SLICK SENSOR ARRAY SYSTEM AND METHOD TO SEAL PRESSURE SENSORS

Description

BACKGROUND

Field

Embodiments of the present disclosure generally relate to a downhole sensor array system. In particular, the disclosure relates to a downhole sensor array system for downhole data collection.

Description of the Related Art

Permanent downhole sensor systems are deployed in oil and gas wells to monitor pressure and temperature within the wellbore, primarily for reservoir surveillance, production optimization, and well integrity. These sensors are powered from the surface and utilize bi-directional communication via an electrical control line. Typically housed in a 0.25″ alloy tube, the control line may contain a single conductor cable, twisted pair, or coaxial cable. To enhance durability, the tube is occasionally encased in a polymer during installation. Positioned at the cable's end, the sensors accommodates pressure and temperature transducers along with associated electronics, often with diameters of 1″ or 0.75″. These sensors are mounted in carriers along the completion tubing string and can be ported either inside the production tubing or within the annulus between the production tubing and casing. Up to eight sensors can be connected to a single 0.25″ tube, typically terminated using pressure-testable, swaged metallic compression fittings or welded directly onto the tube.

However, these conventional systems are only capable of providing single-point logging, which necessitates repetitive repositioning of these systems at various depths for temporary sensor systems, or only provides a limited number of sensor points for permanent sensor systems. This can make data collection time consuming and yields only singular measurements per instance. Further, the size and shape of the conventional systems tend to be non-uniform, making them ineffective for measuring properties in confined annular spaces or outside the casing, where the sensors are encased in cement. Thus, the conventional systems lack of size and shape uniformity makes installation slower, more difficult, and less reliable.

Therefore, a more effective and compact sensor system for downhole measurements are needed.

SUMMARY

In one embodiment, a downhole sensor array system is disclosed. The downhole sensor array system includes a tube encapsulation cable (TEC) and a downhole sensor array disposed within the TEC. The downhole sensor array includes one or more temperature sensors, one or more pressure sensors, and one or more printed circuit boards (PCBs).

In one embodiment, a method of forming a downhole sensor array systen is disclosed. The method of forming a downhole sensor array system includes splicing one or more temperature sensors, one or more pressure sensors, and one or more printed circuit boards (PCBs) into a raw cable to form a downhole sensor array, forming a protective layer around the downhole sensor array to form an encapsulated cable, and forming an outer jacket around the encapsulated cable to form a tube encapsulated cable (TEC). The TEC has an outer diameter of about 0.5 in to about 0.75 in.

In one embodiment, a method of downhole measurement collection is disclosed. The method includes deploying a downhole sensor array system into a well. The downhole sensor array system includes a tube encapsulation cable (TEC) having a diameter of about 0.5 in to about 0.75 in. A downhole sensor array is housed within the TEC. The downhole sensor array includes one or more temperature sensors, one or more pressure sensors, and one or more printed circuit boards (PCBs). Data is collected along a length of a well using the downhole sensor array system. Data collected from the downhole sensor array system is received at a controller.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the present disclosure can be understood in detail, a more particular description of the disclosure, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only exemplary embodiments and are therefore not to be considered limiting of its scope, may admit to other equally effective embodiments.

FIG. 1 is a downhole sensor array system deployed in a well, according to embodiments of the disclosure.

FIG. 2A is a longitudinal section of a downhole sensor array system, according to embodiments of the disclosure.

FIG. 2B is a cross-sectional view of the downhole sensor array system 100 at cut-line 2B-2B, according to embodiments of the disclosure.

FIG. 2C is a cross-sectional view of the downhole sensor array system 100 at cut-line 2C-2C

FIG. 2D is a cross-sectional view of the downhole sensor array system 100 at cut-line 2D-2D

FIG. 3A is a cross-sectional view of a pressure sensor, a PCB and the boss disposed in the TEC at cut-line 3A-3A, according to embodiments of the disclosure.

FIG. 3B is a cross-sectional view of a first boss and its connection to and orientation relative to the pressure sensor, according to embodiments of the disclosure.

FIG. 3C is a perspective view of the first boss, according to embodiments of the disclosure.

FIG. 3D is a cross-sectional view of a second boss and its connection to and orientation relative to the pressure sensor, according to embodiments of the disclosure.

FIG. 3E is a perspective view of the second boss, according to embodiments of the disclosure.

