Key information

Title
A DEVICE, A TOOLSTRING, A DOWNHOLE SYSTEM AND A METHOD FOR DRILLING A LATERAL HOLE FROM A MAIN BORE
Application number
20231096
Case type
National
Status
08.12.2025 Patent meddelt (B1)
Filed
17.10.2023
Effective date
17.10.2023
Publicly available
18.04.2025
Next annual fee due
31.10.2027
Applicant
ALTUS INTERVENTION (TECHNOLOGIES) AS (NO)
Owner
ALTUS INTERVENTION (TECHNOLOGIES) AS (NO)
Inventor
Edvin Riisem (NO) et al.
Agent
HÅMSØ PATENTBYRÅ AS (NO)
Granted
08.12.2025
Patent number
349335
Expiry date
17.10.2043

Abstract and drawing

Disclaimer: This text has been machine-scanned and may contain errors – please refer to "Publications" for legally binding content.
A system (7) for a downhole operation comprising a device (1) and a toolstring (24, 26) is described. The device (1) is formed to be placed within a wellbore (9) and to guide a lower part (244) of the toolstring (24, 26) such that a free end portion (246) in the lower part (244) forms a guide angle (1265) with a longitudinal axis (128) of the device (1). The device (1) enables a hole (100) to be drilled into a formation (95) surrounding the wellbore (9) and subsequent re-entries into the hole (100).

Publications

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Documents

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Date
 Date Doc. No. Process Case number In/Out Journal description To/from
 11.12.2025 08-01 Saksbehandling 20231096(349335) UT PT Registreringsbrev nasjonal patent (15) (PT20231096)
03.10.2025 07-01 Saksbehandling 20231096 UT Intention to grant HÅMSØ PATENTBYRÅ AS
 02.09.2025 06-01 Saksbehandling 20231096 UT PT Varsel om betaling av første årsavgift (3317) (PT20231096) HÅMSØ PATENTBYRÅ AS
 13.03.2025 05-01 Saksbehandling 20231096 INN Korrespondanse (Hovedbrev inn) HÅMSØ PATENTBYRÅ AS
 23.05.2024 04-05 Saksbehandling 20231096 INN P30837NO00_Translated claims HÅMSØ PATENTBYRÅ AS
 23.05.2024 04-04 Saksbehandling 20231096 INN P30837NO00 Description_and_claims_ mark-up HÅMSØ PATENTBYRÅ AS
 23.05.2024 04-03 Saksbehandling 20231096 INN P30837NO00 Description_and_claims_ clean HÅMSØ PATENTBYRÅ AS
 23.05.2024 04-02 Saksbehandling 20231096 INN 182_Response_Office_Action HÅMSØ PATENTBYRÅ AS
 23.05.2024 04-01 Saksbehandling 20231096 INN Korrespondanse (Hovedbrev inn) HÅMSØ PATENTBYRÅ AS
 30.11.2023 03-02 Saksbehandling 20231096 UT PT report 03:13:00
30.11.2023 03-01 Saksbehandling 20231096 UT Substantive examination HÅMSØ PATENTBYRÅ AS
 17.10.2023 02-01 Saksbehandling 20231096 UT Informasjon til oppfinner Lasse Haugland
 17.10.2023 01-04 Saksbehandling 20231096 INN P30837NO00_GPoA HÅMSØ PATENTBYRÅ AS
 17.10.2023 01-03 Saksbehandling 20231096 INN P30837NO00 Figures HÅMSØ PATENTBYRÅ AS
 17.10.2023 01-02 Saksbehandling 20231096 INN P30837NO00 Description_and_claims HÅMSØ PATENTBYRÅ AS
 17.10.2023 01-01 Saksbehandling 20231096 INN Søknadsskjema Patent HÅMSØ PATENTBYRÅ AS

