Well Abandonment and Severance of Control Lines

The present application is a divisional of U.S. patent application Ser. No. 18/115,591, filed Feb. 28, 2023, the entire disclosure of which is incorporated herein by reference.

After drilling a wellbore in a subterranean formation for recovering hydrocarbons such as oil and gas lying beneath the surface, a casing string may be fed into the wellbore. Generally, the casing string protects the wellbore from failure (e.g., collapse, erosion) and provides a fluid path for hydrocarbons during production. Further, cement may be pumped into the annular space between the casing and a wellbore wall to form a seal. To access the hydrocarbons for production, a perforating gun system may be deployed into the casing string to form perforations in the casing and/or cement such that hydrocarbons may flow into the casing string via the perforation. Further, tubing may be lowered into the well as part of production to provide a reduced diameter fluid path for the hydrocarbons during production. Once production operations have concluded, plug and abandonment (P&A) operations may be conducted. P&A operations generally include severing control lines and/or flat packs to reduce sealing issues for the wellbore. Non-severed control lines may provide leak paths for hydrocarbons to travel through a cement seal formed in the wellbore as part of the P&A operations.

Generally, during P&A operations, a cutting tool is lowered into the wellbore to cut the control lines prior to pumping cement into the wellbore since the control lines are generally accessible at this stage. In particular, the cutting tool is lowered to a desired depth in the tubing where the cutting tool is deployed to cut through the tubing and the control lines at the desired depth. However, control lines may float in the annulus between the tubing and the casing. As such, the control lines may move in response to contact with the cutting tool, which may result in the cutting tool failing to successfully sever the control lines. Unfortunately, as set forth above, failing to sever the control lines may result in leak paths extending through the cement, which may compromise the seal formed by the P&A operations.

Disclosed herein are systems and methods for severing control lines and/or flat packs during plug and abandonment (P&A) operations and, more particularly, example embodiments may include injecting a sealing material such as cement into an annulus formed between a wellbore wall of the wellbore and a tubular disposed in the wellbore. The control lines and/or flat packs may be disposed in the annulus. As set forth in greater detail below, the sealing material may be configured to restrain movement of the control lines and/or flat packs such that an orbital cut from a cutting device may reliably sever the control lines and/or flat packs.

illustrates an elevation view of a well system, in accordance with some embodiments of the present disclosure. It should be noted that whilegenerally depicts a land-based operations, those skilled in the art will readily recognize that the principles described herein are equally applicable to subsea operations that employ floating or sea-based platforms and rigs, without departing from the scope of the disclosure. As illustrated, a well abandonment systemmay comprise a vehicle(e.g., mounted truck coiled tubing unit) or any suitable surface systemfor raising and lowering coiled tubingin a wellbore. Generally, the wellboremay be lined with casing, and cementmay be pumped into an outer annulusbetween the casingand a wellbore wallto protect the wellborefrom failure (e.g., collapse, erosion) and to provide a fluid path for hydrocarbons during production. Although the illustrated embodiment shows a drilling rigsupporting the coiled tubing, the vehiclemay be configured to run the coiled tubingwithout a drilling rig. Alternatively, the vehicle and/or the drilling rig may be configured to run any suitable conveyance (e.g., slickline, wireline, drill pipe, etc.) into the wellbore. As set forth in greater detail below, the well system may lower various downhole tools(e.g., perforating guns, cutting devices, milling devices, etc.) via a corresponding conveyance.

Moreover, during plug and abandonment operations, the well abandonment systemmay relay information between the surface and the downhole tools. In particular, the well abandonment systemmay further include an information handling systemconfigured to process information gathered by the downhole tools. For example, sensor data recorded by downhole toolsmay be communicated to and then processed by information handling system. Without limitation, the processing may be performed in real-time. Processing may alternatively occur downhole or may occur both downhole and at the surface. The sensor data recorded by downhole toolsmay be conducted to information handling systemvia coiled tubingor any suitable transmission medium. Information handling systemmay process the signals, and the information contained therein may be displayed for an operator to observe and stored for future processing and reference. Information handling systemmay also contain an apparatus for supplying control signals to the downhole tools.

Information handling systemmay include any instrumentality or aggregate of instrumentalities operable to compute, estimate, classify, process, transmit, receive, retrieve, originate, switch, store, display, manifest, detect, record, reproduce, handle, or utilize any form of information, intelligence, or data for business, scientific, control, or other purposes. For example, an information handling systemmay be a processing unit, a network storage device, or any other suitable device and may vary in size, shape, performance, functionality, and price. Information handling systemmay include random access memory (RAM), one or more processing resources such as a central processing unit (CPU) or hardware or software control logic, ROM, and/or other types of nonvolatile memory. Additional components of the information handling systemmay include one or more disk drives, one or more network ports for communication with external devices as well as various input and output (I/O) devices, such as an input device(e.g., keyboard, mouse, etc.) and a display. Information handling systemmay also include one or more buses operable to transmit communications between the various hardware components.

