130. The term “proximate,” as used herein with respect to the power cable reel 185, means that it is located within 250 meters of the coiled tubing deployment/retrieval apparatus 130. In yet another embodiment, however, the power cable reel 185 is positioned within 100 meters of the coiled tubing deployment/retrieval apparatus 130, if not within 50 meters, if not within 25 meters, if not within 10 meters, if not within 5 meters, or less, of the coiled tubing deployment/retrieval apparatus 130. Nevertheless, in the embodiment of FIG. 1, the power cable reel 185 is positioned on the crane truck 180. The power cable reel 185, in at least one embodiment, comprises the spool that carries a power cable 188 (e.g., second wellbore feature or first wellbore feature) to/from the job site.

FIG. 1 additionally illustrates the power cable 188 passing over a power cable deployment/retrieval apparatus 190, and insert into the wellbore 140 (e.g., open hole wellbore, partially cased wellbore and/or fully cased wellbore). In the illustrated embodiment, the power cable deployment/retrieval apparatus 190 includes a power cable guide 193 coupled to the frame 131, and a power cable injector 195 (e.g., separate power cable injector, second injector or first injector, etc.). In at least this one embodiment, the power cable injector 195 is configured to insert or retrieve the power cable 188 guided by the power cable guide 193 into or out of the wellbore 140 alongside the coiled tubing string 125. While the coiled tubing injector 135 and the power cable injector 195 may be operated at the same time, they may be designed such that they can operate at different speeds and remain within the scope of the disclosure.

Turning to FIG. 2A, illustrated is a well system 200 including a coiled tubing surface equipment spread 205 designed, manufactured and operated according to an alternative embodiment of the disclosure. The well system 200 and coiled tubing surface equipment spread 205 of FIG. 2A are similar in many respects to the well system 100 and coiled tubing surface equipment spread 105 of FIG. 1. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The well system 200, and associated coiled tubing surface equipment spread 205, in at least one embodiment, may find its primary use with a bottom hole assembly (BHA) 210 employing a pulsed power drilling system 250. In at least this one embodiment, the pulsed power drilling system 250 replaces traditional drilling tools (e.g., electrodes replacing the drill bit of FIG. 1) by generating electric pulsating arc through rock and breaking the rock. As shown in this embodiment, the power cable is run alongside (outside) coiled tubing string. Furthermore, in at least one embodiment, the power cable is not attached to coiled tubing string (e.g., connected only to the bottom hole assembly (BHA) and not along the length of the coiled tubing string).

In the embodiment of FIG. 2A, the coiled tubing string 125 is used to convey the pulsed power drilling system 250 and pumped fluid downhole within the wellbore 140. Similarly, the power cable 188 is used to convey electric power to the pulsed power drilling system 250, and in certain embodiments can include conductors for communications (and possibly hydraulic flow lines).

The coiled tubing surface equipment spread 205 of FIG. 2A is often used when drilling a wellbore with coiled tubing and an electrically powered drilling apparatus (e.g., such as the pulsed power drilling system 250). In at least one embodiment, the coiled tubing surface equipment spread 205 may be used with wellbores having at least a 6,100 meter well depth, and 20 cm or larger wellbore size. In at least one embodiment, from about 100 KW to about 500 kW electric power is employed by the pulsed power drilling system 250. Often, the coiled tubing string 125 and power cable 188 sizes will depend on the well depths, fluid flow rates, and/or electric power needs, among other requirements. Notwithstanding, in at least one embodiment, the coiled tubing string 125 outside diameter (OD) ranges from about 6.35 cm to about 10.25 cm, if not from about 7.62 cm to about 9.53 cm, if not about 8.89 cm. Similarly, in at least one embodiment, the power cable 188 outside diameter (OD) ranges from about 1.91 cm to about 5.72 cm, if not from about 2.54 cm to about 5.08 cm, if not about 3.81 cm. All the above values may be useable in wellbore lengths greater than about 4,500 m, if not greater than about 6,100 m, if not greater than about 7,600 m, if not greater than about 9,200 m.

