Functional connecting modules for coiled tubing

Abstract

A coiled-tubing string configured to be disposed in a wellbore includes a first length of coiled tubing, a connecting module coupled to a downhole end of the first length of coiled tubing, a second length of coiled tubing coupled to a downhole end of the connecting module, and a communication line in the first length of coiled tubing and coupled to the connecting module. The connecting module is configured to communicate via the communication line.

Description

Atorney Docket No.: 50511-0092W01FUNCTIONAL CONNECTING MODULES FOR COILED TUBINGTechnical Field

[0001] This disclosure relates to modules for coiled tubing strings for drilling, completion, or operation of wellbores.Background

[0002] In some situations, it may be logistically difficult or impossible to transport and / or dispose within a wellbore a single length of coiled tubing sufficient to reach a desired downhole depth. In such situations, one or more connectors can couple individual lengths of coiled tubing at a wellsite to create a single coiled tubing work string of necessary total length for the planned operations.Atorney Docket No.: 50511-0092W01Summary

[0003] This disclosure relates to well operations with coiled tubing that comprises multiple lengths, and communications with connecting modules attached to the coiled tubing.

[0004] Certain aspects encompass a coiled-tubing string configured to be disposed in a wellbore. The coiled-tubing string includes a first length of coiled tubing, a connecting module coupled to a downhole end of the first length of coiled tubing, a second length of coiled tubing coupled to a downhole end of the connecting module, and a communication line in the first length of coiled tubing and coupled to the connecting module. The connecting module is configured to communicate via the communication line.

[0005] Certain aspects encompass a method of well operations that includes disposing a coiled-tubing string at least partially into a wellbore. The coiled-tubing string includes a first length of coiled tubing, a connecting module coupled to a downhole end of the first length of coiled tubing, a second length of coiled tubing coupled to a downhole end of the connecting module, and a communication line in the first length of coiled tubing and coupled to the connecting module. The connecting module is configured to communicate via the communication line. The method further includes transmitting or receiving a signal to or from the connecting module via the communication line.

[0006] Certain aspects encompass a method of well operations that includes, via a communication line on a first length of tubing of a coiled-tubing string at least partially disposed into a wellbore, receiving a signal from a connecting module at a downhole end of the first length of coiled tubing, wherein a second length of coiled tubing is coupled to a downhole end of the connecting module. The method further includes transmitting or receiving a signal to or from the connecting module via the communication line.

[0007] The aspects above can include some, none or all of the following features. In certain instances, the communication line comprises an electrically conductive wire. In certain instances, the communication line comprises an optical fiber. In certain instances, the communication line comprises a capillary tubing. In certain instances, the connecting module includes a sensor and the communication line is configured toAtorney Docket No.: 50511-0092W01 convey a signal conveyed from the sensor. In certain instances, the connecting module includes a tubing release configured to release the second length of coiled tubing from a remainder of the coiled-tubing string in response to a signal conveyed to the tubing release via the communication line. In certain instances, the connecting module comprises a valve configured to selectively permit flow of fluid between an interior of the coiled-tubing string and a region exterior the coiled-tubing string. The valve can be configured to actuate in response to a signal conveyed to the valve via the communication line. In certain instances, actuating the valve permits circulation of drilling fluid through the lower length of coiled tubing when the first length of coiled tubing or second length of coiled tubing is detached from a remainder of the coiled- tubing string. In certain instances, the connecting module comprises an anchor configured to engage with the communication line and to at least partially relieve a strain on the communication line as the coiled-tubing string flexes. In certain instances, the coiled-tubing string includes a hang-off profile configured to engage with a corresponding profile in a well control stack when the connecting module is positioned proximate a work access window in the well control stack to provide access, through the work access window, to the connecting module. In certain instances, the connecting module is a first connecting module and the coiled-tubing string includes a second connecting module disposed between the first length and the second length and configured to provide a function based on a signal conveyed to or from the second connecting module via the communication line.

[0008] Other features and aspects are described below.Atorney Docket No.: 50511-0092W01Brief Description of Drawings

[0009] FIGS. 1A - 1C are schematic views of an example system for drilling a wellbore in accordance with instances of the present disclosure.

[0010] FIGS. 2A and 2B are schematic, perspective, half cross-sectional illustrations of coiled-tubing connecting modules in accordance with instances of the present disclosure.

[0011] FIGS. 3 A and 3B are schematic perspective illustrations of a hybrid coiled- tubing connector in accordance with instances of the present disclosure, where FIG. 3B is a half cross-sectional illustration.

[0012] FIGS. 4A and 4B are schematic perspective illustrations of a hybrid coiled- tubing connector in accordance with instances of the present disclosure, where FIG. 4B is a half cross-sectional illustration.

[0013] FIG. 5 is a schematic, perspective, half cross-sectional illustration of a hybrid coiled-tubing connector in accordance with instances of the present disclosure.

[0014] FIG. 6 is a schematic, perspective, half cross-sectional illustration of a hybrid coiled-tubing connector in accordance with instances of the present disclosure.

[0015] FIG. 7 is a schematic, perspective, half cross-sectional illustration of a sensor sub in accordance with instances of the present disclosure.

[0016] FIGS. 8A and 8B are schematic, perspective, half cross-sectional illustrations of a flow port sub in accordance with instances of the present disclosure.

[0017] FIGS. 9A and 9B are schematic, perspective, half cross-sectional illustrations of a release assembly in accordance with instances of the present disclosure.

[0018] FIGS. 10A and 10B are schematic, perspective, half cross-sectional illustrations of an inflow sub in accordance with instances of the present disclosure.

[0019] FIG. 11 is a schematic, perspective, half cross sectional illustration of a wire anchor sub in accordance with instances of the present disclosure.

[0020] FIGS. 12A, 12B, and 12C are a schematic side cross-sectional views of example closed-loop geothermal systems in accordance with instances of the present disclosure.Atorney Docket No.: 50511-0092W01Detailed Description

[0021] Geothermal and other well systems can have complex geometries of inlet, outlet, and connecting wellbores which can extend for great lengths at great depths. For example, a system such as that developed by Eavor Technologies Inc. of Calgary, Alberta, includes a network of sealed lateral wellbores that exchange heat with the subterranean zone. Such a system of multiple lateral wellbores connecting inlet and outlet surface wellbores can provide a large surface area for thermal transfer from a geothermal zone and can improve capital efficiency of the closed loop system as there is no need for casing, liners and / or cement for the vast majority of the well, eliminating a substantial consumable in the well construction process. In addition, a multilateral closed loop system can have a larger subsurface volume and residence time of the geothermal working fluid, thereby enhancing the system's energy storage capacity, which is beneficial for dispatchable operation. Yet, the drilling and operating of such deep, multi-lateral wellbores and well systems of complex geometries can present numerous technical challenges.