Alternatively, systems and methods of the present disclosure may be implemented, at least in part, with non-transitory computer-readable media. Non-transitory computer-readable mediamay include any instrumentality or aggregation of instrumentalities that may retain data and/or instructions for a period of time. Non-transitory computer-readable mediamay include, for example, storage media such as a direct access storage device (e.g., a hard disk drive or floppy disk drive), a sequential access storage device (e.g., a tape disk drive), compact disk, CD-ROM, DVD, RAM, ROM, electrically erasable programmable read-only memory (EEPROM), and/or flash memory; as well as communications media such wires, optical fibers, microwaves, radio waves, and other electromagnetic and/or optical carriers; and/or any combination of the foregoing.

illustrate respective cross-sectional views of the well abandonment systemconfigured to sever control linesin the wellbore, in accordance with some embodiments of the present disclosure. In particular,discloses the wellborehaving a plugdisposed in an inner tubular(e.g., production tubing) to form a fluid barrier. That is, the plugmay be run-in-hole and set at a target location in the inner tubularto block fluid from traveling through the inner tubular. The plugmay include any suitable material. In the illustrated embodiment, the plug comprises a cylindrical shape such that a radially outer surfaceof the plugmay seal against a radially inner surfaceof the inner tubularto restrain fluid. However, the plug may include any suitable shape for blocking fluid. Further, the plugmay be expandable. That is, the plugmay be run-in-hole to the target location and then expand at the target location to seal against the inner tubular.

The plugmay be run-in-hole via a conveyance (e.g., plug conveyance) to the target location (e.g., a predetermined sealing position in in the wellbore). Scaling positions (e.g., position for sealing the wellbore during plug and abandonment operations) may be predetermined based at least in part on local regulations, common practice, or other suitable guidance. For example, local regulations may require that a wellbore be sealed between production zones and usable water strata. As such, prior to plug and abandonment operations, a sealing position between a production zone and usable water strata may be predetermined. Moreover, in the illustrated embodiment, the plug conveyanceincludes a slickline configured to lower the pluginto the wellbore. However, the plug conveyancemay include any suitable conveyance, such as a wireline, coiled tubing, drill pipe, or some combination thereof, for running the pluginto the wellbore.

Moreover, the wellboremay be formed with various tubulars (e.g., production tubing, production casing, intermediate casing, surface casing, conductor casing, etc.). In the illustrated embodiment, the conductor casingis the radially outermost tubular disposed in the wellbore. The surface casingmay be disposed within the conductor casing(e.g., disposed radially inward from the conductor casing), and the production casingmay be disposed within the surface casing. Further, the inner tubular(e.g., production tubing) is disposed within the production casing. However, the wellboremay include any suitable structure. For example, the wellboremay include at least one intermediate casing disposed between the surface casingand the production casing. During installation of the tubulars, cementmay be disposed at least between the conductor casingand the wellbore wall, between the surface casingand the conductor casing, and between the production casingand the surface casing. However, an annulusformed between the inner tubularand the production casingmay be left open such that fluid may flow through the annulus. In the illustrated embodiment, the annulusmay be sealed via a packer assemblyor any suitable sealing feature to restrain fluid flow from a bottom of the wellboreto the surface. However, some wellboresmay not include the packer assembly. Further, as illustrated, the plugmay be run-in-hole to a location disposed proximate the packer assembly. The packer assemblyand the plug, in combination, may provide a fluid barrier between the surface and a bottom of the wellboreand/or a production zone.

discloses the inner tubularhaving a plurality of perforations. With the plugset in the inner tubular(e.g., the production tubing), a perforating devicemay be lowered into the wellboreto perforate the inner tubularat a position above the plug. Perforating the inner tubularabove the plugmay open at least one fluid pathbetween a central boreof the inner tubularand the annulus. As set forth above, the annulusmay be formed between the inner tubularand the production casingor wellbore wall. As set forth in greater detail below, the at least one fluid pathmay fluidly connect the central boreto the annulusat a location proximate the plugsuch that sealing material(shown in) may be injected into the annulusfrom the central bore.

Moreover, the perforating devicemay include a perforating gunhaving shaped chargesconfigured to detonate in a substantially radially outward direction to perforate the inner tubularabove the plugdisposed in the wellbore. In the illustrated embodiment, both the inner tubular(e.g., production tubing) and the production casinghave been perforated by the perforating device. For example, a blast from the shaped chargesmay perforate the inner tubular, the production casing, and continue through the wellbore wallinto a downhole formation. Alternatively, the perforating devicemay be configured to only perforate the inner tubular. For example, the perforating devicemay comprise a cutting device(e.g., blade, reamer, hydro jet, plasma torch, etc.) shown in. The cutting deviceis configured to make at least one orbital cut to perforate the inner tubular(e.g., production tubing) above the plugdisposed in the wellbore. However, the cutting devicemay be configured to also perforate the production casingand/or the wellbore wall.