Description, claims and drawings

Disclaimer: This text has been machine-scanned and may contain errors – please refer to "Publications" for legally binding content. Description
3493351A DEVICE, A TOOLSTRING, A DOWNHOLE SYSTEM AND A METHOD FOR DRILLING A LAT-ERAL HOLE FROM A MAIN BOREThe invention relates to a system for downhole operations. The system comprises a toolstring for downhole operations and a device for the downhole operation, wherein the 5 device is formed to be placed within a wellbore and to guide a lower part of the toolstring. A method for drilling the hole into a formation surrounding the wellbore is also described.In the oil and gas industry it may be desired to provide an access between an inside of a wellbore and a formation surrounding the wellbore. The access may provide additional 10 connections between the wellbore and a reservoir surrounding the wellbore to increase oil production from the reservoir, or to increase injection of fluid into the reservoir. The access may be a lateral hole drilled from the main bore into the formation surrounding the main bore. A toolstring comprising a drill bit may drill the hole. While drilling the lateral hole it may be beneficial to pull the toolstring out of the hole and then re-enter the 15 hole to ensure that the drill bit is not getting gradually stuck. The procedure of pulling out and then re-enter the hole during the drilling operation may also allow debris created during the drilling to be more easily removed from the hole. After the hole is drilled it may be beneficial in some cases to treat the hole to increase the potential of the lateral hole. The treatment may be to flush the hole with an acid, install a strainer to reduce 20 produced solids from the hole or other treatments. To improve monitoring of the reservoir it may be an option to place a sensor within the hole. The sensor enables the reservoir properties to be monitored from within the reservoir. It may be required to re-enter the hole both during the drilling operation and post-drilling. The hole is small compared 3493352to the main bore and may therefore be very difficult to re-enter if proper guidance into the hole is not provided.The toolstrings used in downhole operations are restricted in size, i.e. outer diameter by internal obstructions within the well it is to be operated within, e.g. valves. Thus, the hole 5 drilled into the formation being of smaller diameter than the diameter of the main bore results in even more restricted restrictions regarding a part of the toolstring that creates the hole and operates within the hole. An upper part of the toolstring may remain within the wellbore and may create forces required to drill the lateral hole and forces required to operate within the lateral hole. A lower part of the toolstring may receive and use the 10 forces created by the upper part and may drill the lateral hole and operate within the lateral hole. This reduces the complexity in the lower part of the toolstring thereby reducing overall complexity of the toolstring.Traditionally it has been installed a whipstock before a drill pipe is used for drilling the lateral hole. This involves large equipment, is time consuming, and therefore comes with 15 a high cost.Document EP1764475 discloses a drilling system comprising a conveyance means, a drilling tool and a guide for the drilling tool. The drilling system may be run using a wireline or a coil-tubing. The guide is anchored to the inside of the wellbore and guides the drill in a lateral direction relative to the wellbore. Upon completion of drilling the hole, a system 20 for loading a string of sensors in front of the drilling tool is activated. The drilling tool is then used for placing the string of sensors into the hole. If the guide is deactivated and released from the wellbore due to equipment failure or due to operational procedures, a re-entry into the hole is considered very difficult. This means that all operations must be completed while the guide is anchored to the inside of the wellbore. This increases com- 25 plexity in the drilling system and results in the drilling system being long and complex to control. For a scenario where the drilling tool remains within the hole due to being stuck or equipment failure, it may be difficult to recover the drilling system. This is due to the guide being an integrated part of the drilling system. Pulling the drilling system towards 3493353the surface using a surface equipment may cause the guide to be stuck in the drilling tool that extends into the hole.Document US2022170336 discloses a method and an apparatus for milling a window in a casing. The apparatus is run using wireline. The method includes to place a whipstock 5 within the wellbore and then use the apparatus to drill the window in the casing. The debris created during drilling is collected in a collector within the apparatus. Once the window in the casing is drilled, a coil tubing or a drill pipe is required to drill further into the formation that increases the cost of drilling the hole.The invention has for its object to remedy or to reduce at least one of the drawbacks of 10 the prior art, or at least provide a useful alternative to prior art. The object is achieved through features, which are specified in the description below and in the claims that follow.The invention involves creating a hole in a formation surrounding a wellbore and any subsequent operations related to the hole. The hole may have a somewhat lateral direction 15 relative to the wellbore, i.e. the hole and the wellbore may form an angle between them.A device for guiding a lower part of a toolstring is firmly anchored to an internal face of the wellbore. By having the device anchored to the internal face of the wellbore allows a plurality of different toolstrings to enter and re-enter the hole with minimum effort. This simplifies the toolstring used for creating the hole and any subsequently used toolstrings. 20 To create a hole is herein described as to drill a hole. Creating the hole may be done by a method of drilling, milling, flushing, melting material or any other suitable method for creating a hole into a formation surrounding the wellbore.The invention is defined by the independent patent claims. The dependent claims define advantageous embodiments of the invention. 25 In a first aspect the invention relates more particularly to a device for a downhole operation, wherein the device is formed to be placed within a wellbore and to guide a lower part of a toolstring, the device comprises an upper portion and forms a longitudinal axis, the upper portion comprises a guide extending from an entry to a side-opening located in 3493354an outer wall of the device, wherein:- the guide comprises an upper guide comprising a proximal guide area, and an exit guide comprising a distal guide area, the exit guide extending into the side-opening, the proximal guide area facing away from the side opening and the distal guide area facing to- 5 wards the side-opening, the proximal guide area and the distal guide area being positioned with a longitudinal distance between them along the longitudinal axis.The lower part of the toolstring to be guided within the device may enter the guide through the entry, continue the displacement such that the lower part of the toolstring abuts the upper guide and the exit guide. A continued displacement may result in the 10 lower part of the toolstring being guided by the proximal guide area and the distal guide area such that a free end portion of the lower part of the toolstring forms a guide angle with the longitudinal axis. The proximal guide area and the distal guide area may be defined as areas within the device being in contact with the lower part of the toolstring which influence the guide angle between the free end portion and the longitudinal axis. 15 The proximal guide area facing away from the side-opening may be defined as facing in a direction somewhat away from the side-opening and may therefore not be required to face in a direction away from the side-opening that is perpendicular to the longitudinal axis. The distal guide area facing towards the side-opening may be defined as facing in a direction somewhat towards the side-opening and may therefore not be required to face 20 in a direction towards the side-opening that is perpendicular to the longitudinal axis. The proximal guide area and the distal guide area that faces in somewhat opposite directions such that the lower part of the toolstring being guided is provided with a guide-force in a first direction in the proximal guide area, and a guide-force in a second direction in the distal guide area. The first direction may point somewhat away from the side-opening 25 while the second direction may be somewhat in a direction towards the side-opening such that the lower part of the toolstring may be elastically bent, thereby creating the guide angle as the free end portion exits the device. A radial distance between the proximal guide area and the side-opening may be larger compared to a radial distance between the distal guide area and the side-opening. The lower part of the toolstring being in 30 contact in the proximal guide area and the distal guide area may reduce a frictional force between the lower portion of the toolstring and the device compared to prior art wherein 3493355the toolstring is in contact through a large portion of a guiding device.The upper portion may comprise an interface and an anchor, the anchor being configurable between a retracted configuration and an extended configuration. The interface may be adapted for a toolstring to connect to the device and configure the anchor. The guide 5 may extend through the anchor.The wellbore is herein described as a borehole comprising a casing, a liner or other suitable tubular structures. The internal face of the wellbore is herein the internal face of the casing, the liner or the tubular structure forming the wellbore.The longitudinal axis of the device may extend from a centre of a first end of the device to 10 a centre of an opposite second end of the device.The device is intended for use in a variety of operations, e.g. drilling a hole into a formation surrounding the wellbore, placing an object within the hole, retrieving the object placed within the hole, flushing the hole, filling the hole with a substance or any other operation requiring a toolstring to be guided into the hole. 15 The anchor may be a type of anchor often used in packers and straddles that are well known within the art. The packer and straddle type of anchors typically have an open centre forming an access from above the anchor to below the anchor in or near a centre of the device. The anchor may comprise at least one anchor-member formed to engage with the internal face of the wellbore. The anchor-member may in the retracted configuration 20 be positioned such that the anchor-member is prevented from engaging with the internal face of the wellbore. This may be done by positioning the anchor-member within the outer diameter of the upper portion. In the extended configuration, the anchor-member may be displaced to a position such that at least a portion of the anchor-member projects over the outer diameter of the upper-portion. The anchor-member may extend radially from 25 the longitudinal axis. The anchor may remain in the extended configuration by internal mechanisms. A toolstring may be connected to the device and may be used to rearrange the anchor into the retracted configuration. The anchor may be reconfigured repeatedly between different configurations. More specifically, the anchor may be reconfigured