US-12618311-B2 - Methods and systems for installing tubulars in wells

Abstract

A system may include a handling mast, a tubular source stack, a tubing loader, a spider device, and a connection device. The tubing loader is configured to capture a first HVT from the tubular source stack, load the first HVT into the handling mast, capture a second HVT from the tubular source stack, and load the second HVT into the handling mast. The spider device is configured to grasp the first HVT. The connection device is configured to align a proximal end of the first HVT and a distal end of the second HVT and couple the first HVT and the second HVT to form a tubing string. The handling mast is configured to insert the tubing string into the wellbore.

Inventors

• Greg Szutiak
• John R. Muir
• Alan D. Eastman
• Joseph A. Scherer

Assignees

• Greenfire Energy Inc.

Dates

Publication Date

20260505

Application Date

20241108

Claims (16)

1. 1 . A specialized tubing insertion rig (STIR) for installing a plurality of bidirectional fluid conduits (BFC) in a wellbore, the STIR comprising: a handling mast; a tubular source stack, configured to store the plurality of BFC; and a tubing loader, comprising a tubular running too, configured to: capture a first BFC from the tubular source stack, load the first BFC into the handling mast, capture a second BFC from the tubular source stack, and load the second BFC into the handling mast, wherein the handling mast is configured to insert a downhole heat exchanger and the first BFC into the wellbore; a spider device configured to grasp the first BFC so that the first BFC is suspended at least partially within the wellbore by the spider device; and a connection device configured to: align a proximal end of the first BFC and a distal end of the second BFC; and couple a first portion of a fastening component of the proximal end of the first BFC and a second portion of the fastening component of the distal end of the second BFC to form a tubing string, wherein the STIR is configured to insert the tubing string into the wellbore; and a control system configured to: determine a number of rotations of the proximal end of the second BFC during coupling of each BFC and detecting if the number of rotations exceeds a preset rotation threshold; determine a torque experienced between the proximal end of the first BFC and the distal end of the second BFC and detecting if the torque is greater than a preset torque threshold.
2. 2 . The system of claim 1 , wherein each of the plurality of BFC comprises an axial length that is greater than 30 ft in length, wherein the STIR is configured to insert the plurality of BFC having the axial length into the wellbore.
3. 3 . The system of claim 1 , wherein the tubular running tool comprises a bladder configured to grip an internal surface of the BFC.
4. 4 . The system of claim 1 , wherein the handling mast comprises: a tubular running tool configured to capture each of the first BFC and the second BFC; and a winch configured to raise and lower the tubular running tool.
5. 5 . The system of claim 1 , wherein the STIR further comprises an uphole pump, configured to pump working fluid into the BFC during insertion of the BFC into the wellbore.
6. 6 . The system of claim 1 , wherein the connection device comprises a power tong configured to rotate the second BFC to couple the second BFC to the first BFC.
7. 7 . The system of claim 1 , wherein the BFC comprises a vacuum-insulated tubular.
8. 8 . The system of claim 1 , wherein the STIR further comprises an adjustable folding base.
9. 9 . The system of claim 1 , wherein the STIR further comprises an adjustable folding base.
10. 10 . A method for installing bidirectional fluid conduits (BFC) in a wellbore penetrating a source formation, the method comprising: placing a specialized tubing insertion rig (STIR) at a well site including the wellbore, wherein the STIR is configured to handle a plurality of BFC so as not to damage each of the plurality of BFC and insert the plurality of BFC in the wellbore, wherein the plurality of BFC comprises a first BFC and a second BFC; capturing, using a tubular loading tool, the first BFC from a tubular source stack, wherein each of the plurality of BFC comprises a distal end and a proximal end, wherein each distal end comprises a first portion of a fastening component and each proximal end comprises a second portion of the fastening component; loading, using the tubular loading tool, the first BFC into a handling mast; disposing a downhole heat exchanger on the distal end of the first BFC; inserting, using the handling mast, the downhole heat exchanger and the first BFC into the wellbore, wherein the first BFC is inserted with the distal end inserted first and is inserted until the proximal end is positioned adjacent to a spider device configured to grasp each BFC; grasping, using the spider device, the first BFC so that the first BFC is supported at least partially within the wellbore by the spider device; capturing, using the tubular loading tool, the second BFC from the tubular source stack, loading, using the tubular loading tool, the second BFC into the handling mast; aligning, using a connection device, the proximal end of the first BFC and the distal end of the second BFC; coupling, using the connection device, the first portion of the fastening component of the proximal end of the first BFC and the second portion of the fastening component of the distal end of the second BFC to form a tubing string; using a control system: determining a number of rotations of the proximal end of the second BFC during coupling of each BFC and detecting if the number of rotations exceeds a preset rotation threshold, and determining a torque experienced between the proximal end of the first BFC and the distal end of the second BFC and detecting if the torque is greater than a preset torque threshold; and inserting, using the handling mast, the tubing string into the wellbore if the torque is not greater than the preset torque threshold.
11. 11 . The method of claim 10 , wherein the tubular running tool comprises a bladder configured to grip an internal surface of the BFC.
12. 12 . The method of claim 10 , wherein the handling mast comprises: a tubular running tool configured to capture each of the first BFC and the second BFC; and a winch configured to raise and lower the tubular running tool.
13. 13 . The method of claim 10 , wherein the STIR further comprises an uphole pump, configured to pump working fluid into the BFC during insertion of the BFC into the wellbore.
14. 14 . The method of claim 10 , wherein the connection device comprises a power tong configured to rotate the second BFC, wherein the method further comprises rotating, using the power tong, the second BFC in order to couple the second BFC to the first BFC.
15. 15 . The method of claim 10 , wherein the BFC comprises a vacuum-insulated tubular.
16. 16 . The method of claim 10 , wherein the STIR is further configured to carry out tubing insertion operations automatically using a control system.

