Dislodgement of stuck tubing in well operations

Abstract

A method includes, in response to an indication that a length of tubing has become stuck at a downhole location in a wellbore drilled into a subterranean zone, at least partially displacing wellbore fluid with a displacement fluid having a specific gravity greater than a specific gravity of the wellbore fluid. The method further includes, after the at least partially displacing the wellbore fluid with the displacement fluid, dislodging the length of tubing from the downhole location.

Description

F&R Ref. 50511-0093 WO1DISLQDGEMENT OF STUCK TUBING IN WELL OPERATIONSCLAIM OF PRIORITY

[0001] This application claims the benefit of U.S. Provisional Application Serial No. 63 / 700,477, filed on September 27, 2024. The entire contents of the foregoing are incorporated herein by reference.TECHNICAL FIELD

[0002] This disclosure relates to management of tubing in wellbores, including coiled tubing strings for drilling, completion, or operation of well systems.BACKGROUND

[0003] Composite tubing such as composite coiled tubing can be utilized for the drilling of deep wells. Sometimes during operations the tubing can become stuck in the wellbore, necessitating recovery of the coiled tubing which can increase costs and complexity of the operations and the risks to personnel and the environment.F&R Ref. 50511-0093 WO1DESCRIPTION OF DRAWINGS

[0004] Figure 1 is a schematic illustration of a drilling system in accordance with the concepts herein.

[0005] Figures 2A-2C are schematic illustrations of closed-loop geothermal systems in accordance with the concepts herein.

[0006] Figures 3A-3B is a process flow chart of tubing dislodgement operations in accordance with the concepts herein.

[0007] Figs. 4A-4E are schematic illustrations of tubing dislodgement operations in accordance with the concepts herein.

[0008] The drawings are not to scale.F&R Ref. 50511-0093 WO1SUMMARY

[0009] Certain aspects of the present disclosure encompass a method of well operations. The method includes, in response to an indication that a length of tubing has become stuck at a downhole location in a wellbore drilled into a subterranean zone, at least partially displacing wellbore fluid with a displacement fluid having a specific gravity greater than a specific gravity of the wellbore fluid. The method further includes, after the at least partially displacing the wellbore fluid with the displacement fluid, dislodging the length of tubing from the downhole location.

[0010] Certain aspects of the present disclosure encompass a method of dislodging tubing from a stuck location in a wellbore. The method includes increasing a buoyant force exerted on the tubing by displacing wellbore fluid with a displacement fluid having a specific gravity at least equal to a specific gravity of the tubing, and dislodging the tubing from the stuck location at least in part by the buoyant force.

[0011] Certain aspects of the present disclosure encompass a method of well operations. The method includes, in response to an indication that tubing has become stuck at a location in a wellbore, applying force to the tubing in an uphole direction. The force is a combination of at least a tensile force applied to the tubing from applied from a surface location and a buoyant force exerted on the tubing by fluid in the wellbore, the fluid in the wellbore exerting the buoyant force having a specific gravity equal to or greater than a specific gravity of the tubing. After applying the force, the tubing is at least partially retrieved from the wellbore.

[0012] Aspects of the present disclosure can encompass some, none, or all of the following features. The dislodging can be at least in part by a buoyant force exerted by the displacement fluid on the length of tubing. The specific gravity of the displacement fluid can be greater than a specific gravity of the length of tubing. The length of tubing can be composite coiled tubing. The composite coiled tubing can comprise thermoplastic composite pipe. A specific gravity of the length of tubing can be less than about 2.0. The length of tubing can comprise a drill string. The displacement fluid can comprise barite.F&R Ref. 50511-0093 WO1The subterranean zone can be a geothermal production zone. The subterranean zone can be a basement formation.

[0013] Aspects of the present disclosure can encompass some, none, or all of the following features. The wellbore can be further drilled with the drill string, without removing the drill string from the wellbore after the dislodging. The length of tubing can comprise a workover string. The dislodging can be at least in part by applying a tensional force to the length of tubing. Further in response to the indication that the length of tubing has become stuck at the downhole location and prior to the applying the tensional force to the length of tubing, the method can comprise increasing a pressure within the length of tubing, thereby increasing a tensile strength of the length of tubing.