re 3493356peatedly between the retracted configuration, the extended configuration and back to the retracted configuration an unlimited number of times, as known in the art.The device is intended to be used in both vertical and horizontal parts of the wellbore. For operations creating the wellbore debris (e.g. drilling operations) it is beneficial to have 5 the anchor above the side-opening since gravity then tends to pull the wellbore debris away from the upper portion of the device and therefore away from the anchor. The anchor positioned in the upper portion allows a lower portion of the device to be designed with less restrictions.A shape and a size of the wellbore debris is dependent on the drill bit used for drilling the 10 hole. The wellbore debris may comprise shavings from drilling in the wellbore and chunks of formation. The wellbore debris may be fine dust.The device may comprise a sealing element adapted to seal between the device and the internal face of the wellbore. The sealing element may be similar to the types used in known packers and straddles. The sealing element may be positioned below the anchor, 15 above the anchor or above and below the anchor. When there is a sealing element above and below the anchor there may be means for preventing trapped pressure between the sealing elements. The sealing element may be activated by configuring the anchor to the extended position, or the sealing element may be activated by a separate means. The sealing element may prevent the wellbore debris from reaching the anchor thereby re- 20 ducing the probability of the anchor being unable to be configured to the retracted configuration. A production flow from the wellbore to the surface or an injection flow from the surface to the wellbore may be prevented from flowing in an annulus between the device and the internal face of the wellbore by the sealing element. The production flow or injection flow may therefore be required to flow through the device where the benefits 25 of this will become more apparent later in the description.The guide may extend through the anchor and into the side-opening. The guide may comprise an entry-guide, the upper guide and the exit guide. The entry guide may be in an upper end of the upper portion, e.g. in the entry of the device. The entry-guide may reduce difficulties for a lower part of a toolstring to enter the device. The entry-guide may 3493357be a funnel, a chamfered edge, a rounded edge, a groove or any other suitable guidance means. The entry-guide may lead into the upper guide. The upper-guide may comprise a straight portion, a funnel, a track, a groove or a combination of these. The upper-guide may lead to a position offset from the longitudinal axis or may be co-located with the lon- 5 gitudinal axis. The upper-guide may lead into the exit-guide. The exit-guide may be deviated/inclined from the longitudinal axis and extends into the side-opening. The exit-guide may comprise a tunnel, a pipe, V-shaped groove, a U-shaped groove or any other form suitable for guiding the lower part of the toolstring to a predetermined position. The deviation/inclination between the longitudinal axis and the exit-guide may be constant 10 along the length of the exit-guide. The deviation/inclination between the longitudinal axis and the exit-guide may vary along the length of the exit-guide. The lower part of the toolstring may be guided by being abut the proximal guide area and the distal guide area such that the guide angle is formed between the free end portion and the longitudinal axis. The free end portion of the toolstring may maintain the guide-angle after being guided 15 through the device if the lower part of the toolstring is sufficiently rigid.The purpose of the guide is to guide and support the lower part of the toolstring such that the toolstring is guided to a predetermined position compared to the device. The guide may support the lower part of the toolstring such that buckling is delayed or prevented in the lower part of the toolstring. The predetermined position may be adjacent the side 20 opening or somewhere along the inclined line created between the proximal guide area and the distal guide area. The guide may comprise a stop-profile. The stop-profile may be used for stopping the toolstring from displacing compared to the device. The toolstring may comprise a no-go that prevents the toolstring for displacing any further after meeting the stop-profile. The no-go may be a part of the toolstring, or a dedicated part of the 25 toolstring. The stop profile may be used to trigger a switch within the toolstring. The switch within the toolstring may prevent the toolstring from displacing any further after meeting the stop-profile. The stop-profile improves the accuracy in the predetermined position by stopping the toolstring in a predetermined position compared to the device. The stop-profile may be the entry-guide, an edge, a complementary profile that mates 30 with the no-go, the upper-guide or any other suitable profile within the guide. The stopprofile may be the upper end of the upper portion. 3493358The wellbore debris created by the drill bit may be guided into the wellbore by the lower part of the toolstring. The wellbore debris may then be lifted to the surface by the production flow, or the injection flow may transport the wellbore debris deeper into the wellbore. 5 In an alternative embodiment, the device may be for the downhole operation, wherein the device may be formed to be placed within the wellbore and to guide the lower part of a toolstring, wherein:- the device comprises the upper portion and forms the longitudinal axis;- the upper portion may comprise the interface, the anchor and the guide; 10 - the anchor may be configurable between the retracted configuration and the extended configuration;- the interface may be adapted for the toolstring to connect to the device and configure the anchor;- the guide may extend through the anchor and into the side-opening located on the out- 15 er wall of the device; and- the guide may comprise the exit-guide positioned adjacent to the side-opening, where the exit-guide is deviated/inclined from the longitudinal axis.The anchor positioned in the upper portion may allow an easier access between a toolstring and the interface. The interface may be used to connect the device to a toolstring 20 and to configure the anchor. The interface may be adapted for being connected to a setting tool and a pulling tool. The setting tool and the pulling tool may be used for placing the device within the wellbore, reposition the device within the wellbore and retrieving the device from the wellbore. The setting tool and the pulling tool may be types known in the art, e.g. GS pulling tool. The setting tool and pulling tool known in the art are com- 25 mercially available tools requiring minimum effort to implement. The setting tool and pulling tool known in the art may be tools used for setting and retrieving plugs and straddles known in the art.The device is intended to guide the free end portion of the toolstring to the predetermined position. As the guide is intended to guide and support the lower part of the tool 3493359string, there will be contact between the guide and the lower part of the toolstring. Friction forces will therefore naturally occur between the guide and the lower part of the toolstring. The friction forces may come from displacing the free end portion of the lower part of the toolstring through the guide, from a rotation of the lower part of the toolstring 5 while being guided, or a combination of the two. The guide may comprise means for reducing friction between the guide and the lower part of the toolstring. The means for reducing the friction may be to position a low friction material through the guide, or at least in portions of the guide that may have large contact forces between the guide and the lower part of the toolstring, e.g. in the proximal guide area and the distal guide area. 10 Examples of low friction materials may be alloys often used in gliding bearings. Another means for reducing friction may be to include ball bearings or similar within the guide. The ball bearings may reduce friction forces when the lower part of the toolstring is rotating within the guide, e.g. during drilling operations. A third means for reducing friction may be to cover the portions with large contact forces between the guide and the lower 15 part of the toolstring with balls. The balls reduce friction by rotating and therefore preventing “rubbing” between the lower part of the toolstring and the guide.When the guide is to guide a drill bit during the drilling operation, the drill bit may cause a large wear within the guide. This is especially applicable at initiation of the drilling operation where the drill bit is partially within the guide. The guide may comprise a wear re- 20 sistant material. The wear resistant material may be positioned within the exit-guide in an area adjacent the side-opening. The wear resistant material may be a material with high hardness. Materials with hardness 50HRc or higher may be applicable materials. The wear resistant material may be a hard surfacing welding. The wear resistant material may be tungsten carbide inserts. 25 The device may comprise a lower portion, the side-opening may extend from the upper portion and into a portion of the lower portion and the lower portion may comprise a means for receiving a wellbore debris entering the lower portion through the sideopening. The main purpose of the side-opening may be to provide access from the exitguide to an area adjacent the exit-guide and access from the area adjacent the exit-guide 30 and into the lower portion of the device. The means for receiving the wellbore debris may 34933510be a channel, a tunnel, a groove, or any other suitable means for receiving the wellbore debris from the side-opening. The means for receiving the debris may lead the wellbore debris into the wellbore. The wellbore debris may then be transported with the production flow to the surface. The lower portion comprising the means for receiving the well- 5 bore debris enables the annulus between the device and the internal face of the wellbore to be small compared to if there were no means for receiving the wellbore debris. The small annulus positions the exit-guide closer to the internal face of the wellbore and therefore improve guidance of the lower part of the toolstring.In some operations the wellbore debris may be guided into and through the lower portion 10 and into the wellbore below the device. The wellbore debris may be left in the wellbore, or collected at a later point after the device has been removed. For this type of operations, a lower end of the device may be open. It may however be undesirable to leave the wellbore debris in the wellbore. The means for receiving the wellbore debris may comprise a chamber adjacent the side-opening. The chamber may be formed by the outer 15 wall of the lower portion. A lower end of the lower portion may comprise an end cap that is solid such that the debris is prevented from entering into the wellbore from the lower portion. The end cap may have a form to reduce challenges of displacing the device past wellbore obstacles and deeper into the wellbore. The end cap may be a bull nose or any other form that may aid in displacing the device past wellbore obstacles. The wellbore 20 obstacles may be, but is not limited to, changes in diameter, dog legs, damaged wellbore, or any other obstacles known in the art for causing challenges.A volume of debris that the lower portion may be capable of storing may be increased by separating solids from the fluids in the wellbore debris. The lower portion may comprise a filter such that the fluid and solids may be separated. The solids may remain within the 25 chamber while the fluids are forced into the wellbore. The filter may be in the end cap.This enables the fluid to transfer to the wellbore below the device while the solids remain within the chamber. The filter may form an outer diameter of the lower portion or at least a part of the lower portion such that a filter area becomes large compared to if the filter is only in the end cap. The large filter area will delay clogging of the filter. 