions that, when executed by the processor, cause the processor to: Positioning a sliding sleeve tool within a borehole, the sliding sleeve tool having an electronics housing; Actuating the sliding sleeve tool based at least in part on one or more measurements received by an actuation sensor, the actuation sensor being disposed within the electronics housing; Stimulating one or more production zones with a stimulation fluid; Detecting one or more properties of the borehole based at least in part on one or more measurements received by a property sensor, the property sensor being disposed within the electronics housing; Determining a flow rate of the stimulation fluid and Determining a relative acceptance of the stimulation fluid for the one or more production zones based at least in part on the flow rate of the stimulation fluid. [16] The non-transitory computer-readable storage medium of claim 15, wherein the one or more instructions, when executed by the processor, further cause the processor to alter a well treatment operation based at least in part on the flow rate of the stimulation fluid. [17] The non-transitory computer-readable storage medium of claim 15 or 16, wherein the one or more instructions, when executed by the processor, further cause the processor to wirelessly transmit the one or more measurements received by the property sensor. [18] The non-transitory computer-readable storage medium of claim 15, 16 or 17, wherein the one or more instructions, when executed by the processor, further cause the processor to store the one or more measurements received by the property sensor in a memory.

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