In at least one embodiment, the coiled tubing surface equipment spread 205 of FIG. 2A includes a tubular control system 260. The tubular control system 260 may be autonomous, in that it does not include human intervention, but in other embodiments may be semi-autonomous, or human controlled. In at least one embodiment, the tubular control system 260 is configured to operate the coiled tubing injector 135 and the power cable injector 195 in coordination, for example to insert the coiled tubing string 125 and the power cable 188 within the wellbore 140 or to retrieve the coiled tubing string 125 and the power cable 188 from the wellbore 140. In at least one embodiment, the tubular control system 260 includes a power cable control system 265 that is coupled with the power cable injector 195. In this embodiment, the power cable control system 265 is configured to modulate a power cable rate upon which the power cable injector 195 inserts the power cable 188 within the wellbore 140 or retrieves the power cable 188 from the wellbore 140 (e.g., relative to a coiled tubing rate upon which the coiled tubing injector 135 inserts the coiled tubing string 125 within the wellbore 140 or retrieves the coiled tubing string 125 from the wellbore 140). In yet another embodiment, the tubular control system 260 includes a coiled tubing string control system 270, the coiled tubing string control system 270 configured modulate the coiled tubing rate upon which the coiled tubing injector 135 inserts the coiled tubing string 125 within the wellbore 140 or retrieves the coiled tubing string 125 from the wellbore 140 (e.g., relative to a power cable rate upon which the power cable injector 195 inserts the power cable 188 within the wellbore 140 or retrieves the power cable 188 from the wellbore 140).

Turning now to FIG. 2B, with continued reference to FIG. 2A, illustrated is a zoomed in view of the bottom hole assembly (BHA) 210 of FIG. 2A. In the illustrated embodiment, the bottom hole assembly (BHA) 210 is coupled to both of the coiled tubing string 125 and the power cable 188. Further to this embodiment, the bottom hole assembly (BHA) 210 may include a bottom hole assembly (BHA) housing 220, the bottom hole assembly (BHA) housing 220 including an uphole end 225a and a downhole end 225b. Further to the embodiment of FIG. 2B, the uphole end 225a may include a power cable connector 230 engaging with the power cable 188 and a coiled tubing connector 240 engaging with the coiled tubing string 125 and.

In at least one embodiment, the tubular control system 260 (e.g., power cable control system 265) includes a tension measuring device associated with the power cable 188, the tension measuring device configured to measure an amount of tension or compression (e.g., axial tension or axial compression) on the power cable 188 as the power cable injector 195 inserts the power cable 188 within the wellbore 140 or retrieves the power cable 188 from the wellbore 140. In this embodiment, the tubular control system 260 (e.g., power cable control system 265) is configured to modulate the power cable rate upon which the power cable injector 195 inserts the power cable 188 within the wellbore 140 or retrieves the power cable 188 from the wellbore 140 based upon data obtained from the tension measuring device. In at least one embodiment, the tension measuring device is associated with the bottom hole assembly (BHA) housing 220, the tension measuring device configured to couple between the bottom hole assembly (BHA) housing 220 and the power cable 188 to measure the amount of tension or compression on the power cable 188 (e.g., proximate the bottom hole assembly (BHA) housing 220)

In the illustrated embodiment of FIG. 2B, a first tension measuring device 235 is associated with the power cable 188. For example, the first tension measuring device 235 could be coupled between the bottom hole assembly (BHA) housing 220 and the power cable 188 (e.g., in the power cable connector 230). Accordingly, the first tension measuring device 235, which could comprise a load cell, could be used to measure the amount of tension or compression on the power cable 188 (e.g., proximate the bottom hole assembly (BHA) housing 220).