[0022] Coiled-tubing operations such as coiled-tubing drilling (using, for example, thermoplastic composite pipe (TCP) as the drill string) can in some circumstances be advantageous in meeting some such technical challenges. However, very long lengths of coiled tubing can present various logistical and operational problems, necessitating the coupling or uncoupling of individual lengths of tubing at the wellsite or within the wellbore. In addition, coiled-tubing operations may necessitate various functionalities while the tubing is in the wellbore such the sensing of pressure, temperature, or other parameters at points along the tubing string and ensuring uninterrupted signal communication and sufficient flow of drilling fluids into, out of, within, and / or around the tubing string as lengths of tubing may uncoupled from each other while in the wellbore.

[0023] In accordance with instances of the present disclosure, separate lengths of coiled tubing can be coupled together by one or more connecting modules. A connecting module can include various subs or assemblies, some or all of which can perform one or more functions with respect to well operations. A communication lineAtorney Docket No.: 50511-0092W01 can be disposed within the coiled tubing, extending from the surface and communicatively coupled to the connecting module, through which sensor signals, electrical power, or other signals can be conveyed between the connecting module and the surface. In some instances, one communication line can convey signals from multiple subs or assemblies of a single connecting module and / or from multiple connecting modules connecting multiple lengths of tubing. For example, in some instances, the connecting module can include a sensor or sensor sub, and the communication line can be configured to convey a signal between the sensor and the surface. In some instances, the connecting module can include a release assembly configured to release a length of coiled tubing from a remainder of the coiled-tubing string in response to a signal conveyed to the release assembly via the communication line. In some instances, the connecting module can include one or more anchors configured to couple to, grip or otherwise engage with the communication line and to at least partially relieve a strain on the communication line as the coiled-tubing string flexes.

[0024] In some instances, the connecting module can include one or more valve subs configured to selectively permit flow of fluid between an interior of the coiled- tubing string and a region exterior the coiled-tubing string. The valve can, in some instances, be configured to actuate open and / or closed in response to a signal conveyed to the valve via the communication line. In some instances, actuating the valve to an open position permits circulation of drilling fluid through a length of coiled tubing when the length of coiled is detached from a remainder of the coiled-tubing string.

[0025] In some instances, a drilling system can be configured such that the connecting module can be accessed) through a work access window (for example, a work access window within the pressure control stack at or above the wellhead) for installation, repair, or other operations. The connecting module can include a hang- off profile configured to engage with (e.g., grip) a corresponding profile in a wellhead such that the drilling string is held steady in one position and its weight fully supported by the engagement during such operations.

[0026] Other subs of a connecting module can also include, for example, fishing profiles that allow retrieval tools such as spears, grapples, or overshots to predictably connect with the top of a coiled tubing string segment.Atorney Docket No.: 50511-0092W01

[0027] FIG. 1A is example system 100 for drilling a wellbore 102 from the surface 130 of the Earth in accordance with instances of the present disclosure. In some instances, wellbore 102 can be, for example, one or more of the surface wellbores and / or connecting wellbores of a geothermal system such as closed-loop geothermal system 1200 of FIGS. 12A - 12C. In other instances, the wellbore drilled by system 100 can be wellbores of a different kind of geothermal or non-geothermal well system. System 100 includes a bottom-hole assembly (BHA) 104 is disposed at a downhole end of a drill string 106 suspended from a drilling rig 140. Drill string 106 can, in some instances, include coiled tubing, and in some instances can include composite tubing such as thermoplastic composite pipe (TCP). BHA 104 can include a drill bit, ranging equipment, and other suitable apparatus for drilling wellbore 102. BHA 104 in some instances can include a contactless drill bit configured to break rock formation material at the downhole end of wellbore 102 without requiring contact between the bit and the rock face. In some instances the contactless bit can include an electrocrushing bit for electro-pulsed drilling. Examples of contactless drilling systems include plasma drilling (such as the plasma drilling system developed by GA Drilling, A.S.), laser drilling (such as the laser drilling system developed by Foro Energy), micro wave drilling (such as the micro wave drilling system developed by Quaise), thermal spallation techniques such as supercritical water jetting or flame jets, and electro-pulse drilling (such as the electro-pulse drilling systems developed by Tetra Corporation). (It will be understood that portions of a contactless drilling bit may periodically bump, brush against, or otherwise come into contact with the formation during the drilling process.)

[0028] In some instances drill string 106 can include two or more lengths of coiled tubing coupled together by one or more connecting modules. In the illustrated instance, for example, drill string 106 includes three separate lengths of coiled tubing: a first length 108, a second length 110 downhole of first length 108, a third length 112 downhole of second length 110, and a fourth length 113, downhole of third length 112. An uphole end of a tubular connecting module 114 is coupled to the downhole end of first length 108, an uphole end of second length 110 is coupled to a downhole end of connecting module 114. An uphole end of a tubular connecting module 116 is coupled to the downhole end of second length 110 and an uphole end of third length 112 is coupled to the downhole end of connecting module 116. An uphole end of a tubularAtorney Docket No.: 50511-0092W01 connecting module 118 is coupled to the downhole end of third length 112 and an uphole end of fourth length 113 is coupled to the downhole end of connecting module 118. A downhole end of fourth length 113 is in turn coupled to BHA 104. Although in the illustrated instance four lengths of tubing are shown, in some instances a drill string can include a fewer or greater number of (for example, two or five or more) lengths of coiled tubing coupled to each other by respective connecting modules.