34933511The side-opening and therefore the exit-guide may be positioned adjacent where the wellbore debris may be created. Some wellbore debris may therefore enter the guide causing restrictions inside the guide. The guide may comprise a plurality of perforations, the plurality of perforations connect the exit-guide to a lower end of the upper portion, 5 e.g. to the lower portion. The perforations will allow wellbore debris to be flushed from the guide and into the lower portion if the injection flow flows through the guide. The perforation may also allow the production flow to pass the device more easily such that production may be kept high while the device is anchored to the internal face of the wellbore. The production flow may therefore easily transport the wellbore debris to the sur- 10 face.The predetermined position is dependent on the guide-angle. The device may be formed with the option of having one fixed guide-angle thereby reducing the probability of setting the device up wrong prior to commencing an operation. The device may be formed such that the guide-angle may be adjustable. The guide-angle may be adjusted by placing 15 an insert in at least one of the upper-guide and the exit-guide, preferably in the proximal guide area and/or in the distal guide area. The guide-angle may also be adjusted by changing a size of the upper-guide and the exit-guide or any other suitable means for changing the geometry of the guide. Being able to adjust the guide-angle increases the versatility of the device. The guide-angle may be set to a fixed angle prior to placing the 20 device within the wellbore. The guide-angle may be between 2 degrees and 30 degrees, more preferred between 2 degrees and 20 degrees, and preferably between 3 degrees and 10 degrees.The side-opening may be elongated where a length is greater than a width. The width is herein described as a distance perpendicular to the longitudinal axis. The length is herein 25 described as a distance along the longitudinal axis. The side-opening may be wider than the width of the exit-guide. By having the side opening wider, the side-opening creates an access to a large area adjacent the device. This may be beneficial for operations wherein the wellbore debris is expected to be large compared to a diameter of the lower part of the toolstring intended to be guided by the device (e.g. long shavings). The side-opening 30 may be as wide as the width of the exit-guide. This enables the side-opening to aid in 34933512guiding the lower part of the toolstring to the predetermined position. The side-opening may be narrower than the width of the exit-guide. This may be beneficial to increase the accuracy of the predetermined position as the lower part of the toolstring may be guided by the side-opening in an extension of the exit-guide. The side-opening may have a lead- 5 out. The lead-out may provide guidance from the exit-guide into the side-opening. The lead-out may be a chamfered edge or any other suitable form. The side-opening length may extend from below the anchor in the upper portion to a lower end of the upper portion. The side-opening length may extend from the upper portion of the device and into a portion of the lower portion of the device. The length of the side-opening may be such 10 that a projection of the exit-guide remains clear of the side-opening in a lengthwise direction. The length of the side-opening may be such that the free end portion of the lower part of the toolstring following the guide-angle remains clear of the lower portion. A shape of the side-opening may come in many forms and still accomplish the abovementioned characteristics. 15 The device may be adapted to be positioned within the wellbore with a wireline toolstring, a slick line toolstring or a coil tubing toolstring.The guide may be adapted to guide an object and/or a purpose tool attached to an elongated extension through the guide. The purpose tool may be within the free end portion of the lower part. The purpose tool may be a drill bit, a setting tool, a pulling tool, an acid- 20 pump tool, or any other tool suitable for being guided through the guide. The object may be an acid, an uncured cement, a strainer liner, a sensor, a dissolvable plug (temporary plug), a permanent plug or any other object suitable to be placed within a hole in the formation surrounding the wellbore. The lower part of the toolstring may be rigid but elastically deformable when guided partly through the guide such that the free end por- 25 tion exits the device at least partly. The lower part of the toolstring may comprise at least one joint or link to reduce the elastic deformation when guided partly through the guide. The joint may be a universal joint.The guide dimensions may be determined by a skilled person in the art when the operational parameters are available. The operational parameters may be dependent on the 34933513toolstring to be guided.In a second aspect the invention relates more particularly to a toolstring for a downhole operation, wherein:- the toolstring comprises an upper part and a lower part, the lower part comprises a free 5 end portion;- the upper part comprises means for engaging an internal face of a wellbore;- the upper part creates a force transferable to the lower part;- the free end portion has a smaller outer diameter compared to an outer diameter of the upper part; 10 - the lower part is elastically bendable;- the lower part of the toolstring is formed to be guided into and partly through a device placed within the wellbore;- the device is formed to receive the lower part of the toolstring in one end and internally guide the free end portion of the lower part at a guide-angle when the free end portion 15 exits the device; and- the lower part of the toolstring is formed to transfer the force between the upper part of the toolstring and a purpose tool within the lower part of the toolstring.The lower part of the toolstring may comprise a plurality of connected tools. The lower part of the toolstring may be sufficiently rigid to be able to transfer the forces required by 20 the purpose tool in the lower part of the toolstring. The dimensioning of the lower part of the toolstring may be done by a person skilled in the art once the operational parameters for the purpose tool are known. The operational parameters may be e.g. a required weight on a drill bit, a torque required by the drill bit, a force required by a setting tool or a pulling tool etc. 25 As previously described, the guide-angle is the angle between the free end portion in the lower part of the toolstring and the wellbore. The guide-angle may be formed by the guide maintaining a small clearance between the guide and the lower part of the toolstring. The guide-angle may be formed by the lower part of the toolstring being in contact with two portions within the guide, e.g. the proximal guide area and the distal guide area. 34933514The guide-angle may be formed by the lower part of the toolstring being in contact with three portions within the guide.The lower part may elastically bend when being guided into and partly through the device. Once the free end portion is guided through the device, the lower part may be suffi- 5 ciently rigid to continue to displace the free end portion along an inclined line creating the guide-angle. After the lower part is removed from the device the lower part returns to its original shape. The lower part may comprise the joint. The joint may be formed to reduce an elastic bending in the lower part when the free end portion is guided through the device. The joint may be the universal joint. Reducing the elastic bending may reduce a 10 fatigue in the material. A skilled person in the art may design the lower part to be elastically bendable once the operational parameters are available. The operational parameters may be the guide-angle, forces to be transferred through the lower part, the type of purpose tool to be used, etc.The device used for guiding the lower part of the toolstring is placed within the wellbore. 15 This implies that the device imposes the lower part of the toolstring with greater restrictions regarding space compared to the upper part of the toolstring that may remain within the wellbore. The upper part of the toolstring may create the forces required for drilling a hole in a formation surrounding the wellbore and the forces required for subsequent operations within the hole. The lower part of the toolstring may receive and use 20 the forces created by the upper part while being guided partly through the device. This reduces the complexity in the lower part of the toolstring. The lower part of the toolstring may be formed to transfer at least one of a rotational force and an axial force between the upper part of the toolstring and the purpose tool. In other examples, the upper part of the toolstring may create the force(s) required to operate a variety of purpose tools, 25 e.g. the rotational force for the drill bit, the axial force for a drill bit, the axial force for a setting or pulling tool, a hydraulic fluid force for an acid deposit tool, a wellbore fluid flow for displacing a wellbore debris, an electric power for communication with the purpose tool or other suitable forces.In a vertical part of the wellbore, gravity may be used for propelling the toolstring deeper 34933515into the wellbore. When the gravity is unable to propel the toolstring further into the wellbore, the toolstring must create a propulsion force to displace the toolstring deeper into the wellbore. The upper part of the toolstring comprises the means for engaging the internal face of a wellbore. The means for engaging the internal face of a wellbore may 5 create the axial force. The axial force may be used for propelling the toolstring deeper into the wellbore. The means for engaging the internal face of the wellbore and creating the axial force may be used for a variety of applications, e.g. providing a weight on bit during drilling of the hole, providing a force for placing an object within the hole, providing a force for pulling the object from the hole, and other suitable applications when the 10 free end portion is guided through the device. The means for engaging the internal face of the wellbore and creating the axial force may also be used for anchoring the toolstring such that a rotational force may be transferred from the upper part to the lower part of the toolstring. The means for engaging the internal face of the wellbore and creating an axial force may be a wheel-based tractor. The wheel-based tractor may be used to trans- 15 fer a rotational reaction force between the purpose tool and the internal face of the wellbore.The lower part of the toolstring may comprise an elongated extension. The elongated extension may be made of a plurality of members that forms the elongated extension. The members may be tools or just members to extend the lower part of the toolstring. 