FIG. 3F is a third boss and its connection to and orientation relative to the pressure sensor, according to embodiments of the disclosure.

FIG. 3G is a perspective view of the third boss, according to embodiments of the disclosure.

FIG. 4 is a method of forming a downhole sensor array system, according to embodiments of the disclosure.

FIG. 5A is a schematic view of a mill, according to embodiments of the disclosure.

FIG. 5B is a cross-sectional view of a raw cable, according to embodiments of the disclosure.

FIG. 5C is a cross-sectional view of a temperature sensor, according to embodiments of the disclosure.

FIG. 5D is a side view of the temperature sensor, according to embodiments of the disclosure.

FIG. 5E is a cross-sectional view of the temperature sensor spliced into the raw cable, according to embodiments of the disclosure.

FIG. 5F is a side view of the temperature sensor spliced into the raw cable, according to embodiments of the disclosure.

FIG. 5G is a cross-sectional view of a boss spliced into the raw cable, according to embodiments of the disclosure.

FIG. 5H is a cross-sectional view of an encapsulated cable, according to embodiments of the disclosure.

FIG. 5I is a cross-sectional view of the temperature sensor disposed within the encapsulated cable, according to embodiments of the disclosure.

FIG. 5J is a cross-sectional view of the boss disposed within the encapsulated cable, according to embodiments of the disclosure.

FIG. 5K is a cross-sectional view of the temperature sensor disposed in a TEC, according to embodiments of the disclosure.

FIG. 5L is a cross-sectional view of the TEC, according to embodiments of the disclosure.

FIG. 5M is a cross-sectional view of the boss disposed in the TEC, according to embodiments of the disclosure.

FIG. 6 is a method of downhole measurement collection, according to embodiments of the disclosure.

To facilitate understanding, identical reference numerals have been used, where possible, to designate identical elements that are common to the figures. It is contemplated that elements and features of one embodiment may be beneficially incorporated in other embodiments without further recitation.

DETAILED DESCRIPTION

Embodiments of the present disclosure generally relate to a downhole sensor array system. In particular, the disclosure relates to a downhole sensor array system for downhole data collection.

A downhole sensor array system includes a tube encapsulation cable (TEC) and a downhole sensor array disposed within the TEC. The downhole sensor array includes one or more temperature sensors, one or more pressure sensors, and one or more printed circuit boards (PCBs). The downhole sensor array system is formed by splicing one or more temperature sensors, one or more pressure sensors, and one or more printed circuit boards (PCBs) into a raw cable to form a downhole sensor array, forming a protective layer around the downhole sensor array to form an encapsulated cable, and forming an outer jacket around the encapsulated cable to form a tube encapsulated cable (TEC). The TEC has an outer diameter of about 0.5 in to about 0.75 in. The downhole sensor array system collects measurements downhole deploying a downhole sensor array system into a well. Data is collected along a length of a well using the downhole sensor array system. Data collected from the downhole sensor array system is received at a controller.

FIG. 1 is a downhole sensor array system 100 deployed in a well 102. The well 102 includes a wellbore 105, a casing 104, a production tubing 106, cement 114, and a wellhead 108. The wellbore 105 is drilled into ground 101 to reach a reservoir 103. The reservoir 103 contains a volume of a resource, such as oil, gas, or a resource pumped into the reservoir 103 from the surface for storage (e.g., natural gas, a refined petroleum based liquid, or carbon dioxide). In some embodiments, the wellbore 105 is substantially vertical. In other embodiments, the wellbore 105 may be vertical, horizontal, combinations thereof, or iterations therebetween.

A first volume 110 is defined by the production tubing 106, e.g., the first volume is annularly surrounded by the production tubing 106. The casing 104 annularly surrounds the production tubing 106. The casing 104 is typically cemented in place using cement 114. A plurality of perforations 107 are formed through the cement 114. The perforations 107 are formed into the reservoir 103 to enable flow of the resource from the reservoir 103 into the casing 104 and the production tubing 106.

An annular seal 116 is formed above the reservoir 103 and annularly surrounds the production tubing 106 between the casing 104 and the production tubing 106. A second volume 112 is defined by the production tubing 106, the casing 104, and the annular seal 116. The annular seal 116 prevents the flow of the resource into the second volume 112.

The wellhead 108 provides a structural and pressure-containing interface for the well 102 at the surface. The wellhead 108 includes, for example, a tree 122 comprising a plurality of valves, casing spools, and fittings. The tree 122 is configured to regulate the flow of the production tubing 106, among other functions.