[0029] Connecting modules 114, 116, and 118 can be configured to perform one or more functions with respect to well operations. As described in greater detail below, in some instances, a connecting module can include (for example) a sensor (such as a pressure, temperature or other sensor), a tubing release, a valve, or another functional feature. In the illustrated instance, connecting modules 114 and / or 116 and / or 118 can be configured to communicate to and from surface 130 (for example, to or from drilling rig 140) via communication line 120. For example, in instances in which one or more of connecting modules 114 and / or 116 and / or 118 include one or more sensors, communication line 120 can be configured to convey a sensor signal to or from one or more of the sensors. As another example, in instances in which one or more of connecting modules 114 and / or 116 and / or 118 include one or more valves, communication line 120 can be configured to convey a control signal to those valves. In some instances, a single communication line 120 can be configured to convey multiple signals of different types (for example, sensor signals or control signals) to or from a single connecting module or multiple connecting modules.

[0030] In the illustrated instance, communication line 120 is within coiled-tubing length 108 (and, more specifically in the illustrated instance, is within its central bore), extending through connecting module 114 in coiled-tubing length 110 to reach connecting modules 116 and 118. In some instances, communication line 120 can further extend to other connecting modules further downhole. In some instances, some or all of line 120 can also be elsewhere on or within drill string 106 (for example, attached to an exterior of or embedded in a sidewall of all or a portion of a length of coiled tubing and / or connecting module). Communication line 120 can in some instances be a single wire or fiber (of, for example, metallic wire or optical fiber) or may be multiple strands of wires or fibers of the same or different types (for example, may include both a metallic wire and an optical fiber). In some instances communication line 120 can be (or can include) capillary tubes for conveyance ofAtorney Docket No.: 50511-0092W01 pressure or hydraulic signals. In the illustrated instance, each of connecting modules 114, 116, and 118 are configured to communicate via the single communication line 120. In some instances more than one communication line can be installed in communication with one, some, or all of the connecting modules. In some instances, the connecting modules can include wireless transmitters, receivers, repeaters, or other components to facilitate mud-pulse, acoustic, or other wireless communication and / or control.

[0031] FIG. IB shows drilling rig 140 in greater detail, including a work access window 150 which can be accessed via a sliding sleeve 152 (and reinforced with tiebars 158), and FIG. 1C is a corresponding cross-sectional view. In the illustrated instance, drill string 106 can include a hang-off profile 170 configured to engage with a corresponding profile 172 (which in the illustrated instance is a hang-off ram) in well control stack 140. In operation, engagement of hang-off profile 170 can position the connecting modules of drill string 106 to be proximate work access window 150 and other components of drill string 106 as may be necessary or desirable for installation, connection, release, repair, or other operations . As shown in FIG. 1C, in the illustrated instance, for example, connecting module 114 is positioned such that it can be accessed through the work access window 150, and connecting module 114 is a release assembly (such as connecting module 230 of FIGS. 2A and 2B including an upper sub 902 and a lower sub 904. As described in greater detail in reference to FIGS. 9A and 9B, the access provided through access window 150 can permit an operator to connection and upper sub 902 and lower sub 904 (as described in greater detail in FIGS. 9A and 9B).

[0032] In the illustrated instance, work access window 150 is disposed above a flow tee 156 which is turn is disposed between a pair of annular modules 154, each of which can include annular seals or bags 159. Connecting module 116 is, for example, an inflow control sub 240 of FIGS. 2A and 2B, including ports 1004. As described in greater detail below in reference to FIGS. 10A and 10B, with connecting module 116 so positioned, annular seals 159 can isolate ports 1004, enabling continued circulation via bore 157 of flow tee 156 downhole through drill string 106 notwithstanding (temporary or permanent) disconnection of upper sub 902 from lower sub 904.

[0033] FIGS. 2A and 2B are a schematic cross-sectional illustrations of tubular connecting modules 114 and 116, respectively. Connecting module 114 of FIG. 2AAtorney Docket No.: 50511-0092W01 is connected at its uphole end to a downhole end of coiled-tubing length 108 via a tubular connector 204 and at its downhole end to an uphole end of coiled-tubing length 110 via a tubular connector 206. Connecting module 116 of FIG. 2B is connected at its uphole end to a downhole end of coiled-tubing length 110 via a tubular connector 208 and at its downhole end to an uphole end of coiled-tubing length 112 via a tubular connector 209. The central bores of coiled-tubing lengths 108 and 110 and of connecting modules 114 and 116 define a flow passage 202.

[0034] Connectors 204, 206, 208, and / or 209 can in some instances be a so-called “hybrid” connector configured to connect a length of coiled tubing at one end and a sub, tool, or other non-coiled-tubing component at the other end. For example, as described in greater detail below, connectors 204 and / or 206 can be, in some instances, connector 300 of FIGS. 3A-3B, connector 400 of FIGS. 4A-4B, connector 500 of FIG. 5, or connector 600 of FIG. 6, described in more detail in said figures, or another suitable connector.

[0035] As noted above, the connecting modules of the present disclosure can be configured to perform one or more functions with respect to well operations. For example, in the illustrated instance, connecting module 114 includes a tubular sensor sub 210 (which can be, for example, sensor sub 700 of FIG. 7), a tubular flow port sub 220 (which can be, for example, flow port sub 800 of FIGS. 8A-8B), a tubular release assembly 230 (which can be, for example, release assembly 900 of FIGS. 9A- 9B), an tubular inflow sub 240 (which can be, for example, inflow sub 1000 of FIGS. 10A-10B), and a tubular wire anchor sub 250 (which can be, for example, wire anchor sub 1100 of FIG. 11). It will be understood that, in accordance with the present disclosure, connecting module can include some, all, or none of the above subs, and can include (instead or in addition) other types subs or elements. Additionally, the subs can be arranged in a different order than shown in FIGS. 2A and 2B and more than one of the same type of sub can be included. Wire anchor sub 250 can in some instances be configured to partially or fully support the weight of one or more communication lines (such as communication line 120), and may include electrical or other functional connections with said lines.

[0036] Connectors 204, 206, 208, 209, and / or other suitable connectors of the present disclosure can be coupled or connected by threads, fasteners, adhesives, welding or other suitable attachments or combinations thereof. In certain instances, theAtorney Docket No.: 50511-0092W01 connectors 204, 206, 208, and 209 and / or subs 210, 220, 230, 240, and / or 250 can be made partially or entirely of metal, thermoplastic, composite (e.g., thermoplastic composite, carbon, aramid and / or glass fiber and resin composite or other composites) and / or other materials, whether intended for use with metallic coiled tubing, thermoplastic composite coiled tubing, or another configuration of coiled tubing. Different connectors and / or subs in the same string may be constructed of different materials.