20 Dividing the elongated extension into the plurality of members enables the elongated extension to be configurable. The elongated extension may be formed such that at least one of the rotational force and the axial force created in the upper part of the toolstring may be transferred to the purpose tool. The elongated extension may be a solid shaft, or the elongated extension may be hollow near a centre thereby creating a conduit within 25 the elongated extension. The conduit may be used if the toolstring requires a conduitconnection between the upper part of the toolstring and the purpose tool. An outer diameter of the elongated extension and/or the purpose tool may be between 20 and 100 millimetres, more preferred between 20 and 80 millimetres, and most preferred between 20 and 50 millimetres. A length of the elongated shaft may be between 1000 millimetres 30 and 9000 millimetres, more preferred between 1000 millimetres and 6000 millimetres and preferably between 1500 millimetres and 4500 millimetres. The elongated extension 34933516may be provided with limited support within the wellbore. If the depth of the hole to be drilled into the formation is long, a long section of the elongated extension may be unsupported within the wellbore and may result in buckling during drilling. To define “the long extension”, a person skilled in the art needs to perform a buckling analysis when the 5 operational parameters are known. If required, an operation may be split into a plurality of trips into the wellbore. The elongated extension may be adapted between the trips into the wellbore. An example of an operation that may require to be split into the plurality of trips may be the drilling operation. A first elongated extension may be used in a first drill-trip into the wellbore to drill the hole to a first predetermined depth. A second elon- 10 gated extension may be used in a second drill-trip into the wellbore where the hole is drilled to a second predetermined depth. A subsequent number of drill-trips into the wellbore may be completed before a final drill-trip into the wellbore. In the final drill-trip, a final elongated extension may be used to drill the hole to a final predetermined depth. An effect of splitting the drilling operation into the plurality of trips into the wellbore is 15 that the elongated extension is supported by the drilled hole as the hole is drilled deeper.Buckling may then be prevented in the elongated extension. A logging tool may be run between the drill-trips to check the geometry of the hole compared to the wellbore. The upper part of the toolstring may comprise a rotational device adapted to rotate the lower part of the toolstring. Being able to rotate the lower part of the toolstring enables 20 the purpose tool to be rotated when the free end portion is guided into and through the device. The purpose tool may comprise a drill bit. The drill bit may be used for drilling the hole through the wellbore and into the formation surrounding the wellbore. The length of the lower part of the toolstring may determine the length of the hole into the formation. At least one of the purpose tool and the elongated extension may comprise at least one 25 helical flute on an exterior surface. The helical flute(s) may function as a means for transporting the wellbore debris away from the drill bit and into the side-opening of the device.The upper part of the toolstring may comprise a filter and a pump for displacing a wellbore fluid through the conduit within the lower part of the toolstring. The pump may be a 30 progressing cavity pump, a centrifugal pump or any other suitable pump for displacing the 34933517wellbore fluid. The rotational device may supply the pump with the rotation force. The rotational device may rotate a pump shaft. The pump shaft may be connected to the lower part of the toolstring. The rotational device may therefore rotate both the pump shaft and the lower part of the toolstring. The filter may be used for removing solids from the 5 wellbore fluid being displaced by the pump. The filter may be positioned above the pump such that the pump is closer to the lower part of the toolstring. The pump may then displace the wellbore fluid from the filter in the upper part of the toolstring, through the conduit and out through the drill bit. The wellbore fluid may exit a drill bit front. The wellbore fluid flushes the wellbore debris out of the hole being drilled. The flushed debris 10 may settle within the device guiding the lower part of the toolstring. The filter being positioned above the pump ensures that the wellbore fluid is free from solids prior to flushing the hole being drilled. In an alternative embodiment of the toolstring, the filter may be positioned below the pump without departing from the scope of providing the wellbore fluid free from solids prior to flushing the hole being drilled. The pump and the filter may 15 be used for other applications than drilling where the lower part of the toolstring is not required to rotate. These applications may be the acid pump, a cement pump, or other suitable depositing tools where a wellbore fluid flow may be used.The upper part of the toolstring may comprise a collector for collecting debris from the wellbore fluid. The filter may be positioned within the collector where the collector is 20 positioned below the pump. A rotational shaft comprising a conduit in a centre may extend from the pump and to a lower end of the collector. The rotational shaft may connect the pump to the lower part of the toolstring. The toolstring may create a wellbore fluid flow within the wellbore that extends between the pump, the drill bit and then back to the pump again. In an embodiment of the toolstring, the pump may displace the wellbore 25 fluid through the conduit and out the drill bit. The wellbore fluid may then continue to displace from the drill bit, along the lower part and through the guide, and then into a lower end of the collector. Within the collector the wellbore fluid may be displaced through the filter. The filter positioned within the collector filters the wellbore fluid and deposits the solids within the collector. The clean wellbore fluid leaves the filter and dis- 30 places through the pump and into the conduit again. 34933518The means for engaging the internal face of the wellbore and creating the axial force may comprise a stroker. The stroker may comprise a stroker-anchor that may anchor the toolstring to the internal face of the wellbore. The stroker may create an axial force on the lower part of the toolstring. The means for engaging the internal face of the wellbore and 5 creating the axial force may be a combination of the tractor and the stroker. The purpose tool may comprise a sensor setting tool. The setting tool may be used for placing an object within the hole. The setting tool and the object may be guided through the device and into the hole in the formation surrounding the wellbore. The object may be a sensor. The toolstring may comprise a no-go. A person skilled in the art is familiar in using a no-go 10 for stopping a toolstring in a specific location of a wellbore. The no-go may be an increase in the outer diameter of the toolstring or any other suitable no-go means known in the art. A depth of the hole drilled into the formation surrounding the formation or a position that the object is to be placed within the hole may need to be accurate. The no-go may stop the displacement of the toolstring compared to the device. The no-go therefore in- 15 creases accuracy of a depth of the hole that may be drilled or may position the object more accurately within the hole.The lower part of the toolstring has a smaller outer diameter than the upper part of the toolstring. The lower part with a smaller outer diameter may be difficult to displace past wellbore obstacles found within the wellbore. The lower part of the toolstring may com- 20 prise a centralizer. The centralizer may be used for positioning the lower part of the toolstring in a somewhat centralized position within the wellbore. An effect of this is that it may be less challenging to displace the lower part past restrictions and into areas where inside diameter of the wellbore changes. The centralizer may be a part of the no-go. The drill bit may be formed to displace past restrictions and into areas where the inside diam- 25 eter of the wellbore changes. The drill bit may have a form known in the art to reduce challenges to displace past restrictions.The toolstring may be wireline operated, coil tubing operated or slickline operated.In a third aspect the invention relates more particularly to a system for downhole operations, wherein: 34933519- the system comprises a device according to the first aspect of the invention and a toolstring according to the second aspect of the invention.The toolstring and the device may be formed such that the lower part of the toolstring is elastic deformed when the free end portion is guided into and through the device. 5 In a fourth aspect the invention relates more particularly to a method for drilling a hole into a formation surrounding a wellbore, the method comprises the steps of:- providing a device according to the fist aspect of the invention;- displacing the device to a desired position within the wellbore;- anchor the device to an internal face of the wellbore; 10 - providing a toolstring according to the second aspect of the invention;- displace the toolstring such that a lower part of the toolstring is adjacent the device; - displace a free end portion of the lower part of the toolstring into and through the device and drill the hole into the formation surrounding the wellbore; and- retrieve the device from the wellbore. 15 The toolstring for displacing the device to the desired position and anchoring the device to the internal face of the wellbore may comprise a tractor and a setting tool. The toolstring for displacing the device to the desired position and anchoring the device to the internal face of the wellbore may be a slickline toolstring for setting a plug or a straddle. The toolstring for retrieving the device from the wellbore may comprise a tractor, a 20 stroker and a pulling tool. The toolstring for retrieving the device from the wellbore may be a slickline toolstring for pulling a plug or a straddle.The method may comprise to position and retrieve the device within the wellbore using a setting tool and a pulling tool, respectively. The pulling tool may be a GS pulling tool. The method may comprise to relocate the device within the wellbore. The device being 25 relocatable within the wellbore saves time if a plurality of holes are to be drilled.The method may comprise to orientate the device within the wellbore relative to a vertical line prior to anchoring the device to the internal face of the wellbore. The toolstring used for displacing the device to the desired position within the wellbore may comprise 34933520an orientation tool. The orientation tool may orientate the toolstring or a part of the toolstring being rotationally stiff connected to the device. The orientation tool may rotate the toolstring or the part of the toolstring around a longitudinal toolstring-axis. The longitudinal toolstring-axis may be formed between an upper end of the toolstring connected to a 5 surface equipment and a opposite lower end of the toolstring. The orientation tool may orientate the device such that the side-opening is orientated in a high side direction. The terms “high side” and “low side” are used herein for indicating a position within a deviated part of the wellbore. With reference to a watch face position, the “high side” is between 9 o’clock and 3 o’clock, while the “low side” is between 3 o’clock and 9 o’clock. The 10 wellbore debris may be created when drilling the hole into the formation surrounding the wellbore. By orienting the side-opening on the high-side, gravity may aid in transporting the wellbore debris out of the hole and into the side-opening. In a vertical part of the wellbore, it may be desired to position the hole in a specific direction. The device being relocatable combined with the possibility of orientating the device enables the plurality of 15 holes to be made in a specific depth of the wellbore.The method may comprise to collect the wellbore debris within the device while the lower part of the toolstring drills the hole through the wellbore and into the formation surrounding the wellbore. By collecting the wellbore debris created by the drilling, the wellbore is kept clean. 