Further to the embodiment of FIG. 2B, a second tension measuring device 245 is associated with the coiled tubing string 125. For example, the second tension measuring device 245 could be coupled between the bottom hole assembly (BHA) housing 220 and the coiled tubing string 125 (e.g., in the coiled tubing connector 240). Accordingly, the second tension measuring device 245, which could also comprise a load cell, could be used to measure the amount of tension or compression on the coiled tubing string 125 (e.g., proximate the bottom hole assembly (BHA) housing 220). While the embodiment of FIG. 2B illustrates particular placements for the first and second tension measuring devices 235, 245, other embodiments could place them in different locations in the well system 200, for example so long as they are placed to measure the tension and/or compression on the power cable 188 and/or coiled tubing string 125, respectively.

Given the foregoing embodiments, data from the first tension measuring device 235 may be fed to the tubular control system 260 (e.g., power cable control system 265). In turn, the tubular control system 260 (e.g., power cable control system 265) may modulate a power cable rate upon which the power cable injector 195 inserts the power cable 188 within the wellbore 140 or retrieves the power cable 188 from the wellbore 140 (e.g., relative to a coiled tubing rate upon which the coiled tubing injector 135 inserts the coiled tubing string 125 within the wellbore 140 or retrieves the coiled tubing string 125 from the wellbore 140). Similarly, data from the second tension measuring device 245 may be fed to the tubular control system 260 (e.g., coiled tubing string control system 270). In turn, the tubular control system 260 (e.g., coiled tubing control system) may modulate a coiled tubing rate upon which the coiled tubing injector 135 inserts the coiled tubing string 125 within the wellbore 140 or retrieves the coiled tubing string 125 from the wellbore 140 (e.g., relative to a power cable rate upon which the power cable injector 195 inserts the power cable 188 within the wellbore 140 or retrieves the power cable 188 from the wellbore 140). In certain embodiments, only the power cable control system 265 is used, and the coiled tubing string control system 270 is not, and in certain other embodiments the opposite is true. Nevertheless, in the illustrated embodiment, both the power cable control system 265 and the coiled tubing string control system 270 are being employed. Furthermore, while the power cable control system 265 and the coiled tubing string control system 270 are illustrated as part of the integrated tubular control system 260, in other embodiments they are standalone systems.

Turning to FIG. 2C, with continued reference to FIG. 2A, illustrated is a cross-sectional view of one embodiment of the power cable 188 of FIG. 2A. In the illustrated embodiment, the power cable 188 includes an outer tube 280, such as an outer metal tube. Further to the illustrated embodiment, the power cable 188 includes cable lining 282 (e.g., for electric or thermal insulation, coupling and load transfer between the outer tube 280 and the inner insulation material 292, for additional support of external pressure or forces/weight exerted on the power cable, or for other purposes). Further to the illustrated embodiment, the power cable 188 may include a primary fluid hydraulic flowline 284 (e.g., for providing operation fluid to/from the bottom hole assembly (BHA) 210), which may also include its own anti-erosion layer. Further to the illustrated embodiment of FIG. 2C, the power cable 188 may include one or more hydraulic control flowlines 286 (e.g., for providing control fluid to/from the bottom hole assembly (BHA) 210), one or more power conductors 288 (e.g., one or more power conductors for powering the pulsed power drilling system 250), and one or more communication conductors 290 (e.g., one or more electric and/or fiberoptic communication conductors). In at least one embodiment, an insulation material 292 may be located within the outer tube 280, thereby surrounding at least a portion of one or more of the primary fluid hydraulic flowline 284, hydraulic control flowlines 286, power conductors 288 and/or communication conductors 290.

The coiled tubing surface equipment spread 205 of FIGS. 2A through 2C has many advantages over traditional designs, including those traditional designs that place the power cable within the inside diameter (ID) of the coiled tubing string 125. In at least one embodiment, the coiled tubing surface equipment spread 205 of FIGS. 2A through 2C enables having a single, full-length coiled tubing string 125, and a single, full-length power cable 188 (e.g., power & communication cable). Thus, in one embodiment, this provides for a smaller coiled tubing string 125 outside diameter (OD) and a less heavy coiled tubing string 125. This also, in one or more embodiments, reduces coiled tubing string 125 transport and lifting challenges (e.g., including weight and size). This may further eliminate certain challenge of inserting the large power cable 188 inside the coiled tubing string 125, as well as eliminate the need for connecting and disconnecting multiple coiled tubing strings 125 and power cables 188. The coiled tubing surface equipment spread 205 according to FIGS. 2A through 2C of the present disclosure further provides unobstructed fluid flow through the coiled tubing string 125, as well as safer and lower cost operation.