In various embodiments, the downhole sensor array system 100 can be disposed within the cement 114, in the first volume 110, in the second volume 112, or in a combination thereof. In some embodiments, deployment of the downhole sensor array system 100 in the first volume 110 may be temporary deployment. In other embodiments, the deployment of the downhole sensor array system 100 in the first volume may be a permanent deployment. A fluid identification sensor 118 or a gauge carrier 124 may be coupled to a downhole end of the downhole sensor array system 100. The gauge carrier 124 is configured to house the downhole end of the downhole sensor array system 100 and provide balanced shock absorbing for the downhole sensor array system 100. The gauge carrier 124 can be coupled to the production tubing 106 and provide a pressure port to the first volume 110 and/or the second volume 112.

A controller 130 is configured to receive data or input from the downhole sensor array system 100. The downhole sensor array system 100 includes one or more sensors, e.g., temperature sensors, pressure sensors, and vibration sensors, as will be described in further detail below. The wellhead 108 further includes a wellhead outlet 132. The downhole sensor array system 100 exits the wellhead 108 via the wellhead outlet 132. In the event of a breach of the downhole sensor array system 100, in which a resource migrates up the inside of the downhole sensor array system 100, the wellhead outlet 132 includes a pressure barrier to prevent the resource from flowing out the wellhead 108. The controller 130 includes a memory 134, support circuits 136, and a central processing unit (CPU) 138 (e.g., a processor). The controller 130 controls and powers various components of the downhole sensor array system 100 directly, or via other computers and/or controllers.

The controller 130 is any form of general purpose computer processor that is used in an industrial setting for controlling the downhole sensor array system 100. The memory 134, or non-transitory computer readable medium, is one or more of a readily available memory such as random access memory (RAM), dynamic random access memory (DRAM), static RAM (SRAM), and synchronous dynamic RAM (SDRAM) (e.g., DDR1, DDR2, DDR3, DDRL3,LPDDR3, DDR4, LPDDR4, and the like)), read only memory (ROM), floppy disk, hard disk, flash drive, or any other form of digital storage, local or remote. The support circuits 136 of the controller 130 are coupled to the CPU 138 for supporting the CPU 138. The support circuits 136 include cache, power supplies, clock circuits, input/output circuitry and subsystems, data interface options for transferring data to a user or other third party networks, and the like. Operational parameters and operations are stored in the memory 134 as a software routine that is executed or invoked to turn the controller 130 into a specific purpose controller to control the operations of the various downhole sensor array systems 100 and, in some embodiments, a stuffing box when deploying the downhole sensor array system 100 a live well 102. The controller 130 is configured to conduct any of the operations described herein. The instructions stored on the memory 134, when executed, cause one or more of the operations (such as operations of the method 600) described herein to be conducted in relation to the downhole sensor array system 100. The controller 130 and the downhole sensor array system 100 are at least part of a system for monitoring operations of the well 102.

The various operations described herein can be conducted automatically using the controller 130, or can be conducted automatically or manually with certain operations conducted by a user.

FIG. 2A is a longitudinal section of a downhole sensor array system 100. The downhole sensor array system 100 includes a tube encapsulated cable (TEC) 202 encapsulating a downhole sensor array 201. The downhole sensor array 201 includes one or more pressure sensors 204, one or more temperature sensors 206, and one or more printed circuit boards (PCBs) 208. The downhole sensor array system 100 enables high bandwidth, low power consumption assessment of the well 102 through a single uniform cable, such as the TEC 202. In some embodiments, the one or more temperature sensors 206 may have up to 100 temperature sensors in between the one or more pressure sensors 204. The one or more pressure sensors 204 may include up to 100 pressure sensors. The one or more PCBs 208 may include up to 100 PCBs.

Upon deployment, the downhole sensor array system 100 is configured to conduct a comprehensive survey of the well 102, rapidly delivering data from the one or more pressure sensors 204 and the one or more temperature sensors 206, on demand or as pre-instructed, along the length of the well 102. The rapid retrieval of data from the length of the well 102 reduces the amount of time required to accurately assess the condition of the well 102. Furthermore, the downhole sensor array system 100 enables rapid data retrieval and processing without the use of fiber-optic sensing technologies, such as Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS), and without the need for additional data handling or interpretation software.