Description

BACKGROUND In conventional drilling and completion, either a drilling rig or a completion rig would be used for inserting tubulars after a new well is drilled, or for inserting tubulars in an existing well. Both drilling and completion rigs are designed for use with standard steel pipes. Consequently, their equipment may be insufficiently precise and insufficiently gentle to assure that more-delicate high-value tubulars (HVT) are not damaged during insertion into the wellbore. This is especially significant at the joints in a tubing string, which are highly susceptible to assembly errors like cross-threading. In the geothermal context, not only can the joints leak well fluids, but the loss of the heat carried by those fluids can have a strong deleterious effect on well operation. SUMMARY This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter. In some aspects, the techniques described herein relate to a system for installing high-value tubulars (HVT) in a wellbore. The system includes a specialized tubing insertion rig (STIR) configured to handle a plurality of HVT so as not to damage each of the plurality of HVT and insert the plurality of HVT in the wellbore. The STIR includes a handling mast, a tubular source stack, a tubing loader, a spider device, a connection device, and a control system. The tubular source stack is configured to store the plurality of HVT. The tubing loader is configured to capture a first HVT from the tubular source stack, load the first HVT into the handling mast, capture a second HVT from the tubular source stack, and load the second HVT into the handling mast. The handling mast is configured to insert a downhole heat exchanger and the first HVT into the wellbore. The spider device is configured to grasp the first HVT so that the first HVT is suspended at least partially within the wellbore by the spider device. The connection device is configured to align a proximal end of the first HVT and a distal end of the second HVT. The connection device is configured to couple a first portion of a fastening component of the proximal end of the first HVT and a second portion of the fastening component of the distal end of the second HVT to form a tubing string. The STIR is configured to insert the tubing string into the wellbore. The control system configured to: determine a number of rotations of the proximal end of the second HVT during coupling of each HVT; determine if a torque experienced between the proximal end of the first HVT and the distal end of the second HVT is greater than a preset torque threshold. In some aspects, the techniques described herein relate to a method for installing high-value tubulars (HVT) in a wellbore penetrating a source formation. The method includes placing a specialized tubing insertion rig (STIR) at a well site including the wellbore. The STIR is configured to handle a plurality of HVT so as not to damage each of the plurality of HVT and insert the plurality of HVT in the wellbore. The plurality of HVT includes a first HVT and a second HVT. The method includes capturing, using a tubing loader, the first HVT from a tubular source stack. Each of the plurality of HVT includes a distal end and a proximal end. Each distal end includes a first portion of a fastening component and each proximal end includes a second portion of the fastening component. The method includes loading, using the tubing loader, the first HVT into a handling mast. The method includes disposing a downhole heat exchanger on the distal end of the first HVT. The method includes inserting, using the handling mast, the downhole heat exchanger and the first HVT into the wellbore. The first HVT is inserted with the distal end inserted first and is inserted until the proximal end is positioned adjacent to a spider device configured to grasp each HVT. The method includes grasping, using the spider device, the first HVT so that the first HVT is supported at least partially within the wellbore by the spider device. The method includes capturing, using the tubing loader, the second HVT from the tubular source stack. The method includes loading, using the tubing loader, the second HVT into the handling mast. The method includes aligning, using a connection device, the proximal end of the first HVT and the distal end of the second HVT. The method includes coupling, using the connection device, the first portion of the fastening component of the proximal end of the first HVT and the second portion of the fastening component of the distal end of the second HVT to form a tubing string. The method includes determining a number of rotations of the proximal end of the second HVT during coupling of each HVT. The method includes determining if a torque e