[0014] Aspects of the present disclosure can encompass some, none, or all of the following features. The at least partially displacing the wellbore fluid with the displacement fluid can include (a) at least partially displacing the wellbore fluid with a first volume of displacement fluid, the first volume of displacement fluid having a specific gravity greater than the specific gravity of the wellbore fluid, and in response to an indication that the length of tubing remains stuck after the at least partially displacing the wellbore fluid with the first volume of displacement fluid, at least partially displacing the first volume of displacement fluid with a second volume of displacement fluid, the second volume of displacement fluid having a specific gravity greater than the specific gravity of the first volume of displacement fluid and a specific gravity of the length of tubing. The retrieving the length of tubing from the wellbore after displacing wellbore fluid with the displacement fluid can comprise retrieving the length of tubing after the at least partially displacing the first volume of wellbore displacement fluid with the second volume of wellbore displacement fluid. The first volume of displacement fluid can have a specific gravity substantially equal to the specific gravity of the length of tubing. The specific gravity of the first volume of displacement fluid can be less than about 2.0. The specific gravity of the second volume of displacement fluid can be between about 1.0 and about 3.0.

[0015] Aspects of the present disclosure can encompass some, none, or all of the following features. The at least partially displacing wellbore fluid with the displacement fluid canF&R Ref. 50511-0093 WO1 include flowing the displacement fluid in a downhole direction through the length of tubing. The at least partially displacing wellbore fluid with the displacement fluid can include flowing the displacement fluid in a downhole direction through an annulus defined by an inner surface of the wellbore an outer surface of the length of tubing. The flowing the displacement fluid in a downhole direction through the annulus can be in response to an indication of a failure to flow fluid in a downhole direction through the length of tubing.F&R Ref. 50511-0093 WO1DETAILED DESCRIPTION

[0016] The drilling of deep well systems such as multilateral geothermal well systems can present many challenges, including the possibility of tubing becoming stuck at a downhole location during drilling or other operations. Drill strings, workover strings, and other tubing utilized for the drilling of deep well systems, such as coiled tubing strings, may be comprised of composite materials such as thermoplastic composite pipe (TCP). Because such composite materials generally exhibit lower tensile properties compared to metallic strings, the dislodgement of such composite tubing in the event of it becomes stuck can present technical challenges.

[0017] In response to an indication that a length of tubing (such as composite tubing) has become stuck at a downhole location in a wellbore, in accordance with instances of the present disclosure, wellbore fluid can be at least partially displaced with a displacement fluid having a specific gravity (SG) greater than the SG of the wellbore fluid and, in some instances, greater than the SG of the tubing. The buoyant force exerted by the displacement fluid on the tubing can reduce or eliminate the tensile force required to dislodge the tubing.

[0018] FIG. 1 is a schematic illustration of a wellbore drilling system 100 in accordance with an instance of the present disclosure wellbore 102 is formed in a subterranean zone 104 by drilling with tubing 106 positioned therein. In the illustrated embodiment, tubing 106 is a composite coiled tubing (CCT) drill string. Tubing 106 in the illustrated instance is a drill string that includes a bottomhole assembly (BHA) 108 at its downhole end. BHA 108 includes drilling bit 110 and can further include drill collars, directional drilling instrumentation and other various electrical and electronic components for operating and / or controlling drilling bit 110. The central bore 112 of tubing 106 defines a conduit for flowing a drilling fluid 114 to the downhole end of the wellbore to displace broken formation material, which then is carried by drilling fluid 114 up the annulus 116 that is defined between the exterior of tubing 106 and the interior surface of wellbore 102. In the illustrated instance, an uphole portion of wellbore 102 has been lined with casing 118, andF&R Ref. 50511-0093 WO1 a lower portion 120 remains open-hole. In some instances, lower portion 120 may be sealed absent casing, as described in further detail below.