In some embodiments, the one or more temperature sensors 206 and the one or more PCBs 208 include 3-axis vibration sensors. In some embodiments, the vibration sensors are configured to detect inclination, vibration, and acoustic noise. The detection of inclination and acoustic noise enables diagnostics of the well 102 during production or injection. The downhole sensor array system 100 may further include a one or more additional sensors, such as inclination sensors, acoustic sensors, density sensors, viscosity sensors, permittivity sensors, conductivity sensors, pH sensors, flow rate sensors, water cut sensors, carbon dioxide sensors, other suitable sensors for downhole data collection, or a combination thereof. The one or more pressure sensors 204, one or more temperature sensors 206, the one or more PCBs 208, and the one or more additional sensors are connected via a one or more wires 210. The one or more wires 210 are configured to relay data from, and provide power to, the one or more pressure sensors 204, one or more temperature sensors 206, the one or more PCBs 208, and the one or more additional sensors to the controller 130.

The TEC 202 has a diameter of, for example, about 0.5 in to about 0.75 in, such as about 0.625 in. The downhole sensor array 201 (e.g., the one or more pressure sensors 204, the one or more temperature sensors 206, and the one or more PCBs 208) is disposed entirely within the TEC 202, thus requiring a slightly larger diameter to house sensors typically disposed exterior to the TEC 202. Currently, the pressure sensors 204 and the temperature sensors 206 can be sized to have a reduced diameter of about 0.5 in to about 0.75 in, such as about 0.625 in to enable the sensors to be housed within the TEC 202. The diameter of the one or more pressure sensors 204 and the one or more temperature sensors 206 is slightly less than the diameter of the TEC 202 to facilitate receipt within the TEC 202.

The diameter of the TEC 202 is constant along the length of the TEC 202 (e.g., the diameter of the TEC 202 is uniform along the length of the TEC 202). The diameter of the TEC 202 enables uniform delivery of the TEC 202 downhole using conventional pressure control equipment, such as a conventional stuffing box, increasing the ease, speed, and reliability of installation when temporarily deploying the downhole sensor array system 100 into the production tubing 106. The use of conventional equipment is further facilitated by having a slick TEC 202 which facilitates delivery of the TEC 202 downhole using the conventional stuffing box. By housing the one or more pressure sensors 204, one or more temperature sensors 206, and one or more PCBs 208 in the TEC 202, assembly/fabrication of the downhole sensor system can occur offsite, eliminating assembly/fabrication on the drilling floor, as these sensors and PCBs are housed in the slick TEC 202 and the entire TEC 202 can run through the stuffing box.

Further, the diameter of the TEC 202 enables the TEC 202 to be deployed in confined annular spaces, such as the second volume 112, and outside of the casing 104. The constant diameter of the TEC 202 facilitates cement circulation during cementing of the casing 104 in the cement 114 when the TEC 202 is deployed outside of the casing 104 (e.g., within the cement 114). The ability to ensure cement circulation facilitates deployment outside of the casing 104 and enables uniform cement thickness control outside of the casing 104, thus enhancing the integrity of the well 102.

FIG. 2B is a cross-sectional view of the downhole sensor array system 100 at cut-line 2B-2B. A temperature sensor 206A of the one or more temperature sensors 206 is surrounded by an encapsulation material 255. One or more filler wires (e.g., a first filler wire 280A) and one or more wires 210 (e.g., a first wire 210A and a second wire 210B) are disposed adjacent to the temperature sensor 206A and are disposed exterior to the encapsulation material 255. As will be explained if further detail below, the first wire 210A and the second wire 210B extend past the temperature sensor 206A through the TEC 202 to reach the one or more pressure sensors 204 and one or more PCBs 208. The one or more filler wires include a plastic wire, a steel wire, or a fiber yarn (e.g., Kevlar).

The temperature sensor 206A includes a temperature sensor PCB 208B. One or more of the wires 210 (e.g., a third wire 210C, a fourth wire 210D, a fifth wire 210E, and a sixth wire 210F) are disposed within the encapsulation material 255 and connect to the temperature sensor PCB 208B. The space within the encapsulation material 255 that is not occupied by the temperature sensor 206A is filled with a filler material 258. The filler material 258 includes specialist potting compounds such as hot melt, unsaturated polyesters, urethanes, epoxies, and resins. The encapsulation material 255, the first filler wire 280A, the first wire 210A, and the second wire 210B are further encapsulated with a protective layer 250, and the protective layer 250 is surrounded by an outer jacket 252. The protective layer 250 includes a polymer, such as fluorinated ethylenepropylene (FEP). The outer jacket 252 includes a metallic material, such as stainless-steel or nickel alloy.