[0037] FIG. 3A is a schematic illustration (and FIG. 3B a corresponding cross- sectional illustration) of a tubular hybrid connector 300 which can be used, for example, as a connector 204, 206, 208, and / or 209 of FIGS. 2A and 2B, accordance with instances of the present disclosure. In the illustrated instance, an uphole end of connector 300 is coupled to a downhole end of coiled tubing length 108, and the downhole end of connector 300 includes threads 302 (e.g., a box or pin or another type of threads) or another type of connection to couple to the remainder of the connecting module. In the illustrated instance, outside surface 304 of connector 300 is substantially the same diameter as the outside surface 306 of coiled-tubing length 108, but it could be differently sized. The outer surface 304 is shown with flats to facilitate make-up of the threads 302, but it could be provided without flats. As shown in FIG. 3B, in the illustrated instance, one or more seals 308, 310 can create a pressure tight connection for flow passage 202, and profde 312 (e.g., barbs or another profde) grips the inner surface 314 of coiled-tubing length 108.

[0038] FIG. 4A is a schematic illustration (and FIG. 4B a corresponding cross- sectional illustration) of a tubular hybrid connector 400 which can be used, for example, as a connector 204, 206, 208, and / or 209 of FIGS. 2A and 2B, accordance with instances of the present disclosure. In the illustrated instance, connector 400 is similar to connector 300 of FIGS. 3A-3B, except as noted here. An uphole end of connector 400 is coupled to a downhole end of coiled tubing length 108, and the downhole end of connector 400 includes threads 402 to couple to the remainder of the connecting module. As shown in FIG. 4B, in the illustrated instance, one or more seals 408, 410 can create a pressure tight connection for flow passage 202, and profde 412 grips the outer surface 414 of coiled-tubing length 108. In the illustrated instance, outside surface 404 of connector 400 has a larger diameter than the outsideAtorney Docket No.: 50511-0092W01 surface 306 of coiled-tubing length 108; however, a tapered edge 416 prevents the connector from hanging up within the wellbore.

[0039] FIG. 5 is a schematic illustration of a tubular hybrid connector 500 which can be used, for example, as a connector 204, 206, 208, and / or 209 of FIGS. 2A and 2B, accordance with instances of the present disclosure. In the illustrated instance, connector 500 is similar to connectors 400 and 300, except as noted here. An uphole end of connector 500 is coupled to a downhole end of coiled tubing length 108, and the downhole end of connector 500 includes threads 502 to couple to the remainder of the connecting module. Similar to connector 400 of FIGS. 4A-4B, one or more seals 508, 510 can create a pressure tight connection for flow passage 202. Profde 512 grips the outer surface 514 of coiled-tubing length 108 and profde 518 grips the inner surface 520 coiled-tubing length 108. Profdes 512 and / or 508 can be, for example, axially parallel grooves or helical groove. The direction and pitch of helical grooves can be configured to prevent undesired tubular rotation, and / or be configured to tighten as torque (for example, from the bottomhole assembly) is applied to the coiled tubing and connector.

[0040] FIG. 6 is a schematic illustration of a tubular hybrid connector 600 which can be used, for example, as a connector 204, 206, 208, and / or 209 of FIGS. 2A and 2B, in accordance with instances of the present disclosure. In the illustrated instance, connector 600 is similar to connectors 500, 400 and 300, except as noted here. The downhole end of connector 600 includes threads 602 to couple to the remainder of the connecting module, and one or more seals 608 can create a pressure tight connection for flow passage 202. In the illustrated instance, an uphole end of connector 600 is coupled to a downhole end of coiled tubing length 108, and surfaces of cavity 630 are fused (e.g., by adhesive, resin, heat fusing, welding or another method of fusing) to grip the outer surface 614, the inner surface 620, and / or the end 632 of coiled-tubing length 108. In some instances, surfaces 614 and / or 620 can be configured with helical or axial grooves, similar as described above in reference to FIG. 5.

[0041] FIG. 7 is a schematic illustration of a sensor sub 700 which can be used, for example, as sensor sub 210 of FIGS. 2A-2B, accordance with instances of the present disclosure. In accordance with instances of the present disclosure, a sensor sub of a connecting module can include one or more sensors 701 such as pressureAtorney Docket No.: 50511-0092W01 sensors, temperature sensors, flow rate sensors, strain sensors, force sensors, accelerometers, and / or other sensors. For example, in some instances, sensors 701 can be or can include sensors to measure the force exerted by the fluid on the shear wall, which can aid in assessment of flow behavior, turbulence, and erosion effects. In some instances, sensors 701 can include ultrasonic Doppler or laser-based sensors to monitor the speed of fluid near the shear wall, pressure transducers to detect variations in pressure along the shear wall to analyze flow stability and potential cavitation effects. In some instances, sensors 701 can include thermal sensors for assessing heat transfer within the fluid and the shear wall’s impact on thermal gradients. In some instances, sensors 701 can include high-speed cameras or particle image velocimetry (PIV) sensors to track eddy formation and boundary layer effects, and / or acoustic or ultrasonic sensors to detect material degradation caused by high-shear fluid interactions overtime.

[0042] While in conventional coiled tubing operations wellbore conditions may be inferred from circulation pressure, annulus pressure and the string weight, and from data from BHA sensors (such as weight on bit, circulating pressure, annular pressure, temperature, and acceleration data), in accordance with instances of the present disclosure, a sensor sub (or multiple sensor subs - for example, at 10, 100, 200, or more) can be installed in connecting modules at multiple locations along the coiled tubing string. These extra data points can allow for fine control and optimization of coiled tubing and other operating parameters. Furthermore, in some instances, strain and / or force measurements and other data from sensors of sensor subs of the present disclosure can be used by an operator in combination with the elastic modulus of the coiled tubing to accurately determine the length of the coiled tubing in its stretched state as it is hung off in a wellbore. Additionally, if the coiled tubing string becomes stuck from debris in the annulus or wellbore collapse, these measurements can allow operators to determine where along the string the coiled tubing is stuck and optionally disconnect the string above the stuck spot.