[0019] In certain instances, a drilling bit 110 is a contact-type drilling bit, such as a polycrystalline diamond compact (PDC) drilling bit, tri-cone drilling bit, rotary drilling bit, and / or another type of drilling bit that relies on the bit contacting the rock and mechanically transmitting force to load the rock face (i.e., the end wall of the wellbore at which rock is being removed) break the rock, and thus drill. In other instances, the drilling bit can be a contactless drilling bit configured to break the rock at the rock face being drilled without requiring mechanical loading by contact between the bit and the rock face. Examples of contactless drilling bits include bits for 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), microwave drilling (such as the microwave drilling system developed by Quaise, Inc.), thermal spallation drilling including supercritical water jetting or flame jets, electro-pulse drilling (such as the electro-pulse drilling systems developed by Tetra Corporation), and particle drilling (e.g., impacting the rock with particles entrained in fluid, such as the system developed by Particle Drilling Technologies, Inc.). Although, referred to as “contactless,” this descriptor is not meant to exclude systems where portions of a drilling bit may bump, brush against, or otherwise come into contact with the formation during the drilling process.

[0020] In some instances, subterranean zone 104 comprises a geothermal production zone. Drilling system 100 with tubing (drill string) 106 can be used, for example, to drill multilateral wellbores for a closed-loop geothermal system such as well system 200 of FIGS. 2A - 2C. More specifically, FIG. 2A shows an example closed-loop geothermal system 200 in schematic, side cross-sectional view in accordance with the concepts herein. System 200 includes a geothermal well 202 drilled into the Earth from the terranean surface 210 through subterranean zone 104. 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 isF&R Ref. 50511-0093 WO1 granite. In the illustrated instance, well 202 includes an inlet surface wellbore 220 and an outlet surface wellbore 230 in close proximity, each extending between the terranean surface and the subterranean zone 104. The inlet surface wellbore 220 and outlet surface wellbore 230 are connected within the subterranean zone 104 by one or more connecting wellbores 240. In the illustrated instance, connecting wellbores 240 define a multilateral pattern of wellbores, including a plurality of pairs of lateral wellbores 250, a subset of which are kicked off from the inlet wellbore 220 and a subset of which are kicked off from the outlet wellbore 230. The pairs of lateral wellbores 250 each intersect at a respective junction at or near their respective toes. Thus, the inlet wellbore 220, outlet wellbore 230 and connecting wellbores 240 define a closed loop.

[0021] The inlet wellbore 220 and the outlet wellbore 230 can be drilled from the same drilling pad and / or reside on the same well site. In certain instances, the wellbores 220, 230 are drilled within 10, 25, 50 or 100 meters of one another. In other instances, the inlet surface wellbore 220 and the outlet surface wellbore 230 can be separated by a longer distance. For example, FIG. 2C, discussed in more detail below, shows a configuration where the surface wellbores 220, 230 and the connecting wellbores 240 define a U-shape configuration. In certain instances, the inlet surface wellbore 220 and the outlet surface wellbore 230, when the geothermal well 202 is configured as a U-shape, are drilled 3,000 meters or more apart.

[0022] In the illustrated instance, inlet surface wellbore 220 and outlet surface wellbore 230 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 other than vertical (e.g., slanted) and / or may be drilled with the use of directional drilling techniques. The connecting wellbores 240 are drilled using directional drilling techniques through the surface wellbores 220, 230, and include a curve in their trajectory beginning at a kickoff 248 at surface wellbores 220, 230. Although shown as slanted downward, in some instances, some or all of the connecting wellbores are horizontal. In some instances, the connecting wellbores 240 follow the geological dip of the formation in the subterranean zone. In some instances, lateral wellbores 250 are anywhere from 2,000F&R Ref. 50511-0093 WO1 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.