Moreover, as illustrated, the perforating devicemay be configured to make a plurality of perforations to open a plurality of fluid pathsbetween the central boreand the annulus. For example, the perforating devicemay comprise a perforating gunhaving a dozen shaped charges. In response to detonation of the shaped charges, the inner tubularmay be perforated with a dozen corresponding perforationsthat each form a respective fluid pathbetween the central boreand the annulus. As set forth in greater detail below, having a plurality of fluid pathsmay help increase a flow rate of fluid (e.g., the scaling materialshown in) between the central boreand the annulus. The perforating devicemay be configured to form perforationsin the inner tubularwith any suitable spacing, sizing, and number, to provide a desired flow area between the central boreand the annulus.

discloses the sealing materialdisposed in the annulusand the central boreof the inner tubular. With the inner tubularperforated above the plug, the scaling materialmay be injected into the wellbore. In particular, an injection conveyance(e.g., coiled tubing, drill pipe, etc.) may be lowered into the inner tubularto a position proximate the plugand/or the at least one perforationin the inner tubular. The scaling materialmay be delivered in an at least partially liquid state to the central bore. As such, the scaling materialmay flow downhole toward the plugand flow radially outward into the annulusvia the at least one fluid path. As such, the sealing materialmay be injected into the annulusformed between the inner tubular(e.g., production tubing) and the production casingand/or the wellbore wall. The scaling materialis configured to surround at least a portion of the control lineand/or flat pack disposed in the annulus.

Further, the sealing materialmay include cement, plastic, resin, or some combination thereof. As set forth above, the sealing materialis injected into the annulusin at least a partially liquid or fluid state. However, the sealing materialis configured to solidify after being injected into the annulus. For example, the sealing materialmay include cementthat is mixed with water prior to being injected into the wellboresuch that the cementis in a liquid or fluid state. In the fluid state, the cementmay flow through the injection conveyancedown to the central boreand out through the at least one fluid pathinto the annulus. Due to the chemical reaction (e.g., hydration) between the water and the cement, the cementmay solidify or harden over time. Once hardened, the cementdisposed in the annulusmay restrain movement of the control line. Specifically, the hardened cementmay restrain lateral movement of the control line.

discloses the sealing materialbeing milled out from the central boreof the inner tubular. With the sealing materialdisposed and hardened in the annulus, the sealing materialmay be configured to restrain movement of the control linesand/or flat packs such that making an orbital cut(shown in) with the cutting devicemay reliably sever the control linesand/or flat packs. However, to make the orbital cut, the cutting devicemay need to be lowered into the inner tubularto a location in the central borethat is axially aligned with a portion of the annulusthat is filled with the scaling material. Unfortunately, injecting the sealing materialinto the annulusmay also dispose the sealing materialin the central bore, and the sealing materialdisposed in the central boremay be at a same height or higher than the sealing materialin the annulus.

Thus, to lower the cutting deviceinto the inner tubularto a location that is axially aligned with a portion of the annulusthat is filled with the sealing material, at least a portion the sealing materialin the central boremay need to be removed. For example, a milling devicemay be lowered into the central boreto mill out at least a portion of the hardened cementdisposed in the central boreabove the plug. As illustrated, the milling devicemay mill out the cementdown to a location of the plug. Alternatively, the milling devicemay mill out only a portion of the cementin the central bore. However, the milling devicemay at least mill out a sufficient portion of the cementin the central boresuch that the cutting devicemay be lowered to a position in the central borethat is axially aligned with a portion of the annulushaving the hardened cementsurrounding the control linesand/or flat pack.

Moreover, the milling devicemay include a drill bit (e.g., a fixed cutter drill bit, a roller cone bit, a hybrid drill bit, etc.), a reamer, or any other suitable milling device. The milling devicemay be run-in-hole via a milling conveyance(e.g., drill pipe, coiled tubing, etc.) to the hardened cementin the central bore. With the milling devicein position, a mud motor (not shown) may be configured to drive rotation of the milling deviceto engage and mill out the cement. Once the cementin the central bore is sufficiently milled out, the milling conveyancemay be configured to pull the milling deviceout-of-hole.

discloses the control lineand/or flat pack severed via making an orbital cut. As illustrated, the cutting devicemay be run-in-hole to a target location in the central borefor making the at least one orbital cut(e.g., a location that is axially aligned with a portion of the annulusthat is filled with the hardened sealing material). For example, the cutting devicemay be run-in-hole to a milled out portionof the central boreof the inner tubularto make the at least one orbital cut. The cutting devicemay be run-in-hole via a cutting device conveyance(e.g., a slickline, a wireline, coiled tubing, drill pipe, etc.). Further, the cutting devicemay include any suitable cutting device. For example, the cutting devicemay include an abrasive jetting device, a blade cutter, a reamer, a plasma torch, or some combination thereof.