Additionally, the coiled tubing surface equipment spread 205 of FIGS. 2A through 2C has many advantages over having the power cable 188 frequently clamped to coiled tubing string 125 outside diameter (OD). For example, in at least one embodiment, this provides for much faster running in and pulling out of the coiled tubing string 125 from the wellbore 140. In yet another embodiment, this provides for safer operation, for example as there is no need to install cable clamps while running in and removing them while pulling the coiled tubing string 125 out of the wellbore 140. In even yet another embodiment, this provides simpler well pressure control at the surface (e.g., can use combined or individual/separate strippers for coiled tubing string and cable, no clamps to pass through surface/well control equipment, etc.).

Turning to FIG. 3A, illustrated is a well system 300 including a coiled tubing surface equipment spread 305 designed, manufactured and operated according to an alternative embodiment of the disclosure. The well system 300 and coiled tubing surface equipment spread 305 of FIG. 3 are similar in many respects to the well system 200 and coiled tubing surface equipment spread 205 of FIG. 2A. Accordingly, like reference numbers have been used to indicate similar, if not identical, features. The well system 300, and associated coiled tubing surface equipment spread 305, in the illustrated embodiment, is positioned over water 310, for example in an offshore application employing a riser type design or a riser-less type design. In at least one embodiment, the well system 300 further includes well pressure control equipment 320, in this instance a blowout preventor (BOP). Further to the embodiment of FIG. 3A, the well system 300 may include a stripper system 330, the stripper system 330 configured to provide a pressure barrier between one or more of the coiled tubing string 125 and/or the power cable 188 and the wellbore 140.

Turning briefly to FIG. 3B, illustrated is a zoomed in view of the well pressure control equipment 320 and stripper system 330 of FIG. 3A.

Turning now to FIG. 3C, illustrated is a zoomed in view of one embodiment of a stripper system 330c, which may be somewhat similar to the stripper system 330 of FIGS. 3A the 3B, designed, manufactured and/or operated according to one or more embodiments of the disclosure. In the illustrated embodiment of FIG. 3C, the stripper system 330c includes a coiled tubing stripper 340c associated with the coiled tubing injector 135, and/or a power cable stripper 350c associated with the power cable injector 195. In one or more embodiments, such as shown, the coiled tubing stripper 340c and the power cable stripper 350c form at least a portion of an integrated stripper associated with both the coiled tubing string 125 and the power cable 188. For example, in at least one embodiment, a coiled tubing seal 345c of the coiled tubing stripper 340c and a power cable seal 355c of the power cable stripper 350c are parallel with one another. Other embodiments of the disclosure may be used wherein the coiled tubing stripper 340c and the power cable stripper 350c form at least a portion of a non-integrated stripper.

Turning now to FIG. 3D, illustrated is a zoomed in view of one embodiment of a stripper system 330d, which may be somewhat similar to the stripper system 330 of FIG. 3A the 3B, designed, manufactured and/or operated according to one or more embodiments of the disclosure. In the illustrated embodiment of FIG. 3D, the stripper system 330d includes a coiled tubing stripper 340d associated with the coiled tubing injector 135, and/or a power cable stripper 350d associated with the power cable injector 195. In one or more embodiments, such as that shown, the coiled tubing stripper 340d and the power cable stripper 350d form at least a portion of an integrated stripper associated with both the coiled tubing string 125 and the power cable 188. For example, in at least one embodiment, a coiled tubing seal 345d of the coiled tubing stripper 340d and a power cable seal 355d of the power cable stripper 350d are angled relative to one another, for example by an angle (θ). In at least one embodiment, the angle (θ) is at least 2 degrees, if not at least 4 degrees, if not at least 10 degrees, if not at least 15 degrees, if not at least 25 degrees, if not at least 45 degrees. In at least one embodiment, the angle (θ) ranges from 5 degrees to 35 degrees, if not from 10 degrees to 25 degrees. Other embodiments of the disclosure may be used wherein the coiled tubing stripper 340d and the power cable stripper 350d form at least a portion of a non-integrated stripper.