[0043] Referring to FIG. 7, tubular sensor sub 700 includes a pressure -tight electronics bay 702 with a cover 704 and seals 706. Inside the electronics bay 702 are, in the illustrated instance, one or more circuits 708 (e.g., printed circuit boards (PCB), integrated circuits and / or other circuits) with one or more sensors, microprocessors, batteries and / or other components. In some instances, the sensorAtorney Docket No.: 50511-0092W01 sub 700 is connected to other components of the system in a “wired” connection, although it could alternatively or additionally use “wireless” communication (radio frequency, mud pulse, and / or another wireless type connection). In the illustrated instance, a pressure sensor 710 is fluidly connected to the internal flow passage 202 with pressure port 712, another pressure sensor 714 is fluidly connected to the outside of the sensor sub 700 with pressure ports 716. A plug 718 with seals 720 is used to seal the annular pressure port 716. Threads 722 and a seal 724 are used to sealably connect the sensor sub 700 to other components of the connecting module 114. The sensors and other components of sensor sub 700 can be electrically and / or optically connected to a communication line (such as communication line 120 of FIGS. 1 and 2A-2B).

[0044] Communication line 120 in some instances of the present disclosure may include optical fibers for distributed sensing of strain, temperature, vibrations and / or other characteristics. Distributed sensing data can be used to infer wellbore conditions during coiled tubing operations to further optimize job efficiency.

[0045] FIGS. 8 A - 8B are cross-sectional schematic illustrations of a flow port sub 800 which is tubular and can be used, for example, as a flow port sub 220 of FIGS. 2A-2B, in accordance with instances of the present disclosure. A significant challenge with conventional coiled tubing operations such as milling, drilling, and cleanouts in horizontal wells is transport of cuttings and or debris from the wellbore to surface. A flow port sub such as flow port sub 800 can be configured to provide additional flow rate within the annulus at one or more discrete points along the coiled tubing string, increasing lifting velocity in the heel and vertical sections of a wellbore where it has the most impact for debris transport, and also providing cooling within the annulus. Flow port sub 800 includes one or more flow ports 802. Translation of sliding sleeve 804 opens or closes (e.g., occludes) flow ports 802 to permit or prevent fluid flow from flow passage 202 to the annulus (or vice-versa), with FIG. 8A illustrating sleeve 804 in the closed position and FIG. 8B illustrating sleeve 804 in the open position. Threads 806 with seals 808 sealably connect the flow port sub 800 to other components of the connecting module. Seals 810 can prevent fluid leakage when sleeve 804 is in the closed position. Varying the position of the sliding sleeve 804 allows the valve to incrementally throttle flow rate through the ports 802. The position of the sliding sleeve 804 can be controlled mechanically or electronicallyAtorney Docket No.: 50511-0092W01(with, for example, hydraulic, electric solenoid, electric motor, bimetal strip, or other types of actuators actuated by control signals conveyed via a communication line such as communication line 120 of FIG. 1), and such control can be autonomous control (for example, via a downhole circuit) based on readings or feedback from sensors in a sensor sub (such as sensor sub 700).

[0046] FIG. 9A- 9B are cross-sectional schematic illustrations of a tubular release assembly which can be used, for example, as a release assembly 230 of FIGS. 2A- 2B, in accordance with instances of the present disclosure. Release assembly 900 includes an upper sub 902 and a lower sub 904 coupled (as shown in FIG. 9A) via retractable dogs 906 of upper sub 902 engaging with groove 914 of lower sub 904 (with seals 908 preventing fluid flow between flow passage 202 and the annulus). Dogs 906 can be retracted (for example, with a hydraulic, electrical or another type of actuator actuated by control signals conveyed via a communication line such as communication line 120 of FIG. 1) to uncouple the subs, as shown in FIG. 9B. Threads 910 with seals 912 sealably connect release assembly 900 to other components of the connecting module. In some instances, groove 914 within the lower sub 904 can be configured such that it can be engaged with by a fishing tool such as a GS spear.

[0047] FIGS. 10A- 10B are cross-sectional schematic illustrations of a tubular inflow sub 1000 which can be used, for example, as inflow sub 240 of FIGS. 2A-2B. Inflow sub 1000 can enable the tool string and mid-string functional modules above the inflow valve to be safely disconnected from lower lengths of the coiled tubing sections while maintaining circulation through the lower portion of the coiled tubing string, maintaining or enhancing the safety and operation of the system in the event of damage to the coiled tubing string above surface. Inflow sub 1000 can include a body 1002 with annular flow ports 1004. Flow between the annulus and the flow passage through the flow ports 1004 can be selectively blocked (opened or closed) by a cylindrical piston 1006 (with seals 1008, 1010, and 1012). Hydraulic pressure from the flow passage 202 through the tool string is communicated to the hydraulic chamber 1014 through one or more hydraulic passages 1016. The hydraulic end effect created by differential sealing areas of seals 1008, 1010, and 1012 determines the pressure differential between the internal flow passage 202 and the annulus needed to shift the cylindrical piston from a closed position (depicted in FIG. 10A,Atorney Docket No.: 50511-0092W01 in which inflow of fluid from the annulus of the tool into the flow passage 202 is prevented) to the open position (depicted in FIG. 10B). A check valve cartridge 1018 is shown with an internal flow passage 1020, one or more seals 1022, and a flapper 1024 which, when in the open position as shown in FIG. 10A, allows for flow through the tool string flow passage 202. Piston 1006 opens automatically when the annular pressure is increased beyond the pressure within the flow passage 202 by a predetermined margin, at which time check valve cartridge 1018 closes and prevents backflow to the tool string above the inflow valve within the flow passage 202. More than one check valve cartridge 1018 may be used for redundancy. Threads 1025 (and a seal 1026) are used to sealably connect the inflow sub 1000 to other components of the connecting module. One or more seals 1028 around the communication line 120 seal communication line 120 within the body 1002 to prevent fluid flow around the wire within the wire passage 1030.

[0048] With an inflow sub such as inflow sub 1000 installed in a connecting module, the string can be hung off at surface with sealing devices positioned above and below the flow ports of the inflow device. Fluid can be pumped into the annular space between the sealing devices resulting in the flow ports opening and allowing fluid to be displaced down the coiled tubing string if circulation within the coiled tubing string is stopped for any reason. Back up pumps may be used to maintain circulation through the inflow valves if the main circulation pumps are not available. Alternatively, or in addition, flow ports 1004 in body 1002 can in some embodiments be threaded to accept one or more flow line directly connected to inflow sub 1000.