[0023] FIG. 2A shows each pair of lateral wellbores 250 parallel to one another extending in the same direction (azimuth) from their respective surface wellbore 220, 230. The lateral wellbores 250 extending from the inlet surface wellbore 220 are shown above the lateral wellbores 250 extending from the outlet surface wellbore 230. In some instances, the upper lateral wellbores 250 are directly above their (and are, in some instances, directly above a respective one of the lower lateral wellbores 250. In FIG. 2A the upper lateral wellbores 250 each turn to intersect its adjacent lower lateral wellbore 250 pair at the junction 254 to connect the surface wellbores 220, 230. In other instances, one or more of the lower lateral wellbores 250 could intersect the upper lateral wellbores 250. Regardless, the configuration of connecting wellbores 240, 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 220, 230 at different depths (i.e., with different kickoffs 248). In FIG.2A , the lower lateral wellbores 250 extend past and below the junction 254 to define a sump 252. The sump 252 provides a location for debris to accumulate outside of the flow path through the wellbores. In other instances, one or more of the upper lateral wellbores 250 could extend past the junction to define the sump 252.

[0024] The connecting wellbores 240 of FIG. 2A slant downward; i.e., they have an inclination 270 from vertical. In some instances, some or all of the connecting wellbores can be horizontal (i.e., having an inclination 270 of about ninety degrees) or substantially horizontal. In some instances, as shown in FIG. 2B, connecting wellbores 240 can have a steeper slant; i.e., inclination 270 can be less than that shown in FIG. 2B, or vertical (inclination 270 is zero) or substantially vertical. In some instances, connecting wellbores 240 follow the geological dip of the formation in the subterranean zone. In some instances, lateral wellbores 250can have a length of 2,000 meters to 10,000 meters or more and can reach a depth of 1,000 meters to 8,000 meters or more.

[0025] FIG. 2C is another embodiment of a geothermal well system 200 having lateral wellbores 250 extending, respectively, from the inlet and outlet surface wellbores 220, 230F&R Ref. 50511-0093 WO1 toward one another. The pairs of lateral wellbores 250, once intersected, together with the inlet and outlet wellbores 220, 230, define a generally U-shape. The configuration of connecting wellbores 240 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 220, 230 at different depths (i.e., with different kickoffs 248).

[0026] Referring to FIGS. 2A - 2C, collectively, in some instances, the surface wellbores 220, 230 are cased (at least partially or entirely), and the connecting wellbores 240, including the junctures at the kickoffs 248 are open hole (i.e., without casing or liner or a junction liner). In some instances, the connecting wellbores 240 can be at least partially lined (e.g., include a liner or casing in those portions where the subterranean zone 104 is fractured, susceptible to collapse, unconsolidated or otherwise needing a liner). The connecting wellbores 240, including the junctures to the inlet and outlet surface wellbores 220, 230 are sealed (entirely or substantially) with a sealant against exchange of fluids with the surrounding subterranean zone 104. 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 202 during operation is recovered to the surface, and no or little naturally occurring fluids from the subterranean zone 104 are recovered. In other words, the resulting well 202 is closed loop. In certain instances, the sealant can be applied to the wellbores during drilling the connecting wellbores 240, 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.

[0027] In the illustrated instance, system 200 further includes a facility 260 disposed between inlet surface wellbore 220 and outlet surface wellbore 230. Well 202 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 104. In certain instances, facility 260 includes valves and pumps for controlling the flow of the geothermal working fluid through the wellF&R Ref. 50511-0093 WO1202, 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 260 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 260 is disposed at or near the Earth’s surface; in other instances, facility 260 may be disposed partially or fully within a subsurface location. The facility 260 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.

[0028] Drilling of such deep, multi-lateral wellbores and well systems of complex geometries as shown in FIGS. 2 A - 2C can present numerous technical challenges. As described above, CCT components (such as tubing 106 of FIG. 1 or other CCT strings such as workover strings) can in some circumstances be advantageous in meeting some such technical challenges. However, CCT exhibits highly variable engineering properties influenced by operating parameters such as temperature and internal pressure. For example, tensile strength significantly increases with internal pressures around 10,000 psi but can drastically decrease as temperature rises. Additionally, changes in internal pressure may lead to substantial length variations, complicating maintenance of precise drilling parameters like weight on bit. However, these and other variables in drilling, completing, working-over, or other operations with respect to such systems can, in some circumstances, increase the likelihood of the drill string becoming stuck downhole during drilling or other well operations.