FIG. 2C is a cross-sectional view of the downhole sensor array system 100 at cut-line 2C-2C. The one or more wires (e.g., the first wire 210A, the second wire 210B, the third wire 210C, the fourth wire 210D, the fifth wire 210E, and the sixth wire 210F) extend along the TEC 202, along with the one or more filler wires 280 (e.g., the first filler wire 280A, a second filler wire 280B, a third filler wire 280C, and a fourth filler wire 280D). The one or more filler wires 280 (e.g., the first filler wire 280A, the second filler wire 280B, the third filler wire 280C, and the fourth filler wire 280D) provide stability and strain relief along the length of the TEC 202. The TEC 202 connects to the controller 130 via a connection cable (not shown). In some embodiments, the connection cable may include a similar cable architecture to the TEC (e.g., the connection cable includes a first wire, a second wire, a third wire, a fourth wire, a fifth wire, a the sixth wire, a first filler wire, a second filler wire, a third filler wire, and a fourth filler wire). In another embodiment, the connection cable contains only the first wire, the second wire, and fillers. The fillers ensure the outer diameter remains constant between the TEC 202 and the connection cable.

FIG. 2D is a cross-sectional view of the downhole sensor array system 100 at cut-line 2D-2D. A boss 240 is disposed within the TEC 202. The boss 240 includes wire channel 222 that is sealably disposed longitudinally through the boss 240 and enables the one or more wires (e.g., the first wire 210A, the second wire 210B, the third wire 210C, the fourth wire 210D, the fifth wire 210E, and the sixth wire 210F) to pass through the boss 240 along the TEC 202 in order to relay measurements from the downhole sensor array system 100 to the controller 130. The boss 240 further includes anchor points 260, a one or more seals 243, and a locator 270. The anchor points 260 are connected to the one or more filler wires 280 (e.g., the first filler wire 280A) via an attachment wire 265 (shown in FIG. 3A). The locator 270 may include a magnet and enables locating the boss 240 within the TEC 202 after installation within the TEC 202.

The boss 240 is sized to fit in the TEC 202 and is sealably disposed and secured therein. Sealing of the boss in the TEC 202 can include a one or more seals 243. The one or more seals 243 may include an O-ring 330, as shown in FIG. 3B and FIG. 3C, a seal boss 332, as shown in FIG. 3D and FIG. 3E, or a spot weld 334, as shown in FIG. 3F. The seals 243 create a seal between the boss 240 and the TEC 202. The one or more seals 243 prevent the gases, fluids, or other materials from flowing to other areas in the TEC 202, thereby preventing damage to the one or more temperature sensors 206, vibration sensors, and additional sensors within the TEC 202.

FIG. 3A is a cross-sectional view of a pressure sensor 204A, a PCB 208A and the boss 240 disposed in the TEC 202 at cut-line 3A-3A. The pressure sensor 204A is one of the one or more pressure sensors 204, and is accessed by the boss 240. The PCB 208A is one of the one or more PCBs 208. The one or more wires 210 are coupled to a PCB 208A via a one or more connections, e.g., a first connection 310A is coupled to the first wire 210A, a second connection 310B is coupled to the second wire 210B, a third connection 310C is coupled to the third wire 210C, a fourth connection 310D is coupled to the fourth wire 210D, a fifth connection 310E is coupled to the fifth wire 210E, and a sixth connection 310F is coupled to the sixth wire 210F. The pressure sensor 204A is coupled to the PCB 208A via a seventh connection 314. The pressure sensor 204A and the PCB 208A surrounded by a mounting frame 315 having anchor points 260, which are connected to the one or more filler wires (e.g., the first filler wire 280A) via an attachment wire 265. The mounting frame 315 accommodates the minimum TEC 202 bend radius in order to prevent damage to the pressure sensor 204A and the PCB 208A. A compression seal 320 is disposed between the pressure sensor 204A and the boss 240. The compression seal 320 includes a seal channel 309 formed therethrough.