[0049] FIG. 11 is a cross-sectional schematic illustration of a tubular anchor sub 1100 which can be used, for example, as anchor sub 250 of FIGS. 2A-2B. Anchor sub 1100 includes a lug 1102 that engages with and supports the communication line 120 and maintains the appropriate amount of slack to relieve strain on the communication line as the coiled-tubing string flexes during coiled tubing operations. Threads 1104 are used to connect the anchor sub 1100 to other components of the connecting module. Although in the illustrated instance communication line 120 passes through anchor sub 250 such that it can extend further downhole to other subs within the communication module (or to and through one or more downhole lengths of coiled tubing to subs in other communication modules coupled to those downhole lengths of tubing), in some instances the communication line can terminate at one orAtorney Docket No.: 50511-0092W01 more lugs 1102 (such as shown in FIG. 2B). Lugs 1102 can in some instances be configured to support communication lines for, for example, electrical power or other applications.

[0050] In some instances threads of the above-described subs can be reversed with respect to each other such that tubing sections at the uphole and downhole ends of the module can be simultaneously connected to the module by rotating the module without rotating the sections above or below the connector.

[0051] FIG. 12A shows an example closed-loop geothermal system 1200 in schematic, side cross-sectional view in accordance with the concepts herein. System 1200 includes a geothermal well 1202 drilled into the Earth from the terranean surface 1210 through a geothermal subterranean zone of interest 1204. In certain instances, the subterranean zone is a formation, portion of formation or multiple formations having little to no naturally occurring fluids. In certain instances, the formation can be impermeable or substantially impermeable (for example, 0.1 millidarcies or less). In certain instances, the subterranean zone is in a basement formation. In certain instances, the rock of the subterranean zone is granite. In the illustrated instance, well 1202 includes an inlet surface wellbore 1220 and an outlet surface wellbore 1230 in close proximity, each extending between the terranean surface and the subterranean zone 1204. The inlet surface wellbore 1220 and outlet surface wellbore 1230 are connected within the subterranean zone 1204 by one or more connecting wellbores 1240. In the illustrated instance, connecting wellbores 1240 define a multilateral pattern of wellbores, including a plurality of pairs of lateral wellbores 1250, a subset of which are kicked off from the inlet wellbore 1220 and a subset of which are kicked off from the outlet wellbore 1230. The pairs of lateral wellbores 1250 each intersect at a respective junction at or near their respective toes. Thus, the inlet wellbore 1220, outlet wellbore 1230 and connecting wellbores 1240 define a closed loop.

[0052] The inlet wellbore 1220 and the outlet wellbore 1230 can be drilled from the same drilling pad and / or reside on the same well site. In certain instances, the wellbores 1220, 1230 are drilled within 10, 25, 50 or 100 meters of one another. In other instances, the inlet surface wellbore 1220 and the outlet surface wellbore 1230 can be separated by a longer distance. For example, FIG. 12C, discussed in more detail below, shows a configuration where the surface wellbores 1220, 1230 and theAtorney Docket No.: 50511-0092W01 connecting wellbores 1240 define a U-shape configuration. In certain instances, the inlet surface wellbore 1220 and the outlet surface wellbore 1230, when the geothermal well 1202 is configured as a U-shape, are drilled 3,000 meters or more apart.

[0053] In the illustrated instance, inlet surface wellbore 1220 and outlet surface wellbore 1230 are vertical wellbores, drilled substantially straight (i.e., without the use of directional drilling methods or equipment). In other instances, one or both of the surface wellbores are otherthan vertical (e.g., slanted) and / or may be drilled with the use of directional drilling techniques. The connecting wellbores 1240 are drilled using directional drilling techniques through the surface wellbores 1220, 1230, and include a curve in their trajectory beginning at a kickoff 1248 at surface wellbores 1220, 1230. Although shown as slanted downward, in some instances, some or all of the connecting wellbores are horizontal. In some instances, the connecting wellbores 1240 follow the geological dip of the formation in the subterranean zone. In some instances, lateral wellbores 1250 are anywhere from 2,000 meters to 10,000 meters or more in length and from 1,000 meters to 8,000 meters or more in depth from the surface. Typical wells may be deeper than 3000 meters in depth.

[0054] FIG. 12A shows each pair of lateral wellbores 1250 parallel to one another extending in the same direction (azimuth) from their respective surface wellbore 1220, 1230. The lateral wellbores 1250 extending from the inlet surface wellbore 1220 are shown above the lateral wellbores 1250 extending from the outlet surface wellbore 1230. In some instances, the upper lateral wellbores 1250 are directly above their (and are, in some instances, directly above a respective one of the lower lateral wellbores 1250. In FIG. 12A the upper lateral wellbores 1250 each turn to intersect its adjacent lower lateral wellbore 1250 pair at the junction 1254 to connect the surface wellbores 1220, 1230. In other instances, one or more of the lower lateral wellbores 1250 could intersect the upper lateral wellbores 1250. Regardless, the configuration of connecting wellbores 1240, one set atop the other defines a stacked wellbore pattern, with one sub-pattern of wellbores above and one sub-pattern of wellbores below. In certain instances, one or more additional sets of stacked patterns can be drilled from the surface wellbores 1220, 1230 at different depths (i.e., with different kickoffs 1248). In FIG. 12A, the lower lateral wellbores 1250 extend past and below the junction 1254 to define a sump 1252. The sump 1252 provides aAtorney Docket No.: 50511-0092W01 location for debris to accumulate outside of the flow path through the wellbores. In other instances, one or more of the upper lateral wellbores 1250 could extend past the junction to define the sump 1252.