20 The production flow may be maintained during the drilling of the hole into the formation.This enables a production of hydrocarbons to continue while the drilling operation is performed. The production flow may be used for transporting the wellbore debris to a surface. Production zones positioned above the device may be temporarily blocked using straddles to increase production from below the device as well as potentially through the 25 hole being drilled.The method may comprise to use an injection flow for aiding in collecting the wellbore debris within the device. If the device comprises the filter in the lower portion, the injection flow may compress the solids in the wellbore debris such that more debris may be collected within the device. The injection flow may be used for cleaning the guide. 34933521The method may comprise to displace a wellbore fluid through a lower part of the toolstring while drilling the hole. This reduces probability of jamming the drill bit within the hole and aid in flushing the wellbore debris into the lower portion of the device.The method may comprise to collect the wellbore debris within the upper part of the 5 toolstring. When collecting the wellbore debris within the upper part of the toolstring, the wellbore debris is transported by the wellbore fluid flow from the hole being drilled and into the collector. This reduces the probability of losing any wellbore debris within the wellbore.The method comprises to place an object within the hole in the formation surrounding 10 the wellbore. To perform any subsequent operations post-drilling may increase the versatility of the hole created.In the following is described examples of preferred embodiments illustrated in the accompanying drawings, wherein:Fig.1 shows a perspective view of a device; 15 Figs.2a-f show steps in a method for placing the device within a wellbore, drilling a hole into a formation surrounding the wellbore, and placing a sensor inside the hole;Figs.3a-c show different embodiments of a drill-toolstring;Fig.4 shows a first embodiment of the device where the device guides the drill- 20 toolstring; andFig.5 shows a second embodiment of the device where the device guides the drill-toolstring.Any positional indications refer to the position shown in the figures. In the figures, same or corresponding elements are indicated by same reference numerals. For clarity reasons, 25 some elements may in some of the figures be with-out reference numerals. A person skilled in the art will understand that the figures are just principal drawings. The relative 34933522proportions of individual elements may also be distorted.Figure 1 shows a device 1 for downhole operations. The device 1 comprises an upper portion 12 and a lower portion 16. The upper portion 12 comprises an anchor 124. The anchor 124 is configurable between a retracted configuration and an extended configura- 5 tion. In the extended configuration a plurality of anchor elements 1242 projects over the outer diameter of the upper portion 12. A side-opening 14 extends from the upper portion 12 and into the lower portion 16. The side-opening 14 is located on an outer wall 146 of the device 1. The side-opening 14 has an elongated shape where a length 142 is greater than a width 144. The lower portion 16 comprises an end cap 162. The end cap 162 is 10 shown as a bull nose.Figure 2a shows a setting-toolstring 22 and the device 1 within a wellbore 9. The wellbore 9 is in this embodiment a liner in a horizontal part of a wellbore path. The wellbore 9 is surrounded by a cement 93. The cement 93 is surrounded by a formation 95. The settingtoolstring 22 is connected to a surface (not shown) via a wireline 8 in a first end. The set- 15 ting-toolstring 22 comprises a tractor 2422, an orientation tool 226, and a setting tool 222. The setting tool 222 connects the device 1 to the setting-toolstring 22 such that the device 1 can be displaced to a desired depth and orientated within the wellbore 9. The setting tool 222 is connected to the device 1 in an interface 122 in the upper portion 12. At the desired depth the orientation tool 226 orientates the device 1 such that the side- 20 opening 14 is oriented towards a high side. The setting tool 222 is used for configuring the anchor 124 in the upper portion 12 to the extended configuration. In the extended configuration, the plurality of anchor elements 1242 are engaged with an internal face 92 of the wellbore 9. Once the device 1 is firmly anchored to the internal face 92 the setting tool 222 is disconnected from the device 1. The setting-toolstring 22 is then pulled out of 25 the wellbore 9.Figure 2b shows a system 7 for downhole operation comprising a drill-toolstring 24 and the device 1. The drill-toolstring 24 comprising an upper part 242 and a lower part 244. The lower part 244 comprises a free end portion 246. The free end portion 246 will be described in more details in figure 2c. The upper part 242 is engaged with the internal 34933523face 92 within the wellbore 9, while the lower part 244 is to be guided partly through the device 1. A plurality of alternative embodiments of the drill-toolstring 24 will be described in more details in figures 3a-c. The upper part 242 comprises the tractor 2422, a rotational device 2423, a filter 2424, and a pump 2425. The pump 2425 is shown as a progressing 5 cavity pump. The filter 2424 is positioned above the pump 2425. The lower part 244 comprises an extension 2442, a drill bit 2444, and a no-go 2449. The no-go 2449 comprises biasing means and acts as a centralizer and lifts the lower part 244 away from the internal face 92 and the low side such that the drill bit 2444 easily enters the device 1. The no-go 2449 is in this embodiment not a part of the free end portion 246. The extension 2442 10 and the drill bit 2444 form a conduit 24422 that connects the pump 2425 to the drill bit 2444. The lower part 244 of the drill-toolstring 24 has been guided into a guide 126 through an entry 1260 in the upper part 12 of the device 1. The guide 126 comprises an upper guide 1262 and an exit guide 1264. The exit-guide 1264 has a tubular shape. The exit-guide 1264 comprises perforations 1266 connecting the guide 126 to a chamber 164 15 in the lower portion 16 of the device 1. The chamber 164 is formed by an outer wall of the lower portion 16, the end cap 162 and the upper portion 12. The chamber 164 is adjacent to a part of the side-opening 14.Figure 2c shows that the drill-toolstring 24 has been displaced further towards the device 1. The guide 126 has guided the lower part 244 such that the free end portion 246 has 20 been guided through the guide 126 and forms a guide-angle 1265 with a longitudinal axis 128 of the device 1. The free end portion 246 is the part of the lower part 244 that forms the guide-angle 1265. The free end portion 246 has a smaller outer diameter 2462 compared to an outer diameter 243 of the upper part 242. The lower part 244 has drilled a hole 100 through the wellbore 9, the cement 93 and into the formation 95. While drilling 25 the hole 100 the pump 2425 has pumped a wellbore fluid 98. The wellbore fluid 98 has been pumped through the filter 2424 into the conduit 24422 and out through the drill bit 2444. The wellbore fluid 98 has flushed a wellbore debris 96 out of the hole 100. The wellbore debris 96 has settled inside the chamber 164. The biasing means in the no-go 2449 has been compressed and the no-go 2449 has entered into the device 1. The no-go 30 2449 has stopped the drill-toolstring 24 from displacing any further such that the hole 100 has a predetermined depth. If some wellbore debris 96 has settled inside the guide 34933524126 an injection flow 99 may be injected from the surface such that any wellbore debris 96 within the guide 126 may be flushed through the perforations 1266 and into the chamber 164.Figure 2d shows a sensor-placing toolstring 26 comprising the upper part 242 and the 5 lower part 244. The upper part 242 comprises the tractor 2422 and a stroker 2427. The lower part 244 comprises the extension 2442, the no-go 2449, a sensor setting tool 2446 and a sensor 2448. The free end portion 246 comprises a part of the extension 2442, the setting tool 2446 and the sensor 2448. The free end portion 246 is guided through the guide 126 the same way as shown in figure 2c such that the sensor 2448 is placed within 10 the hole 100.Figure 2e shows a retrieving-toolstring 28 connected to the device 1. The retrievingtoolstring 28 comprises the tractor 2422, the stroker 2427 and a pulling tool 224. The pulling tool 224 is connected to the interface 122 in the upper portion 12 of the device 1 such that the device 1 is connected to the retrieving-toolstring 28. The anchor 124 in the 15 upper portion 12 is then configured to the retracted configuration. The device 1 is thereafter retrieved from the wellbore 9. The wellbore debris 96 remains within the chamber 164 and is therefore recovered from the wellbore 9 with the chamber 164. The sensor 2448 can be seen positioned inside the hole 100.Figure 2f shows that the device 1 has been retrieved from the wellbore 9 while the sensor 20 2448 remains within the hole 100.Figure 3a shows a first embodiment of the drill-toolstring 24. The drill-toolstring 24 comprises the upper part 242 and the lower part 244. The upper part 242 comprises the tractor 2422 and the rotational device 2423. The rotational device 2423 rotates the lower part 244. The lower part 244 comprises the extension 2442, the no-go 2449 and the drill 25 bit 2444. The extension 2442 has a solid cross-section.Figure 3b shows a second embodiment of the drill-toolstring 24 and similar to the drilltoolstring in figures 2b-c. The drill-toolstring 24 comprises the upper part 242 and the lower part 244. The upper part 242 comprises the tractor 2422, the rotational device 349335252423, the filter 2424, and the pump 2425. The lower part 244 comprises the extension 2442, the no-go 2449, and the drill bit 2444. The pump 2425 displaces the wellbore fluid 98 through the filter 2424, into the conduit 24422 within the extension 2442 such that the wellbore fluid 98 exits the drill bit 2444. 