Turning to FIG. 4, illustrated is a representation of a system 400 that may be employed to perform various steps, methods, and techniques disclosed herein (e.g., via the execution of software). In the embodiment of FIG. 4, the system 400 may include a Computer System and Models module 410 according to one or more embodiments of the disclosure. In at least one embodiment, the Computer System and Models module 410 may include one or more processor(s), cache, memory, storage, and/or one or more peripheral device(s). Any two or more of these components may be operatively connected via a system bus that provides a means for transferring data between those components.

In the illustrated embodiment, the Computer System and Models module 410 is configured to receive data from a Surface & Downhole Sensor Data Module 420. In at least one embodiment, the Surface & Downhole Sensor Data Module 420 may include one or more of a power cable tension measuring device and/or a coiled tubing string tension measuring device. In at least one embodiment, the Surface & Downhole Sensor Data Module 420 may further include one or more processor(s), cache, memory, storage, and/or one or more peripheral device(s). Any two or more of these components may be operatively connected via a system bus that provides a means for transferring data between those components.

The Computer System and Models module 410, for example having received data from the Surface & Downhole Sensor Data Module 420, is then configured to send instructions to the Tubular Control System 430 (e.g., which may operatively include the Power Cable Control System Module 440 and/or Coiled Tubing String Control System Module 450). As detailed above, the Power Cable Control System Module 440 and/or Coiled Tubing String Control System Module 450 may then: 1) modulate a power cable rate upon which the power cable injector inserts the power cable within the wellbore or retrieves the power cable from the wellbore relative to a coiled tubing rate upon which the coiled tubing injector inserts the coiled tubing string within the wellbore or retrieves the coiled tubing string from the wellbore; or 2) modulate the coiled tubing rate upon which the coiled tubing injector inserts the coiled tubing string within the wellbore or retrieves the coiled tubing string from the wellbore relative to the power cable rate upon which the power cable injector inserts the power cable within the wellbore or retrieves the power cable from the wellbore.

Aspects disclosed herein include:

A. A coiled tubing deployment/retrieval apparatus, the coiled tubing deployment/retrieval apparatus including: 1) a frame; 2) a coiled tubing guide coupled to the frame; 3) a coiled tubing injector coupled to the frame, the coiled tubing injector configured to insert or retrieve a coiled tubing string guided by the coiled tubing guide into or out of a wellbore; and 4) a power cable injector coupled to the frame, the power cable injector configured to insert or retrieve a power cable into or out of the wellbore alongside the coiled tubing string.

B. A coiled tubing surface equipment spread, the coiled tubing surface equipment spread including: 1) a coiled tubing deployment/retrieval apparatus, the coiled tubing deployment/retrieval apparatus including: a) a frame; b) a coiled tubing guide coupled to the frame; c) a coiled tubing injector coupled to the frame, the coiled tubing injector configured to insert or retrieve a coiled tubing string guided by the coiled tubing guide into or out of a wellbore; and d) a power cable injector coupled to the frame, the power cable injector configured to insert or retrieve a power cable into or out of the wellbore alongside the coiled tubing string; and 2) a coiled tubing reel positioned proximate the coiled tubing deployment/retrieval apparatus, the coiled tubing reel including coiled tubing wound thereabout.