[0055] The connecting wellbores 1240 of FIG. 12A slant downward; i.e., they have an inclination 1270 from vertical. In some instances, some or all of the connecting wellbores can be horizontal (i.e., having an inclination 1270 of about ninety degrees) or substantially horizontal. In some instances, as shown in FIG. 12B, connecting wellbores 1240 can have a steeper slant; i.e., inclination 1270 can be less than that shown in FIG. 12A, or vertical (inclination 1270 is zero) or substantially vertical

[0056] FIG. 12C is another embodiment of a geothermal well system 1200 having lateral wellbores 1250 extending, respectively, from the inlet and outlet surface wellbores 1220, 1230 toward one another. The pairs of lateral wellbores 1250, once intersected, together with the inlet and outlet wellbores 1220, 1230, define a generally U-shape. The configuration of connecting wellbores 1240 defines a pattern of wellbores, in certain instances, in the same plane. In certain instances, one or more additional patterns of connecting wellbores can be drilled between the surface wellbores 1220, 1230 at different depths (i.e., with different kickoffs 1248).

[0057] Referring to FIGS. 12A and 12B and 12C, collectively, in some instances, the surface wellbores 1220, 1230 are cased (at least partially or entirely), and the connecting wellbores 1240, including the junctures at the kickoffs 1248 are open hole (i.e., without casing or liner or a junction liner). In some instances, the connecting wellbores 1240 can be at least partially lined (e.g., include a liner or casing in those portions where the subterranean zone 1204 is fractured, susceptible to collapse, unconsolidated or otherwise needing a liner). The connecting wellbores 1240, including the junctures to the inlet and outlet surface wellbores 1220, 1230 are sealed (entirely or substantially) with a sealant against exchange of fluids with the surrounding subterranean zone 1204. In some instances, the sealant can be in the form of a fluid sealant (such as an alkali-silicate fluid) flowed through the wellbores. The sealant is designed such that all or substantially all of the geothermal working fluid circulated through the well 1202 during operation is recovered to the surface, and no or little naturally occurring fluids from the subterranean zone 1204 are recovered. In other words, the resulting well 1202 is closed loop. In certain instances, the sealant can be applied to the wellbores during drilling the connecting wellboresAtorney Docket No.: 50511-0092W011240, e.g., included in the drilling fluid and / or supplied in fluid slugs distinct from the drilling fluid. Alternatively or additionally, the sealant is applied after drilling and / or during operation of the well. In certain instances, the sealant can be included in the geothermal working fluid and / or supplied in fluid slugs, distinct from the geothermal working fluid.

[0058] In the illustrated instance, system 1200 further includes a facility 1260 disposed between inlet surface wellbore 1220 and outlet surface wellbore 1230. Well 1202 can be sealed and a geothermal working fluid added to the closed loop and circulated in the system such that it absorbs heat from subterranean zone 1204. In certain instances, facility 1260 includes valves and pumps for controlling the flow of the geothermal working fluid through the well 1202, as well as a heat exchanger for extracting the heat from the geothermal working fluid and conveying it into a related process, such as a Rankine cycle (e.g., Organic Rankine Cycle) or other heat cycle that generates electricity, a steam generation process for industrial, agricultural or residential use, or another process. In certain instances, instead of, or in addition to a heat exchanger, facility 1260 directly uses the heated geothermal working fluid, such as by passing it through an expander (e.g., a turbine) that drives a electric generator or directly using the heat of the geothermal working fluid in an industrial, agricultural or residential process. In some instances, facility 1260 is disposed at or near the Earth’s surface; in other instances, facility 1260 may be disposed partially or fully within a subsurface location. The facility 1260 need not be housed in one location. For example, in some instances, it can be split between one or more discrete locations connected by piping.

[0059] In some instances, a coiled tubing string can been designed such that connecting modules as described above (which can include, for example, a check valve, bypass valves, and other suitable components) can be positioned along the coiled tubing string, approximately 1 kilometer apart. The check valves in the connecting modules can serve the same purpose as the flow check assembly positioned in the BHA; they stop flow from returning up the coiled tubing. Each of these bypass valves can be opened to the annulus via the telemetry cable. Depending where the influx is, the volumetric method can be used to allow the controlled migration of the influx to above a bypass port that is not plugged. At that point, the bypass valve can be opened and the influx can be circulated out. If there is an issue opening any of theAtorney Docket No.: 50511-0092W01 bypass valves the influx can be removed using the volumetric method. For a parted drill string, the same methodology can be used but the bypass valves do not need to be utilized since the string is still capable of being circulated through. Shutting in with the upper pipe rams and circulating out through the bleed-off line is the preferred method to circulate the influx out if the influx is above the parted string. If the influx is below the parted string the volumetric method will need to be utilized. To kill the well, the mud weight will need to be increased from the point where circulation.

[0060] Coiled tubing may experience burst failure due to internal overpressure or collapse due to external pressure when not adequately balanced. These risks are exacerbated in high-pressure, high-temperature (HPHT) environments and must be managed through conservative design margins and active pressure control. As a mitigation measure, the drill string can be a composite drill string engineered for a minimum burst pressure of 103 MPa, well above a maximum anticipated surface pressure of (for example) 70 MPa. In this example, a >45% safety margin is provided for under worst-case pressure scenarios.

[0061] All components can be designed to meet or exceed a working pressure rating of 70 MPa at 120°C, ensuring integrity across thermal cycles and pressure transients during dynamic circulation events. The connecting modules can include with remotely actuated circulation ports, which can be opened proactively to relieve pressure and prevent localized buildup that could lead to burst conditions. These ports also help avoid collapse scenarios by managing annular flow and pressure equilibrium, especially during transitions such as pump shutdown or fluid density changes.

[0062] Sensors in connecting modules can continuously track internal and annular pressure, temperature, and strain, providing early detection of conditions that could result in structural compromise. Surface systems can respond dynamically to mitigate risk before failure thresholds are reached. A stuck or parted string can pose a significant risk of losing wellbore control, especially if the circulation path is compromised.

[0063] String immobility due to stuck pipe or mechanical drag may be recognized as a risk, particularly in ultra-deep and extended-reach drilling scenarios. High- strength composite strings with connecting modules (as described above) can be engineered to tolerate over 100 tonnes of overpull (for example, 200 or 250 tonnes), and the conveyance system is rated to 200 tonnes of pull, allowing for substantialAtorney Docket No.: 50511-0092W01 mechanical margin. Connecting modules can be placed along the string (for example, every 1,000 meters), featuring real-time telemetry for strain, pressure, torque, temperature, and vibration to detect stuck pipe onset early, remote -actuated circulation ports to accelerate annular flow and remove solids, remote-controlled release mechanisms to detach stuck sections without surface cuts or internal cutters, and double flapper check valves for pressure integrity and backflow prevention. Such a multi-layered approach dramatically reduces the likelihood of a stuck pipe event, while providing flexible, precise, and safe remediation options if it occurs.