Moreover, at the target location, the cutting devicemay be configured to cut through the inner tubular(e.g., production tubing) and the sealing materialin the annulusand sever the control linesurrounded by the sealing material. Indeed, the hardened sealing materialis configured to restrain at least lateral movement of the control line. As set forth above, the cutting devicemay fail to cut the control lineif the control lineis permitted to move in response to contact with the cutting device. However, in the illustrated embodiment, as the cutting devicecuts through the sealing materialand engages the control lineand/or flat pack, the remaining sealing materialmay prevent the control lineand/or flat pack from moving laterally in response to contact with the cutting device. That is, the cutting devicemay engage a radially inner sideof the control lineand a radially outer sideof the control linemay be in contact with the remaining hardened scaling material. As the cutting deviceengages the radially inner side, the remaining hardened sealing materialmay prevent the control linefrom moving radially outward such that the cutting devicemay engage and sever the control line. Similarly, should the cutting deviceengage another side of the control line, an opposite side of the control linemay interface with the remaining hardened sealing materialto prevent the control linefrom moving with respect to the cutting device.

discloses the sealing material(e.g., cement) disposed in the orbital cutand the central bore. After making the orbital cut, additional sealing materialmay be injected into the central boreof the inner tubular(e.g., production tubing) to fill the volume removed by making the orbital cutand at least a portion of the central bore. As set forth above, the control linesmay provide leak paths for hydrocarbons to travel through a seal formed in the wellbore as part of the P&A operations. Accordingly, filling the orbital cutwith the additional sealing materialmay fluidly isolate a lower portionof the severed control linefrom an upper portionof the severed control line, which may block a leak path for hydrocarbons.

illustrate respective cross-sectional views of another well abandonment systemconfigured to sever the control linesin the wellbore, in accordance with some embodiments of the present disclosure.discloses the wellborehaving a primary plugdisposed in an inner tubularto form a fluid barrier, as well as the inner tubularhaving a plurality of perforations. The primary plugmay be run-in-hole and set at a target location in the inner tubular(e.g., the production tubing) to block fluid from traveling through the inner tubularat the primary plug. The primary plugmay include any suitable material. In the illustrated embodiment, the primary plugcomprises a cylindrical shape such that a radially outer surfaceof the primary plugmay seal against the radially inner surfaceof the inner tubularto restrain fluid. However, the primary plugmay include any suitable shape for blocking fluid. Further, the primary plugmay be expandable. That is, the primary plugmay be run-in-hole to the target location and then expand at the target location to seal against the inner tubular.

Further, the annulusmay be formed between the inner tubularand the production casingand/or the wellbore wallmay be left open (e.g., not filled with cement) such that fluid may flow through the annulus. In the illustrated embodiment, the annulusmay be sealed via the packer assemblyor any suitable sealing feature to restrain fluid flow from the bottom of the wellboreto the surface. Further, as illustrated, the primary plugmay be run-in-hole to a location disposed proximate the packer assembly. The packer assemblyand the primary plug, in combination, may provide a fluid barrier between the surface and the bottom of the wellboreand/or a production zone.

Moreover, with the primary plugset in the inner tubular, the perforating device(e.g., perforating gun, blade, reamer, hydro jet, plasma torch, etc.) may be lowered into the wellboreto perforate the inner tubularabove the primary plug. Perforating the inner tubularabove the primary plugmay open the at least one fluid pathbetween the central boreof the inner tubularand the annulus. As set forth above, the annulusmay be formed between the inner tubularand the production casingand/or the wellbore wall. The at least one fluid pathmay fluidly connect the central boreto the annulusat a location proximate the primary plugsuch that the sealing materialmay be injected into the annulusfrom the central bore. In the illustrated embodiment, the inner tubularhas a plurality of perforationssuch that a plurality of fluid pathsextend between the central boreand the annulus.