[0029] A method of dislodging such stuck tubing is described greater detail in reference to FIGS. 3 A-3B and illustrated in FIGS. 4A -4C. Method 300 of FIGS. 3 A-3B begins at step 302 with receipt of an indication that tubing (such as a drill string, workover strig, or other tubular string) has become stuck at a location within the wellbore. An example of such sticking is shown in FIG. 4A, in which a distal end of tubing 106, including bottomhole assembly 108, has become mired in fill 402 that may comprise heavy fluids and solids thatF&R Ref. 50511-0093 WO1 have accumulated at the downhole end of wellbore 102 during drilling or other operational processes. In the instance shown in FIG. 4A, wellbore fluid 401 - which may comprise drilling fluid, working fluid, workover fluid, produced fluid, or another fluid used in or resulting from wellbore operations - may be present in central bore 112 and in annulus 116. The method proceeds to step 304 in which the location at which the tubing has become stuck is determined. Such a location determination can be important in so that decisions can be made on the best path forward to free the tubing. For example, some of the steps described in greater detail below may involve the cutting of the tubing or disconnection at disconnects positioned along the length of the tubing. As another example, if the tubing is stuck where it has the highest tensile strength, this allows the operator to apply greater tension to attempt to free the tubing. The location that the pipe is stuck can also aid in the determination as to how and why it is stuck, differential, or mechanical. In some instances, the location is determined by free-point calculations. In some instances, in addition to or instead of free-point calculations, telemetry can be used to determine the location at which the tubing is stuck. In some instances, sensors 410 can be mounted along tubing 106 to monitor stresses within the or on tubing string 106 as the method continues as described below.

[0030] The tensile strength of some CCT (including, for example, CCT comprised of composite fibers arranged helically) can be increased with the application of increased pressure within the tubing. Therefore, at step 306, before proceeding with the steps described further below in which attempts may be made to dislodge the tubing by applying a tensile force, pressure can be applied to the inside of the tubing to thereby increase to tensile strength of the tubing. In some instances, this pressurization step is not included prior to step 308 but may be included at one or more later points in the process prior to the application of tensile force. In some instances, a pressurization step may be included prior to each application of tensile force as described below.

[0031] Proceeding to step 308, an attempt is made to dislodge the tubing by applying a tensional force to the string in an uphole direction, by attempting to further run the string into the wellbore, or both. The torsional force applied can in some instances be up to the maximum tensile load of the tubing. Proceeding to step 310, a determination is made as toF&R Ref. 50511-0093 WO1 whether the attempt was successful. If at step 310 it is determined that the attempt is successful and the tubing is freed, then the method proceeds to step 312 in which operations (such as drilling or workover operations) can continue. In some instances, such operations can continue without the necessity of removing the string from the wellbore. If at step 310 the attempt is determined that the tubing remains stuck, then the method proceeds to step 314 in which an attempt is made to circulate fluid from the surface through the tubing to the distal end of the tubing string. Proceeding to step 316 it is determined whether such circulation is occurring. If at step 316 it is determined that such circulation is in fact occurring, then the method proceeds to step 318 in which - as shown in FIG. 4B - a volume of displacement fluid 404 having a higher SG than the SG of wellbore fluid 401 is flowed into the tubing to at least partially displace that wellbore fluid 401.

[0032] In some instances, at this step 318, the displacement fluid 404 has an SG equal or substantially equal to the SG of tubing 106. Thermoset and thermoplastic composite materials typically have SG ranging from 0.9 to 3.0. Composite tubulars suitable for drilling applications may possess specific gravities between 1.3 and 1.8, whereas conventional steel tubulars have a SG approaching 8. A composite string with a 1.6 SG hung off in a wellbore with displacement fluid of 1.6 SG is neutrally buoyant. Thus, the buoyant force exerted by the displacement fluid 404 on the tubing may decrease the tensile force that may be required. Suitable displacement fluids can include commercially available barite based muds which can have specific gravities of up to 2.64 or more.