The boss 240 further includes an annular channel 306 and a pressure channel 308. The annular channel 306 can extend around the entire perimeter of the boss, or around any portion thereof, to facilitate access into the pressure channel 308. The pressure port 304 is disposed in the TEC 202 and configured to enable pressure measurements of the region surrounding the TEC 202. Gases, fluids, or other materials surrounding the TEC 202 enter the pressure channel 308 via the pressure port 304 and flow through the pressure channel 308 to the pressure sensor 204A via the seal channel 309. The pressure sensor 204A measures the pressure of the gases, fluids, or other materials surrounding the TEC 202 and relays the measurement to the controller 130 via the PCB 208A. In some embodiments, the pressure port 304 is aligned with the pressure channel 308. In other embodiments, the pressure port 304 is not aligned with the pressure channel 308.

FIG. 3B is a cross-sectional view of a first boss 240A and its connection to and orientation relative to the pressure sensor 204A. FIG. 3C is a perspective view of the first boss 240A. The TEC 202 defines a TEC volume 308. The pressure sensors 204, the PCBs 208, and the bosses 240 are disposed in the TEC volume 308. The one or more seals 243 include the O-ring 330 is disposed in an annular O-ring channel 331. The O-ring channels 331 are located proximate to one or more pressure ports 304 formed in the TEC 202.

FIG. 3D is a cross-sectional view of a second boss 240B and its connection to and orientation relative to the pressure sensor 204A. FIG. 3E is a perspective view of the second boss 240B. The one or more seals 243 include the one or more seal bosses 332 are configured to enable the TEC 202 to be crimped onto the second boss 240B at a one or more crimp locations 340. The crimp locations 340 are located proximate to one or more pressure ports 304 formed in the TEC 202.

FIG. 3F is a cross-sectional view of a third boss 240C and its connection to and orientation relative to the pressure sensor 204A. FIG. 3G is a perspective view of the third boss 240C. The one or more seals 243 include a spot weld 334. The spot welds 334 are located proximate to one or more pressure ports 304 formed in the TEC 202.

In some embodiments, an annular volume 350 is defined between the TEC 202 and the boss 240 to facilitate fluid access through pressure port 304 into the annular channel 306. The annular volume 350 is defined between the boss 240, the one or more seals 243 (e.g., the O-ring 330, the seal bosses 332, or the spot weld 334), and the TEC 202. The annular channel 306 facilitates the flow of the gases, fluids, or other materials from the pressure port 304 toward the pressure channel 308. When the pressure port 304 is not directly aligned with the pressure channel 308, the gases, fluids, or other materials flow into an annular volume 350. Thus, the annular channel 306 simplifies the fabrication of the pressure ports 304, as the exact orientation of the pressure channel 308 does not need to be known when the pressure ports 304 are fabricated.

FIG. 4 is a method 400 of forming a downhole sensor array system 100. A portion of the method 400 is performed on a mill 500, as shown in FIG. 5A. At operation 402, a one or more temperature sensors 206 are spliced into a raw cable 502A to form a first spliced cable 502B. The operation 402 may be repeated for up to 100 temperature sensors 206 which are spaced along the TEC 202 at distances to align with user monitoring requirements. As shown in FIG. 5B, the raw cable 502A may be surrounded by a harness 503, such as a tape. The raw cable 502A has an initial outer diameter of about 5 mm to 15 mm, such as about 11 mm. The raw cable 502A includes one or more filler wires (e.g., a first filler wire 280A, a second filler wire 280B, a third filler wire 280C, and a fourth filler wire 280D) and one or more wires (e.g., a first wire 210A, a second wire 210B, a third wire 210C, a fourth wire 210D, a fifth wire 210E and a sixth wire 210F). The one or more filler wires 280 include a plastic wire, a steel wire, a fiber yarn (e.g., Kevlar). The one or more filler wires 280 provide stability and strain relief along the length of the resultant TEC 202.

As shown in FIG. 5C and FIG. 5D, the temperature sensor 206A includes a temperature sensor PCB 208B including a one or more components 508. A shield 505 surrounds the temperature sensor PCB 208B and a potting material. The potting material and the shield 505 form a semi-circular shape having a flat bottom and that conforms to the harness 503 of the raw cable 502A, e.g., the outer diameter is about 5 mm to 15 mm, such as about 11 mm. The third wire 210C, the fourth wire 210D, the fifth wire 210E and the sixth wire 210F are connected to the temperature sensor PCB 208B. In some embodiments, one of the components 508 of the temperature sensor PCB 208B includes a locator, such as a magnet. The locater enables locating the temperature sensor PCB 208B within the TEC 202 after assembly of the TEC 202 is complete.