discloses a secondary plugdisposed in the inner tubular. As illustrated, the secondary plugmay be run-in-hole and set in a position uphole from both the primary plugand the plurality of perforations(e.g., the plurality of fluid pathsextending between the central boreand the annulus). Moreover, the secondary plugmay comprise a through boreextending from an uphole endto a downhole endof the secondary plugsuch that fluid may pass through the secondary plug. However, the secondary plugmay also include a check-valveconfigured to restrain fluid flow in the uphole direction. The check-valvemay include any suitable type of check valve for restraining flow of the scaling materialin the uphole directionand permitting fluid flow of the scaling materialin a downhole directionthrough the check-valve. For example, the check-valvemay include a flapper check valve having a flapper (not shown) configured to swing open in response to fluid (e.g., the sealing material) flowing in the downhole directionand close in response to the fluid flowing in the uphole direction. Alternatively, a closing sleeve (not shown) may be disposed in the secondary plugto restrain fluid flow in the uphole directionwhile permitting fluid flow in the downhole direction. That is, the closing sleeve may open in response to the injection conveyancestinging into the closing sleeve. With the closing sleeve connected to the injection conveyance, downhole flow of the sealing material into the closing sleeve from the injection conveyancemay block fluid flowing in the uphole direction. Further, in response to the injection conveyancedisconnecting (e.g., sting out) the closing sleeve is configured to close to block fluid flow in the uphole direction. However, any suitable device may be used to restrain fluid flow in the uphole directionwhile permitting fluid flow in the downhole directionthrough the secondary plug.

discloses the scaling materialdisposed in the annulusand a portion of the central boredisposed between the primary plugand the secondary plug(e.g., a lower central bore portion). As illustrated, the sealing material(e.g., cement) may be pumped through the check-valveinto the lower central bore portion. Further, as illustrated, the scaling materialmay be injected through the secondary plugvia the injection conveyance(e.g., drill pipe, coiled tubing, or some combination thereof) to help minimize an amount of the sealing materialinjected into the portion of the central boredisposed uphole from the secondary plug(e.g., an upper central bore portion). As set forth in greater detail below, the cutting device(shown in) may make the orbital cut(shown in) above the secondary plug, so maintaining the upper central bore portionclear of sealing materialmay allow the cutting deviceto be lowered into position for making the orbital cutwithout having to mill out the upper central bore portionwith the milling device(shown in). In some embodiments, the sealing materialmay be pushed downhole through the secondary plugvia a dart (not shown) driven downhole with fluid pressure from a fluid (e.g., drilling fluid, cleaning fluid, etc.) injected into the wellbore. The fluid may provide fluid pressure to drive the dart while also cleaning the upper central bore portionas the dart moves toward the secondary plug.

Moreover, the sealing materialmay be pumped into the lower central bore portionin a partially liquid state. Accordingly, as the lower central bore portionis filled with the scaling material, fluid pressure from the sealing materialentering through the check-valvemay drive the sealing materialthrough the at least one fluid pathand into the annulus. The scaling materialmay continue to be pumped through the check-valveto drive the sealing materialto fill a portion of the annulusproximate the packer assemblyand continue to flow uphole in the annulusto fill the annulusup to a position uphole from the secondary plug. That is, sealing materialmay be pumped into the annulusuntil the annulusis at least sufficiently filled such that the sealing materialsurrounds at least a portion of a control linedisposed uphole from the secondary plug.

Further, as set forth above, the sealing materialmay include cement, plastic, resin, or some combination thereof. As set forth above, the sealing materialmay be pumped into the lower central bore portionand the annulusin a partially liquid state. However, the sealing materialis configured to solidify after being injected into the annulus. For example, the scaling materialmay include cementthat is mixed with water prior to being injected into the wellboresuch that the cementis in a liquid or fluid state. However, due to the chemical reaction (e.g., hydration) between the water and the cement, the cementmay solidify or harden over time. Once hardened, the cementdisposed in the annulusmay restrain movement of the control line. Specifically, the hardened cementmay restrain lateral movement of at least a portion of the control linedisposed uphole from the secondary plug.

discloses the injection conveyance(shown in) removed from the central boreof the inner tubular. Once the annulusis at least sufficiently filled with the sealing materialsuch that the sealing materialsurrounds at least a portion of a control linedisposed uphole from the secondary plug, the injection conveyancemay be disconnected from the secondary plugand pulled out-of-hole. Further high pressure fluid (e.g., a cleaning fluid) may be run into the inner tubularto remove the sealing materialdisposed uphole from the secondary plug. As set forth above, maintaining the upper central bore portionclear of sealing materialmay allow the cutting device(shown in) to be lowered into position for making the orbital cutwithout having to mill out the upper central bore portionwith the milling device(shown in). Running the high pressure fluid into the central boreof the inner tubularmay remove at least a portion of the sealing materialthat may have entered the upper central bore portionduring connection and/or disconnection of the injection conveyance, as well as any sealing materialthat may have entered the upper central bore portionduring injection of the sealing materialthrough the secondary plug.