[0033] For example, a drill string with an SG of 1.45 may be used for drilling with a mud with an SG of 1.3, at a depth of 1000 meters. The hole diameter may be approximately 8.5 inches, the pipe outer diameter may be approximately six inches, the pipe inner diameter may be approximately four inches. Assume that the mud in the annulus has an SG of approximately 1.4, sufficient to pick up cuttings. In this example, the ratio of the string and the drilling fluid in the string to the fluid in the annulus is .988 (<1 = buoyant), with a net buoyancy of 2890 N / lOOOm of pipe. If the mud in the annulus is displaced with a displacement fluid having an SG of 1.6, the ratio of the string and the drilling fluid in the string to the fluid in the annulus is 0.948, with a net buoyancy of 14904 N / lOOOm of pipe. If the fluid in the drilling string is displaced with a mud having an SG of 1.3 and the annulusF&R Ref. 50511-0093 WO1 with a mud with an SG of 1.6, the ratio of the string and the drilling fluid in the string to the fluid in the annulus is 0.865, with a net buoyancy of 38752 N / lOOOm of pipe. In the last case, this generates an upward lift of 38752 N (8711 lbs), without the necessity of applying a tensional pull on the tubing from the surface.

[0034] Proceeding to step 320 (and assuming the buoyancy alone is not sufficient to free the tubing), another attempt is made to dislodge the tubing by applying tension to the string in an uphole direction, by attempting to further run the string into the wellbore, or both. If it is then determined at next step 322 that the attempt is successful and the tubing is freed, then the method proceeds to step 312 in which operations (such as drilling or workover operations) can continue. In some instances, such operations can continue without the necessity of removing the string from the wellbore. In some instances, it may be necessary or desirable to remove displacement fluid from the wellbore prior to such continuing of operations to ensure that the buoyant force of the displacement fluid does not result in, for example, insufficient weight-on-bit.

[0035] If at step 322 it is determined that step 320 has been unsuccessful in freeing the tubing, the method proceeds to step 326 in which - as shown in FIG. 4C - a volume of displacement fluid 406 having a higher SG than the SG of displacement fluid 404 and higher than the SG of tubing 106 is flowed into the tubing to at least partially displace the volume of displacement fluid 404. Proceeding to step 328, another attempt is made dislodge the tubing by applying tension to the string in an uphole direction, attempting to further run the string into the wellbore, or both. The buoyant force exerted by the displacement fluid 406 on the tubing may further decrease the tensile force that may be required or may itself result in the freeing of the tubing. If it is then determined at next step 330 that the attempt is successful and the tubing is freed, then the method proceeds to step 332 in which operations (such as drilling or workover operations) can continue. In some instances, such operations can continue without the necessity of removing the string from the wellbore. If at step 330 it is determined that the attempt at dislodgment has been unsuccessful, then the method proceeds to step 334 in which other operations steps may be conducted to address the situation, such as cutting the tubing or disconnecting a portion of the tubing from the rest of the tubing.F&R Ref. 50511-0093 WO1

[0036] Returning to step 316, if it is determined that circulation down tubing 106 is not occurring or possible, then the method proceeds to step 336 in which it is determined whether it is possible to pump fluid in a downhole direction through annulus 116. If at step 336 it is determined that such annular flow is not possible, then the method proceeds to step 342 in which other operations steps may be conducted to address the situation, such as cutting the tubing or disconnecting a portion of the tubing from the rest of the tubing.

[0037] If at step 336 it is determined that pumping of fluid in a downhole direction through the annulus is possible, then, at step 338 as shown in FIG. 4C, a volume of displacement fluid 404 having a higher SG than the SG of wellbore fluid 401 is flowed in a downhole direction into the annulus 116 to at least partially displace that wellbore fluid 401. In some instances, at this step 338, the displacement fluid 404 has an SG equal or substantially equal to the SG of tubing 106. Proceeding to step 342, another attempt is made dislodge the tubing by applying tension to the string in an uphole direction, by attempting to further run the string into the wellbore, or both. The buoyant force exerted by the displacement fluid 404 on the tubing may decrease the tensile force that may be required. If it is then determined at next step 344 that the attempt is successful and the tubing is freed, then the method proceeds to step 346 in which operations (such as drilling or workover operations) can continue. In some instances, such operations can continue without the necessity of removing the string from the wellbore.