5 Figure 3c shows a third embodiment of the drill-toolstring 24. The drill-toolstring 24 comprises the upper part 242 and the lower part 244. The upper part 242 comprises the tractor 2422, the rotational device 2423, the pump 2425, a collector 2426 and the filter 2424. The filter 2424 is positioned within the collector 2426. The collector 2426 comprises a rotational shaft 2428 with a conduit in the centre. The rotational shaft 2428 connects the 10 pump 2425 with the lower part 244 such that the rotational shaft 2428 may transfer a rotational force to the lower part 244. The lower part 244 comprises the extension 2442, the no-go 2449, and the drill bit 2444. The pump 2425 displaces the wellbore fluid 98 from the filter 2424, into the rotational shaft 2428 and further into the conduit 24422 before the wellbore fluid 98 exits the drill bit 2444. The wellbore fluid 98 then moves 15 along the lower part 244 and enters a lower end 2429 of the collector 2426. The filter 2424 filters any wellbore debris 96 in the wellbore fluid 98 such that the wellbore debris 96 settles within the collector 2426. The filtered wellbore fluid 98 then continues through the pump 2425 and into the rotational shaft 2428 again.Figure 4 shows the free end portion 246 of the lower part 244 has been guided through 20 the device 1. The device 1 is shown in more details and it can be seen that the guide 126 comprises an entry guide 1261. The entry guide 1261 guides into the upper guide 1262. The upper guide 1262 comprises a funnel 12622 that guides into the exit-guide 1264. The exit-guide 1264 has a wear resistant material 12642 to prevent the drill bit 2444 from causing too much wear in the exit-guide 1264. The free end portion 246 has a smaller 25 outer diameter compared to an inner diameter of the guide 126 such that there is a clearance between the two. The lower part 244 has been elastically deformed within the guide 126 and holds a sufficient rigidity to transfer an axial force and rotational force between the upper part 242 and the drill bit 2444. The guide-angle 1265 is formed by the free end portion 246 being in contact with a proximal guide area 1268 within the upper 30 guide 1262 and a distal guide area 1269 within the exit guide 1264. The proximal guide 34933526area 1268 face somewhat away from the side-opening 14 while the distal guide area 1269 face somewhat towards the side-opening 14. The proximal guide area 1268 creates a proximal guide-force 12681 and the distal guide area 1269 creates a distal guide-force 12691 between the device 1 and the lower part 244. The proximal guide-force 12681 and 5 the distal guide-force 12691 are substantially in a plane wherein the free end portion 246 is to be guided within and have force-components in opposite directions, i.e. the proximal guide-force 12681 and the distal guide-force 12691 may be somewhat in opposite directions to be able to elastically bend the lower part 244. The proximal guide area 1268 and the distal guide area 1269 are positioned with a radial distance 1282 between them rela- 10 tive to the longitudinal axis 128, i.e. the proximal guide area 1268 has a radial distance from the side-opening 14 that is larger compared to a distance between the distal guide area 1269 and the side-opening 14. The proximal guide area 1268 and the distal guide area 1269 are positioned with a longitudinal distance 1284 between them along the longitudinal axis 128. The radial distance 1282 and the longitudinal distance 1284 influence the 15 guide angle 1265 and may be determined once operational parameters like the guide angle 1265 and the outer diameter 2462 of the free end portion 246 are known.Figure 5 shows an alternative embodiment wherein the guide-angle 1265 is formed by the lower part 244 being in contact with the proximal guide area 1268, the distal guide area 1269 and an enhancement guide area 1267. The enhancement guide area 1267 be- 20 ing within the upper guide 1262 and positioned closer to the entry guide 1261 compared to the proximal guide area 1268. The enhancement guide area 1267 may be used to influence the guide angle 1265 and may somewhat face in an opposite direction of the proximal guide area 1268.It should be noted that the above-mentioned embodiments illustrate rather than limit the 25 invention, and that those skilled in the art will be able to design many alternative embodiments without departing from the scope of the appended claims. In the claims, any reference signs placed between parentheses shall not be construed as limiting the claim. Use of the verb "comprise" and its conjugations does not exclude the presence of elements or steps other than those stated in a claim. The article "a" or "an" preceding an element 30 does not exclude the presence of a plurality of such elements. 34933527The mere fact that certain measures are recited in mutually different dependent claims does not indicate that a combination of these measures cannot be used to advantage.
Claims
34933528C l a i m s1. A device (1) for a downhole operation, wherein the device (1) is formed to be placed within a wellbore (9) and to guide a lower part (244) of a toolstring (24,5 26), the device (1) comprises an upper portion (12) and forms a longitudinal axis (128), the upper portion (12) comprises a guide (126) extending from an entry (1260) to a side-opening (14) located in an outer wall (146) of the device (1); c h a r a c t e r i s e d i n that:- the guide (126) comprises an upper guide (1262) comprising a proximal guide10 area (1268), and an exit guide (1264) comprising a distal guide area (1269), the exit guide (1264) extending into the side-opening (14), the proximal guide area (1268) facing away from the side opening (14) and the distal guide area (1269) facing towards the side-opening (14), the proximal guide area (1268) and the distal guide area (1269) being positioned with a longitudinal distance (1284) be-15 tween them along the longitudinal axis (128).2. The device (1) according to claim 1, wherein the upper portion (12) comprises an interface (122) and an anchor (124), the anchor (124) is configurable between a retracted configuration and an extended configuration, the guide (126) extending through the anchor (124).20 3. The device (1) according to claim 2, wherein the interface (122) is adapted for being connected to a setting tool (222) and a pulling tool (224).4. The device (1) according to any one of the preceding claims, wherein the guide (126) comprises means for reducing friction between the guide (126) and the lower part (244) of the toolstring (24, 26).25 5. The device (1) according to any one of the preceding claims, wherein the guide (126) comprises a wear resistant material (12642).6. The device (1) according to any one of the preceding claims, wherein the device (1) comprises a lower portion (16), the side-opening (14) extends from the upper34933529portion (12) and into a portion of the lower portion (16) and the lower portion (16) comprises a means for receiving a wellbore debris (96) entering the lower portion (16) through the side-opening (14).7. The device (1) according to claim 6, wherein the means for receiving the well-5 bore debris (96) entering the lower portion (16) comprises a chamber (164) adjacent the side-opening (14).8. The device (1) according to claim 7, wherein the lower portion (16) comprises a filter.9. The device (1) according to any one of the preceding claims, wherein the guide10 (126) comprises a plurality of perforations (1266), the plurality of perforations (1266) connect the exit-guide (1264) to a lower end of the upper portion (12).10. The device (1) according to any one of the preceding claims, wherein the proximal guide area (1268) and the distal guide area (1269) forms a guide angle (1265), the guide-angle (1265) being between 2 degrees and 30 degrees.15 11. The device (1) according to any one of the preceding claims, wherein the sideopening (14) has a length (142) and a width (144), wherein the length (142) along the longitudinal axis (128) is greater than the width (144) perpendicular to the longitudinal axis (128).12. A toolstring (24, 26) for a downhole operation, c h a r a c t e r i s e d20 i n that:- the toolstring (24, 26) comprises an upper part (242) and a lower part (244), the lower part (244) comprises a free end portion (246);- the upper part (242) comprises means (2422, 2427) for engaging an internal face (92) of a wellbore (9);25 - the upper part (242) creates a force transferable to the lower part (244);- the free end portion (246) has a smaller outer diameter (2462) compared to an outer diameter (243) of the upper part (242);- the lower part (244) is elastically bendable;34933530- the lower part (244) of the toolstring (24, 26) is formed to be guided into and partly through a device (1) placed within the wellbore (9);- the device (1) is formed to receive the lower part (244) of the toolstring (24, 26) in one end and internally guide the free end portion (246) of the lower part (244)5 at a guide-angle (1265) when the free end portion (246) exits the device (1); and - the lower part (244) of the toolstring (24, 26) is formed to transfer the force between the upper part (242) of the toolstring (24, 26) and a purpose tool (2444, 2446) within the lower part (244) of the toolstring (24, 26).13. The toolstring (24, 26) according to claim 12, wherein the force may be at least10 one of a rotational force and an axial force.14. The toolstring (24, 26) according to any one of claims 12 and 13, wherein the means for engaging the internal face (92) of the wellbore (9) and creating an axial force is a wheel-based tractor (2422).15. The toolstring (24, 26) according to any one of claims 12 to 14, wherein the lower15 part (244) of the toolstring (24,26) comprises an elongated extension (2442).16. The toolstring (24) according to any one of claims 12 to 15, wherein the upper part (242) of the toolstring (24) comprises a rotational device (2423) adapted to rotate the lower part (244) of the toolstring (24).17. The toolstring (24) according to any one of claims 12 to 16, wherein the purpose20 tool comprises a drill bit (2444).18. The toolstring (24) according to any one of claims 15 and 17, wherein at least one of the purpose tool (2444) and the elongated extension (2442) comprises at least one helical flute on an exterior surface.19. The toolstring (24) according to any one of claims 12 to 18, wherein the upper25 part (242) of the toolstring (24) comprises a filter (2424) and a pump (2425) for displacing a wellbore fluid (98) through a conduit (24422) within the lower part (244) of the toolstring (24).3493353120. The toolstring (24) according to claim 19, wherein the upper part (242) of the toolstring (24) comprises a collector (2426) for collecting a wellbore debris (96) from the wellbore fluid (98).21. The toolstring (24, 26) according to any one of claims 12 to 20, wherein the5 means for engaging the internal face (92) of the wellbore (9) and creating an axial force comprises a stroker (2427).22. The toolstring (26) according to claim 21, wherein the purpose tool comprises a sensor setting tool (2446).23. The toolstring (24, 26) according to any one of claims 12 to 22, wherein the tool-10 string (24, 26) comprises a no-go (2449).24. A system (7) for downhole operations, c h a r a c t e r i s e d i n that:- the system (7) comprises a device (1) according to any one of claims 1 to 11 and a toolstring (24, 26) according to any one of claims 12 to 23.15 25. Method for drilling a hole (100) into a formation (95) surrounding a wellbore (9), the method comprises the steps of:- providing a device (1) according to any one of claims 1 to 11;- displacing the device (1) to a desired position within the wellbore (9);- anchor the device (1) to an internal face (92) of the wellbore (9);20 - providing a toolstring (24, 26) according to any one of claims 12 to 23;- displace the toolstring (24, 26) such that a lower part (244) of the toolstring (24, 26) is adjacent the device (1);- displace a free end portion (246) of the lower part (244) of the toolstring (24, 26) into and through the device (1) and drill the hole (100) into the formation25 (95) surrounding the wellbore (9); and- retrieve the device (1) from the wellbore (9).3493353226. The method according to claim 25, wherein the method comprises to position and retrieve