discloses the control lineand/or flat pack severed via making the orbital cutat a position uphole the secondary plug. As illustrated, the cutting devicemay be run-in-hole to a target location in the central borefor making the at least one orbital cut(e.g., a location that is axially aligned with a portion of the annulusthat is filled with the hardened sealing material). As set forth above, the sealing materialis pumped into the annulusto a position that is uphole from the secondary plug. Further, as set forth above, the upper central bore portion(e.g., the portion of the central boredisposed above the secondary plug) may be substantially clear of sealing material. Accordingly, with the injection conveyancepulled out-of-hole, the cutting devicemay run-in-hole to the target location above the secondary plug. Indeed, the cutting devicemay be run-in-hole to the target location above the secondary plugwithout having to mill out the upper central bore portionwith the milling device. The cutting devicemay be run-in-hole via a cutting device conveyance(e.g., a slickline, a wireline, coiled tubing, drill pipe, etc.). Further, the cutting devicemay include any suitable cutting device. For example, the cutting devicemay include an abrasive jetting device, a blade cutter, a reamer, a plasma torch, or some combination thereof.

Moreover, at the target location above the secondary plug, the cutting devicemay be configured to cut through the inner tubular(e.g., production tubing) and the sealing materialin the annulusand sever the control linesurrounded by the sealing material. Indeed, the hardened sealing materialis configured to restrain at least lateral movement of the control line. As set forth above, the cutting devicemay fail to cut the control lineif the control lineis permitted to move in response to contact with the cutting device. However, in the illustrated embodiment, as the cutting devicecuts through the sealing materialand engages the control lineand/or flat pack, the remaining sealing materialmay prevent the control lineand/or flat pack from moving laterally in response to contact with the cutting device. That is, the cutting devicemay engage a radially inner sideof the control lineand the radially outer sideof the control linemay be in contact with the remaining hardened sealing material. As the cutting deviceengages the radially inner side, the remaining hardened sealing materialmay prevent the control linefrom moving radially outward such that the cutting devicemay engage and sever the control line. Further, as set forth above, should the cutting deviceengage another side of the control line, an opposite side of the control linemay interface with the remaining hardened sealing materialto prevent the control linefrom moving with respect to the cutting device.

discloses the sealing materialdisposed in the orbital cutand the upper central bore portion. After making the orbital cut, additional sealing materialmay be injected into the upper central bore portionof the inner tubular(e.g., production tubing) to fill the volume removed by making the orbital cutand fill at least a portion of the upper central bore portion. As set forth above, control linesmay provide leak paths for hydrocarbons to travel through the seal formed in the wellboreas part of the P&A operations. Accordingly, filling the orbital cutwith the additional sealing materialmay fluidly isolate the lower portionof the severed control linefrom the upper portionof the severed control line, which may block a leak path for hydrocarbons.

illustrate respective cross-sectional views of another well abandonment systemconfigured to sever control linesin a wellbore, in accordance with some embodiments of the present disclosure.discloses the wellborehaving the primary plugdisposed in the inner tubularto form a fluid barrier, as well as the inner tubularhaving a plurality of perforations. The primary plugmay be run-in-hole and set at a target location in the inner tubular(e.g., the production tubing) to block fluid from traveling through the inner tubularat the primary plug. As set forth above, the primary plugmay include any suitable material. In the illustrated embodiment, the primary plugcomprises a cylindrical shape such that a radially outer surfaceof the primary plugmay seal against a radially inner surfaceof the inner tubularto restrain fluid. However, the primary plugmay include any suitable shape for blocking fluid. Further, the primary plugmay be expandable. That is, the primary plugmay be run-in-hole to the target location and then expand at the target location to seal against the inner tubular.

Further, the annulusmay be formed between the inner tubularand the production casingand/or the wellbore wallmay be left open (e.g., not filled with sealing material) such that fluid may flow through the annulus. In the illustrated embodiment, the annulusmay be sealed via a packer assemblyor any suitable sealing feature to restrain fluid flow from the bottom of the wellboreto the surface. Further, as illustrated, the primary plugmay be run-in-hole to a location disposed proximate the packer assembly. The packer assemblyand the primary plug, in combination, may provide a fluid barrier between the surface and the bottom of the wellboreand/or a production zone.

Moreover, with the primary plugset in the inner tubular, the perforating device(e.g., perforating gun, blade, reamer, hydro jet, plasma torch, etc.) may be lowered into the wellboreto perforate the inner tubularabove the primary plug. In particular, the perforating devicemay be configured to perforate the inner tubularto form a first perforation zoneand a second perforation zone. The first perforation zonemay be disposed proximate the primary plug. In particular, the first perforation zonemay be disposed immediately uphole from the primary plug, and the second perforation zonemay be disposed uphole from the first perforation zone. The first perforation zoneand the second perforation zonemay be spaced apart axially (i.e., axially offset). As illustrated, a non-perforated zonemay be disposed between the first perforation zoneand the second perforation zoneto separate the first perforation zonefrom the second perforation zone. The non-perforated zonemay have an axial length between-meters, which may provide sufficient space for the secondary plug(shown in) discussed below.