[0038] If at step 344 it is determined that step 342 has been unsuccessful in freeing the tubing, the method proceeds to step 348 in which - as shown in FIG. 4D - a volume of displacement fluid 406 having a higher SG than the SG of displacement fluid 404 and higher than the SG of tubing 106 is flowed into the annulus 116 to at least partially displace the volume of displacement fluid 404. Proceeding to step 350, another attempt is made dislodge the tubing by applying tension to the string in an uphole direction, attempting to further run the string into the wellbore, or both. The buoyant force exerted by the displacement fluid 406 on the tubing may further decrease the tensile force that may be required or may itself result in the freeing of the tubing. If it is then determined at next step 352 that the attempt is successful and the tubing is freed, then the method proceeds to step 354 in which operations (such as drilling or workover operations) can continue. InF&R Ref. 50511-0093 WO1 some instances, such operations can continue without the necessity of removing the string from the wellbore. If at step 352 it is determined that the attempt at dislodgment has been unsuccessful, then the method proceeds to step 356 in which other operations steps may be conducted to address the situation, such as cutting the tubing or disconnecting a portion of the tubing from the rest of the tubing.

[0039] In this disclosure, “approximately” or “substantially” means a deviation or allowance of up to 10 percent (%) and any variation from a mentioned value is within the tolerance limits of any machinery used to manufacture the part. Likewise, “about” can also allow for a degree of variability in a value or range, for example, within 10%, within 5%, or within 1% of a stated value or of a stated limit of a range.

[0040] Values expressed in a range format should be interpreted in a flexible manner to include not only the numerical values explicitly recited as the limits of the range, but also to include all the individual numerical values or sub-ranges encompassed within that range as if each numerical value and sub-range is explicitly recited. For example, a range of “0.1% to about 5%” or “0.1% to 5%” should be interpreted to include about 0.1% to about 5%, as well as the individual values (for example, 1%, 2%, 3%, and 4%) and the sub-ranges (for example, 0.1% to 0.5%, 1.1% to 2.2%, 3.3% to 4.4%) within the indicated range. The statement “X to Y” has the same meaning as “about X to about Y,” unless indicated otherwise. Likewise, the statement “X, Y, or Z” has the same meaning as “about X, about Y, or about Z,” unless indicated otherwise.

[0041] In this disclosure, 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 for the 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.F&R Ref. 50511-0093 WO1

[0042] The term “uphole” as used herein means in the direction along a wellbore tubing string or the wellbore from its distal end (furthest from the surface) towards the surface, and “downhole” as used herein means the direction along a tubing string or the wellbore from the surface towards its distal end. A downhole location means a location along the tubing string or wellbore downhole of the surface.

[0043] 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 subcombination. 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.

[0044] 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

F&R Ref. 50511-0093 WO1WHAT IS CLAIMED IS:

1. A method of well operations, the method comprising: in response to an indication that a length of tubing has become stuck at a downhole location in a wellbore drilled into a subterranean zone, at least partially displacing wellbore fluid with a displacement fluid having a specific gravity greater than a specific gravity of the wellbore fluid; and after the at least partially displacing the wellbore fluid with the displacement fluid, dislodging the length of tubing from the downhole location.

2. The method of claim 1, wherein the dislodging is at least in part by a buoyant force exerted by the displacement fluid on the length of tubing.

3. The method of any one of claims 1 or 2, wherein the specific gravity of the displacement fluid is greater than a specific gravity of the length of tubing.

4. The method of any one of claims 1 to 3, wherein the length of tubing comprises composite coiled tubing.

5. The method of claim 4, wherein the composite coiled tubing comprises thermoplastic composite pipe.

6. The method of any one of claims 1 to 5, wherein a specific gravity of the length of tubing is less than about 2.0.

7. The method of any one of claims 1 to 6, wherein the length of tubing comprises a drill string.F&R Ref. 50511-0093 WO18. The method of any one of claims 1 to 7, further comprising, without removing the drill string from the wellbore after the dislodging, further drilling the wellbore with the drill string..