C. A method, the method including: 1) providing a coiled tubing surface equipment spread, the coiled tubing surface equipment spread including: a) a coiled tubing deployment/retrieval apparatus, the coiled tubing deployment/retrieval apparatus including; i) a frame; ii) a coiled tubing guide coupled to the frame; iii) a coiled tubing injector coupled to the frame, the coiled tubing injector configured to insert or retrieve a coiled tubing string guided by the coiled tubing guide into or out of the wellbore; and iv) a power cable injector coupled to the frame, the power cable injector configured to insert or retrieve a power cable into or out of the wellbore alongside the coiled tubing string; b) a coiled tubing reel positioned proximate the coiled tubing deployment/retrieval apparatus, the coiled tubing reel including coiled tubing wound thereabout; and c) a power cable reel positioned proximate the coiled tubing deployment/retrieval apparatus, the power cable reel including a power cable wound thereabout; and 2) operating the coiled tubing injector and the power cable injector in coordination to insert the coiled tubing string and the power cable within a wellbore or retrieve the coiled tubing string and the power cable from the wellbore.

D. A bottom hole assembly, the bottom hole assembly including: 1) a bottom hole assembly housing, the bottom hole assembly housing including an uphole end and a downhole end, the uphole end including a power cable connector configured to engage with a power cable; and 2) a tension measuring device associated with the bottom hole assembly housing, the tension measuring device configured to couple between the bottom hole assembly housing and the power cable to measure an amount of tension on the power cable proximate the bottom hole assembly housing.

E. A well system, the well system including: 1) a wellbore extending from a terranean surface through one or more subterranean formations; and 2) a bottom hole assembly located in the wellbore, the bottom hole assembly including: a) a bottom hole assembly housing, the bottom hole assembly housing including an uphole end and a downhole end, the uphole end including a power cable connector configured to engage with a power cable; and b) a tension measuring device associated with the bottom hole assembly housing, the tension measuring device configured to couple between the bottom hole assembly housing and the power cable to measure an amount of tension on the power cable proximate the bottom hole assembly housing.

F. A method, the method including: 1) positioning a bottom hole assembly within a wellbore extending from a terranean surface through one or more subterranean formations, the bottom hole assembly including: a) a bottom hole assembly housing, the bottom hole assembly housing including an uphole end and a downhole end, the uphole end including a power cable connector configured to engage with a power cable; and b) a tension measuring device associated with the bottom hole assembly housing, the tension measuring device configured to couple between the bottom hole assembly housing and the power cable to measure an amount of tension on the power cable proximate the bottom hole assembly housing; and 2) modulating a power cable rate upon which the power cable is insert within the wellbore based upon data obtained from the tension measuring device.

G. A surface equipment spread, the surface equipment spread including: 1) a frame; 2) a first injector coupled to the frame, the first tubing injector configured to insert or retrieve a first wellbore feature into or out of a wellbore; 3) a second injector coupled to the frame, the second injector configured to insert or retrieve a second wellbore feature into or out of the wellbore alongside the first wellbore feature; and 4) a control system coupled with the first injector, the control system configured to modulate a first rate upon which the first injector inserts the first wellbore feature within the wellbore or retrieves the first wellbore feature from the wellbore relative to a second rate upon which the second injector inserts the second wellbore feature within the wellbore or retrieves the second wellbore feature from the wellbore.

H. A well system, the well system including: 1) a wellbore extending through one or more subterranean formations; and 2) a coiled tubing surface equipment spread positioned over the wellbore, the coiled tubing surface equipment spread including: a) a frame; b) a first injector coupled to the frame, the first tubing injector configured to insert or retrieve a first wellbore feature into or out of a wellbore; c) a second injector coupled to the frame, the second injector configured to insert or retrieve a second wellbore feature into or out of the wellbore alongside the first wellbore feature; and d) a control system coupled with the first injector, the control system configured to modulate a first rate upon which the first injector inserts the first wellbore feature within the wellbore or retrieves the first wellbore feature from the wellbore relative to a second rate upon which the second injector inserts the second wellbore feature within the wellbore or retrieves the second wellbore feature from the wellbore.