As shown in FIG. 5E and FIG. 5F, the first filler wire 280A, the first wire 210A, and the second wire 210B extend past the temperature sensor 206 along the flat bottom of the temperature sensor 206. The region 510 around the connection of the third wire 210C, the fourth wire 210D, the fifth wire 210E and the sixth wire 210F to the temperature sensor PCB 208B is filled with a sealant, such as a silicone sealant or a room temperature vulcanizing (RTV) sealant, and coated with an insulating film, such as a polyimide tape, to form the first spliced cable 502B.

At optional operation 404, as shown in FIG. 5G, a one or more pressure sensors 204, a one or more PCBs 208, and a one or more bosses 240 are spliced into the first spliced cable 502B to form a second spliced cable 502C (e.g., the downhole sensor array 201). The one or more pressure sensors 204 are accessed by one of the one or more bosses 240. The boss 240 includes wire channel 222 that is sealably disposed longitudinally through the boss 240 and enables the one or more wires (e.g., the first wire 210A, the second wire 210B, the third wire 210C, the fourth wire 210D, the fifth wire 210E, and the sixth wire 210F) to pass through the boss 240 along the TEC 202 in order to relay measurements from the downhole sensor array system 100 to the controller 130. The boss 240 further includes anchor points 260, a one or more seals 243, and a locator 270. The anchor points 260 are connected to the one or more filler wires 280 (e.g., the first filler wire 280A) via an attachment wire 265 (shown in FIG. 3A). The locator 270 may include a magnet and enables locating the boss 240 within the TEC 202 after installation within the TEC 202.

At operation 406, as shown in FIG. 5H, FIG. 5I, and FIG. 5J, a protective layer 250 is formed around the first spliced cable 502B (or second spliced cable 502C) to form an encapsulated cable 502D. The protective layer 250 is formed using an extrusion process to coat the first spliced cable 502B in an extrusion material. The extrusion material includes a polymer, such as fluorinated ethylenepropylene (FEP). The protective layer 250 has an outer diameter from about 10 mm to about 15 mm, such as about 13.5 mm. The protective layer 250 provides mechanical and heat protection and is a low-friction material to aid with insertion of the encapsulated cable 502D into the mill 500.

At optional operation 408, the one or more pressure sensors 204, a one or more PCBs 208, and a one or more bosses 240 are spliced into the encapsulated cable 502D to form the second spliced cable 502C. Portions of the protective layer 250 are removed from the encapsulated cable 502D to enable the one or more pressure sensors 204, a one or more PCBs 208, and a one or more bosses 240 to be spliced into the encapsulated cable 502D to form the downhole sensor array 201. The protective layer 250 is them reformed around the second spliced cable 502C to form the encapsulated cable 502D. Operation 408 may be used as an alternative operation when Operation 404 is not performed.

At operation 410, as shown in FIG. 5A, FIG. 5K, FIG. 5L, and FIG. 5M, an outer jacket 252 is formed around the encapsulated cable 502D to form a tube encapsulated cable (TEC) 202. The downhole sensor array 201 is disposed within the TEC 202. The outer jacket 252 is formed around the encapsulated cable 502D using the mill 500. An outer jacket strip 599 and the encapsulated cable 502D are fed into the mill 500. The encapsulated cable 502D may be fed into a feed tube 590. The feed tube 590 guides the encapsulated cable 502D into the mill 500. The outer jacket strip 599 (and resulting outer jacket 252) are includes a metallic material, such as a stainless-steel or nickel alloy. Using a multi-stage roller die 591, the outer jacket strip 599 is rolled into a tube. The multi-stage roller die 591 includes about 4 to 12 dies, such as about 8 dies. The tube has an outer diameter of about 15 mm to about 25 mm, such as about 20 mm. The tube is seam welded at a welding station 592 to form the outer jacket 252. The feed tube 590 provides heat protection to the encapsulated cable 502D during the welding operation.

The outer jacket 252 is cooled at a cooling station 593 to remove the heat from welding that could damage the TEC 202. After cooling, the quality of the weld is checked at an Eddy current inspection station 594. After inspection, ovality roller dies 595 form the outer jacket 252 to remove any ovality from the weld. Reducing dies 596 then reduce the outer diameter of the outer jacket 252 to about 0.5 in to about 0.75 in, such as about 0.625 in, to form the TEC 202. The TEC 202 is then cleaned and coiled at the cleaning station 597 and coiling station 598, respectively.