9. The method of any one of claims 1 to 8, wherein the length of tubing comprises a workover string.

10. The method of any one of claims 1 to 9, wherein the dislodging is at least in part by applying a tensional force to the length of tubing.

11. The method of claim 10, further comprising, further in response to the indication that the length of tubing has become stuck at the downhole location and prior to the applying the tensional force to the length of tubing, increasing a pressure within the length of tubing, thereby increasing a tensile strength of the length of tubing.

12. The method of any one of claims 1 to 11, wherein the at least partially displacing the wellbore fluid with the displacement fluid comprises: at least partially displacing the wellbore fluid with a first volume of displacement fluid, the first volume of displacement fluid having a specific gravity greater than the specific gravity of the wellbore fluid; and in response to an indication that the length of tubing remains stuck after the at least partially displacing the wellbore fluid with the first volume of displacement fluid, at least partially displacing the first volume of displacement fluid with a second volume of displacement fluid, the second volume of displacement fluid having a specific gravity greater than the specific gravity of the first volume of displacement fluid and a specific gravity of the length of tubing; and wherein the retrieving the length of tubing from the wellbore after displacing wellbore fluid with the displacement fluid comprises retrieving the length of tubing after the at least partially displacing the first volume of wellbore displacement fluid with the second volume of wellbore displacement fluid.F&R Ref. 50511-0093 WO113. The method of claim 12, wherein the first volume of displacement fluid has a specific gravity substantially equal to the specific gravity of the length of tubing.

14. The method of any one of claims 12 to 13, wherein a specific gravity of the first volume of displacement fluid is less than about 2.0.

15. The method of any one of claims 12 to 14, wherein a specific gravity of the second volume of displacement fluid is between about 1.0 and about 3.0.

16. The method of any one of claims 1 to 15, wherein the displacement fluid comprises barite.

17. The method of any one of claims 1 to 16, wherein the at least partially displacing wellbore fluid with the displacement fluid comprises flowing the displacement fluid in a downhole direction through the length of tubing.

18. The method of any one of claims 1 to 17, wherein the at least partially displacing wellbore fluid with the displacement fluid comprises flowing the displacement fluid in a downhole direction through an annulus defined by an inner surface of the wellbore an outer surface of the length of tubing.

19. The method of claim 18, wherein the flowing the displacement fluid in a downhole direction through the annulus is in response to an indication of a failure to flow fluid in a downhole direction through the length of tubing.

20. The method of any one of claims 1 to 19, wherein the subterranean zone is a geothermal production zone.F&R Ref. 50511-0093 WO121. The method of any one of claims 1 to 20, wherein the subterranean zone is a basement formation.

22. A method of dislodging tubing from a stuck location in a wellbore, the method comprising: increasing a buoyant force exerted on the tubing by displacing wellbore fluid with a displacement fluid having a specific gravity at least equal to a specific gravity of the tubing; and dislodging the tubing from the stuck location at least in part by the buoyant force.

23. The method of claim 22, wherein the displacement fluid has a specific gravity greater than a specific gravity of the tubing.

24. The method of any one of claims 22 or 23, wherein the dislodging is at least in part by application of a tensile force on the tubing from a surface location.

25. A method of well operations, the method comprising: in response to an indication that tubing has become stuck at a location in a wellbore, applying force to the tubing in an uphole direction, the force comprising a combination of at least: a tensile force applied to the tubing from applied from a surface location; and a buoyant force exerted on the tubing by fluid in the wellbore, the fluid in the wellbore exerting the buoyant force having a specific gravity equal to or greater than a specific gravity of the tubing; and after applying the force, at least partially retrieving the tubing from the wellbore.

26. The method of claim 25, wherein the fluid in the wellbore exerting the buoyant force on the tubing is a displacement fluid disposed in the wellbore in response to theF&R Ref. 50511-0093 WO1 indication that the tubing has become stuck at the location in the wellbore.

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