Moreover, the first perforation zonemay include at least one first perforation, which opens at least one first fluid pathbetween the central boreof the inner tubularand the annulussuch that the sealing materialmay be injected into the annulusfrom the central borevia the at least one fluid path. Further, as illustrated, the first perforation zonemay include a plurality of first perforationsthat open a plurality of first fluid pathsbetween the central boreof the inner tubularand the annulus. The first perforation zonemay extend 1.0 to 10.0 meters along the inner tubular. Further, each first fluid path of the plurality of first fluid pathsin the first perforation zonemay be axially offset from at least one adjacent first fluid path along the inner tubularby 1.0 to 30.0 centimeters. Additionally, the second perforation zonemay include at least one second perforation, which opens at least one second fluid pathbetween the central boreof the inner tubularand the annulus. Similarly, the second perforation zonemay include a plurality of perforationsthat open a plurality of second fluid pathsbetween the central boreof the inner tubularand the annulus. The second perforation zonemay extend 1.0 to 10.0 meters along the inner tubular. Each second fluid path of the plurality of second fluid pathsin the second perforation zone may be axially offset from at least one adjacent second fluid path along the inner tubularby 1.0 to 30.0 centimeters.

discloses a secondary plugdisposed in the inner tubular. As illustrated, the secondary plugmay be run-in-hole and set in a position uphole from the primary plug. In particular, the secondary plugmay be run-in-hole and set in a position between the first perforation zoneand the second perforation zonesuch that the secondary plugis disposed between the at least one first fluid pathand the at least one second fluid path. Moreover, the secondary plugmay comprise the through boreextending from the uphole endto the downhole endof the secondary plugsuch that fluid may pass through the secondary plug. However, the secondary plugmay also include the check-valveconfigured to restrain fluid flow in the uphole direction. The check-valvemay include any suitable type of check valve for restraining flow of the sealing materialin the uphole directionand permitting fluid flow of the sealing materialin the downhole directionthrough the check-valve. For example, the check-valvemay include a flapper check valve having a flapper configured to swing open in response to fluid (e.g., the sealing material) flowing in the downhole directionand close in response to the fluid flowing in the uphole direction.

discloses the sealing materialdisposed in the wellbore. As illustrated, the scaling material(e.g., cement) may be pumped through the check-valveinto the lower central bore portion(e.g., the portion of the central boredisposed between the primary plugand the secondary plug). The sealing materialmay be injected through the secondary plugvia the injection conveyance(e.g., drill pipe, coiled tubing, or some combination thereof). Moreover, the sealing materialmay be pumped into the lower central bore portionin a partially liquid state. Accordingly, as the lower central bore portionis filled with the sealing material, fluid pressure from the sealing materialentering through the check-valvemay drive the sealing materialthrough the at least one first fluid pathand into the annulus. The sealing materialmay continue to be pumped through the check-valveto drive the sealing materialto fill a portion of the annulusproximate the packer assemblyand continue to flow upward in the annulusto a portion of the annulusadjacent the second perforation zone. As the sealing materialcontinues to be pumped through the check-valve, the sealing materialmay flow into the central boreof the inner tubular, above the secondary plug, via the at least one second fluid path. Moreover, as the at least one second fluid pathis disposed above the secondary plug, the sealing materialpumped into and through the annulus may surround at least a portion of a control linedisposed uphole from the secondary plug.

In some embodiments, an upper end of the annulusmay be sealed. For example, the wellboremay be formed as part of an underwater drilling operation such that the upper end of the annulusmay be sealed. As such, the at least one second fluid pathmay allow the sealing materialto flow into and through the annuluswithout causing a significant pressure increases in the annulus(i.e., significant pressure increases in the annulus may rupture the tubulars). That is, the at least one second fluid pathmay provide a pressure outlet for the annulus.

Further, as set forth above, the sealing materialmay include cement, plastic, resin, or some combination thereof. As set forth above, the sealing materialmay be pumped into the lower central bore portionand the annulusin a partially liquid state. However, the sealing materialis configured to solidify after being injected into the annulus. For example, the sealing materialmay include cementthat is mixed with water prior to being injected into the wellboresuch that the cementis in a liquid or fluid state. However, due to the chemical reaction (e.g., hydration) between the water and the cement, the cementmay solidify or harden over time. Once hardened, the cementdisposed in the annulusmay restrain movement of the control line. Specifically, the hardened cementmay restrain lateral movement of at least a portion of the control linedisposed uphole from the secondary plug. However, as set forth in greater detail below, the injection conveyanceshould be removed before the sealing materialhardens to prevent the sealing materialin the central boreabove the secondary plugfrom trapping the injection conveyancein the wellbore.