The bosses 240 have an outer diameter that is less than the inner diameter of the outer jacket 252 of the TEC 202 to avoid damage from the reducing dies 596 and to ensure the final outer diameter of the outer jacket 252 of the TEC 202 is maintained across the placement of the one or more pressure sensors 204. Sealing of the boss 240 in the TEC 202 can include a one or more seals 243. The one or more seals 243 may include an O-ring 330, a seal boss 332, or a spot weld 334. The seals 243 create a seal between the boss 240 and the TEC 202. The one or more seals 243 prevent the gases, fluids, or other materials from flowing to other areas in the TEC 202, thereby preventing damage to the one or more temperature sensors 206, vibration sensors, and additional sensors within the TEC 202.

At operation 412, a pressure port 304 is formed in the TEC 202. In some embodiments, a pressure port 304 is drilled or punched into the TEC 202. The locator 270 is used to locate the correct position to drill or punch the pressure port 304 into the TEC 202. The use of a Hall Effect sensor on the outside of the TEC 202 may be used to identify the position of the locator 270 and, thus, the boss 240 along the length of the TEC 202.

FIG. 6 is a method 600 of downhole measurement collection. At operation 602, a downhole sensor array system 100 is deployed into a well 102. The downhole sensor array system 100 preferably includes a string of sensors along a length ranging from about 1 m to about 20,000 m, such as about 1,000 m to about 2,000 m, to enable a wide measurement range along the length of the wellbore 105, regardless of location. The downhole sensor array system 100 is deployed downhole using conventional pressure control equipment, such as a stuffing box. The downhole sensor array system 100 can be deployed outside of the casing (e.g., in the cement 114), in a first volume 110, in a second volume 112, or in a combination thereof. A controller 130 may be used to control the deployment of the downhole sensor array system 100 into the well 102 by controlling the stuffing box. More specifically, the controller 130 may control the speed and depth of the deployment of the downhole sensor array system 100 into the well 102 via the stuffing box.

At operation 604, the downhole sensor array 201 rapidly collects data along the length of the downhole sensor array system 100 positioned in the well 102. The downhole sensor array 201 is configured to conduct a comprehensive survey of the well 102, rapidly delivering data from the one or more pressure sensors 204, the one or more vibration and acoustic sensors, and the one or more temperature sensors 206 along the length of the well 102. The rapid retrieval of data from the length of the well 102 reduces the amount of time required to accurately assess the condition of the well 102. Furthermore, the downhole sensor array system 100 enables the rapid data retrieval and processing without the use of fiber-optic sensing technologies, such as Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS), and without the need for additional data handling or interpretation software. In some embodiment, however, fiber optic systems may be employed to enhance or augment the downhole sensor array system 100.

At operation 606, the controller 130 receives the data collected from the downhole sensor array system 100. The controller includes a memory 134, support circuits 136, and a central processing unit (CPU) 138 (e.g., a processor). The controller 130 controls various components of the downhole sensor array system 100 directly, or via other computers and/or controllers. Operational parameters and operations are stored in the memory 134 as a software routine that is executed or invoked to turn the controller 130 into a specific purpose controller to control the operations of the various downhole sensor array systems 100 and, in some embodiments, a stuffing box.

In summary, a downhole sensor array system includes a downhole sensor array disposed within a tube encapsulated cable (TEC). The downhole sensor array includes a one or more pressure sensors, a one or more temperature sensors, and a one or more printed circuit boards (PCBs) and extends any desired length along the TEC. The downhole sensor array is disposed entirely within the TEC to facilitate delivery downhole, as well as into a volume defined by the production tubing and the casing, or positioned outside of the casing and disposed within the cement used to secure the casing in place. The downhole sensor array system enables high bandwidth, low power consumption assessment of a well through a single cable. Further, the downhole sensor array system is configured to conduct a comprehensive survey of the well, rapidly delivering data from the one or more pressure sensors and the one or more temperature sensors along the length of the well. The rapid retrieval of data from the length of the well reduces the amount of time required to accurately assess the condition of the well.

While the foregoing is directed to embodiments of the present disclosure, other and further embodiments of the disclosure may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.