the device (1) within the wellbore (9) using a setting tool (222) and a pulling tool (224), respectively.27. The method according to any one of claims 25 and 26, wherein the method5 comprises to relocate the device (1) within the wellbore (9).28. The method according to any one of claims 25 to 27, wherein the method comprises to orientate the device (1) within the wellbore (9) relative to a vertical line prior to anchoring the device (9) to the internal face (92) of the wellbore (9).29. The method according to any one of claims 25 to 28, wherein the method com-10 prises to collect a wellbore debris (96) within the device (1) while the lower part (244 )of the toolstring (24) drills the hole (100) through the wellbore (9) and into the formation (95) surrounding the wellbore (9).30. The method according to any one of claims 25 to 28, wherein a production flow is used for transporting the wellbore debris (96) to a surface.15 31. The method according to any one of claims 25 to 29, wherein the method comprises to use an injection flow (99) for aiding in collecting the wellbore debris (96) within the device (1).32. The method according to any one of claims 25 to 31, wherein the method comprises to displace a wellbore fluid (98) through the lower part (244) of the tool-20 string (24) while drilling the hole (100).33. The method according to any one of claims 25 to 28 and 32, wherein the method comprises to collect the wellbore debris (96) within the upper part (242) of the toolstring (24).34. The method according to any one of claims 25 to 33, wherein the method com-25 prises to place an object (2448) within the hole (100) in the formation (95) surrounding the wellbore (9).P a t e n t k r a v1. Anordning (1) for en nedihullsoperasjon, hvori anordningen (1) er utformet for å plasseres inne i et brønnhull (9) og for å styre en nedre del (244) av en verktøystreng (24, 26), anordningen (1) omfatter et øvre parti (12) og danner en5 lengdeakse (128), det øvre partiet (12) omfatter en føring (126) som strekker seg fra en inngang (1260) til en sideåpning (14) som befinner seg i en ytre vegg (146) av anordningen (1);k a r a k t e r i s e r t v e d at:– føringen (126) omfatter en øvre føring (1262) omfattende et proksimalt10 føringsområde (1268), og en utgangsføring (1264) omfattende et distalt føringsområde (1269), utgangsføringen (1264) strekker seg inn i sideåpningen (14), det proksimale føringsområdet (1268) vender bort fra sideåpningen (14) og det distale føringsområdet (1269) vender mot sideåpningen (14), det proksimale føringsområdet (1268) og det distale føringsområdet (1269) er plassert i en15 langsgående avstand (1284) fra hverandre langs lengdeaksen (128).2. Anordning (1) ifølge krav 1, hvori det øvre partiet (12) omfatter en kontaktflate (122) og et anker (124), ankeret (124) er konfigurerbart mellom en tilbaketrukket konfigurasjon og en utvidet konfigurasjon, føringen (126) strekker seg gjennom ankeret (124).20 3. Anordning (1) ifølge krav 2, hvori kontaktflaten (122) er tilpasset for å koples til et setteverktøy (222) og et trekkeverktøy (224).4. Anordning (1) ifølge hvilket som helst av de foregående kravene, hvori føringen (126) omfatter midler for å redusere friksjon mellom føringen (126) og den nedre delen (244) av verktøystrengen (24, 26).25 5. Anordning (1) ifølge hvilket som helst av de foregående kravene, hvori føringen (126) omfatter et slitesterkt materiale (12642).6. Anordning (1) ifølge hvilket som helst av de foregående kravene, hvori anordningen (1) omfatter et nedre parti (16), sideåpningen (14) strekker seg fra34det øvre partiet (12) og inn i et parti av det nedre partiet (16) og det nedre partiet (16) omfatter et middel for å motta et brønnhullsavfall (96) som kommer inn i det nedre partiet (16) gjennom sideåpningen (14).7. Anordning (1) ifølge krav 6, hvori middelet for å motta brønnhullsavfallet (96)5 som kommer inn i det nedre partiet (16) omfatter et kammer (164) ved siden av sideåpningen (14).8. Anordning (1) ifølge krav 7, hvori det nedre partiet (16) omfatter et filter.9. Anordning (1) ifølge hvilket som helst av de foregående kravene, hvori føringen (126) omfatter en flerhet av perforeringer (1266), flerheten av perforeringer10 (1266) forbinder utgangsføringen (1264) til en nedre ende av det øvre partiet (12).10. Anordning (1) ifølge hvilket som helst av de foregående kravene, hvori det proksimale føringsområdet (1268) og det distale føringsområdet (1269) danner en føringsvinkel (1265), føringsvinkelen (1265) er mellom 2 grader og 30 grader.15 11. Anordning (1) ifølge hvilket som helst av de foregående kravene, hvori sideåpningen (14) har en lengde (142) og bredde (144), hvori lengden (142) langs lengdeaksen (128) er større enn bredden (144) vinkelrett på lengdeaksen (128).12. Verktøystreng (24, 26) for en nedihullsoperasjon, k a r a k t e r i s e r t v e d at:20 – verktøystrengen (24, 26) omfatter en øvre del (242) og en nedre del (244), den nedre delen (244) omfatter et fritt endeparti (246);– den øvre delen (242) omfatter midler (2422, 2427) for inngrep med en innvendig flate (92) i et brønnhull (9);– den øvre delen (242) danner en kraft som er overførbar til den nedre delen25 (244);– det frie endepartiet (246) har en mindre ytre diameter (2462) sammenliknet med en ytre diameter (243) i den øvre delen (242);– den nedre delen (244) er elastisk bøyelig;35– den nedre delen (244) av verktøystrengen (24, 26) er utformet for å føres inn i og delvis gjennom en anordning (1) plassert inne i brønnhullet (9);– anordningen (1) er utformet til å motta den nedre delen (244) av verktøystrengen (24, 26) i én ende og innvendig føre det frie endepartiet (246) av5 den nedre delen (244) ved en føringsvinkel (1265) når det frie endepartiet (246) går ut av anordningen (1); og– den nedre delen (244) av verktøystrengen (24, 26) er utformet til å overføre kraften mellom den øvre delen (242) av verktøystrengen (24, 26) og et formålsverktøy (2444, 2446) inne i den nedre delen (244) av verktøystrengen (24,10 26).13. Verktøystreng (24, 26) ifølge krav 12, hvori kraften i det minste kan være én av en rotasjonskraft og en aksialkraft.14. Verktøystreng (24, 26) ifølge hvilket som helst av kravene 12 og 13, hvori middelet for inngrep med den innvendige flaten (92) i brønnhullet (9) og for å15 danne en aksialkraft, er en hjulbasert traktor (2422).15. Verktøystreng (24, 26) ifølge hvilket som helst av kravene 12 til 14, hvori den nedre delen (244) av verktøystrengen (24, 26) omfatter en avlang forlengelse (2442).16. Verktøystreng (24) ifølge hvilket som helst av kravene 12 til 15, hvori den øvre20 delen (242) av verktøystrengen (24) omfatter en rotasjonsanordning (2423)tilpasset til å rotere den nedre delen (244) av verktøystrengen (24).17. Verktøystreng (24) ifølge hvilket som helst av kravene 12 til 16, hvori formålsverktøyet omfatter en borkrone (2444).18. Verktøystreng (24) ifølge hvilket som helst av kravene 15 og 17, hvori i det25 minste én av formålsverktøyet (2444) og den avlange forlengelsen (2442)omfatter minst én spiralformet rille på en utvendig overflate.3619. Verktøystreng (24) ifølge hvilket som helst av kravene 12 til 18, hvori den øvre delen (242) av verktøystrengen (24) omfatter et filter (2424) og en pumpe (2425) for å forskyve et brønnhullsfluid (98) gjennom en kanal (24422) inne i den nedre delen (244) av verktøystrengen (24).5 20. Verktøystreng (24) ifølge krav 19, hvori den øvre delen (242) av verktøystrengen (24) omfatter en oppsamler (2426) for å samle opp et brønnhullsavfall (96) fra brønnhullsfluidet (98).21. Verktøystreng (24, 26) ifølge hvilket som helst av kravene 12 til 20, hvori middelet for inngrep med den innvendige flaten (92) i brønnhullet (9) og for å10 danne en aksialkraft, omfatter en stroker (2427).22. Verktøystreng (26) ifølge krav 21, hvori formålsverktøyet omfatter et sensorsetteverktøy (2446).23. Verktøystreng (24, 26) ifølge hvilket som helst av kravene 12 til 22, hvori verktøystrengen (24, 26) omfatter en no-go (2449).15 24. System (7) for nedihullsoperasjoner, k a r a k t e r i s e r t v e d at:– systemet (7) omfatter en anordning (1) ifølge hvilket som helst av kravene 1 til 11 og en verktøystreng (24, 26) ifølge hvilket som helst av kravene 12 til 23.25. Fremgangsmåte for å bore et hull (100) inn i en formasjon (95) som omgir et brønnhull (9), fremgangsmåten omfatter trinnene:20 – å tilveiebringe en anordning (1) ifølge hvilket som helst av kravene 1 til 11;– å forskyve anordningen (1) til en ønsket posisjon inne i brønnhullet (9);– å forankre anordningen (1) til en innvendig flate (92) i brønnhullet (9);– å tilveiebringe en verktøystreng (24, 26) ifølge hvilket som helst av kravene 12 til 23;25 – å forskyve verktøystrengen (24, 26) slik at en nedre del (244) av verktøystrengen (24, 26) er ved siden av anordningen (1);– å forskyve et fritt endeparti (246) av den nedre delen (244) av verktøystrengen (24, 26) inn i og gjennom anordningen (1) og bore hullet (100) inn i formasjonen 34933537(95) som omgir brønnhullet (9); og– å trekke ut anordningen (1) fra brønnhullet (9).26. Fremgangsmåte ifølge krav 25, hvori fremgangsmåten omfatter å plassere og trekke tilbake anordningen (1) inne i brønnhullet (9) ved bruk av henholdsvis et5 setteverktøy (222) og et trekkeverktøy (224).27. Fremgangsmåte ifølge hvilket som helst av kravene 25 og 26, hvori fremgangsmåten omfatter å omplassere anordningen (1) inne i brønnhullet (9).28. Fremgangsmåte ifølge hvilket som helst av kravene 25 til 27, hvori fremgangsmåten omfatter å orientere anordningen (1) inne i brønnhullet (9)10 relativt til en vertikal linje forut for forankring av anordningen (1) til den innvendige flaten (92) i brønnhullet (9).29. Fremgangsmåte ifølge hvilket som helst av kravene 25 til 28, hvori fremgangsmåten omfatter å samle et brønnhullsavfall (96) inne i anordningen (1) mens den nedre delen (244) av verktøystrengen (24) borer hullet (100) gjennom15 brønnhullet (9) og inn i formasjonen (95) som omgir brønnhullet (9).30. Fremgangsmåte ifølge hvilket som helst av kravene 25 til 28, hvori en produksjonsstrømning brukes for å transportere brønnhullsavfallet (96) til en overflate.31. Fremgangsmåte ifølge hvilket som helst av kravene 25 til 29, hvori20 fremgangsmåten omfatter å bruke en injeksjonsstrømning (99) for å hjelpe med å samle opp brønnhullsavfallet (96) inne i anordningen (1).32. Fremgangsmåte ifølge hvilket som helst av kravene 25 til 31, hvori fremgangsmåten omfatter å forskyve et brønnhullsfluid (98) gjennom den nedre delen (244) av verktøystrengen (24) under boring av hullet (100).25 33. Fremgangsmåte ifølge hvilket som helst av kravene 25 til 28 og 32, hvori fremgangsmåten omfatter å samle opp brønnhullsavfallet (96) innenfor den øvre delen (242) av verktøystrengen (24).3493353834. Fremgangsmåte ifølge hvilket som helst av kravene 25 til 33, hvori fremgangsmåten omfatter å plassere et objekt (2448) inne i hullet (100) i formasjonen (95) som omgir brønnhullet (9).
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Patent classes

IPC classesE21B 7/06E21B 41/00CPC classesE21B 7/061E21B 41/0035E21B 7/068

Citations

EP 1764475 A1 (A1)US 5131467 A (A)US 2018/0010419 A1 (A1)

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ALTUS INTERVENTION (TECHNOLOGIES) AS
Moseidveien 35 4033 STAVANGER NO (STAVANGER Municipality, Rogaland county)Org. number: 915728847Inventors
Edvin Riisem
Hoveveien 151 4323 SANDNES NO (SANDNES Municipality, Rogaland county)
Lasse Haugland
Pastellveien 13 4344 BRYNE NO (TIME Municipality, Rogaland county)

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HÅMSØ PATENTBYRÅ AS
HÅMSØ PATENTBYRÅ AS

Org. number: 918752900

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