discloses the injection conveyance(shown in) removed from the central boreof the inner tubular. Once the annulusis at least sufficiently filled with the sealing materialsuch that the sealing materialsurrounds at least a portion of the control linedisposed uphole from the secondary plug, the injection conveyancemay be disconnected from the secondary plugand pulled out-of-hole through the sealing materialdisposed in the central boreabove the secondary plug. As such, the injection conveyancemust be removed before the sealing materialsets and is still in an at least partially liquid state. Further, prior to the sealing materialsetting, high pressure fluid (e.g., cleaning fluid) may be run into the inner tubularto remove the sealing materialdisposed uphole from the secondary plug. As set forth above, maintaining the upper central bore portionclear of sealing materialmay allow the cutting device(shown in) to be lowered into position for making the orbital cut(shown in) without having to mill out the upper central bore portion. Running the high pressure fluid (e.g., the cleaning fluid) into the central boreof the inner tubularmay remove at least a portion of the sealing materialthat may have entered the upper central bore portionduring injection of the sealing materialinto the wellbore.

discloses the control lineand/or flat pack severed via making the orbital cutat a position uphole the secondary plug. As illustrated, the cutting devicemay be run-in-hole to a target location in the central borefor making the at least one orbital cut(e.g., a location that is axially aligned with a portion of the annulusthat is filled with the hardened scaling material). As set forth above, the sealing materialis pumped into the annulusto a position that is uphole from the secondary plug. Further, as set forth above, the upper central bore portion(e.g., the portion of the central boredisposed above the secondary plug) may be substantially clear of sealing material. Accordingly, once the injection conveyanceis pulled out-of-hole and the upper central bore portionis cleaned, the cutting devicemay run-in-hole to the target location above the secondary plugwithout having to mill out the upper central bore portion. The cutting devicemay be run-in-hole via a cutting device conveyance(e.g., a slickline, a wireline, coiled tubing, drill pipe, etc.). Further, the cutting devicemay include any suitable cutting device. For example, the cutting devicemay include an abrasive jetting device, a blade cutter, a reamer, a plasma torch, or some combination thereof.

Moreover, at the target location above the secondary plug, the cutting devicemay be configured to cut through the inner tubular(e.g., production tubing) and the sealing materialin the annulusand sever the control linesurrounded by the sealing material. Indeed, the hardened sealing materialis configured to restrain at least lateral movement of the control line. As set forth above, the cutting devicemay fail to cut the control lineif the control line is permitted to move in response to contact with the cutting device. However, in the illustrated embodiment, as the cutting devicecuts through the sealing materialand engages the control lineand/or flat pack, the remaining sealing materialmay prevent the control lineand/or flat pack from moving laterally in response to contact with the cutting device. That is, as the cutting deviceengages a first side of the control line, an opposite side of the control linemay interface with the remaining hardened scaling materialto prevent the control linefrom moving with respect to the cutting devicesuch that the cutting devicemay engage and sever the control line.

discloses the sealing materialdisposed in the orbital cutand the upper central bore portion. After making the orbital cut, additional sealing materialmay be injected into the upper central bore portionof the inner tubular(e.g., production tubing) to fill the volume removed by making the orbital cutand fill at least a portion of the upper central bore portion. As set forth above, the control linesmay provide leak paths for hydrocarbons to travel through a seal formed in the wellboreas part of the P&A operations. Accordingly, filling the orbital cutwith the additional sealing materialmay fluidly isolate the lower portionof the severed control linefrom the upper portionof the severed control line, which may block a leak path for hydrocarbons.

Accordingly, the present disclosure may systems and methods for severing control lines and/or flat packs during plug and abandonment (P&A) operations. The systems and methods may include any of the various features disclosed herein, including one or more of the following statements.

Statement 1. A method, comprising: injecting a sealing material into an annulus formed between a tubular and a wellbore wall, wherein the sealing material is configured to surround at least a portion of a control line disposed in the annulus; making at least one orbital cut, via a cutting device, through the tubular, the sealing material in the annulus, and the control line surrounded by the sealing material; and filling the at least one orbital cut and at least a portion of a central bore of the tubular with the sealing material to seal a wellbore.

Statement 2. The system of statement 1, wherein the cutting device comprises an abrasive jetting device, a blade cutter, a reamer, a plasma torch, or some combination thereof.

Statement 3. The system of any preceding statement, further comprising running a plug into a wellbore, via a plug conveyance, to a sealing position in a tubular disposed in the wellbore, wherein the plug conveyance comprises a slickline, a wireline, coiled tubing, drill pipe, or some combination thereof.

Statement 4. The system of any preceding statement, further comprising perforating a tubular above a plug disposed in a wellbore, via a perforating device, to open at least one fluid path between the central bore of the tubular and the annulus formed between the tubular and the wellbore wall.