[0064]

[0065] The term “uphole” as used herein means in the direction along a wellbore from its distal end towards the surface, and “downhole” as used herein means the direction along a wellbore from the surface towards its distal end. A downhole location means a location along a wellbore downhole of the surface. The terms “a,” “an,” or “the” are used to include one or more than one unless the context clearly dictates otherwise. The term “or” is used to refer to a nonexclusive “or” unless otherwise indicated. The statement “at least one of A and B” has the same meaning as “A, B, or A and B.” In addition, it is to be understood that the phraseology or terminology employed in this disclosure, and not otherwise defined, is forthe purpose of description only and not of limitation. Any use of section headings is intended to aid reading of the document and is not to be interpreted as limiting; information that is relevant to a section heading may occur within or outside of that particular section.

[0066] While this disclosure contains many specific implementation details, these should not be construed as limitations on the subject matter or on what may be claimed, but rather as descriptions of features that may be specific to particular implementations. Certain features that are described in this disclosure in the context of separate implementations can also be implemented, in combination, or in a single implementation. Conversely, various features that are described in the context of a single implementation can also be implemented in multiple implementations, separately, or in any suitable sub-combination. Moreover, although previously described features may be described as acting in certain combinations and even initially claimed as such, one or more features from a claimed combination can, in some cases, be excised from the combination, and the claimed combination may be directed to a sub-combination or variation of a sub-combination.Atorney Docket No.: 50511-0092W01

[0067] Particular implementations of the subject matter have been described. Nevertheless, it will be understood that various modifications, substitutions, and alterations may be made. While operations are depicted in the drawings or claims in a particular order, this should not be understood as requiring that such operations be performed in the particular order shown or in sequential order, or that all illustrated operations be performed (some operations may be considered optional), to achieve desirable results. Accordingly, the previously described example implementations do not define or constrain this disclosure.

Claims

Atorney Docket No.: 50511-0092W01What is claimed is:

1. A coiled-tubing string configured to be disposed in a wellbore, the coiled- tubing string comprising: a first length of coiled tubing; a connecting module coupled to a downhole end of the first length of coiled tubing; a second length of coiled tubing coupled to a downhole end of the connecting module; and a communication line in the first length of coiled tubing and coupled to the connecting module, the connecting module configured to communicate via the communication line.

2. The coiled-tubing string of claim 1, wherein the communication line comprises an electrically conductive wire.

3. The coiled-tubing string of claim 1 or claim 2, wherein the communication line comprises a an optical fiber.

4. The coiled-tubing string of any of claims 1 to 3, wherein the communication line comprises a capillary tubing.

5. The coiled-tubing string of any of claims 1 to 4, wherein: the connecting module comprises a sensor; and the communication line is configured to convey a signal conveyed from the sensor.

6. The coiled-tubing string of any of claims 1 to 5, wherein the connecting module comprises a tubing release configured to release the second length of coiled tubing from a remainder of the coiled-tubing string in response to a signal conveyed to the tubing release via the communication line.Atorney Docket No.: 50511-0092W017. The coiled-tubing string of any of claims 1 to 6. wherein the connecting module comprises a valve configured to selectively permit flow of fluid between an interior of the coiled-tubing string and a region exterior the coiled-tubing string.

8. The coiled-tubing string of claim 7, wherein actuating the valve permits circulation of drilling fluid through the lower length of coiled tubing when the first length of coiled tubing or second length of coiled tubing is detached from a remainder of the coiled-tubing string.

9. The coiled-tubing string of any of claims 1 to 8, wherein the connecting module comprises an anchor configured to engage with the communication line and to at least partially relieve a strain on the communication line as the coiled-tubing string flexes.

10. The coiled-tubing string of any of claims 1 to 9, wherein the coiled-tubing string comprises a hang-off profile configured to engage with a corresponding profile in a well control stack when the connecting module is positioned proximate a work access window in the well control stack to provide access, through the work access window, to the connecting module.

11. The coiled-tubing string of any of claims 1 to 10, wherein: the connecting module is a first connecting module; and the coiled-tubing string comprises a second connecting module disposed between the first length and the second length and configured to provide a function based on a signal conveyed to or from the second connecting module via the communication line.

12. A method of well operations comprising: disposing a coiled-tubing string at least partially into a wellbore, the coiled- tubing string comprising: a first length of coiled tubing; a connecting module coupled to a downhole end of the first length of coiled tubing;Atorney Docket No.: 50511-0092W01 a second length of coiled tubing coupled to a downhole end of the connecting module; and a communication line in the first length of coiled tubing and coupled to the connecting module, the connecting module configured to communicate via the communication line; and transmitting or receiving a signal to or from the connecting module via the communication line.

13. The method of claim 12, wherein the communication line comprises a an optical fiber.

14. The method of claim 13 or 14 wherein the communication line comprises a capillary tubing.

15. The method of claim 12, wherein: the connecting module comprises a sensor; and the signal is a signal conveyed from the sensor.

16. The method of any of claims 12 to 15, wherein: the connecting module comprises a tubing release; and the signal is a signal to release the second length of coiled tubing from a remainder of the coiled-tubing string.

17. The method of any of claims 12 to 18, wherein the connecting module comprises a valve configured to selectively permit flow of fluid between an interior of the coiled-tubing string and a region exterior the coiled-tubing string.

18. A method of well operations comprising: via a communication line on a first length of tubing of a coiled-tubing string at least partially disposed into a wellbore, receiving a signal from a connecting module at a downhole end of the first length of coiled tubing, wherein a second length of coiled tubing is coupled to a downhole end of the connecting module; andAtorney Docket No.: 50511-0092W01 transmitting or receiving a signal to or from the connecting module via the communication line.

19. The method of claim 18, wherein: the connecting module comprises a tubing release; and the signal is a signal to release the second length of coiled tubing from a remainder of the coiled-tubing string.

20. The method of claim 18, wherein the connecting module comprises a valve configured to selectively permit flow of fluid between an interior of the coiled-tubing string and a region exterior the coiled-tubing string.

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